ML031330797
| 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
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
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
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
Report No: 50-272/2003-03, 50-311/2003-03
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)
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
LIST OF ACRONYMS
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
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
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