ML031330797

IR 05000272-03-003, IR 05000311-03-003, on 12/30/02 - 3/29/03, for Public Service Electric Gas Nuclear LLC, Salem Units 1 and 2, Adverse Weather Protection, Equipment Alignment, Non-routine Plant Evolutions, Post Maintenance Testing

ML031330797
Person / Time
Site:	Salem
Issue date:	05/13/2003
From:	Meyer G Reactor Projects Branch 3
To:	Richard Anderson Public Service Electric & Gas Co
References
IR-03-003
Download: ML031330797 (44)

See also: IR 05000311/2003003

Text

May 13, 2003

Mr. Roy A. Anderson

Chief Nuclear Officer and President

PSEG LLC - N09

P. O. Box 236

Hancocks Bridge, NJ 08038

SUBJECT: SALEM NUCLEAR GENERATING STATION - NRC INTEGRATED

INSPECTION REPORT 50-272/03-03, 50-311/03-03

Dear Mr. Anderson:

On March 29, 2003, the US Nuclear Regulatory Commission (NRC) completed an inspection at

your Salem Units 1 and 2. The enclosed integrated inspection report documents the inspection

findings, which were discussed on April 4, 2003, with Mr. Tim OConnor and other members of

your staff.

The inspection examined activities conducted under your license as they relate to safety and

compliance with the Commissions rules and regulations and with the conditions of your license.

The inspectors reviewed selected procedures and records, observed activities, and interviewed

personnel.

The report documents two NRC-identified findings and two self-revealing findings of very low

safety significance (Green); three were determined to involve violations of NRC requirements.

However, because of the very low safety significance and because they are entered into your

corrective action program, the NRC is treating these three findings as non-cited violations

(NCVs) consistent with Section VI.A of the NRC Enforcement Policy. Additionally, a licensee-

identified violation which was determined to be of very low safety significance is listed in this

report. If you contest any NCV in this report, you should provide a response within 30 days of

the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory

Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the

Regional Administrator, Region I; the Director, Office of Enforcement; and the NRC Resident

Inspector at the Salem Nuclear Generating Station.

Since the terrorist attacks on September 11, 2001, the NRC has issued five Orders (dated

February 25, 2002, January 7, 2003 and three dated April 29, 2003) and several threat

advisories to licensees of commercial power reactors to strengthen licensee capabilities,

improve security force readiness, and enhance access authorization. The NRC also issued

Temporary Instruction (TI) 2515/148 on August 28, 2002, that provided guidance to inspectors

to audit and inspect licensee implementation of the interim compensatory measures (ICMs)

required by the Order dated February 25, 2002. Phase 1 of TI 2515/148 was completed at all

commercial nuclear power plants during calendar year (CY) 2002, and the remaining

inspections are scheduled for completion in CY 2003. Additionally, table-top security drills were

conducted at several licensee facilities to evaluate the impact of expanded adversary

characteristics and the ICMs on licensee protection and mitigative strategies. Information

Mr. Roy A. Anderson 2

gained and discrepancies identified during the audits and drills were reviewed and dispositioned

by the Office of Nuclear Security and Incident Response. For CY 2003, the NRC will continue

to monitor overall safeguards and security controls, conduct inspections, and resume force-on-

force exercises at selected power plants. Should threat conditions change, the NRC may issue

additional Orders, advisories, and temporary instructions to ensure adequate safety is being

maintained at all commercial power reactors.

In accordance with 10 CFR 2.790 of the NRCs "Rules of Practice," a copy of this letter and its

enclosure will be available electronically for public inspection in the NRC Public Document

Room or from the Publicly Available Records (PARS) component of NRCs document system

(ADAMS). ADAMS is accessible from the NRC Web site at

http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Glenn W. Meyer, Chief

Projects Branch 3

Division of Reactor Projects

Docket Nos: 50-272, 50-311

License Nos: DPR-70, DPR-75

Enclosure: Inspection Report 50-272/03-03, 50-311/03-03

w/Attachment: Supplemental Information

Mr. Roy A. Anderson 3

cc w/encl:

M. Friedlander, Director - Business Support

J. Carlin, Vice President - Engineering

D. Garchow, Vice President - Projects and Licensing

G. Salamon, Manager - Nuclear Licensing

T. OConnor, Vice President - Operations

R. Kankus, Joint Owner Affairs

J. J. Keenan, Esquire

Consumer Advocate, Office of Consumer Advocate

F. Pompper, Chief of Police and Emergency Management Coordinator

M. Wetterhahn, Esquire

State of New Jersey

State of Delaware

N. Cohen, Coordinator - Unplug Salem Campaign

E. Gbur, Coordinator - Jersey Shore Nuclear Watch

E. Zobian, Coordinator - Jersey Shore Anti Nuclear Alliance

Mr. Roy A. Anderson 4

Distribution w/encl:

Region I Docket Room (with concurrences)

D. Orr, DRP - NRC Resident Inspector

H. Miller, RA

J. Wiggins, DRA

G. Meyer, DRP

S. Barber, DRP

A. Kugler, OEDO

J. Clifford, NRR

R. Fretz, PM, NRR

G. Wunder, Backup PM, NRR

DOCUMENT NAME: C:\ORPCheckout\FileNET\ML031330797.wpd

After declaring this document An Official Agency Record it will be released to the Public.

To receive a copy of this document, indicate in the box: "C" = Copy without attachment/enclosure "E" = Copy with attachment/enclosure "N" = No copy

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U.S. NUCLEAR REGULATORY COMMISSION

REGION I

Docket Nos: 50-272, 50-311

License Nos: DPR-70, DPR-75

Report No: 50-272/2003-03, 50-311/2003-03

Licensee: PSEG LLC

Facility: Salem Nuclear Generating Station, Units 1 & 2

Location: P.O. Box 236

Hancocks Bridge, NJ 08038

Dates: December 30, 2002 - March 29, 2003

Inspectors: J. Daniel Orr, Senior Resident Inspector

Raymond K. Lorson, Senior Resident Inspector

Fred L. Bower, Resident Inspector

G. Scott Barber, Senior Project Engineer

Joseph T. Furia, Senior Health Physicist

F. Jeff Laughlin, Operations Engineer

Keith A. Young, Reactor Inspector

Robert M. Berryman, Reactor Inspector

Daniel L. Schroeder, Reactor Inspector

Gregory C. Smith, Senior Physical Security Inspector

Jason C. Jang, Senior Health Physicist

David P. Beaulieu, Senior Resident Inspector, Calvert Cliffs

Approved By: Glenn W. Meyer, Chief,

Projects Branch 3

Division of Reactor Projects

TABLE OF CONTENTS

1. REACTOR SAFETY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

1R01 Adverse Weather Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

1R02 Evaluation of Changes, Tests, or Experiments . . . . . . . . . . . . . . . . . . . . . . . . . 3

1R04 Equipment Alignment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4

1R05 Fire Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

1R06 Flood Protection Measures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

1R11 Licensed Operator Requalification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

1R12 Maintenance Rule (MR) Implementation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

1R13 Maintenance Risk Assessments and Emergent Work Evaluation . . . . . . . . . . . 8

1R14 Personnel Performance During Non-routine Plant Evolutions . . . . . . . . . . . . . . 8

1R15 Operability Evaluations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

1R17 Permanent Plant Modifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

1R19 Post-Maintenance Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

1R22 Surveillance Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

1R23 Temporary Plant Modifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

2. RADIATION SAFETY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

2OS1 Access Control to Radiologically Significant Areas . . . . . . . . . . . . . . . . . . . . . 18

2OS2 ALARA Planning and Controls . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

2OS3 Radiation Monitoring Instrumentation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

2PS3 Radiological Environmental Monitoring Program (REMP) . . . . . . . . . . . . . . . . 20

4. OTHER ACTIVITIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

4OA2 Problem Identification and Resolution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

4OA3 Event Followup . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

4OA5 Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

4OA6 Meetings, including Exit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

4OA7 Licensee-Identified Violations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

ATTACHMENT: SUPPLEMENTAL INFORMATION . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

KEY POINTS OF CONTACT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED . . . . . . . . . . . . . . . . . . . . . . . 2

LIST OF DOCUMENTS REVIEWED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2

LIST OF ACRONYMS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

ii Enclosure

SUMMARY OF FINDINGS

IR 05000272/03-03, IR 05000311/03-03; 12/30/02 - 3/29/03; Public Service Electric Gas

Nuclear LLC, Salem Units 1 and 2; Adverse Weather Protection, Equipment Alignment, Non-

routine Plant Evolutions, Post Maintenance Testing.

The report covered a 13-week period of inspection by resident inspectors, and inspections by a

regional radiation specialist, a regional security specialist, and a regional projects inspector.

Three Green non-cited violations (NCVs), one Green finding, and one unresolved item (URI)

with safety significance to be determined were identified. The significance of most findings is

indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP). Findings for which the SDP does not apply

may be Green or be assigned a severity level after NRC management review. The NRCs

program for overseeing the safe operation of commercial nuclear power reactors is described in

NUREG-1649, Reactor Oversight Process, Revision 3, dated July 2000.

A. NRC-Identified and Self-Revealing Findings

Cornerstone: Initiating Events

 Green. A self-revealing finding occurred when Salem Units 1 and 2 experienced

a control air transient. Equipment anomalies during the transient revealed a

valve configuration problem, an incomplete control air preventive maintenance

item, and inadequate corrective action for a significant air leak.

This finding was not a violation of NRC requirements, in that the performance

deficiencies occurred on non-safety related systems. The finding had an actual

impact on plant stability and operator actions were necessary to reseat a reactor

coolant system letdown line relief valve. This finding screened to Green in phase

1 of the SDP, because mitigation equipment was not affected by the control air

transient. (Section 1R14)

Cornerstone: Mitigating Systems

 Green. The inspectors identified that PSEG did not initiate corrective action to

ensure that the emergency diesel generators (EDGs) would remain unaffected

by apparent roof leaks.

This NCV of 10 Code of Federal Regulations (CFR) 50, Appendix B, Criterion

XVI, Corrective Action, is greater than minor, because it affected the mitigating

systems cornerstone of equipment reliability and unavailability. The 1C EDG

required corrective action to dry wetted safety-related electrical terminals prior to

its operation. This finding was of very low significance, because the 1C EDG

condition existed for less than the TS allowed outage time. (Section 1R01)

 Green. A self-revealing finding was identified when the 1B emergency diesel

generator (EDG) tripped during post-maintenance testing (PMT). The PMT was

iii Enclosure

for separate test reasons and fortuitously revealed the EDG deficiency. The

EDG deficiency involved a known electrical connector problem and inadequate

interim corrective actions.

This NCV of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, is

greater than minor, because it affected the mitigating systems cornerstone of

equipment reliability. This finding was of very low significance, because the

inadequate interim corrective actions did not cause any EDG to be inoperable for

greater than the TS allowed outage time. (Section 1R19.1)

 Green. The inspectors identified that temporary modifications to the 22 auxiliary

feedwater (AFW) pump and the 13 AFW pump skids were not properly

evaluated.

This NCV of 10 CFR 50, Appendix B, Criterion III, Design Control was greater

than minor, because it affected the mitigating system cornerstone and the

reliability of two AFW pumps. This finding was determined to be of very low

safety significance, because pump shaft leakoff conditions were such that the

unauthorized modifications had not impacted pump operation. (Section 1R04.1)

B. Licensee-Identified Violations

A violation of very low safety significance, which was identified by PSEG has been

reviewed by the inspector. Corrective actions, taken or planned by PSEG have been

entered into PSEGs corrective action program. The violation and corrective action

tracking number are listed in Section 4OA7 of this report.

iv Enclosure

REPORT DETAILS

Summary of Plant Status

Unit 1 began the period at full power. Salem Unit 1 significantly reduced power on January 21,

March 3, and March 24, 2003, for river grass conditions. Power was returned to 100% in each

instance as the river grass conditions subsided and after the circulating water (CW) system

repairs were completed. The details of the January 21 power reduction are described in

Section 1R14.2. On February 22 plant operators reduced power to 70% reactor power for

switchyard maintenance activities. Power was restored to 100% on February 25.

Unit 2 began the period at 100%. Operators initiated a manual reactor trip on March 29, in

response to severe river grass conditions and CW system repairs. The details of the March 29

reactor trip are described in Section 1R14.4. Salem Unit 2 was returned to full power operation

on April 2.

1. REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

a. Inspection Scope

The inspectors reviewed PSEGs response to adverse weather conditions during a snow

blizzard on February 16 and 17, 2003. The review included control room logs,

corrective action notifications and plant walkdowns.

b. Findings

Introduction. The inspectors identified that PSEG did not initiate corrective action to

ensure that the EDGs would remain unaffected by existing roof leaks. This finding was

determined to be of very low risk significance (Green), because the condition only

affected the 1C EDG and existed for less than the allowed out of service time.

Description. On February 16, 2003, the 2A EDG room was inadvertently filled with

carbon dioxide from its automatic fire suppression system. Operators and fire protection

technicians quickly determined that no fire had caused the actuation. The 2A EDG

room was ventilated to habitable conditions within three hours and no other vital plant

areas were affected by the carbon dioxide discharge. The 2A EDG remained operable

for the duration.

PSEG discovered that a thermal fire protection detector had become wetted by snow

entering through ventilation penetrations on the top of the EDG rooms. PSEG entered

this problem into its corrective action program as notification 20132342.

On February 20, 2003, the inspectors were present in the 1C EDG room to observe

preparations for and the conduct of its monthly surveillance test. The inspectors

observed that water was puddling on top of an electrical terminal panel mounted to the

1C EDG generator. Operators present in the room also observed the condition, stopped

2

any further preparations to start the 1C EDG and initiated a request to electrical

maintenance. Several terminal connections had become wet through conduit

penetrations. The electricians dried the terminal connections. The source of the water

was snow melt through roof and ventilation system leaks. The inspector walked down

all other Salem Unit 1 and Unit 2 EDG rooms and discovered that 4 of 6 EDG rooms

had similar leaks. Only the 1C EDG room leaked onto safety-related electrical

equipment.

On February 21, 2003, the inspectors discussed the EDG roof leak conditions with the

operations manager. A notification had not yet been initiated for the impact on the 1C

EDG. On February 22, 2003, operators initiated a notification for the 1C EDG roof

leaks, 20132895.

On March 1, 2003, the inspectors walked down several vital areas of the plant during a

rain storm. The inspectors identified other roof leaks in the EDG rooms. In particular

the inspectors identified water impinging on all three Salem Unit 1 EDG service water

flow control valves, 11, 12, and 13SW39. There was evidence that the leaks had

existed over time, because the SW39 valve air operators were stained by the roof leaks.

The inspectors were confident the roof leaks were not affecting the controls of the

SW39 valves. However, the inspectors believed the roof leaks should have been

corrected to assure continued reliable operations of the EDGs.

Analysis. The deficiency associated with this problem is inadequate problem

identification. Four days after a blizzard made apparent EDG roof leaks and caused an

inadvertent CO2 actuation, another EDG was impacted. The inspectors could also

identify that roof leaks had often wetted some EDG service water cooling valves by the

presence of stains. Prior to this finding, these problems were not identified in the

corrective action program for resolution. This finding affected the equipment

performance attribute of the availability/reliability objective of the mitigating system

cornerstone. The finding was more than minor, because corrective action was

necessary to dry the 1C EDG electrical terminal panel prior to its operation. This activity

also extended its unavailability. The finding screened to green in Phase 1 of the SDP.

The performance deficiency existed with the 1C EDG because PSEG did not remain

alert to further water intrusion after the 2A EDG CO2 actuation revealed maintenance

problems with the EDG roofs. The finding screened to green in Phase 1 of the SDP,

because the condition existed for less than the TS allowed outage time.

Enforcement. 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, requires that

conditions adverse to quality, such as defective equipment, are promptly identified and

corrected. Contrary to the above, PSEG failed to identify roof leaks prior to impacting

an electrical terminal panel on the 1C EDG. Roof leaks had affected the 2A EDG room

by inadvertently actuating CO2 four days prior. The violations were identified on

February 20, and March 1, 2003. Because the failure to promptly identify and correct an

adverse condition in the EDG rooms was determined to be of very low significance and

has been entered into the corrective action program (notification 20132895), this

violation is being treated as a non-cited violation consistent with Section VI.A of the NRC

Enforcement Policy: NCV 50-272/03-03-01, Failure to Identify EDG Room Roof Leaks.

Enclosure

3

1R02 Evaluation of Changes, Tests, or Experiments

a. Inspection Scope

The inspectors reviewed samples of safety evaluations for the initiating events, barrier

integrity and mitigating systems cornerstones to verify that changes and tests were

reviewed and documented in accordance with 10 CFR 50.59 and when required, prior

NRC approval was obtained prior to implementation. The samples included safety

evaluations for design change package (DCP) changes. The inspectors assessed the

adequacy of the safety evaluations through interviews with the cognizant plant staff and

review of supporting information, such as calculations, engineering analyses, design

change documentation, the Updated Final Safety Analysis Report (UFSAR), technical

specifications (TSs) and plant drawings. In addition, the inspectors reviewed the

administrative procedures that control the screening, preparation, and issuance of the

safety evaluations to ensure that the procedures adequately implemented the

requirements of 10 CFR 50.59, Changes, Tests, and Experiments.

The inspectors also reviewed a sample of changes that PSEG had evaluated (using a

screening process) and determined to be outside of the scope of 10 CFR 50.59,

therefore not requiring a full safety evaluation. The inspectors performed this review to

assess if PSEG conclusions with respect to 10 CFR 50.59 applicability were

appropriate. The sample of issues that were screened out included design changes and

set point changes.

The inspectors also reviewed issues that had been entered into the corrective action

program to determine if PSEG had been effective in identifying problems associated

with the 10 CFR 50.59 safety evaluation process. A sample of these issues was

selected for further review during which the inspectors assessed the adequacy of the

corrective actions which had been implemented for the selected issues.

The safety evaluations and screens were selected based on the safety significance of

the affected structures, systems and components (SSC). A listing of the safety

evaluations, safety evaluation screens and other documents reviewed is provided in the

attachment.

b. Findings

No findings of significance were identified.

1R04 Equipment Alignment

.1 Unreviewed AFW Pump Skid Modification

a. Inspection Scope

Enclosure

4

The inspectors performed a partial system walkdown on March 12 and 13, 2003, during

planned maintenance activities for the 22 AFW (AFW) pump train. The inspectors

walked down redundant portions of the AFW system and observed that the ongoing

maintenance activities did not extend beyond the 22 AFW pump train. The inspectors

referenced Salem operating procedure AFW System Operation, S2.OP-SO.AF-

0001(Q).

b. Findings

Introduction. The inspectors identified that a temporary modification to the 22 AFW

pump was not properly evaluated. The temporary modification included tygon hoses

attached to all four drain ports on the inboard and outboard pump gland leakoff basins.

This finding was determined to be of very low risk significance (Green), because an

actual loss of safety function for the 22 AFW pump did not occur.

Description. On February 12, 2003, the inspectors identified tygon hoses attached to all

four drain ports on the inboard and outboard pump gland leakoff basins of the 22 AFW

pump. The inspectors concern was a potential to clog the tygon hoses; the tygon hoses

were added only for housekeeping appearances. Clogged tygon hoses would

subsequently flood the gland leakoff basin and allow water to penetrate the pump

bearing oil seals. The tygon hoses appeared to have been in place for at least several

months. The inspectors discussed the tygon hose modification with the main control

room supervisors. On February 12, 2003, equipment operators removed the

unauthorized modification to the 22 AFW pump.

The inspectors noticed packing leakoff at both ends of the pump shaft. The inspectors

estimated the packing leakoff at about one gallon per minute at each end. Packing

leakoffs of that magnitude would have flooded the gland leakoff basin within minutes

after a tygon hose clogged. The inspectors believed that the tygon hoses attached to

route the leakoff directly to a floor drain opening presented a greater potential for

clogging compared to the ports alone. The unmodified gland leakoff basin ports would

allow water to spill to the equipment base and presented a small opportunity for

clogging.

On February 13 during subsequent inspector walkdowns on the Salem Units 1 and 2

AFW systems, the inspectors identified a similar configuration issue with the 13 AFW

pump. The 13 AFW pump gland leakoff basins were not identical, but of similar design.

The 13 AFW pump gland basins included a threaded bushing at the bottom and another

higher elevation overflow port, but below any penetration area to the bearing oil seal.

The 13 AFW pump gland basin had been modified with pipe plugs reducing the drain

capacity to only one port. The inspectors noticed that the oil seals were not submerged.

Analysis. The deficiency associated with this problem is design control, but it also has

an element of problem resolution. PSEG was not thorough in reviewing extent of

condition for the specific issue. The inspectors further identified that the 13 AFW pump

skid was unnecessarily and inappropriately modified. This finding affected the

equipment performance attribute of the reliability objective of the mitigating system

Enclosure

5

cornerstone and the 22 and 13 AFW pumps. This finding is more than minor, because

the tygon hoses and pipe plugs reduced the drain capabilities of the gland leakoff

basins. A flooded leakoff basin would have contaminated the pump bearing oil. The

finding screened to green in Phase 1 of the SDP, because the condition did not cause

an actual loss of safety function for any AFW pumps.

Enforcement. 10 CFR 50, Appendix B, Criterion III, Design Control, requires that

measures shall be established for the selection and review of materials and processes

that are essential to the safety-related functions of structures, systems, and

components. Contrary to the above, PSEG failed to review the addition of drain hoses

and pipe plugs to the 22 AFW and 13 AFW pumps gland leakoff basins. The violations

were identified on February 12, 2003, and existed for an unknown period of time, but

probably greater than several months. Because the failure to assess the impact on

AFW pump performance was determined to be of very low significance and has been

entered into the corrective action program (notification 20135512), this violation is being

treated as a non-cited violation consistent with Section VI.A of the NRC Enforcement

Policy: NCV 50-272 and 311/03-03-02, Failure to Properly Evaluate AFW Pump Skid

Modifications.

.2 Other Partial System Walkdowns

a. Inspection Scope

The inspectors performed partial system walkdowns on the 12 charging pump on

March 3, 2003, and the 1A and 1C emergency diesel generators on March 13. Both

partial system walkdowns were performed while planned maintenance occurred on the

redundant train. The inspectors verified by walkdowns in the Unit 1 auxiliary building

that the redundant trains were operating or aligned in accordance with Salem operating

procedures S1.OP-SO-CVC-0002(Q), Charging Pump Operation and S1.OP-SO.DG-

0001 and 0003(Q), 1A and 1C Diesel Generator Operation.

b. Findings

No findings of significance were identified.

1R05 Fire Protection

a. Inspection Scope

On March 28, 2003, the inspectors walked down all portions of the Salem service water

intake structure. The inspectors assessed each area for control of transient

combustibles and ignition sources, fire detection and suppression capabilities, and fire

barriers. The inspectors referenced Salem fire protection procedure, NC.NA-AP-0025,

Operational Fire Protection Program, and engineering document, DE.PS.ZZ-0001-A2-

FHA, Salem Fire Protection Report - Fire Hazards Analysis, to ascertain PSEGs

established fire protection requirements.

Enclosure

6

b. Findings

No findings of significance were identified.

1R06 Flood Protection Measures

a. Inspection Scope

The inspectors reviewed PSEGs corrective actions to identify and review preventive

maintenance practices for safety-related cable vaults susceptible ground water intrusion.

The inspectors observed the as-found condition for a vault containing safety-related

cables to the Salem Units 1 and 2 service water intake structure. The vault was

observed on March 11, 2003, and after significant rain fall. The corrective action

notifications included 20127365 and 20105022 and were described in NRC Inspection

Report 50-272/02-09, 50-311/02-09, Section 1R06 (URI 50-272 & 50-311/02-09-01).

b. Findings

No findings of significance were identified.

The inspectors observed the only remaining safety-related vault susceptible to ground

water intrusion and noted the vault to be dry. There was no evidence of previous

flooding. The vaults contained a passive drain system and observed it to be clear of

debris. URI 50-272 & 50-311/02-09-01 is closed.

1R11 Licensed Operator Requalification

.1 Biennial Review

a. Inspection Scope

The inspectors reviewed PSEG requalification exam results for the biennial testing

cycle. The inspection assessed whether pass rates were consistent with the guidance

of NUREG-1021, Revision 8, Operator Licensing Examination Standards for Power

Reactors and NRC Manual Chapter 0609, Appendix I, Operator Requalification Human

Performance SDP."

The inspectors verified that:

C Crew pass rate was greater than 80%. (Pass rate was 100%)

C Individual pass rate on the dynamic simulator test was greater than or equal to

80%. (Pass rate was 100%)

C Individual pass rate on the comprehensive written exam was greater than 80%.

(Pass rate was 100%)

C Individual pass rate on the walk-through (JPMs) was greater than 80%. (Pass

rate was 100%)

Enclosure

7

C More than 75% of the individuals passed all portions of the exam. (100% of the

individuals passed all portions of the exam)

b. Findings

No findings of significance were identified.

.2 Quarterly Simulator Observation

a. Inspection Scope

On March 12, 2003, the inspectors observed a licensed operator simulator training

scenario to assess the operators performance and also the evaluators and participants

critiques. The scenario was considered an as-found evaluation of the operators

performance. It was conducted first in the training schedule after several weeks of off-

training activities. The scenario involved a nuclear instrument failure, a main condenser

tube failure, a spurious pressurizer spray valve failure, and an anomaly with AFW after

the operators initiated a manual reactor trip. The inspectors verified that the operators'

actions were consistent with the appropriate operating, alarm response, abnormal and

emergency procedures.

b. Findings

No findings of significance were identified.

1R12 Maintenance Rule (MR) Implementation

a. Inspection Scope

The inspectors reviewed recent operating problems, notifications, system health reports,

and MR performance criteria to determine whether PSEG had effectively monitored the

performance of the Unit 1 and Unit 2 service water systems. The inspectors reviewed

PSEGs MR disposition for a service water pump failure on April 28, 2002. The

inspectors also reviewed PSEGs intended corrective actions (notification 20098392) for

the pump failure.

b. Findings

No findings of significance were identified.

1R13 Maintenance Risk Assessments and Emergent Work Evaluation

a. Inspection Scope

The inspectors reviewed PSEGs planning and risk assessments for the following risk

significant activities:

Enclosure

8

C Emergent 11 residual heat removal (RHR) heat exchanger inoperability resulting

from boric acid corrosion and degraded studs on January 8 (Also, see Section

1R15 Operability Evaluations for a more detailed description as it relates to the

technical issues.)

C Total station air compressor (SAC) outage during the week of February 19

C 13 AFW pump maintenance during the week of February 27

C 11 Charging pump maintenance on March 3

C 22 AFW pump maintenance on March 13

C 2C EDG planned maintenance on March 19

The inspectors reviewed the risk assessment of these planned maintenance activities

with respect to 10 CFR 50.65(a)(4). The inspectors also walked down the protected

equipment and maintenance locations to verify that risk was managed in accordance

with PSEGs risk evaluation forms.

b. Findings

No findings of significance were identified

1R14 Personnel Performance During Non-routine Plant Evolutions

.1 Loss of the 2B Vital Bus

a. Inspection Scope

The inspectors reviewed PSEGs response to an unexpected loss of the 2B vital bus on

January 15, 2003. The event occurred as the result of vibration caused by the

discharging of 2B EDG output breaker springs during removal from the 2B bus. The

inspectors observed plant process parameters and the operators response to this event

from the control room and reviewed operations procedure, S2.OP-AB.4KV-0002(Q),

Loss of 2B 4KV Vital Bus to assess whether the response was appropriate and in

accordance with TS and procedural requirements. Additionally, the inspectors reviewed

the transient assessment response plan (TARP) report and the planned and completed

corrective actions to determine whether the operator actions were adequate.

b. Findings

No findings of significance were identified.

.2 Power Reduction Due to a Circulating Water (CW) System Problem

a. Inspection Scope

The inspectors reviewed PSEGs response to an unexpected loss of the 13A CW

traveling screen while the 13B CW traveling screen was removed from service for

planned maintenance. The loss of the 13A CW traveling screen was caused by the

failure of the shear pin after about one week of operation. The inspectors reviewed

Enclosure

9

plant parameters, interviewed operators and reviewed the TARP report to determine

whether PSEG responded appropriately to this event.

b. Findings

No findings of significance were identified.

.3 Salem Units 1 and 2 Control Air Transient

a. Inspection Scope

On February 25, 2003, during evolutions to support a total SAC outage, both Salem

units experienced lowering control air header pressures. Both units emergency air

compressors auto-started as designed to support the control air systems. Salem Unit 1

was further impacted as a result of the control air transient and a chemical volume

control system relief valve lifted. The inspectors interviewed control room operators

involved with the control air transient, reviewed emergency classification guidelines, and

assessed PSEGs investigation in the matter.

b. Findings

Introduction. Configuration control errors on the station air system and previously

identified station air system leaks challenged the backup control air system response.

Further equipment anomalies from inadequate preventive maintenance ultimately

caused an unexpected reactor coolant system release to the pressurizer relief tank

(PRT). This finding was determined to be of very low risk significance (Green), because

the reactor coolant system leakage to the PRT was in compliance with TS actions.

Description. Both Salem units are supported by a single station air system. The station

air system with three air compressors is further divided into service air and control air

portions. The control air system supports safety and non-safety related pneumatically

operated instruments and valves. Control air in the auxiliary building is further

supported by standby emergency control air compressors (ECACs). The standby

ECACs will start on a loss of all three air compressors or a low control air header

pressure. The control air system is not needed to prevent or mitigate the consequences

of a postulated accident. The service air system supports miscellaneous plant services

such as air drops for pneumatic tools.

PSEG intended to secure all three station air compressors (SACs) to facilitate repairs to

a common control switch and to replace several SAC service water cooling isolation

valves. Five temporary air compressors installed through maintenance header

connections were used to maintain the service air and control air headers. The ECACs

automatic start on loss of all SACs was disabled to maintain the ECACs in a standby

condition.

On February 25 control room operators intended to secure the temporary air

compressor operation and support the station air system with the No. 2 SAC. The

Enclosure

10

temporary air compressors proved to be unreliable during trial operation and the original

maintenance plans were being abandoned. The No. 2 SAC had not been operated for

several weeks but was believed ready for operation.

The No. 2 SAC operated for 26 minutes and then tripped on high oil temperature. Both

Unit 1 and Unit 2 ECACs started on low control air header pressures. After the trip of

No. 2 SAC, a Unit 1 PRT high pressure alarm was received in the main control room.

Operators discovered that a chemical volume and control system letdown isolation valve

(1CV7) had closed. The 1CV7 air operated valve isolated the normal reactor coolant

system letdown flow path and subjected a 600 psig relief valve (1CV6) to full reactor

coolant system pressure, 2235 psig. 1CV6 relieved to the PRT at about 75 gpm for

about eight minutes causing the PRT high pressure alarm. Operators reseated 1CV6 by

closing the upstream letdown line isolation valves.

PSEG initiated a TARP on February 25 to investigate the control air transient and review

the operator and plant responses. The TARP team and other investigations discovered:

1) Existing significant air leaks on the station air system challenged the ability of

the ECACs to recover air header pressures on a loss of all station air

compressors. For instance, a single leak on a station air line to the service water

intake structure accounted for 20% consumption and was discovered on August

28, 2001. The air line repair was canceled with no further evaluation.

2) The No. 2 SAC tripped because a lube oil temperature control valve was

manually jacked closed. The configuration control error likely occurred on

January 5, 2003, when the No. 2 SAC was returned to service after maintenance

activities.

3) The air operated valve, 1CV7, isolating letdown in an abnormal configuration

occurred because a redundant air panel failed to swap air supply to the less

affected control air header. PSEG discovered that preventive maintenance for

the redundant air panel had been incomplete for several years. An oversight in

scoping the preventive maintenance for redundant air supply panels neglected

the portion of the redundant air panel that could have maintained sufficient air

supply to 1CV7.

4) The control room operators and equipment operators adequately responded

to the control air transient. PSEG further concluded that the control room

operators identified in a reasonable amount of time the lifting letdown relief valve

and increasing PRT level. The control operators were prompt to reseat 1CV6

once it had been identified to be open.

The inspectors concluded that PSEG thoroughly investigated the loss of station air

header pressure.

Analysis. The performance deficiencies associated with this event included an

inadequate resolution of a significant station air system leak, incomplete preventive

Enclosure

11

maintenance on a control air system component, and human performance for a valve

configuration error. This finding was greater than minor, because it had an actual impact

on plant stability and operator actions were necessary to reseat a letdown line relief

valve. This finding screened to Green in phase 1 of the SDP, because mitigation

equipment was not affected by the control air transient.

Enforcement. This finding was not a violation of NRC requirements. Although the

reactor coolant system barrier was affected, the performance deficiencies occurred on

non-safety related systems. PSEG entered this issue into its corrective action program

as notification 20133239.

.4 Salem Unit 2 Manual Reactor Trip Due to CW System Grassing Problems

a. Inspection Scope

On March 29, 2003, at approximately 0400, Salem Unit 2, at 100% power received

multiple CW system traveling screen high d/p alarms. Equipment operators at the CW

intake structure reported severe grassing conditions. PSEG had established dedicated

equipment operators at the CW intake structure to monitor the marsh grass impact

during the prior several weeks. (The marsh grass seasonally impacts the Salem units

river water systems as dead reeds and detritus enter the Delaware River during the

spring thaws and seasonably high tides.) During the grassing event, the control room

operators initiated a downpower and secured three of six CW pumps due to high

condenser d/p. After securing the third CW pump, control room operators manually

tripped Unit 2 from about 80% power. The inspectors responded to the main control

room, interviewed control room operators, walked down all control board indications for

abnormalities, walked down the safety-related service water system intake structure,

and observed the grassing at the CW intake structure. The inspectors also interviewed

management for additional insights on operator and equipment performance. PSEGs

program for detritus level monitoring quantified the grass levels during the event as

some of the highest in over a decade of monitoring. A significant amount of trash was

also present and impacted the CW system performance.

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations

.1 Degraded RHR Heat Exchanger Studs

a. Inspection Scope

The inspectors reviewed PSEGs response to a degraded condition identified on

January 8, 2003, that involved boric acid corrosion of the 11 RHR heat exchanger lower

flange studs. This resulted in a loss of material such that the diameter for several studs

was found to be reduced by more than the allowed 5%. PSEGs initial corrective

Enclosure

12

actions were to declare the 11 RHR heat exchanger inoperable, enter TS 3.5.2, which

required a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> limiting condition for operation shutdown action. PSEG replaced

about thirty studs and exited the TSs action statement. The inspectors reviewed the

actions to manage the plant risk, observed selected stud replacement activities,

interviewed personnel, and attended maintenance planning meetings to ensure that

PSEG implemented appropriate actions to mitigate the plant risk and to restore the 11

RHR heat exchanger to an acceptable condition.

The inspectors reviewed operability determination (OD)03-001 which concluded that the

11 RHR heat exchanger would be operable (but degraded) provided that at least 14

studs were replaced with new studs and also that the remaining studs (i.e., those left in

place) did not exceed a 15% reduction in original diameter. The inspectors observed

field measurements for several of the studs removed from the heat exchanger and did

not observe any with a diameter reduction of greater than 12%. The inspectors also

interviewed plant engineers to assess the adequacy of previous corrective actions for

the degraded stud condition.

b. Findings

No findings of significance were identified.

.2 Other Operability Evaluations

a. Inspection Scope

The inspectors reviewed operability screenings or evaluations for the following degraded

equipment issues:

C MSSV (21MS15) weepage identified on December 5, 2002

C 1A EDG lube oil strainer degradation identified on January 8, 2003

C 21 Containment fan cooler unit (CFCU) degraded pipe plugs identified on

February 15, 2003

C 15 CFCU service water outlet valve (15SW72) failure identified on

March 22, 2003

b. Findings

No findings of significance were identified.

1R17 Permanent Plant Modifications

a. Inspection Scope

The inspectors reviewed selected permanent plant modification packages to verify that

the design bases, licensing bases, and performance capability of risk significant SSC

had not been degraded through plant modifications.

Enclosure

13

Plant changes were selected for review based on risk insights for the plant and included

SSC associated with the initiating events, barrier integrity and mitigating systems

cornerstones. The inspection included walkdowns of selected plant systems and

components, interviews with plant staff, and the review of applicable documents

including procedures, calculations, modification packages, engineering evaluations,

drawings, corrective action documents, the UFSAR and TSs.

The inspectors verified that selected attributes were consistent with the design and

licensing bases. These attributes included component safety classification, energy

requirements supplied by supporting systems, seismic qualification, instrument set-

points, uncertainty calculations, electrical coordination, electrical loads analysis, and

equipment environmental qualification. Design assumptions were reviewed to verify that

they were technically appropriate and consistent with the UFSAR. For each modification

the 50.59 screens or evaluations were reviewed as described in section 1R02 of this

report. The inspectors verified that procedures, calculations and the UFSAR were

properly updated with revised design information and operating guidance. The

inspectors also verified that the as-built configuration was accurately reflected in the

design documentation and that post-modification testing was adequate to ensure the

SSC would function properly.

The inspectors also reviewed issues that had been entered into the corrective action

program to determine if PSEG had been effective in identifying problems associated

with the plant modification process and activities. A sample of these issues was

selected for further review during which the inspectors assessed the adequacy of the

corrective actions which had been implemented for the selected issues. A listing of

documents reviewed is provided in the attachment.

b. Findings

No findings of significance were identified.

1R19 Post-Maintenance Testing (PMT)

.1 1B EDG Trip During PMT

a. Inspection Scope

The inspectors observed PSEGs response to a 1B EDG electrical trip during PMT on

March 14, 2003. The inspectors discussed the matter with technicians in the field and

observed PSEGs methodology to discover all potential causes.

b. Findings

Introduction. PSEG had ineffective interim corrective actions for a known deficiency

with the Salem EDG potential transformer drawer connectors. This finding was

determined to be of very low risk significance (Green), because the inadequate interim

Enclosure

14

corrective actions only affected the 1B EDG for a short duration and only on one

subsequent occasion, March 14, 2003.

Description. On March 14, 2003, the 1B EDG output breaker tripped approximately

three minutes after achieving full load. The 1B EDG was operating for PMT and had

been fast loaded per TS 4.8.1.1.2c. PSEG assembled a TARP team to completely

understand the EDG trip.

The TARP concluded that the potential transformer drawer secondary auxiliary coupler,

a Jones plug, was not properly connected. The potential transformer drawer and Jones

plug were disconnected as part of the ragout for personnel and equipment safety during

the maintenance activity. The Jones plug had become misaligned during the return to

service. Electrical continuity was lost during the EDG post-maintenance operation and

caused the diesel generator output breaker to trip.

EDG trips had occurred for identical reasons on January 6, 2002, and January 9, 2002,

for the 1B and 2A EDGs. PSEG had established interim corrective actions after the

January 9, 2002, EDG trip to specify electrical continuity checks on the Jones plug after

reconnecting.

The technicians for this recent EDG trip performed the continuity checks; however,

some anomalies occurred. The technicians initially did not achieve acceptable electrical

continuity as verified through resistance checks. Several attempts were made and the

drawer bolts were finally tightened to achieve continuity within the acceptable range.

The post EDG trip investigation revealed that pins had been dislodged in the Jones

connector.

The TARP team concluded that the initial interim corrective actions were inadequate.

Additional interim corrective actions were added to visually verify the Jones plug pins

mated during PT drawer reinstallation. PSEG also specified additional maintenance

instructions to formalize and strengthen the continuity verification process. PSEG

intended to complete a permanent design change and eliminate the connector problem

for all six Salem EDGs by December 2003.

Analysis. The performance deficiency associated with this problem was inadequate

problem identification and resolution. Technicians should have questioned their

additional actions to achieve acceptable continuity reading. In January 2002 PSEG

should have also more completely defined the interim corrective actions necessary to

ensure a proper connection in the degraded Jones plugs. This finding affected the

equipment performance attribute of the reliability objective of the mitigating system

cornerstone. This finding is more than minor, because the Salem emergency diesel

generators were being returned to service without adequate interim corrective actions

and verification for a known electrical connector deficiency. The 1B EDG trip on March

14, 2003, was fortuitous in that the conditions were sufficient to reveal the inadequate

Jones plug connection during the PMT and not during an actual actuation. The finding

screened to green in Phase 1 of the SDP, because the condition did not cause any EDG

to be inoperable for greater than its TS allowed outage time.

Enclosure

15

Enforcement. 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, requires that

in the case of significant conditions adverse to quality, measures shall be established

that preclude repetition. Contrary to the above, PSEG failed to establish adequate

corrective actions to ensure that the Salem EDG PT drawer connectors were reliably

connected and verified after maintenance activities. This was a deficient condition that

was identified by PSEG on January 9, 2002. Later PSEG established additional

corrective action measures on January 14, 2003 after the 1B EDG tripped for the same

root cause identified in January 2002. Because the failure to establish adequate

measures for deficient EDG PT drawer connectors was determined to be of very low

significance and has been entered into the corrective action program (notification

20135488), this violation is being treated as a non-cited violation consistent with Section

VI.A of the NRC Enforcement Policy: NCV 50-272 and 311/03-03-03, EDG Deficient

Corrective Actions.

.2 22 AFW Pump Packing Performance

a. Inspection Scope

The inspectors observed portions of and reviewed documentation for PMT associated

with work activities on the 22 AFW pump train during a planned maintenance outage.

The work activities occurred on March 12, 2003, and included redundant air panels 700-

2G, 2M, and 2Y preventive maintenance. These redundant air panels affected the

operation of AFW flow control valves 21AF21 and 22AF21. The inspectors assessed

whether the testing appropriately demonstrated that the 22 AFW pump train was

returned to an operationally ready condition. The inspectors were present for an

inservice test surveillance on the 22 AFW pump at the conclusion of the maintenance.

b. Findings

The inspectors observed the startup of the 22 AFW pump in the field on March 13.

Shortly after startup equipment operators noticed the inboard pump shaft packing gland

emitting steam. While a small stream of water is desirable to maintain the packing and

pump shaft cool and stable, steam emission is undesirable and could have lead to

packing failure and, in the worst case, pump failure.

The operators promptly loosened the packing gland follower and were successful in

establishing stable packing gland performance. The 22 AFW pump has had a history of

significant packing leakoff. Equipment operators and maintenance technicians were

prepared during the pre-job brief and maintenance planning to adjust the 22 AFW pump

packing as necessary and on startup.

No recent maintenance activities occurred that should have overtightened the inboard

packing gland follower causing steam emission. A senior reactor operator present and

overseeing the packing adjustment initiated a corrective action notification (20135513)

to review past operability of the 22 AFW pump. This issue will remain unresolved

pending PSEGs investigation and review for past operability. (URI 50-311/03-03-04)

Enclosure

16

.3 13 AFW Pump Maintenance

a. Inspection Scope

The inspectors reviewed post-maintenance test documentation for maintenance

activities associated with the 12AF11 and 14AF11 air operated flow control valves.

These valves support AFW from the Unit 1 turbine-driven AFW pump to the 12 and 14

steam generators. The inspectors verified that the PMT procedures, activities, and

results were adequate to verify operability and functional capability as described in NRC

Inspection Procedure 81111.19, PMT, prior to the affected systems being returned to

service. The inspectors also walked down the maintenance locations and verified that

maintenance was properly authorized by senior reactor operators and conducted in

accordance with procedures.

b. Findings

No findings of significance were identified.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors observed portions and reviewed results of the following surveillance

tests:

C Unit 2 channel 4 pressurizer pressure calibration on January 28, 2003

C Unit 1 engineered safety features solid state protective system slave relays test

for train A on March 5

C 12 component cooling water pump inservice testing on March 13

C 22 EDG fuel oil transfer pump monthly surveillance testing on March 14

C 2B safety-related 4kV bus under voltage relay testing on March 14

C 22 Safety injection pump inservice testing on March 19

The inspectors verified that test results were within procedure requirements, TS

requirements, and in-service testing program requirements as applicable.

b. Findings

No findings of significance were identified.

1R23 Temporary Plant Modifications

a. Inspection Scope

The inspectors reviewed Temporary Modification No.03-001, Salem Unit 1 No.14

Steam Generator Level Transmitter Level Column Vent Valve Seat Leakage. The

temporary modification involved the installation of an additional isolation valve on the

Enclosure

17

vent line downstream of the leaking vent valve. The inspector assessed: (1) the

adequacy of the 10 CFR 50.59 evaluation; (2) the seismic qualification evaluation that

assessed the weight of the additional valve on the instrument tubing; and (3) the

adequacy of the post-installation testing.

b. Findings

No findings of significance were identified.

2. RADIATION SAFETY

Cornerstone: Occupational Radiation Safety

2OS1 Access Control to Radiologically Significant Areas

a. Inspection Scope

During the period February 24-28, 2003, the inspector reviewed exposure significant

work areas (i.e., High Radiation Areas, and Airborne Radioactivity Areas) in the plant

and associated controls and surveys of these areas to determine if the controls (e.g.,

surveys, postings, barricades) were acceptable. For these areas, the inspector

reviewed radiological job requirements and attended job briefings to determine if

radiological conditions in the work area were adequately communicated to workers

through briefings and postings.

The inspector also verified radiological controls, radiological job coverage, and

contamination controls to ensure the accuracy of surveys and applicable posting and

barricade requirements. The inspector obtained this information via interviews with

PSEG personnel, walkdown of systems, structures, and components, and examination

of records, procedures, or other pertinent documents.

The inspector determined if prescribed radiation work permits (RWPs), procedures and

engineering controls were in place, whether PSEG surveys and postings were complete

and accurate, and if air samplers were properly located. The inspector reviewed RWPs

used to access exposure significant work areas to identify the acceptability of work

control instructions or control barriers specified.

The inspector reviewed electronic pocket dosimeter alarm set points (both integrated

dose and dose rate) for conformity with survey indications and plant policy. RWP #105,

Task #0810002, which allowed access to High Radiation Areas in the low level radwaste

storage facility and five posted high or locked high radiation areas located in the spent

fuel and auxiliary buildings, were reviewed as part of this inspection. The controls

implemented by PSEG were compared to those required under plant TS 6.12 and 10

CFR 20, Subpart G, for control of access to high and locked high radiation areas.

b. Findings

Enclosure

18

No findings of significance were identified.

2OS2 ALARA Planning and Controls

a. Inspection Scope

The inspector reviewed ALARA job evaluations, exposure estimates, and exposure

mitigation requirements and compared ALARA plans with the results achieved. A

review was conducted of: the integration of ALARA requirements into work procedures

and RWP documents; the accuracy of person-hour estimates and person-hour tracking;

and generated shielding requests and their effectiveness in dose rate reduction. The

inspector obtained this information via interviews with PSEG personnel, walkdown of

systems, structures, and components, and examination of records, procedures, or other

pertinent documents.

A review of actual exposure results versus initial exposure estimates for work performed

during 2002 was conducted including: comparison of estimated and actual dose rates

and person-hours expended; determination of the accuracy of estimations to actual

results; and determination of the level of exposure tracking detail, exposure report

timeliness and exposure report distribution to support control of collective exposures to

determine conformance with the requirements contained in 10 CFR 20.1101(b). The

actual 2002 exposure was 154.49 person-rem for Unit 1 and 131.428 person-rem for

Unit 2. The inspector also reviewed the exposure goal established for 2003 (9.75

person-rem for Unit 1 and 115.25 person-rem for Unit 2), which included an exposure

goal of 110 person-rem for the Unit 2 spring refueling outage (2RF13).

b. Findings

No findings of significance were identified.

2OS3 Radiation Monitoring Instrumentation

a. Inspection Scope

The inspector reviewed field radiological controls instrumentation utilized by radiation

protection (RP) technicians and plant workers to measure radioactivity, including

portable field survey instruments, friskers and portal monitors. The inspector reviewed

five selected RP instruments observed in the radiologically controlled area (RCA). Items

reviewed was verification of proper function and certification of appropriate source

checks and calibration for these instruments used to ensure that occupational

exposures are maintained in accordance with 10 CFR 20.1201.

The evaluation of PSEG performance was based on interviews with PSEG personnel,

walkdown of systems, structures, and components, and examination of records,

procedures, or other pertinent documents.

Enclosure

19

b. Findings

No findings of significance were identified.

Cornerstone: Public Radiation Safety

2PS3 Radiological Environmental Monitoring Program (REMP)

.1 REMP

a. Inspection

The inspector reviewed the following documents to evaluate the effectiveness of

PSEGs REMP at the PSEG Maplewood Testing Services Laboratory, Maplewood, NJ,

and at the Salem/Hope Creek site. The requirements of the REMP are specified in the

Technical Specifications/Offsite Dose Calculation Manual (TS/ODCM).

Maplewood Testing Services Laboratory

C 2001 Annual REMP Report and the 2002 Draft Report;

C Analytical results for 2003 REMP samples;

C Most recent calibration results for all TS/ODCM air samplers;

C Calibration results for gamma, alpha/beta, and tritium measurement instruments;

C Review of Maplewood Testing Services Laboratory Quality Assurance (QA)

Manual;

C Implementation of the quality control program;

C Review of the 2002 gamma, alpha/beta, and tritium quality control charts;

C Implementation of the interlaboratory and intralaboratory comparisons;

C Implementation of the environmental thermoluminescent dosimeters (TLDs)

program;

C Land Use Census procedure and the 2001/2002 results;

C Associated sampling and analytical REMP procedures.

Salem/Hope Creek Site

C Salem ODCM (Revision 15, July 11, 2002), Hope Creek ODCM (Revision 20,

April 5, 2002), and technical justifications for ODCM changes, including sampling

media and locations;

C Most recent calibration results of the newly installed Primary Tower (work order 60023443) and Back-up Tower (work order 6002344) meteorological monitoring

instruments for wind direction, wind speed, and temperature;

C Review of the 2002 meteorological monitoring data recovery statistics;

C Meteorological monitoring program self-assessment report;

C QA Assessment Reports (Report Nos. 2002-0218, REMP/ODCM Procedures,

Training, Performance Indicators, and Event Followup) for the REMP/ODCM

implementations.

Enclosure

20

The inspector toured and observed the following activities to evaluate the effectiveness

of PSEGs REMP:

C Observation for the operability of meteorological monitoring instruments at the

tower and the control room;

C Observation of PSEGs analytical laboratory activities, PSEG Maplewood Testing

Services Laboratory;

C Observation for air iodine/particulate sampling techniques;

C Walkdown for determining whether air samplers and TLDs were located as

described in the ODCM (including control and indicator stations) and for

determining the equipment material condition.

The inspector also reviewed the potential onsite and offsite radiological dose

consequences associated with PSEG's discovery of a leak in the Unit 1 spent fuel pool

and the subsequent identification of tritium contamination in four onsite test well

locations (K, L M, N) located adjacent to the onsite Salem facility. The specific

discussion associated with this matter are contained in Section 4OA3 of this report and

NRC Inspection Report 50-272; 50-311/2002-009 Section 4OA2.3.

b. Findings

No findings of significance were identified.

.2 Radioactive Material Control Program

a. Inspection Scope

The inspector reviewed the following documents and made observations to ensure that

PSEG met the requirements specified in its program for the unrestricted release of

material from the RCA:

C Most recent calibration results for the radiation monitoring instrumentation (small

articles monitor, SAM-9), including the (a) alarm setting, (b) response to the

alarm, and (c) the sensitivity;

C PSEGs criteria for the survey and release of potentially contaminated material

using a gamma spectroscopy (calibrations efficiency for bulk sample analyses);

C Methods used for control, survey, and release from the RCA;

C Use of SAM-9 at RCA access points;

C Associated procedures and records to verify for the lower limits of detection for

bulk sample analyses.

The review was against criteria contained in 10CFR20, NRC Circular 81-07, NRC

Information Notice 85-92, NUREG/CR-5569, Health Position Data Base (Positions 221

and 250), and PSEG's procedures.

b. Findings

Enclosure

21

No findings of significance were identified.

4. OTHER ACTIVITIES

4OA2 Problem Identification and Resolution

.1 CW System Frequent Failures

a. Inspection Scope

The inspectors also reviewed the identified root cause(s) and planned corrective actions

for the loss of the 13A CW traveling screen event discussed in Section 14.2. The root

causes for this event included improper alignment of the shear pin hub caused by

inadequate maintenance procedural guidance. The inspectors also reviewed corrective

action program documents to determine whether other previous shear pin failures had

occurred due to improper alignment during maintenance.

b. Findings

No findings of significance were identified; however, the inspectors identified that the

corrective actions for previous similar events that involved the breaking of the shear pins

had not been effective. This was not considered a violation of NRC requirements since

the CW system was not a safety-related mitigating system.

.2 REMP Corrective Action Review

a. Inspection Scope

The inspector reviewed the selected following documents to evaluate the effectiveness

of PSEGs problem identification and resolution processes in the areas of REMP:

C Condition Reports (CRs) for the REMP:

1003-4916; 1006-6506; 1006-9421; 1006-9422; 1007-2124; 1007-5340; 1007-

6168; 1007-5391; 1007-6519; 1007-6891; 1007-9940 and 1009-9983

C CRs for the Meteorological Monitoring Programs:

2009-5181; 2010-0037; 2010-3814; 2010-8528; 2012-3864; 2011-4695; 2012-

5321; 2012-6346; 2012-7542; 2012-8819; 2013-0388; 2013-0744; 2013-0854;

and 2013-0854;

C Special Report: Hope Creek-Plant Event #39561- Loss of Meteorological Data at

Salem and Hope Creek Stations, February 4, 2003,

C Action Plan for Improving Meteorological Monitoring System Reliability;

C Self-Assessment Report Number 80043789 Activity 040, Meteorological System,

June 21, 2002.

b. Findings

No findings of significance were identified.

Enclosure

22

.3 10 CFR 50.59 and Plant Modification Corrective Action Review

a. Inspection Scope

The inspectors reviewed corrective action documents associated with 10 CFR 50.59

issues and plant modification issues to ensure that PSEG was identifying, evaluating,

and correcting problems associated with these areas and that the corrective actions for

the issues were appropriate. The inspectors also reviewed several QA audit and self-

assessments related to 10 CFR 50.59 and plant modification activities at the Salem

Generating Station.

b. Findings

No findings of significance were identified.

.4 Occupational Radiation Safety Corrective Action Review

a. Inspection Scope

The inspector reviewed QA audits and surveillance, and RP department self-

assessments performed during the period from July 2002 - February 2003, related to

occupational radiation safety, and determined if identified problems were entered into

the corrective action system for resolution. Attachment 1 contains a listing of the

documents reviewed. The inspector also reviewed the tracking, evaluation and

resolution of these identified issues.

b. Findings

No findings of significance were identified.

.5 Security Program Implementation

a. Inspection Scope

The inspectors reviewed the findings of an independent team that had been contracted

by PSEG to review security program implementation. The audit team concluded that

there were potential violations of security plan and regulatory requirements regarding

response team staffing and compensatory measures. PSEG did not consider the

findings to be violations of the security plan or regulatory requirements; however, they

did forward the audit team findings to the NRC for review.

The inspectors review disclosed that the response team manning issue involved the use

of some response team members on compensatory posts. The inspectors review of

this issue determined that this practice did not degrade the total overall defensive

strategy and was not a violation of the security plan or regulatory requirements.

Additional information on this issue would contain Safeguards Information and is,

therefore, not documented here.

Enclosure

23

The inspectors review of the potential violation regarding compensatory measures

disclosed that the compensatory measures initially implemented for some degraded

assessment aids met security plan and regulatory requirements. However, upon further

PSEG management review, it was determined that the compensatory measures could

be strengthened by the addition of an officer posted in the area. The posted officer

exceeded the compensatory requirements identified in the security plan. Additional

information on this issue would contain Safeguards Information and is, therefore, not

documented here.

b. Findings

No findings of significance were identified.

.6 Cross-References to PI&R Findings Documented Elsewhere

Section 1R01 describes a degraded condition, a roof leak, in the 2A EDG room that

caused a CO2 fire suppression system actuation. A few days afterwards PSEG had not

addressed additional EDG room roof leaks that allowed water to enter a safety related

electrical panel on the 1C EDG. The inspectors also identified that other roof leaks were

impinging safety-related EDG equipment as evidenced by water stains; yet no corrective

actions existed to address the degraded roof conditions.

Section 1R04.1 describes an unauthorized modification identified by NRC inspectors on

the 22 AFW pump. The inspectors further identified that PSEG did not perform an

adequate extent of condition review and the 13 AFW pump was similarly impacted.

Section 1R14.3 describes a control air transient that was negatively impacted by

equipment deficiencies, air leaks, in the station air control system. One air leak in

particular was a significant load on the control air system performance. The air leak had

been previously identified by PSEG, but repairs were canceled with no further action

intended. Although the control air system is outside the regulatory scope of a required

corrective action program, this finding demonstrated weaknesses in correcting

equipment deficiencies that impacted a reactor safety cornerstone.

Section 1R19.1 describes a finding for inadequate interim corrective actions associated

with EDG reliability. The event further includes a detail for lack of resolution when

expected results were not initially received.

4OA3 Event Followup

.1 Salem Unit 1 Spent Fuel Pool Water Leak

a. Inspection Scope

As described in NRC Inspection Report No. 50-272/02-09; 50-311/02-09, PSEG

identified the presence of a leak of contaminated water into the Unit 1 Auxiliary Building

associated with the Unit 1 spent fuel pool. The inspector reviewed PSEGs ongoing

Enclosure

24

investigation, the action plan to resolve this issue, and its collection of samples from

existing and supplemental test well locations to determine if the leak had potentially

impacted the onsite and offsite environment. During this inspection, the inspector

reviewed the latest sample results, ongoing sampling, and sample analyses as

discussed below. The inspector also reviewed the current status of the implementation

of PSEGs action plan to investigate, mitigate, and repair the leak. PSEGs plan

included a testing and repair plan, development and implementation of a site sampling

plan, engineering support and analysis plan, leak identification plan, cleaning of telltale

drains and remote visual inspection of telltales, robotic and submersible inspections of

the spent fuel pool, diving support as necessary, local leak rate testing, and root cause

analysis. The inspector also reviewed PSEGs extent of condition review efforts. The

potential dose consequences on the Hope Creek site were also reviewed.

On February 3-4, 2003, the inspector and New Jersey State representatives toured the

Fuel Handling and Auxiliary Buildings to examine locations where Unit 1 spent fuel pool

water was leaking or believed to be leaking into adjacent areas (e.g., Unit 1 78-foot

Mechanical Penetration Room, Unit 1 64-foot Switch Gear Room). The inspector also

toured the areas where PSEG dug supplemental test wells for purposes of detecting

and evaluating potential tritium migration and locating the source of the leak.

On February 6, 2003, PSEG identified that two onsite wells (N and O) located next to

the Unit 1 spent fuel building exhibited tritium contamination above the state reporting

level. PSEG promptly informed New Jersey and the NRC. The inspector reviewed the

sample results.

On February 11, 2003, the inspector reviewed the performance of PSEGs Maplewood

Testing Services Laboratory, Maplewood, New Jersey. This laboratory analyzes REMP

samples collected around the Salem/Hope Creek site as required by the TS and the

ODCM. This laboratory also analyzes samples collected of on-site well waters and soil

samples. The inspector reviewed: (1) analytical methodologies; (2) measurement

techniques for tritium, gamma, and gross alpha/beta; (3) implementation of the quality

control program; (4) review of the 2002 gamma, alpha/beta, and tritium quality control

charts; (5) implementation of the inter-laboratory and intra-laboratory comparisons; and

(6) calibration results for gamma, alpha/beta, and tritium measurement instruments.

On February 19, 2003, PSEG informed the NRC that two additional wells (M, K) were

found to contain tritium. One test location was next to the Unit 1 spent fuel storage

building while the other was located adjacent to the Unit 2 containment building. PSEG

had informed New Jersey. The inspector reviewed those sample results.

The inspector reviewed onsite sample results of wells to determine the presence of

tritium contamination for wells termed production wells, which provide potable water for

the Salem and Hope Creek site. The inspector also reviewed analytical results of tritium

and gamma isotopes for water samples collected at monitoring wells at 20-ft, 40-ft, 60-ft,

and 80 ft. depths, as applicable. The inspector also reviewed New Jersey analyses for

tritium. The inspector reviewed the analytical results of gamma isotopes, which

indicated that there was no evidence of plant related gamma contaminations in the

Enclosure

25

wells. The comparisons of tritium results between PSEG and New Jersey were

reviewed to evaluate level of agreement. The inspector also reviewed the analytical

sample results for wells that were located on the outer periphery of the Salem facility to

ascertain potential migration of contamination beyond the four wells (K, M, N, and O)

identified to contain tritium contamination.

As discussed above, PSEG identified, as of February 26, 2003, that four onsite test well

locations (K, M, N, and O) exhibited varying levels of detectable tritium contamination.

Three of the test wells were adjacent to the Unit 1 Fuel Handling Building. The fourth

sample location was adjacent to the Unit 2 containment area. The inspector performed

independent dose calculations, using the methodology specified in NRC Regulatory

Guide 1.109, to independently assess the potential offsite doses attributable to tritium

contained in onsite test well locations. These calculations conservatively assumed the

consumption of water with highest measured tritium concentrations and the presence of

a viable drinking water pathway.

b. Findings

No findings of significance were identified.

The inspector did not identify any immediate impact of the Unit 1 spent fuel pool leak

and associated test well tritium contamination on the health and safety of onsite

workers or members of the public. PSEG was continuing to implement its leak

identification, repair, and mitigation plan including the ongoing sampling and analysis

aspects of the plan. PSEG was cleaning out telltale drains for the Unit 1 spent fuel pool

to aid in location of apparent leaks. Liquid from telltale drains was being collected and

processed via the liquid radwaste processing system.

.2 (Closed) LER 50-272/02-004-00, Manual Reactor Trip and Automatic AFW Actuation on

Low Steam Generator Level due to Feedwater Pump Runback

On November 12, 2002, Salem Unit 1 was manually tripped due to a steam generator

feedwater pump runback resulting from an accidental control circuit short during

maintenance troubleshooting. Plant response to the manual reactor trip was normal.

This event was also described in NRC Inspection Report 50-272/02-09, 50-311/02-09,

Section 1R14 Personnel Performance During Non-Routine Plant Evolutions. This LER

was reviewed by the inspector, and no findings of significance or violations of NRC

requirements were identified. PSEG entered the reactor trip and maintenance issue into

its corrective action program as notification 20122632. This LER is closed.

.3 (Closed) LER 50-272/02-006-00, As Found Values for MSSV and Pressurizer Safety

Valve (PSV) Lift Setpoints Exceed TS Allowance

This LER described out of specification results for as found lift setpoints on a PSV and a

MSSV. The valves were removed during the 1R15 Salem Unit 1 outage in October

2002 for testing in accordance with TS 4.0.5, Surveillance Requirements for inservice

inspection and testing of ASME Code Class 1, 2 and 3 components. A PSV tested at

Enclosure

26

-3.50% and below the 3% lift setting tolerance in TS 3.4.2.2. A MSSV tested at +4.71%

and above the 3% lift setting tolerance in TS 4.7.1.1. The inspectors reviewed the LER

and interviewed valve engineers involved with the test program. PSEG concluded that

the PSV may have lifted low because it was a manufacturer original assembly valve and

internal parts may not have been lapped. PSEG also determined that the MSSV

probably lifted high due to misalignment from rough handling at the Salem site prior to

shipment. The MSSVs are tested at an offsite facility. PSEG had previously determined

that rough handling of safety valves can impact the lift setpoint. PSEGs failure to

establish controls that impacted the performance of a PSV and a MSSV is a minor

violation.

The LER described an actual benefit for the lower PSV setting in regards to

overpressure protection of the reactor coolant system boundary. An inadvertent safety

injection analysis was also considered and the lower set PSV did not affect the

calculated results since safety injection would not have caused the PSV to lift at even

the lower setpoint. The lower set PSV did not impact the barrier integrity cornerstone.

Although PSEG believed the MSSV setpoint drift occurred post-removal for testing, the

LER considered the impact of an installed higher set MSSV. The MSSV in question was

the highest set MSSV, four other MSSVs relieve at lower required TS setpoints. For all

applicable final safety analysis report events, the highest set MSSV did not open and

thus absent another failure, there was no impact on the calculated results for the limiting

transients or the barrier integrity cornerstone. This finding constitutes a violation of

minor significance that is not subject to enforcement action in accordance with Section

IV of the NRCs Enforcement Policy. PSEG documented the setpoint drift problems in

notifications 20116805 and 20116997. This LER is closed.

.4 (Closed) LER 50-272/02-009-00, Failure to Perform Required Action of TS 3.1.3.2.1

0n December 12, 2002, control rod 1C3 individual rod position indication was declared

inoperable on Salem Unit 1. The associated TS action statement 3.1.3.2.1.a required

that either the position of the non-indicating rod be determined by use of the power

distribution monitoring system (PDMS) or the incore movable detectors once every 8

hours or reduce thermal power to less than 50% of rated. Reactor engineers performed

the rod position verification by the PDMS twice at six hour intervals on Unit 2 instead of

Unit 1. Reactor engineers later reviewing the results of the PDMS surveillance

determined that the verification was performed on the wrong Salem unit. The PDMS

verification was performed correctly on Unit 1 seven hours late. The surveillance

validated that rod 1C3 on Unit 1 was within its required position. PSEG entered this

human performance issue into its corrective action program as notification 20124652 .

This finding is more than minor, because it impacted a fuel cladding attribute for the

barrier integrity cornerstone. This finding was also considered to have a very low safety

significance (Green) by the Phase 1 SDP because it only involved the fuel barrier. This

licensee-identified finding was a violation of TS 3.1.3.2.1, Rod Position Indication

Systems. Because this finding was determined to be of very low significance and has

been entered into the corrective action program (notification 20124652), this violation is

Enclosure

27

being treated as a non-cited violation consistent with Section VI.A of the NRC

Enforcement Policy. This LER is closed.

.5 Salem Unit 2 Manual Reactor Trip on March 29, 2003

Control room operators manually tripped Salem Unit 2 in response to CW system

challenge precipitated by severe marsh grass at the intake structure. The inspectors

responded to the site and main control room verifying that the trip response was normal

and that stable hot shutdown conditions were verified. Other aspects of the inspectors

activities are described in Section 1R14.1.

4OA5 Other

.1 (Open) URI 50-272/02-09-06: Determine if PSEG met all ODCM and 10 CFR 20

effluent release requirements associated with the Unit 1 spent fuel pool leak.

a. Inspection Scope

As discussed in Section 4OA2 of this report, the inspector reviewed current onsite

radiological sample results for near field and far field wells surrounding the Salem

facility. The inspector also conducted a baseline radiological environmental monitoring

inspection for the Salem and Hope Creek site to evaluate offsite dose impact associated

with site operations.

b. Findings

At the completion of this inspection, PSEG was continuing with its onsite sampling

program to identify the distribution of tritium in onsite groundwater. Four onsite test wells

were identified to contain detectable levels of tritium. PSEG was evaluating

development of additional sampling plans to evaluate, in part, tritium migration. This

URI remains open pending inspector review of additional sample plans and PSEG

sample results.

4OA6 Meetings, including Exit

On April 4, 2003, the resident inspectors presented the inspection results to Mr. Tim

OConnor and other members of this staff who acknowledged the findings. The

inspectors confirmed that proprietary information was not provided or examined during

the inspection.

4OA7 Licensee-Identified Violations

Section 4OA3.4 of this inspection report describes a violation of very low safety

significance (Green) which was identified by PSEG and is a violation of NRC

requirements which meets the criteria of Section VI of the NRC Enforcement Policy,

NUREG-1600, for being dispositioned as a non-cited violation.

Enclosure

ATTACHMENT: SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee personnel

J. Carlin, Vice President of Engineering

T. Cellmer, Radiation Protection Manager

D. Garchow, Vice President of Licensing/Projects

K. Augustine, CVCS System Engineer

J. Balcita, Lead Engineer (Appendix R)

C. Berger, 50.59 Technical Response Lead

J. Bisti, DCP HC Technical Response Lead

K. Buddebohn, Licensing

K. Fleischer, Supervisor of Design Engineering

V. Fregonese, Engineering Manager

M. Hassler, Radiation Protection Operations Superintendent - Salem

J. Hilditch, Tech. Support Supervisor

F. Hummel, RHR System Engineer

G. Jones, Tech. Support Business Analyst

C. Kapes, Reliability Engineer

T. McCool, DCP Salem Technical Response Lead

M. Moiser, Licensing

R. Montgomery, Senior Engineer, Flow Accelerated Corrosion Program

N. Nag, Electrical Engineer

J. Nagle, Licensing Supervisor

T. Neufang, ALARA Supervisor - Salem

J. O,Connor, Engineering, Plant Chief

M. Pat, QA Engineer

B. Rodgers, Design Engineer/Sargent & Lundy

G. Salamon, NSL Manager

B. Sebastian, ALARA and Support Superintendent

E. Springer, DMG Business Analyst

M. Tadjalli, Engineering Supervisor

J. Volence, Staff Engineer

L. Wazdinger, Ops Director

NRC personnel

R. Lorson, Senior Resident Inspector, Salem

F. Bower, Resident Inspector, Salem

Attachment

2

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

50-311/03-03-04 URI 22 AFW pump packing performance. (Section

1R19.2)

Opened and Closed

50-272/03-03-01 NCV Failure to identify EDG room roof leaks. (Section

1R01)

50-272&311/03-03-02 NCV Failure to properly evaluate AFW pump skid.

(Section 1RO4.1)

50-272&311/03-03-03 NCV EDG deficient corrective actions. (Section 1R19.1)

Closed

50-272&311/02-09-01 URI Submerged safety-related electrical cables

appropriate corrective actions. (Section 1R06)

Discussed

50-272/02-09-06 URI Salem Unit 1 Spent Fuel Pool Water Leak.

(Section 4OA5)

LIST OF DOCUMENTS REVIEWED

In addition to the documents identified in the body of this report, the inspectors reviewed the

following documents and records:

Sections 1R02 and 1R17

Permanent Plant Modifications

DCP 80008148, Salem Unit 2 Steam Generator Nozzle Transition Forging, Rev. 0

DCP 80008505, 4KV/125VDC Control Circuit Modification, Rev. 2

DCP 80008741, Modification of PORV control circuits, Rev. 1

DCP 80017352, Modify Control Wiring Configuration and Gearing for 21SJ54, Rev. 0

DCP 80029004, Appendix R Cable Reroutes - Unit 2, Rev.1

DCP 80030171, Hot Shutdown Panel Cross Tie - Unit 2, Rev.1

DCP 80033503, Installing Vents on RHR to Safety Injection/Charging Pump Cross

Connection Piping for Salem 2, Rev. 2

Attachment

3

10 CFR 50.59 Safety Evaluations

S00-019, Removal of PDP Charging Pump from Service, Rev. 0

S00-027, 2PR1 and 2PR2 Control Circuit Modification, Rev. 0

S01-004, Increase Setpoint of BF-82 and BF-90 PSVs from 1350 psig to 1620 psig, Rev. 4

S01-008, Unit 1 RMS Upgrade, Rev. 0

S01-013, 15/25 Feed Water Heater Pressure Equalizing Line Orifice Resizing, Rev. 1

S01-017, Hot Shutdown Panel Cross Tie - Unit 1, Rev. 1

S02-001, Analysis of CVCS Cross-Tie, Rev. 0

S02-006, Salem Unit 1 Steam Generator Snubber Elimination, Rev. 0

S02-007, Evaluation of MSIVs as Containment Isolation Valves, Rev. 0

10 CFR 50.59 Safety Evaluation Screens

DCP 80005242, Salem Unit Containment Particulate, Iodine, and Gas RMS Upgrade,

Rev. 1

DCP 80006746, Overhead Annunciator DAC Firmware Upgrade

DCP 80015124, Wiring Change for MOVs 2CV68 and 2CV69

DCP 80017352, Modify Control Wiring Configuration and Gearing for 21SJ54, Rev. 0

DCP 80020460, Modification of Fan 2VHE45, ABV Exhaust Fan Number 21

DCP 80022667, 230 VAC Circuit Breaker Instantaneous Trip Settings: I-2110 MCC

DCP 80026404, ABV Exhaust Fan (Number 23 - 2VHE47) Bearing Replacement

DCP 80027983, Change in Tap Location for Discharge Pressure of 21 Component

Cooling Pump

DCP 80029004, Appendix R Cable Reroutes/Hot Short Re-mediation, Rev. 1

DCP 80033503, Installing Vents to RHR to Safety Injection/Charging Pump Cross

Connect Piping for Salem 2, Rev. 2

DCP 80030171, Hot Shutdown Panel Cross Tie - Unit 2, Rev. 0

DCP 80034979, Steam Generator Scrubber Elimination, Rev. 0

DCP 80037132, 2SJ12/13 Leakage Resolution

DCP 80041307, Change S/G Low-Low Level Setpoint To Account For OE 13281, Rev. 1

Design References and Calculations

ES-4.003(Q), 125 Volt DC Short Circuit and System Voltage Drop Calculation, Rev. 2

ES-13.006(Q), Breaker and Relay Coordination Calculation for safety-related AC

Systems, Rev. 2

ES-15.005(Q), 230 Vital Bus Voltage Drop Calculations for Control Circuits, Rev. 1

ES-15.009(Q), Essential Controls Inverter Load Study For PSEG SNGS Units 1 and 2,

Rev. 5

S-C-BF-MDC-1153, Resolution of Balance of Plant Design Pressure, Rev. 2

S-C-BF-MDC-1876, Feedwater Heater High Level Trip During Plant Load Transients, Rev. 0

S-C-CN-MEE-1073, Condensate System Design Pressure Reconciliation, Rev. 1

S-C-G-240-MDC-0239, MSR & FW Heater Drain Tank Equalizing Line Orifice Sizing, Rev. 0

Procedures

Attachment

4

NC.CC.AP.ZZ-0015(Q), Development and Maintenance Bill of Materials and Equipment

Masters, Rev. 0

NC.CC-AP.ZZ-0080(Q), Engineering Change Process, Rev. 4

NC.CC-AP.ZZ-0081(Q), Engineering Change Implementation & Test Process, Rev. 4

NC.CC-AP.ZZ-0082(Q), Implementation Plans, Rev. 1

NC.CC-AP.ZZ-0083(Q), Test Plans, Rev. 1

NC.CC-AP.ZZ-0084(Q), Conduct of Test, Rev. 0

NC.DE-AP.ZZ-0008(Q), Control of Design & Configuration Change, Tests, and

Experiments For Workbook Style Change Packages, Rev. 2

NC.DE-WB.ZZ-0001(Q), Standard Design Change Workbook One, Rev.15

NC.DE-WB.ZZ-0002(Q), Generic Equivalent Replacement, Rev. 5

NC.DE-WB.ZZ-0003(Q), Engineering Workbook For Equivalent Replacement, Rev. 9

NC.DE-WB.ZZ-0004(Q), Engineering Workbook For Document Only And Part Change

Sponsor Organization, Rev. 8

NC.DE-WB.ZZ-0005(Q), Engineering Workbook For As-Built Document, Rev. 8

NC.DE-WB.ZZ-0006(Q), Engineering Change Authorization, Rev. 14

NC.NA-AP.ZZ-0008(Q), Configuration Control Program, Rev. 18

NC.NA-AP.ZZ-0059(Q), Regulatory Change Determination & 10CFR50.59 Review

Process, Rev. 9

NC.NA-AS.ZZ-0059(Q), 10CFR50.59 Program Guidance, Rev. 5

NC.WM-AP.ZZ-0002(Q), Performance Improvement Process, Rev. 6

SC.MD-PM.ZZ-0005(Q), Molded Case Circuit Breaker Maintenance, Rev. 3

SC-MD-PM.ZZ-0005(Q), Molded Case Circuit Breaker Maintenance, Rev. 2, Completed

November 9, 2001

S1.OP-AB.CR-0002(Q), Control Room Evacuation Due To Fire In Control Room, Relay

Room Or Ceiling Of The 460/230V Switchgear Room, Rev. 12

S2.OP-AB.CR-0002(Q), Control Room Evacuation Due To Fire In Control Room, Relay

Room Or Ceiling Of The 460/230V Switchgear Room, Rev. 15

S1.OP-SO.CVC-0023(Q), CVCS Cross-Connect Alignment To Unit 2, Rev. 0

S1-OP-SO.115-0002(Q), Alternate Shutdown System UPS System Operation, Rev. 5

S2-OP-SO.115-0002(Q), Alternate Shutdown System UPS System Operation, Rev. 7

S1.RA-ST.CVC-0023(Q), Inservice Testing 13 Charging Pump Acceptance Criteria, Rev. 4

CRs, Notifications and Work Orders

CRs

70017302 70019043 70022332 70023141 70023469

70023621 70023988 70024420 70024911 70027683

70028176 70028654 70028713

Notifications

20087950 20088412 20095350 20097818 20097861

20099102 20108633 20111616 20118250 20120389

Attachment

5

20124328 20128225 20128353

Work Orders

30027562 30027563 30034414 30034580 50000262

60006815 60006816 60006817 60015019 60015020

Drawings

Piping and Instrument Diagrams

205202 A 8760, Sh. 1-3 Steam Generator Feed & Condensate

205205 A 8762, Sh. 1-6 Unit 1 Bleed Steam & Heater Drains

205228-A-8761, Sh. 2 Number 1 Unit Chemical And Volume Control Operation,

Rev. 76

205305 A 8762, Sh. 1-6 Unit 2 Bleed Steam And Heater Drains

205324-A-8761, Number 1 Unit Safety Injection, Rev. 51

244083-A-9679, Number 1 Unit Pressurizer PORV And Stop Valves And

Overpressure Protection System, Rev. 18

244084-A-9679, Number 2 Unit Pressurizer PORV And Stop Valves And

Overpressure Protection System, Rev. 9

Single Line Diagrams

203002-A-8789, Number 1 Unit 4160 Vital Buses One-Line, Rev. 34

203007-A-8789, Number 1 Unit 125VDC One-Line, Rev. 28

203061-A-8789, Number 2 Unit 4160 Vital Buses One-Line, Rev. 32

207910-A-1776, 1A West Valves And Misc. 230V Vital Controller Center One-Line, Rev.

37

211349-B-9511, Number 1 Unit Control Area 1ADE 28VDC Distribution Cabinet, Rev. 11

222485-A-1779, Number 2 Unit Auxiliary Building 2C West Valves And Misc. 230V Vital

Contr. Ctr. One-Line, Rev. 47

223720-A-1404, Number 2 Unit 125VDC One-Line, Rev. 31

Schematic Diagrams

110454, Assembly Drawing Safety Injection Pumps, Rev. 2

Self-Assessments and QA Audits

Focused Self-Assessment Report, 1R14 Outage DCP Quality Self-Assessment, Configuration

Control, June 27, 2001

Focused Self-Assessment Report, 80048378, Focused Self-Assessment To Ensure That The

Outstanding Changes Identified On Affected Documents

Associated With Change Packages Are Incorporated On

Attachment

6

Permanent Design Document Accurately And Efficiently,

Design Engineering, August 28, 2002

Focused Self-Assessment Report, 80055021, Assessment of 10 CFR 50.59 Program

Implementation, Nuclear Safety and Licensing,

December 27, 2002

Focused Self-Assessment Report, 80043343, Internal Bench Marking Of The Implementation

of Design Change Process In The PSEG Nuclear

Organizations, Technical Support Organization,

July 31, 2002

Focused Self-Assessment Report, 80053554, 1R15 Modification Effectiveness, Technical

Support Organization/Implementation and Test Group,

December 21, 2002

QA Assessment Report 2002-0071, 2R12 Outage Activities - Tech. Support/Nuclear Reliability,

June 4, 2002

QA Assessment Report 2002-0162, Sargent & Lundy Change Package Quality, July 3, 2002

QA Assessment Report 2002-0197, Salem 1R15 Engineering Outage Preparations,

August 12, 2002

QA Assessment Report 2002-0279, 1R15 Outage Engineering Oversight, December 10, 2002

Miscellaneous Documents

ANSI B 31.1, 1967, Part 102-Design Criteria

ND.DE-TS.ZZ-2012(Q), Low Voltage Circuit Breakers and Combination Starters - Salem 240V

and 480V Control Circuits, Rev. 1

SIC-00-023R Structural Integrity Report, Steam Generator Feedwater Nozzle Transition

Replacement Process

Site Organization Chart, Engineering Organization

TS, Salem Generating Station

Updated Final Safety Analysis Report, Salem Generating Station

VTD 301137, Dresser Industries Installation, Operating and Maintenance Manual for Centrifugal

Charging and SI Pumps, Rev. 25

VTD 316490-01, CCP Pump Performance Curve

Section 4OA2: RP Program Assessments

QA Assessments and Observations

QAAR 2003-0005 RF-11 Pre-Outage Assessment

QAAR 2002-0147 Portable Instrument repair and Calibration

QAAR 2002-0222 Radiation Monitoring System

QAAR 2002-0293 1R15 Refueling Outage Activities

QAAMF 2002-0318 Salem 1R15 Temporary Shielding Installation

QAAMF 2002-0322 Salem 1R15 RP Area Setups and Work Practices

QAAMF 2002-0341 Salem 1R15 Management Oversight

QAAMF 2002-0350 Normal Operating Pressure/Normal Operating Temperature Containment

Walkdown

QAAMF 2002-0356 NRC Performance Indicators

Attachment

7

Departmental Self-Assessments

80047782/0020 RP Corrective Action Evaluations

80047782/0050 Decontamination

80047782/030 Personnel Contamination Events

RP3Q-02-001 RP Performance for Filter Replacement Activities

80047782/070 Remote Alarming Radiation Monitors Evaluation

80038318/0120 Self-Monitor Program

80038318/070 Work Practices of RP

80051804/0020 RP Assessment of Corrective Actions

80051804/0060 Management/Supervisor/Tech Oversight

80051804/0030 OE Program Effectiveness

80047782/0060 Respiratory Protection

RP4Q-02-001 Impact of Security Personnel Loading on Whole Body Contamination

Monitors

80051804/070 Surveys and Monitoring

RP1Q-03-001 2002 RP Self-Assessment Schedule Performance

RP1Q-03-003 PWR/ALARA Committee Meeting

RP1Q-03-002 2002 RP CRE

LIST OF ACRONYMS

AFW Auxiliary Feedwater

ALARA As Low As Is Reasonably Achievable

CFCU Containment Fan Cooler Unit

CFR Code Of Federal Regulations

CR Condition Report

CW Circulating Water

CY Calendar Year

DCP Design Change Package

ECACs Emergency Control Air Compressors

EDG Emergency Diesel Generator

ICMs Interim Compensatory Measures

MR Maintenance Rule

MSSV Main Steam Safety Valve

NCVs Non-Cited Violations

NRC Nuclear Regulatory Commission

ODCM Offsite Dose Calculation Manual

PARS Publicly Available Records

PDMS Power Distribution Monitoring System

PMT Post-Maintenance Testing

PRT Pressurizer Relief Tank

PSEG Public Service Electric Gas

PSV Pressurizer Safety Valve

QA Quality Assurance

RCA Radiologically Controlled Area

Attachment

8

REMP Radiological Environmental Monitoring Program

RHR Residual Heat Removal

RP Radiation Protection

RWP Radiation Work Permit

SAC Station Air Compressor

SDP Significance Determination Process

SSC Structures, Systems and Components

TARP Transient Assessment Response Plan

TLDs Thermoluminescent Dosimeters

TS Technical Specification

UFSAR Updated Final Safety Analysis Report

URI Unresolved Item

Attachment