ML102220170
| ML102220170 | |
| Person / Time | |
|---|---|
| Site: | Salem, University of New Mexico |
| Issue date: | 08/10/2010 |
| From: | Arthur Burritt Reactor Projects Branch 3 |
| To: | Joyce T Public Service Enterprise Group |
| BURRITT, AL | |
| References | |
| IR-10-003 | |
| Download: ML102220170 (50) | |
See also: IR 05000272/2010003
Text
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION I
475 ALLENDALE ROAD
KING OF PRUSSIA, PA 19406-1415
I*
August 10, 2010
Mr. Thomas P. Joyce
President and Chief Nuclear Officer
P.O. Box 236
Hancock's Bridge, NJ 08038 I
SUBJECT: SALEM NUCLEAR GENERATING STATION, UNIT NOS. 1 AND 2-
NRC INTEGRATED INSPECTION REPORT 05000272/2010003 and
Dear Mr. Joyce:
On June 30,2010, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at
the Salem Nuclear Generating Station, Unit Nos. 1 and 2. The enclosed integrated inspection
report documents the inspection results discussed on July 8, 2010, with Mr. Fricker and other
members of your staff.
The inspection examined activities conducted under your license as they relate to safety and
compliance with the Commission's 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 one NRC-identified finding and one self-revealing finding of very low
significance (Green). One of these two findings was determined to involve a violation of NRC
requirements. Additionally, one licensee-identified violation of very low safety significance is
listed in this report. However, because of the very low safety significance of these two violations
and because they were entered into your corrective action program (CAP), the NRC is treating
these findings as non-cited violations (NCVs) consistent with Section VI.A.1 of the NRC
Enforcement Policy. 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, United
States Nuclear Regulatory CommisSion, Washington, DC 20555-0001; and the NRC Resident
Inspector at the Salem Nuclear Generating Station. In addition, if you disagree with the cross-
cutting aspect assigned to any finding in this report, you should provide a response within 30
days of the date of this inspection report, with the basis of your disagreement, to the Regional
Administrator, Region I, and the NRC Resident Inspector at Salem Nuclear Generating Station.
T. Joyce 2
In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its
enclosure, and your response (if any) will be available electronically for public inspection in the
NRC Public Document Room or from the Publicly Available Records (PARS) component of
NRC's 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).
Arthur L. Burritt, Chief
Projects Branch 3
Division of Reactor Projects
Docket Nos: 50-272; 50-311
Enclosure: Inspection Report 05000272/2010003 and 05000311/2010003
w/Attachment A: Supplemental Information
Attachment B: TI 172 MSIP Documentation Questions Salem Unit 1
cc w/encl: Distribution via ListServ
T. Joyce 2
In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its
enclosure, and your response (if any) will be available electronically for public inspection in the
NRC Public Document Room or from the Publicly Available Records (PARS) component of
NRC's 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.
IRA!
Arthur L. Burritt, Chief
Projects Branch 3
Division of Reactor Projects
Docket Nos: 50-272; 50-311
Distribution w/encl.
M. Dapas, Acting RA (R10RAMAIL Resource) C. Douglas, DRP
D. Lew, Acting DRA (R10RAMAIL Resource) A. Turilin, DRP
J. Clifford, DRP (R1DRPMAIL Resource) D. Schroeder, DRP, SRI
D. Roberts, DRS (R1DRSMail Resource) K. McKenzie, DRP, OA
P. Wilson, DRS (R1DRSMaii Resource) L. Trocine, RI, OEDO
A. Burritt, DRP RidsNrrPMSalem Resource
L. Cline, DRP RidsNrrDorlLpl1-2Resource
ROPreportsResource@nrc.gov
DOCUMENT NAME: G:\DRP\BRANCH3\lnspection\Reports\lssued\SAL 1003.docx
SUNSI Review Complete: LC (Reviewer's Initials) ML102220170
After declaring this document "An Official Agency Record" it will be released to the Public.
To receive a copy 0 this document, indicate in the box: "C n= CODY without attachment/enclosure "En = CoDV with attachment/enclosure *N" = No copy
OFFICE mmt RIIDRP I RIIDRP I RIIDRP I I
NAME DSchroederl LCline/LC ABurritvALB
DATE 07/30/10 08/06/10 08/10/10
OFFICIAL RECORD COPY
1
U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Docket Nos: 50-272, 50-311
Report No: 05000272/2010003 and 05000311/2010003
Licensee: PSEG Nuclear LLC (PSEG)
Facility: Salem Nuclear Generating Station, Unit Nos. 1 and 2
Location: P.O. Box 236
Hancocks Bridge, NJ 08038
Dates: April 1, 2010 through June 30, 2010
Inspectors: D. Schroeder, Senior Resident Inspector
H. Balian, Resident Inspector
D. Johnson, Acting Resident Inspector
S. Ibarrola, Acting Resident Inspector
J. Furia, Senior Health PhysiCist
M. Patel, Reactor Inspector
1. O'Hara, Reactor Inspector
Approved By: Arthur L Burritt, Chief
Projects Branch 3
Division of Reactor Projects
Enclosure
2
TABLE OF CONTENTS
SUMMARY OF FI NDINGS ......................................................................................................... 3
REPORT DETAILS .................................................................................................................... 5
1. REACTOR SAFETy ............................................................................................................... 5
1R01 Adverse Weather Protection ................................................................................... 5
1R04 Equipment Alignment ............................................................................................. 6
1R05 Fire Protection ........................................................................................................ 7
1R07 Heat Sink Performance ......................................................................... " ............... 8
1R08 Inservice Inspection (lSI) ........................................................................................ 8
1R11 Licensed Operator Requalification Program .............................. " ...... " .. " .............. 12
1R12 Maintenance Effectiveness ................................................................................... 13
1R13 Maintenance Risk Assessments and Emergent Work Control .. " .......................... 15
1R15 Operability Evaluations .. " ........... ,.............................................. " ......................... 16
1R18 Plant Modifications ............................................................................................... 16
1R19 Post-Maintenance Testing .............................................. " .................................... 17
1R20 Refueling and Other Outage Activities ...................................... " .......... " .......... " .. 18
1R22 Surveillance Testing ............................... " ............................................................ 20
1EP6 Drill Evaluation .. " ....................................................................... " .................... " .. 20
2. RADIATION SAFETY .................................................................................................." ....... 21
2RS1 Radiological Hazard Assessment and Exposure Controls .... " .............................. 21
2RS2 Occupational As Low As Reasonably Achievable (ALARA) Planning and Controls23
4. OTHER ACTIVITIES .......................... " ............................. " ............................................. " .. 23
40A 1 Performance Indicator (PI) Verification .......................... " ................................ " ... 23
40A2 Identification and Resolution of Problems ............................ " .... " ................ " ....... 24
40A3 Event Follow-up ............................................................. ,..................................... 25
40A5 Temporary Instruction (TI) 2515/172 .................. " ...................... " ......................... 26
40A6 Meetings, Including Exit ................................................. " ...................... " ............. 27
40A7 Licensee Identified Violations ................................................................................ 27
ATTACHMENT A: SUPPLEMENTAL INFORMATION ............................................................. 27
ATTACHMENT B: T1172 MSIP DOCUMENTATION QUESTIONS SALEM UNIT 1 ........ " ...... 27
SUPPLEMENTAL INFORMATION ..........................................................................................A-1
KEY POI NTS OF CONTACT ................................................. " .......... " .................................. "A-1
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED .................................................... ".A-1
LIST OF DOCUMENTS REVIEWED ......................................................................... " .......... "A-1
LIST OF ACRONYMS ...........................................................................................................A-17
TI 172 MSIP Documentation Questions Salem Unit 1.. .................................. " .......... " ............ B-1
Enclosure
3
SUMMARY OF FINDINGS
IR 05000272/2010003, 05000311/2010003; 04/01/2010 - 06/30/2010; Salem Nuclear
Generating Station Unit Nos. 1 and 2; Inservice Inspection and Maintenance Effectiveness.
The report covered a three-month period of inspection by resident inspectors, and announced
inspections by a regional radiation specialist and reactor engineers. One Green non cited
violation (NCV) and one Green finding were identified. The significance of most findings is
indicated by their color (Green, White, Yellow, or Red) using Inspection Manual Chapter (lMC)
0609, "Significance Determination Process" (SOP) and the cross-cutting aspect of a finding is
determined using IMC 0310, "Components Within the Cross-Cutting Areas." Findings for which
the SOP does not apply may be Green or be assigned a severity level after NRC management
review. The NRC's program for overseeing the safe operation of commercial nuclear power
reactors is described in NUREG-1649, "Reactor Oversight Process," Revision 4, dated
December 2006.
Cornerstone: Initiating Events
- Green. A self-revealing finding of very low safety significance was identified on January
21, 2010, because a control system short circuit caused the 21 steam generator feed
pump (SGFP) to trip. This caused a turbine runback and ultimately an automatic Unit 2
reactor trip due to low water level in one of four steam generators (SGs). The short
circuit occurred because technicians did not use the correct procedure to repair
degraded insulation on the barrel of a connector lug that was identified in the 21 SGFP
control system in November 2009. PSEG repaired the short circuit prior to restart of Unit
2 on January 23, 2010. The issue was entered into the corrective action program as
notification 20448229. PSEGs immediate corrective actions for this issue included
repairing the degraded insulation, fixing lug alignment and performing extent of condition
inspections on the other Unit 2 SGFP panels for degraded insulation. No other
deficiencies were identified.
This performance deficiency is more than minor because it is associated with the human
performance attribute of the Initiating Events cornerstone, and it adversely affected the
cornerstone objective to limit the likelihood of events that upset plant stability and
challenge critical safety functions. Specifically, not following PSEG procedure SC.DE-
TS.ZZ-2039 on November 11, 2009, caused the 21 SGFP trip and subsequent
automatic reactor trip due to low SG water level on January 21,2010. The finding was
evaluated under IMC 0609, Attachment 4. The inspectors determined that the finding is
of very low safety significance because it does not contribute to both the likelihood of a
reactor trip and the likelihood that mitigation equipment or functions will not be available.
The inspectors determined that this finding has a cross-cutting aspect in the area of
human performance because PSEG personnel did not follow procedure requirements
while repairing plant equipment. Specifically, technicians applied electrical tape to the
21 SGFP pressure switch connector lug barrel on November 11, 2009, which did not
meet PSEG procedure SCDE-TS.ZZ-2039 requirements. (HA (b)) (Section 1R12)
Enclosure
4
Cornerstone: Mitigating Systems
/
failure to perform auxiliary feedwater (AFW) discharge piping system pressure tests on
buried piping components as required by 10 CFR 50.55a(g)(4) and the referenced
American Society of Mechanical Engineers Code (ASME),Section XI, paragraph IWA-
5244 for Salem Unit 1. The required tests are intended to demonstrate the structural
integrity of the buried piping portions of the system. PSEG entered this condition into
the corrective action program (notification 20459689) and replaced the affected Unit 1
AFW piping.
This performance deficiency is more than minor, because, if left uncorrected, it would
have resulted in a more significant safety concern. Specifically, the inspectors
determined that based on the degraded condition of the coating and piping discovered
during excavation on Unit 1, without performance of the required pressure test, an
undetected failure of the piping would have resulted due to continued, undetected
corrosion. The finding impacts the Mitigating Systems cornerstone. Using IMC 0609,
Attachment 4, the finding was determined to be of very low safety significance because it
was not a design or qualification deficiency, did not result in an actual loss of safety
function, and was not potentially risk significant for external events. No cross cutting
Aspect is assigned to this violation because this condition began in 1988, more than 3
years ago, and is not indicative of current performance. (Section 1R08)
Other Findings
- One violation of very low safety significance was identified by PSEG and has been
reviewed by the inspectors. Corrective actions taken or planned by PSEG have been
entered into PSEG's corrective action program (CAP). This violation and its corrective
action tracking numbers are listed in Section 40A7 of this report.
Enclosure
5
REPORT DETAILS
Summary of Plant Status
Salem Nuclear Generating Station Unit 1 (Unit 1) began the period at full power. On April 2,
operators reduced power to 89 percent because heavy river water detritus prevented adequate
cooling of the main condenser. On April 3, operators shut down Unit 1 to begin the twentieth
refueling outage (RFO) (S1 R20). On April 29 the RFO ended when operators synchronized the
main generator to the grid. On May 1, operators returned Unit 1 to full power. On June 15,
operators reduced power to 3 percent and removed the main turbine from service due to erratic
operation of the 13 steam generator (SG) feed regulating valve (FRV). Operators synchronized
Unit 1 to the grid again on June 16, but because the 12 SG FRV was not adequately controlling
12 SG water level, operators removed the main turbine from service on June 17. Operators
synchronized Unit 1 to the grid on June 17 and returned the unit to full power on June 18. Unit
1 remained at or near full power for the remainder of the inspection period.
Salem Nuclear Generating Station Unit 2 (Unit 2) began the period at full power. On April 1,
operators reduced power to 83 percent because heavy river water detritus prevented adequate
cooling of the main condenser. On April 2, operators reduced power to 69 percent because
heavy river water detritus prevented adequate cooling of the main condenser. On April 5,
operators began power ascension and reached full power on April 7. Unit 2 remained at or near
full power for the remainder of the inspection period.
1. REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity and Emergency
Preparedness
1R01 Adverse Weather Protection (71111.01 - 1 sample)
.1 Summer Readiness of Offsite and Alternate AC Power Systems
a. Inspection Scope
The inspectors completed one adverse weather inspection sample to evaluate the
readiness of offsite power to the Salem units prior to the summer season when electrical
grid stability can be most challenged. The inspectors verified that PSEG provided
procedure requirements or guidance to monitor and maintain availability and reliability of
the offsite AC Power (OSP) system prior to and during adverse weather conditions.
Specifically, the inspectors verified that the procedures addressed:
- The actions to be taken when notified by the electrical system operations center
(ESOC) of the PJM interconnection that the posHrip voltage of the OSP system at
Salem will not be acceptable to assure the continued operation of the safety-related
loads without transferring to the emergency diesel generators (EDGs);
- The compensatory actions to be performed if ESOC cannot predict the post-trip
voltage;
- The re-assessment of plant risk for maintenance activities that could affect grid
reliability or OSP system availability to the Salem units; and
Enclosure
6
- Communication requirements between Salem and the ESOC regarding plant
changes that could impact the transmission system, or the capacity of the
transmission system to provide adequate aSP.
The inspectors also reviewed PSEG's seasonal readiness preparations for the summer
season specific to the main power transformers and the asp system. The inspectors
interviewed engineering and work control personnel and reviewed work orders and
completed portions of WC-AA-107, Seasonal Readiness, to verify that PSEG took
measures to ensure the reliability of the main transformers and the asp system during
the summer season. The documents reviewed during this inspection are listed in the
Attachment A.
b. Findings
No findings of significance were identified.
1 R04 Equipment Alignment (71111.04 - 3 samples; 71111.04S -1 sample)
.1 Partial Walk down
a. Inspection Scope
The inspectors completed three partial system walk down inspection samples. The
inspectors walked down the systems listed below to verify the operability of redundant or
diverse trains and components when safety equipment was inoperable. The inspectors
focused their review on potential discrepancies that could impact the function of the
system and increase plant risk. The inspectors reviewed applicable operating
procedures, walked down control systems components, and verified that selected
breakers, valves, and support equipment were in the correct position to support system
operation. The inspectors also verified that PSEG properly utilized its corrective action
program to identify and resolve equipment alignment problems that could cause initiating
events or impact the capability of mitigating systems or barriers. Documents reviewed
are listed in the Attachment A.
- Unit 1, 12 service water (SW) header while hardened to support planned
unavailability of the 11 SW header;
service (OOS); and
Enclosure
7
.2 Complete Walk down
a. Inspection Scope
The inspectors conducted one complete walk down inspection sample of the Unit 1
safety injection (SI) system on June 28 through 30, 2010. The inspectors independently
verified the alignment and status of SI pump and valve electrical power, labeling,
hangers and supports, and associated support systems. The walk down also included
evaluation of system piping and equipment to verify pipe hangers were in satisfactory
condition, oil reservoir levels were normal, pump rooms and pipe chases were
adequately ventilated, system parameters were within established ranges, and
equipment deficiencies were appropriately identified. The inspectors interviewed
engineering personnel and reviewed corrective action evaluations associated with the
system to determine whether equipment alignment problems were identified and
appropriately resolved. Documents reviewed are listed in the Attachment A.
b. Findings
No findings of significance were identified.
1R05 Fire Protection (71111.05Q - 6 samples)
.1 Fire Protection - Tours
a. Inspection Scope
The inspectors completed six fire protection quarterly inspection samples. The
inspectors walked down the systems listed below to assess the material condition and
operational status of fire protection features. The inspectors verified that combustibles
and ignition sources were controlled in accordance with PSEG's administrative
procedures; fire detection and suppression equipment was available for use; that
passive fire barriers were maintained in good material condition; and that compensatory
measures for out of service (OOS), degraded, or inoperable fire protection equipment
were implemented in accordance with PSEG's fire plan. Documents reviewed are listed
in the Attachment A.
- Unit 1, auxiliary building, 84' elevation inside the charging pipe alley;
- Unit 1, electrical penetration, 78' elevation;
- Unit 1, AFW pumps area, 84' elevation;
- Unit 1, diesel fuel oil storage area, 84' elevation;
- Unit 2, diesel fuel oil storage area, 84' elevation; and
- Unit 1, containment during the RFO.
b. Findings
No findings of significance were identified.
Enclosure
8
1R07 Heat Sink Performance (71111.07A-1 sample)
a. Inspection Scope
The inspectors completed one annual heat sink performance inspection sample. The
inspectors reviewed performance data and interviewed the NRC Generic Letter (GL) 89-
13 program manager to verify that potential HX or heat sink deficiencies were identified
and PSEG adequately resolved heat sink performance problems. Specifically, the
inspectors reviewed 12B component cooling water (CCW) HX data. Inspectors
evaluated trending data and verified that equipment would perform satisfactorily under
design basis conditions. The method of performance monitoring was compared to the
guidance provided in NRC GL 89-13, "Service Water System Problems Affecting Safety-
Related Equipment," and Electric Power Research Institute NP 7552, "HX Performance
Monitoring Guidelines." Documents reviewed are listed in the Attachment A.
b. Findings
No findings of significance were identified.
1R08 Inservice Inspection (lSI) (71111.08P -1 sample)
a. Inspection Scope
The inspector observed a selected sample of nondestructive examination (NOE)
activities in process. Also, the inspector reviewed the records of selected additional
samples of completed NOE and repair/replacement activities. The sample selection was
based on the inspection procedure objectives and risk priority of those components and
systems where degradation would result in a significant increase in risk of core damage.
The observations and documentation reviews were performed to verify that the activities
inspected were performed in accordance with the American Society of Mechanical
Engineers (ASME) Boiler and Pressure Vessel Code requirements.
The inspector reviewed the licensee's performance of a visual inspection (VT) of the Unit
1 reactor vessel closure head (RVCH) and the installed upper head penetrations. The
inspector reviewed the visual procedure, the qualifications of the personnel and
reviewed the inspection report documenting the inspection results. The inspector also
reviewed the data sheets for the penetrant tests completed on three of the penetration
welds of the RVCH.
The inspector reviewed records for ultrasonic testing (UT), visual testing (VT), penetrant
testing (PT) and magnetic particle testing (MT) NDE processes. PSEG did not perform
any radiographic testing (RT) during this outage. The inspector reviewed inspection
data sheets and documentation for these activities to verify the effectiveness of the
examiner, process, and equipment in identifying degradation of risk significant systems,
structures and components and to evaluate the activities for compliance with the
requirements of ASME Code,Section XI.
Enclosure
9
Steam Generator Inspection Activities
The inspectors reviewed a sample of the Unit 1 steam generator eddy current testing
(ECT) tube examinations, and applicable procedures for monitoring degradation of
steam generator tubes to verify that the steam generator examination activities were
performed in accordance with the rules and regulations of the steam generator
examination program, Salem Unit 1 steam generator examination guidelines, NRC
Generic Letters, 10CFR50, technical specifications for Unit 1, Nuclear Energy Institute
97-06, EPRI PWR steam generator examination guidelines, and the ASME Boiler and
Pressure Vessel Code Sections V and XI. The review also included the Salem Unit 1
steam generator degradation assessment and steam generator Cycle 21 and 22
operational assessment. The inspector also verified the individual certifications for
personnel participating in the SG ECT inspections during the 1 R20 refueling outage. The
inspector reviewed PSEG's efforts in identifying wear degradation to the tubing in the
four SGs at Unit 1. The majority of the identified wear indications were attributed to anti
vibration bar (AVB) wear in the u bend regions of the four SGs. The inspector reviewed
the analyses and evaluations that determined that a total of 14 SG tubes would be
removed from service by plugging.
Boric Acid Corrosion Control Program Activities
The inspector reviewed the PSEG boric acid corrosion control program. The resident
inspectors observed PSEG personnel performing boric acid walkdown inspections,
inside containment, and in other affected areas outside of containment, at the beginning
of the Unit 1 refueling outage. The inspectors reviewed the notifications generated by
the walkdowns and the evaluations conducted by Engineering to disposition the
notifications. Additionally, the inspector reviewed a sample of notifications and
corrective actions completed to repair the reported conditions.
Section XI Repair/Replacement Samples:
AFW System Piping. Control Air & Station Air: The inspectors reviewed PSEG's
discovery, reporting, evaluation and the repair/replacement of Unit 1 AFW piping that
was excavated for inspection during the April 2010 Unit 1 refueling outage (1R20).
PSEG conducted this inspection in accordance with PSEG's Buried Piping Inspection
Program. Additionally, the inspectors reviewed the UT testing results performed to
characterize the condition of the degraded Unit 1 buried AFW piping.
The inspector also reviewed the repair/replacement work orders and the 50.59 screening
and evaluation for the AFW, CA and SA piping. The inspectors reviewed the fabrication
of the replacement piping, reviewed the documentation of the welding and NDE of the
replacement piping and reviewed the pressure tests used to certify the replacement
piping. Additionally, the inspector reviewed the specified replacement coating, the
application of the replacement coating and the backfill of the excavated area after the
piping had been tested.
The inspector reviewed the finite element analysis (FEA) results from PSEG's past
operability analysis on the affected Unit 1 buried AFW piping completed by the licensee
Enclosure
10
in order to demonstrate past operability at a reduced system pressure of 1275 psig. The
design pressure of the AFW system is 1950 psig.
The inspector also reviewed the UT testing results (approximately 400) performed on
portions of the Unit 2 AFW buried piping, in response to the conditions observed on
Unit 1 AFW buried piping to determine if degradation existed on the Unit 2 buried AFW
piping.
Rejectable Indication Accepted For Service After Analysis:
The inspector reviewed the Notification and the UT data report of a rejectable wall
thickness measurement on the #11 SG feedwater elbow during 1R20. The inspector
reviewed the additional wall thickness data taken to further define the condition and
reviewed the finite element analysis (FEA) which verified that sufficient wall thickness
remained to operate the component until the next refueling outage when it will be
replaced.
b. Finding
Introduction. The inspector identified a Green non-cited violation (NCV) of 10 CFR
50.55a(g)(4) and the referenced American Society of Mechanical Engineers (ASME)
Code,Section XI, paragraph IWA-5244 for PSEG's failure to perform required pressure
tests of buried AFW components for Salem Unit 1.
Description. Portions of the Unit 1 and Unit 2 AFW system piping is buried piping and
has not been visually inspected since the plant began operation in 1977 for Unit 1 and
since 1979 for Salem Unit 2. This piping is safety related, 4.0" ID, ASME Class 3,
Seismic Class 1 piping. In April 2010, approximately 680 ft. (340 ft. of the #12 SG AFW
supply and 340 ft. of the #14 SG AFW supply) of piping between the pump discharge
manifold and the connection to the main feedwater piping to the affected SGs was
discovered to be corroded to below minimum wall thickness (0.278") for the 1950 psi
design pressure of the AFW System. The discovery was noted by PSEG during a
planned excavation implementing their buried pipe inspection program. The lowest wall
thickness measured in the affected piping was 0.077". The affected Unit 1 piping was
replaced. Although no leakage was evident as a result of the corrosion, the inspector
questioned PSEG about whether the IWA-5244 periodic pressure tests had been
conducted on this underground piping.
10 CFR 50.55(a)(g)(4)(ii) requires licensees to follow the in-service requirements of the
ASME Code,Section XI. Paragraph IWA-5244 of Section XI requires licensees to
perform system pressure tests on buried components to demonstrate the structural
integrity of the tested piping. The system pressure test required by IWA-5244 is
considered to be an inservice inspection and is part of Section XI.Section XI and IWA-
5244 do not specify other non-destructive examinations (NDE) on buried components to
demonstrate structural integrity other than a flow test if the system pressure test cannot
be performed. PSEG had not performed the required tests for Unit 1 since 1988. Thus,
PSEG did not perform the inservice inspection provided by the ASME Code,Section XI,
intended to demonstrate the structural integrity of this safety related buried piping.
Enclosure
11
PSEG was aware of the need to perform these required tests because they sought relief,
from the NRC, from the previous Code required pressure testing in 1988 for Unit 1 only.
Relief was granted to PSEG, by the NRC, to perform an alternate flow test in 1991 for
Unit 1. However, PSEG did not perform the proposed alternate flow tests for Unit 1
since 1988. Thus, PSEG had a chance to foresee and correct this performance
deficiency, but missed the opportunity at the time of processing the final results of the
relief request. PSEG replaced the affected Unit 1 buried piping during the refueling
outage in April/May 2010. The required pressure tests were successfully completed
after the replacement of the Unit 1 buried piping. PSEG determined that the buried
portions of AFW maintained structural integrity because the AFW system functioned as
required during the plant shutdown prior to the start of 1R20 (April 2010) and based
upon the results of a finite element analysis PSEG conducted using as-found UT
readings of excavated portions of the Unit 1 piping.
As part of the extent of condition for the testing issue identified on Unit 1, PSEG
reviewed the status of lSI testing for Unit 2 AFW and determined that the testing had not
been performed since 2001. PSEG currently plans to excavate the Unit 2 buried piping
for inspection during the Unit 2 refueling outage scheduled for the spring of 2011. PSEG
also completed an operability determination and risk assessment to justify continued
operation until the next refueling outage. These evaluations determined that the
condition was acceptable for continued operation until spring 2011. At present, it was
not feasible to conduct the system pressure test or alternate flow test while at power,
and to date there has been no detected degradation of the coating or piping on the Unit
2 buried AFW piping.
Analysis. Visual inspections and UT measurements completed by PSEG on Unit 1 AFW
buried piping in April 2010 identified degraded pipe coating and wall thinning on a
portion of the excavated pipe. Considering the effect of this identified degradation, not
performing the ASME Code,Section XI, paragraph IWA-5244 required pressure test at
the required frequency for this normally inaccessible buried piping would result in an
undetected loss of structural integrity for buried Unit 1 AFW discharge piping. The
inspectors determined this was a performance deficiency.
This performance deficiency was more than minor because, if left uncorrected, it would
have resulted in a more significant condition. Specifically, in light of the as-found
degraded conditions of the coating and the piping discovered during excavation in Unit
1, an undetected failure of the piping would have resulted due to further continued,
undetected corrosion, and continued pipe wall degradation eventually resulting in the
loss of structural integrity and inoperability of the Unit 1 AFW system.
The inspector screened this performance deficiency using IMC 0609, Attachment
0609.04, "Phase 1 Initial Screening and Characterization of Findings." This finding
impacts the Mitigating Systems cornerstone by adversely affecting the secondary, short
term decay heat removal capability. Because the finding was not a design or
qualification defiCiency, did not result in an actual loss of safety function, and was not
potentially risk significant for external events, the inspector determined that the finding
screened to Green, very low safety significance for Unit 1.
Enclosure
12
The inspector determined that a cross cutting aspect did not exist because the issue was
not indicative of current performance because the condition existed since 1991, more
than 3 years ago. Specifically, the failure to perform these pressure tests began in 1988
when PSEG requested relief from the requirement and did not incorporate the actions of
the relief into the plant inservice inspection program when it was granted in 1991.
Enforcement. 10 CFR 50.55a(g)(4) states, in part: "Throughout the service life of a
boiling or pressurized water-cooled nuclear power facility, components which are
classified as ASME Code Class 1, Class 2 and Class 3 must meet the requirements, set
forth in Section XI of editions of the ASME Boiler and Pressure Vessel Code".
Paragraph IWA-5244, Buried Components, of Section XI says, in part:
"(b) For buried components where a VT-2 visual examination cannot be
performed, the examination requirement is satisfied by the following: (1) The system
pressure test for buried components that are isolable by means of valves shall consist of
a test that determines the rate of pressure loss. Alternatively, the test may determine
the change in flow between the ends of the buried components. "
Contrary to these requirements, PSEG did not perform the required pressure tests of the
buried AFW piping to the #12 SG and #14 SG at Salem Unit 1. Specifically, from
February 1988 to April 2010 the required pressure tests were not performed to
demonstrate structural integrity on the affected buried Unit 1 AFW piping during the 2 nd
In Service Inspection Interval (2/27/88 to 5/19/01) and during the 1st (5/19/01 to 6/3/04)
and 2nd (6/24/04 to 5/20/08) periods of the 3'd In Service Inspection Interval (5/19/01 to
5/19/11 ).
Because PSEG entered this condition for Salem Unit 1 into the corrective action process
(Notification 20459686) and because it is of very low safety significance (Green), it is
being treated as a non-cited violation consistent with Section VI.A.1 of the NRC
Enforcement Policy. NCV 50-272/2010003-01, Buried AFW Discharge Piping Not
Tested In Accordance With 10 CFR 50.55a.
1R11 Licensed Operator Regualification Program (71111.11Q -1 sample)
.1 Regualification Activities Review by Resident Staff
a. Inspection Scope
The inspectors completed one quarterly licensed operator requalification program
inspection sample. Specifically, the inspectors observed a scenario administered to a
single crew during an emergency preparedness drill on May 18, 2010. The scenario
included a crane damaging the AFW storage tank, a small reactor coolant leak, a rod
ejection that resulted in a small break loss-of-coolant accident, and a rupture to
containment spray piping that resulted in a loss of containment integrity.
The inspectors reviewed operator implementation of the abnormal and emergency
operating procedures. The inspectors examined the operators' ability to perform actions
associated with high risk activities, the Emergency Plan, previous lessons learned items,
and the correct use and implementation of procedures. The inspectors observed and
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verified that deficiencies were adequately identified, discussed, and entered into the
CAP, as appropriate. Documents reviewed are listed in the Attachment A.
b. Findings
No findings of significance were identified.
1R12 Maintenance Effectiveness (71111.12Q - 3 samples)
a. Inspection Scope
The inspectors completed three quarterly maintenance effectiveness inspection
samples. The inspectors reviewed performance monitoring and maintenance
effectiveness issues for the three systems listed below. The inspectors reviewed
PSEG's process for monitoring equipment performance and assessing preventive
maintenance effectiveness. The inspectors verified that systems and components were
monitored in accordance with the Maintenance Rule Program requirements. The
inspectors compared documented functional failure determinations and unavailability
hours to those being tracked by PSEG to evaluate the effectiveness of PSEG's condition
monitoring activities and to determine whether performance goals were being met. The
inspectors reviewed applicable work orders, corrective action notifications, and
preventive maintenance tasks. The documents reviewed are listed in the Attachment A.
- Unit 1 and Unit 2, radiation monitors;
- Unit 2, steam generator feed pumps; and
- Unit 1, service water.
b. Findings
Introduction: A self-revealing finding of very low safety significance was identified on
January 21, 2010, because a control system short circuit caused the 21 SGFP to trip.
This caused a turbine runback and ultimately an automatic Unit 2 reactor trip due to low
water level in one of four SGs. The short circuit occurred because technicians did not
use the correct procedure to repair degraded insulation on the barrel of a connector lug
that was identified in the 21 SGFP control system in November 2009. PSEG repaired
the short circuit prior to restart of Unit 2 on January 23, 2010. The issue was entered
into the corrective action program as notification 20448229.
Description: On January 21,2010, the 21 SGFP tripped due to a short circuit between
the normally closed and normally open terminals for the 21 SGFP low suction pressure
trip switch. The short circuit caused a false low suction pressure trip signal that tripped
the 21 SGFP, which caused a turbine run back to 66%. This run back was designed to
lower the steam flow demanded from the SGs to within the capacity of the SGFP that did
not trip. However, on January 21, the reduction in power was not rapid enough and
Salem Unit 2 automatically tripped from 78% power due to low steam generator water
level.
Following the trip technicians identified that the electrical short that caused the trip had
developed between a connector lug barrel and an adjacent wire terminal due degraded
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14
wire insulation on the lug barrel. The technicians also determined that this same short
was previously identified as the cause of the difficulty that operators had resetting the 21
SGFP on November 11, 2009, during the Unit 2 startup after the S2R17 refueling
outage. To address the condition identified in November 2009, the technicians covered
the affected connector lug barrel with electrical tape. This allowed operators to restore
the 21 SGFP to service and continue the Unit 2 start-up. The reset problems for the 21
SGFP repeated again on January 5, 2010, during the Unit 2 plant startup after the
January 3, 2010 plant trip. However, troubleshooting in early January did not identify a
cause for the trip and the 21 SGFP was ultimately successfully reset and restored to
service with no corrective actions completed.
PSEG conducted a root cause investigation after the January 21,2010, trip and
determined the root cause was poor work practices during initial component installation
and subsequent maintenance activities. Specifically, improper orientation of the lug put
the lug barrel and wire terminal in contact with one another, which subsequently caused
the lug barrel insulation to degrade ultimately resulting in the short circuit.
The inspectors determined that the corrective actions taken by technicians when they
originally identified the short between the lug barrel and wire terminal in November 2009,
were not adequate. As stated above, to correct the short, technicians covered the
affected insulation with electrical tape. The inspectors reviewed PSEG procedure
SC.DE-TS.ZZ-2039, "Cable Termination Methods at Salem Generating Station," and
determined that applying tape to the barrels of lugs was not permitted. Therefore, the
corrective actions taken by technicians to address the degraded condition identified in
November 2009, did not meet PSEG procedure requirements and resulted in the
21 SGFP trip that cause the Unit 2 reactor trip on January 21,2010.
PSEGs corrective actions following the January 21, 2010 included performing extent of
condition inspections on the other Unit 2 SGFP panels for degraded insulation no other
deficiencies were identified. Following completion of the root cause analysis additional
extent of condition inspections for connector lug orientation were specified. Unit 1
inspections were completed in April 2010 and no deficiencies were identified. Unit 2
inspections are scheduled for the next refueling outage in 2011. PSEG entered
corrective action issues for this event into the corrective action program as NOTF
20448229.
To improve the reliability of the plant operations in response to a single SGFP trip,
PSEG installed an automatic plant run back feature in the 1990s. The inspectors
confirmed that this feature was not credited in the plant's accident analysis, and
therefore, determined that the failure of the runback to prevent a reactor trip after the 21
SGFP tripped on January 21 was not a safety concern. PSEG's plans to review the
causes of the ineffective runback as part of the response to correction action program
NOTF 20448229.
Analysis: Not performing repairs to the affected 21 SGFP pressure switch lug barrel in
accordance with PSEG SCDE-TS.ZZ-2039, "Cable Termination Methods at Salem
Generating Station," resulted in a short circuit that caused a 21 SGFP trip that resulted in
a Unit 2 reactor trip due to low SG water level. This was a performance deficiency. The
inspectors determined that the performance deficiency was more than minor because it
Enclosure
15
was associated with the human performance attribute of the Initiating Events
cornerstone, and it adversely affected the cornerstone objective to limit the likelihood of
events that upset plant stability and challenge critical safety functions. Specifically, not
following PSEG procedure SC.DE-TS.ZZ-2039 on November 11, 2009, caused the 21
SGFP trip and subsequent automatic reactor trip due to low SG water level on January
21, 2010. The finding was evaluated under IMC 0609, Attachment 4, "Phase 1 - Initial
Screening and Characterization of Findings." The inspectors determined that the finding
is of very low safety significance because it does not contribute to both the likelihood of a
reactor trip and the likelihood that mitigation equipment or functions will not be available.
The inspectors determined that this finding has a cross-cutting aspect in the area of
human performance because PSEG personnel did not follow procedure requirements
while repairing plant equipment. Specifically, technicians applied electrical tape to the
21 SGFP pressure switch connector lug barrel on November 11, 2009, which did not
meet PSEG procedure SC.DE-TS.ZZ-2039, "Cable Termination Methods at Salem
Generating Station," requirements. (HA (b))
Enforcement: Enforcement action does not apply because the performance deficiency
did not involve a violation of a regulatory requirement: FIN 05000311/2010003-02, 21
Steam Generator Feed Pump Trip.
1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13 - 5 samples)
a. Inspection Scope
The inspectors completed five maintenance risk assessment and emergent work control
inspection samples. The inspectors reviewed the maintenance activities listed below to
verify that the appropriate risk assessments were performed as specified by 10 CFR
50.65(a)(4) prior to removing equipmentfor work. The inspectors reviewed the
applicable risk evaluations, work schedules, and control room logs for these
configurations. PSEG's risk management actions were reviewed during shift turnover
meetings, control room tours, and plant walkdowns. The inspectors also used PSEG's
on-line risk monito~(Equipment OOS workstation) to gain inSights into the risk
associated with these plant configurations. The inspectors reviewed notifications
documenting problems associated with risk assessments and emergent work
evaluations. Documents reviewed are listed in the Attachment A.
- Unit 1 and Unit 2, planned unavailability of Unit 1 control room emergency air
conditioning system to support planned maintenance on the 1A 125 VDC electrical
bus on April 7;
- Unit 1, planned unavailability of the 1A EDG and 14 station power transformer during
a RFO on April 8;
- Unit 1, contingency measures to provide alternate power to the 12 spent fuel pool
(SFP) pump during unavailability of the 1B 4kV vital bus on April 12;
- Unit 1, unplanned unavailability of the 1C 4kV vital bus concurrent with planned
unavailability of the 1B EDG and 11 SW header on April 16;
- Unit 2, planned unavailability of the 2A EDG with station blackout Unit 3 out of
service on May 27.
Enclosure
16
b. Findings
No findings of significance were identified.
1R15 Operability Evaluations (71111.15 - 8 samples)
a. Inspection Scope
The inspectors completed eight operability evaluation inspection samples. The
inspectors reviewed the operability determinations for degraded or non-conforming
conditions associated with:
SRA;
- Unit 1 boration flowpath following unplanned unavailability of the 1C 4kV vital bus
while in Mode 6;
- Unit 1 SW system given early installation of restraints on pipe support SWPS-5;
- Unit 1 CCW system during planned unavailability of the 11 CCW HX and biofouling
- Unit 1 AFW piping following discovery of wall thinning of buried piping;
and
The inspectors reviewed the technical adequacy of the operability determinations to
ensure the conclusions were justified. The inspectors also walked down accessible
equipment to corroborate the adequacy of PSEG's operability determinations.
Additionally, the inspectors reviewed other PSEG identified safety-related equipment
deficiencies during this report period and assessed the adequacy of their operability
screenings. Documents reviewed are listed in the Attachment A.
b. Findings
No findings of significance were identified.
1R18 Plant Modifications (71111.18 - 4 samples)
.1 Permanent Modifications
a. Inspection Scope
The inspectors completed two permanent plant modification inspection samples by
reviewing the key characteristics associated with the two permanent plant modifications
described below. The inspectors' review verified that the design bases, licensing bases,
and performance capability of the affected systems were not degraded by the
modifications. The inspectors verified the new configuration was accurately reflected in
the design documentation and that the post-modification testing was adequate to ensure
the structures, systems, and components affected would continue to function properly.
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The inspectors' also interviewed plant staff and reviewed issues that were entered into
the GAP to assess whether PSEG was effective at identifying and resolving problems
associated with the modification process. The 10 GFR 50.59 screening associated with
these permanent plant modifications were also reviewed. The documents reviewed are
listed in the Attachment A.
- The inspectors reviewed the modification package used to replace the section of
buried Unit 1 AFW discharge header piping located between the Unit 1 auxiliary and
containment buildings. PSEG replaced this section of piping because significant
coating degradation and external corrosion and wall thinning was identified on the
piping during inspections conducted in preparation for license renewal.
- The inspectors reviewed the modification package used to replace the Unit 1 PS-1
pressurizer spray valve internals. The purpose of the new design was to provide
better flow control characteristics and reduce the valve's susceptibility to sticking.
b. Findings
No findings of significance were identified .
.2 Temporarv Modifications
a. Inspection Scope
The inspectors completed two plant modification inspection samples by reviewing the
key characteristics associated with the two temporary plant modifications described
below. The inspectors verified that the design bases, licensing bases, and performance
capability of the affected systems were not degraded by the temporary modifications.
The 10 GFR 50.59 screen associated with each modification were also reviewed.
Documents reviewed for this inspection are listed in the Attachment A.
- The inspectors reviewed the modification package used to supply temporary power
to the 12 SFP pump. The modification moved the 12 SFP pump power supply from
the 1 B 460 VAG vital bus to the 1A 460 VAG vital bus to provide SFP cooling
capacity from both the 11 and 12 SFP pumps while the 1B 460 VAG vital bus was
de-energized for planned maintenance.
- The inspectors reviewed the modification package used to plug a Unit 1 feedwater
flow control valve (13BF19) air supply regulator weep hole in order to ensure that full
pressure was used to position the air-operated valve.
b. Findings
No findings of significance were identified.
1R19 Post-Maintenance Testing (71111.19 - 6 samples)
a. Inspection Scope
The inspectors completed six post-maintenance testing (PMT) inspection samples. The
inspectors observed portions of and/or reviewed the PMT results for the maintenance
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activities listed below. The inspectors verified that the effect of testing on the plant was
adequately addressed by control room and engineering personnel; testing was adequate
for the maintenance performed; acceptance criteria were clear, demonstrated
operational readiness and were consistent with design and licensing basis
documentation; test instrumentation calibration was current and the appropriate range
and accuracy for the application; tests were performed, as written, with applicable
prerequisites satisfied; and equipment was returned to an operational status and ready
to perform its safety function. Documents reviewed are listed in the Attachment A.
- Work order (WO) 30156599, preventive maintenance of the 1A vital instrument bus
inverter;
- WO 30171818, planned overhaul of the 1B EDG during Unit 1 RFO;
- WO 60090348, replacement of shaft and pins on 21CCW HX inlet valve, 21 SW
122;
- WO 60090391, replacement of shaft and pins on 22 CCW HX inlet valve, 22 SW
122;
- WO 30152753, preventive maintenance of the 22 AFW pump; and
- WO 60088790, temporary repair of an oil leak on 21 SI pump outboard bearing.
b. Findings
No findings of significance were identified.
1R20 Refueling and Other Outage Activities (71111.20 - 1 sample)
a. Inspection Scope
Unit 1 RFO (S1 R20). The inspectors completed one refueling outage activity inspection
sample. The inspectors observed or reviewed the following RFO activities to verify that
operability requirements were met and that risk, industry experience, the fatigue rule,
and previous site specific problems were considered. Documents reviewed are listed in
the Attachment A.
The inspectors reviewed the schedule and risk assessment documents associated with
S1 R20 to confirm that PSEG appropriately considered risk, operating experience, and
site specific problems in developing and implementing a plan that ensured maintenance
of defense-in-depth systems and barriers. Prior to S1 R20, the inspectors reviewed
PSEG's outage risk assessment to identify risk significant equipment configurations and
determine whether planned risk management actions were adequate. During S1 R20,
the inspectors verified that PSEG managed the outage risk in accordance with the
outage plan.
The inspectors observed portions of the shutdown and cool down processes and
monitored PSEG controls over the outage activities. The inspectors also verified that
cool down rates were within technical specification (TS) limitations. The inspectors
entered containment at the start of the refuel outage to check for evidence of previously
unidentified reactor coolant leakage. Throughout S1 R20, the inspectors made additional
containment entries to inspect for indications of unidentified leakage, damaged
equipment, foreign material control, radiation worker work practices and fire prevention.
Enciosure
19
The inspectors observed portions of refueling activities from the refueling bridge in
containment and the SFP to verify refueling gates and seals were properly installed and
verify that foreign material exclusion boundaries were established around the reactor
cavity. Core offload and core reload activities were periodically observed from the
control room and refueling bridge to verify operators adequately controlled fuel
movements in accordance with approved procedures.
The inspectors verified that tagged equipment was properly controlled and equipment
configured to safely support maintenance work. Specifically, inspectors observed the
control of work activities in the auxiliary building during reduced inventory to verify that
the risk of unplanned equipment unavailability was minimized. Equipment work areas
were periodically observed to determine whether foreign material exclusion boundaries
were adequate.
During control room tours, the inspectors verified that operators maintained adequate
reactor coolant system (RCS) level and temperature and that indications were within the
expected range for the operating mode.
The inspectors verified that offsite and onsite electrical power sources were maintained
in accordance with TS requirements and consistent with the outage risk assessment.
Periodic walk downs of portions of the on-site electrical buses and the EDGs were
conducted during risk significant electrical configurations.
The inspectors verified through routine plant status activities that the decay heat removal
safety function was maintained with the appropriate redundancy as required by TS and
consistent with PSEG's outage risk assessment. During core offload, the inspectors
periodically verified that the fuel pool cooling system was performing in accordance with
plant design parameters and consistent with PSEG's risk assessment for the RFO.
The inspectors observed the Unit 1 RCS draining to a reduced inventory condition on
April 19, 2010. RCS inventory controls and contingency plans were reviewed by
inspectors to verify that they met TS requirements and provided for adequate inventory
control. The inspectors reviewed procedures and observed portions of activities in the
control room when the unit was in reduced inventory modes of operation. The
inspectors verified that level and core temperature measurement instrumentation were
installed and operational. Calculations that provided time to boil information were also
reviewed for RCS reduced inventory conditions as well as the SFP during increased
heat load conditions.
Inspectors verified that PSEG managed fatigue of outage workers by reviewing a
sampling of waiver requests, self declarations, and fatigue assessments that were
available near the end of the RFO. PSEG scheduled covered workers such that
minimum days off for individuals working on outage activities were in compliance with
the fatigue rule. In addition, control room staff for Unit 2 remained on operating unit work
hour controls.
Containment status and procedural controls were reviewed by the inspectors during fuel
offload and reload activities to verify that TS and procedure requirements were met for
containment. Specifically, the inspectors verified that during fuel movement activities,
Enclosure
20
personnel, materials, and equipment were staged to close containment penetrations as
specified in the licensing basis.
The inspectors conducted a thorough walk down of containment prior to reactor startup.
Areas of containment where work was completed were inspected for evidence of
leakage and to ensure debris that could block containment sump screens was removed.
The condition of equipment used for fire detection, prevention, and suppression were
inspected for operability and functionality. Portions of mode changes and reactor startup
were observed and reviewed for compliance with applicable procedures and TS.
b. Findings
No findings of significance were identified.
1R22 Surveillance Testing (71111.22 - 9 samples)
a. Inspection Scope
The inspectors completed nine surveillance testing inspection samples. The inspectors
observed portions of and/or reviewed results for the surveillance tests listed below to
verify, as appropriate, whether the applicable system requirements for operability were
adequately incorporated into the procedures and that test acceptance criteria were
consistent with procedure requirements, the TS requirements, the updated final safety
analysis report (UFSAR), and American Society of Mechanical Engineers (ASME)
Section XI for pump and valve testing. Documents reviewed are listed in the Attachment
A.
- S1.0P-ST.RHR-0005, Residual Heat Removal Valves and Orifices;
- S1.0P-ST.MS-0003, Steam Line Isolation and Response Time Testing;
- S1.0P-ST.TRB-0002, Turbine Protection System - Full Functional Test;
- S1.0P-ST.SJ-0015, Intermediate Head Hot Leg Throttling Valve Flow Balance
Verification;
- SC.MD-DC.RC-0003, Calibration of Pressurizer Safety Relief Valve Indicating
Switches;
- S1.0P-ST.AF-0007, 13 AFW Pump Full Flow Test;
- S2.0P-ST.SJ-0001, Inservice Testing of 21 Safety Injection Pump;
- S1.0P-LR.FP-0001, Type C Leak Rate Test for 1FP147 and 1FP148; and
- S1.0P-LR.CVC-0003, Type C Leak Rate Testfor 1CV116, 1CV284, and 1CV296.
b. Findings
No findings of significance were identified.
1EP6 Drill Evaluation (71114.06 - 1 sample)
a. Inspection Scope
The inspectors completed one drill evaluation inspection sample. On May 18, 2010, the
inspectors observed a drill from the control room simulator during an evaluated
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21
emergency preparedness drill. The inspectors evaluated operator performance relative
to developing event classifications and notifications. The inspectors referenced Nuclear
Energy Institute (NEI) 99-02, "Regulatory Assessment Performance Indicator (PI)
Guideline," Revision 6, and verified that PSEG correctly counted the evaluated
scenario's contribution to the NRC PI for drill and exercise performance.
b. Findings
No findings of significance were identified.
2. RADIATION SAFETY
Cornerstone: Radiation Safety - Public and Occupational
2RS1 Radiological Hazard Assessment and Exposure Controls (71124.01)
a. Inspection Scope
Radiological Hazard Assessment
The inspectors reviewed any changes to plant operations that may result in a significant
new radiological hazard for onsite workers or members of the public. The inspectors
verified PSEG had assessed the potential impact of these changes and implemented
periodic monitoring, as appropriate, to detect and quantify the radiological hazard.
The inspectors reviewed a sample of two completed radiological surveys of selected
plant areas. The inspectors verified that the thoroughness and frequency of the surveys
were appropriate for the given radiological hazard.
The inspectors conducted walk downs of the plant that included radioactive waste
processing, storage, and handling areas to evaluate material conditions and potential
radiological conditions.
The inspectors selected radiological risk-significant work activities that involved
exposure to radiation and were performed during Unit 1's RFO. Activities selected
included: primary steam generator work including eddy current testing, secondary steam
generator work including foreign object search and retrieval, and replacement of the #14
reactor coolant pump motor. The inspectors verified that appropriate pre-work surveys
were performed and were appropriate to identify and quantify the radiological hazard
and to establish adequate protective measures. The inspectors evaluated the
radiological survey program to determine if the following hazards were properly
identified:
- Identification of hot particles;
- The presence of alpha emitters;
- The potential for airborne radioactive materials, including the potential
presence of transuranics and/or other hard-to-detect radioactive materials;
- The hazards associated with work activities that could suddenly and severely
increase radiological conditions; and
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- Severe radiation field dose gradients that can result in non-uniform exposures
to the body.
The inspectors selected three to five air sample survey records and verified that samples
were collected and counted in accordance with PSEG procedures. The inspectors
observed work in potential airborne areas and verified that air samples were
representative of the breathing air zone. The inspectors verified that PSEG has a
program for monitoring levels of loose surface contamination in areas of the plant with
the potential for the contamination to become airborne.
Radiological Hazards Control and Work Coverage
During tours of the facility and review of ongoing work selected in Section 2 (above), the
inspectors evaluated ambient radiological conditions. The inspectors verified that
existing conditions were consistent with posted surveys, radiation work permits (RWPs),
and worker briefings, as applicable.
During job performance observations, the inspectors verified the adequacy of
radiological controls, such as required surveys, radiation protection job coverage, and
contamination controls. The inspectors evaluated PSEG's means of using electronic
pocket dosimeters in high noise areas as high radiation area (HRA) monitoring devices.
The inspectors verified that radiation monitoring devices were placed on the
individual's body consistent with the method that PSEG has employed to
monitor dose from external radiation sources. The inspectors verified that the dosimeter
was placed in the location of highest expected dose or that PSEG was properly
employing an NRC-approved method of determining effective dose equivalent.
For high-radiation work areas with significant dose rate gradients (a factor of 5 or
more), the inspectors reviewed the application of dosimetry to effectively monitor
exposure to personnel. The inspectors verified that PSEG's controls were adequate.
The inspectors reviewed three to five RWPs for work within airborne radioactivity areas
with the potential for individual worker internal exposures. The inspectors evaluated
airborne radioactive controls and monitoring, including potentials for significant airborne
contamination. For these selected airborne radioactive material areas, the inspectors
verified barrier integrity and temporary high-efficiency particulate air ventilation system
operation.
The inspectors examined PSEG's physical and programmatic controls for highly
activated or contaminated materials stored within spent fuel and other storage pools.
The inspectors verified that appropriate controls were in place to preclude inadvertent
removal of these materials from the pool.
The inspectors conducted selective inspection of posting and physical controls for HRAs
and very high radiation areas, to the extent necessary to verify conformance with the
Occupational PI.
Enclosure
23
b. Findings
No findings of significance were identified.
2RS2 Occupational As Low As Reasonably Achievable (ALARA) Planning and Controls
(71124.02)
a. Inspection Scope
Radiological Work Planning
The inspectors obtained from PSEG a list of work activities ranked by actual or
estimated exposure that were in progress and selected three work activities of the
highest exposure significance (listed in Section 2RS1 above).
The inspectors reviewed the ALARA work activity evaluations, exposure estimates, and
exposure mitigation requirements. The inspectors determined that PSEG had
reasonably grouped the radiological work into work activities, based on historical
precedence, industry norms, and/or special circumstances.
The inspectors verified that PSEG's planning identified appropriate dose mitigation
features, considered alternate mitigation features, and defined reasonable dose goals.
The inspectors verified that PSEG's ALARA assessment had taken into account
decreased worker efficiency from use of respiratory protective devices and or heat stress
mitigation equipment. The inspectors determined that PSEG's work planning considered
the use of remote technologies as a means to reduce dose and the use of dose
reduction insights from industry operating experience and plant-specific lessons learned.
The inspectors verified the integration of ALARA requirements into work procedure and
RWP documents.
The inspectors compared the results achieved with the intended dose established in
PSEG's ALARA planning for these work activities. The inspectors compared the person-
hour estimates provided by maintenance planning and other groups to the radiation
protection group with the actual work activity time requirements, and evaluated the
accuracy of these time estimates. The inspectors determined the reasons for any
inconsistencies between intended and actual work activity doses. The inspectors
focused on those work activities with planned or accrued exposure greater than 5
person-rem.
The inspectors determined that post-job reviews were performed and that identified
problems were entered into PSEG's CAP.
b. Findings
No findings of significance were identified.
4. OTHER ACTIVITIES
40A 1 Performance Indicator (PI) Verification (71151 - 6 samples)
Enclosure
24
a. Inspection Scope
The inspectors reviewed PSEG submittals for the Unit 1 and Unit 2 initiating events
cornerstone performance indicators discussed below. To verify the accuracy of the PI
data reported during this period the data was compared to the PI definition and guidance
contained in NEI 99-02, "Regulatory Assessment Performance Indicator Guideline,"
Revision 5.
Cornerstone: Initiating Events
- Unit 1 and Unit 2 unplanned scrams;
- Unit 1 and Unit 2 unplanned scrams with complications; and
- Unit 1 and Unit 2 unplanned power changes.
The inspectors verified the accuracy of the data by comparing it to CAP records, control
room operators' logs, the site operating history database, and key performance indicator
summary records.
b. Findings
No findings of significance were identified.
40A2 Identification and Resolution of Problems (71152 - 1 annual sample; 1 trend sample)
.1 Review of Items Entered into the Corrective Action Program
As required by Inspection Procedure 71152, "Identification and Resolution of Problems,"
and in order to help identify repetitive equipment failures or specific human performance
issues for follow-up, the inspectors performed a daily screening of all items entered into
PSEG's CAP. This was accomplished by reviewing the description of each new
notification and attending daily management review committee meetings. Documents
reviewed are listed in the Attachment A.
.2 Semi-Annual Review to Identify Trends
a. Inspection Scope
As required by Inspection Procedure 71152, "Identification and Resolution of Problems,"
the inspectors performed a review of PSEG's CAP and associated documents to identify
trends that could indicate the existence of a more significant"safety issue. The
inspectors' review was focused on repetitive equipment and corrective maintenance
issues, but also considered the results of daily inspector CAP item screening discussed
in Section 40A2.1. The review included issues documented in system health reports,
corrective maintenance WOs, component status reports, site monthly meeting reports
and maintenance rule assessments. The inspectors' review nominally considered the
six-month period of December 2009 through May 2010, although some examples
expanded beyond those dates when the scope of the trend warranted. The inspectors
compared and contrasted their results with the results contained in PSEG's latest
integrated quarterly assessment report. Corrective actions associated with a sample of
Enclosure
25
the issues identified in PSEG's trend report were reviewed for adequacy. The inspectors
also evaluated the trend report specified in SPP-3.1, Corrective Action Program.
Documents reviewed are listed in the Attachment A.
b. Assessment and Observations
No findings of significance were identified.
The inspectors noted a trend of low level issues entered into the CAP related to
equipment reliability. There were multiple issues with service water flow control valves
and issues with the Unit 1 steam generator flow control regulating valves. The
inspectors also noted deficiencies with the scope, planning, and implementation of long
term equipment preventive maintenance. Some of the preventive maintenance
deficiencies have been corrected through implementation of a performance centered
maintenance plan. PSEG is aware of the issues identified through this trend review and
is appropriately addressing these issues .
.3 Annual Sample: Transformer Load Tap Changer Failures
a. Inspection Scope
The inspectors reviewed PSEG's actions to investigate and identify the cause of the 12
station power transformer load tap changer failure that resulted in a reactor trip on
December 28, 2007. The inspectors also reviewed PSEG's action towards identification
and completion of corrective actions. The inspectors reviewed PSEG's procedures,
vendor documents, notifications, orders, corrective actions, and root cause evaluations
to understand the equipment functions and operational history, as well as the
identification, evaluation, and corrective actions associated with the load tap changer
failures. System engineers and other PSEG staff were interviewed to gain additional
insights on the failures. Documents reviewed are listed in the Attachment A.
b. Findings and Observations
No findings of significance were identified.
The inspectors found that PSEG appropriately identified degraded conditions associated
with load tap changer failures and entered them into the CAP. PSEG's root cause
investigation determined the cause of the load tap changer failure to be inadequate
scope of maintenance procedures on load tap changer internal components and
insufficient performance monitoring of degraded load tap changer conditions. The
investigations revealed severe coking of the selector switch components, Which included
damage to four of the six collector rings, and melted contacts. Inspectors determined
that the evaluations of degraded conditions were thorough and included considerations
for extent of condition. The inspectors reviewed PSEG's corrective actions and
determined that they were appropriate to adequately address identified deficiencies.
40A3 Event Follow-up (71153 - 1 sample)
.1 (Closed) LER 05000311/2010-002-01, Automatic Reactor
Enclosure
26
Trip Due to 21 Steam Generator Feedwater Pump (SGFP) Trip and Steam Generator
Low Level
On January 21, 2010, at 1818 hours0.021 days <br />0.505 hours <br />0.00301 weeks <br />6.91749e-4 months <br />, the 21 SGFP tripped. A turbine runback
automatically initiated as expected and steam generator level in all four steam
generators (SG) lowered. The 22 SG reached the SG low level reactor trip setpoint at
1820 hours0.0211 days <br />0.506 hours <br />0.00301 weeks <br />6.9251e-4 months <br /> resulting in an automatic reactor trip. The turbine runback function initiated
by the loss of 21 SGFP did not prevent a reactor trip as designed; however, this feature
was not credited in the Salem accident analysis and, therefore, was not required to
operate to maintain plant safety. All control rods fully inserted on the trip. All three
AFW pumps started in response to the low SG water level and decay heat was removed
by the steam dumps to the main condenser. Operators entered the emergency
procedures for the plant trip and stabilized the plant in Mode 3.
The cause of the 21 SGFP trip was an internal wiring short in the SGFP control circuit
that resulted in a false low suction pressure trip signal. The cause for the wiring short
was the result of poor work practices. Corrective actions consist of lug inspections,
document changes, training analysis, and evaluation of the integrated plant response to
a SGFP from full power and implementing changes as appropriate. The inspectors
completed a review of this LER and identified one finding of very low safety significance
as documented in Section 1 R12. This LER is closed.
b. Findings
The finding for this event is documented in Section 1R12.
40A5 Temporarv Instruction (TI) 2515/172
a. Inspection Scope
The Temporary Instruction (TI), 2515/172 provides for confirmation that owners of
pressurized-water reactors (PWRs) have implemented the industry guidelines of the
Materials Reliability Program (MRP) -139 regarding nondestructive examination and
evaluation of certain dissimilar metal welds in the RCS containing nickel based Alloys
600/82/182.
During 1R20 PSEG inspected the dissimilar metal weld on the 1" reactor vessel drain
piping with no detected indications. Salem Unit 1 has dissimilar metal welds in the eight
reactor coolant system piping to reactor vessel nozzle safe end welds. No additional
inspections or MSIP applications were performed during 1R20.
This TI requires documentation of specific questions in an inspection report. The
questions and responses are included in this report as Attachment B. I*
I
b. Findings
No findings of significance were identified.
Enclosure
27
40A6 Meetings, Including Exit
The inspectors presented the inspection results to Mr. C. Fricker and other members of
PSEG management at the conclusion of the inspection on July 8, 2010. The inspectors
asked PSEG whether any materials examined during the inspection were proprietary.
No proprietary information was identified.
40A7 Licensee Identified Violations
The following violation of NRC requirements was identified by PSEG. It was determined
to have very low significance (Green) and to meet the criteria of Section VI of the NRC
Enforcement Policy, NUREG-1600, for being dispositioned as a non-cited violation.
PSEG identified general corrosion that reduced the wall thickness of the safety related
piping to less than the design minimum wall thickness of 0.278" for the system design
pressure of 1950 psig. The lowest measured wall thickness was 0.077"; however, a
finite element analysis for the degraded piping demonstrated past operability at a
reduced operating pressure of 1275 psig.
10 CFR 50, Appendix B, Criterion III, Design Control requires in part that measures shall
be established to assure that applicable regulatory requirements and design bases are
correctly translated into specifications, drawings, and instructions and that these
measures shall include provisions to assure the proper selection and review for
suitability of application of materials, parts, equipment, and processes. During pipe
excavation and inspections conducted as part of PSEGs buried piping program PSEG
identified that it did not provide an effective protective coating for the buried section of
AFW piping on Unit 1.
This finding was associated with the mitigating systems cornerstone, specifically the
short term decay heat removal capability. The finding was determined to be Green
because it was a design or qualification deficiency that was confirmed not to result in
loss of operability of the AFW system. PSEG entered this condition into the corrective
action program as notification 20456999.
ATTACHMENT A: SUPPLEMENTAL INFORMATION
ATTACHMENT B: T1172 MSIP DOCUMENTATION QUESTIONS SALEM UNIT 1
Enclosure
A-1
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee personnel:
C. Fricker, Site Vice President
E. Eilola, Plant Manager
L. Rajkowski, Engineering Director
R. DeSanctis, Maintenance Director
J. Garecht, Operations Director
R. Gary, Radiation Protection Manager
J. Higgins, System Engineer
F. Hummel, System Engineer
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened/Closed
05000272/2010003-01 NCV Buried AFW Discharge Piping Not Tested In
Accordance With 10 CFR 50.55a
(Section 1 R08)05000311/2010003-02 FIN 21 Steam Generator Feed Pump Trip.
(Section 1R12)
Closed
05000311/2010-002-01 LER Automatic Reactor Trip Due to 21 SGFP
Trip and Steam Generator Low Level
(Section 40A3.2)
LIST OF DOCUMENTS REVIEWED
In addition to the documents identified in the body of this report, the inspectors reviewed the
following documents and records:
Section 1R01: Adverse Weather Protection
Procedures
SC.OP-AB.ZZ-0001 (0), Adverse Environmental Conditions, Revision 12
SC.OP-PT.ZZ-0002(0), Station Preparations for Seasonal Conditions, Revision 11
Notifications
20377404 20415043 20437093 20437117 20446050 20449579
20465389
Attachment A
A-2
Orders
30120734 30180434 60053920 60081317 60081770 60083588
60083540 60083588 60087645 60087770 60088526 60089636
60090176
Other Documents
2010 Salem Summer Seasonal Readiness Affirmation
WC-AA-107, Seasonal Readiness, Revision 10
Section 1R04: Equipment Alignment
Procedures
S1.0P-SO.CC-0002, 11 & 12 Component Cooling Heat Exchanger Operation, Revision 26
S1.0P-SO.SW-0002, 11 Nuclear Service Water Header Outage, Revision 26
S1.0P-ST.ZZ-0004 (a), 92 Day Locked Valve Verification, Revision 3
S2.0P-SO.DG-0005, Preparation for Removing a Diesel Generator from Service, Revision 5
S2.0P-SO.SW-0005, Service Water System Operation, Revision 40
Drawings
224342 207482 207483 205236 AF-1-2B AF-1-3A
AF-1-2A 205234
Notifications
20458147 20458148 20468758
Other Documents
Tagging Work List 4263810, 12 SW HDR Hardening (11 OUTAGE) 1R20, 04/12/2010 @ 22:09
Section 1R05: Fire Protection
Procedures
FRS-II-433, Salem - Unit 1 (Unit 2) Pre-fire Plan, Auxiliary Feed Water Pumps Area Elevation
84'-0", Revision 6
FRS-II-435, Salem - Unit 1 (Unit 2) Pre-fire Plan, Diesel Fuel Oil Storage Area Elevation 84'-0",
Revision 5
FRS-II-511, Salem - Unit 1 (Unit 2) Pre-fire Plan, Electrical Penetration Area Elevation 78'-0",
Revision 5
Section 1 R07: Heat Sink Performance
Procedures
ER-AA-340, GL 89-13 Program Implementing Procedure, Revision 4
ER-AA-340-1001, GL 89-13 Program Implementing Instructional Guide, Revision 6
ER-AA-340-1003, GL 89-13 Program Pis, Revision 2
Attachment A
A-3
Section 1 ROB: I nservice Inspection
Notifications:
20457869, Control Air Piping Leak'
20462034, Basis AFW Discharge Line Design Pressure'
20461785, Untimely retrieval of Design Documents'
20461255, U2 Containment Liner Blisters'
20459259, U2 Containment Liner Blisters'
20459689, failure to do IWA-5244 pressure tests'
20456999, Guided Wave (GW) pipe wall loss 20% to 44%', in Equipment Apparent Cause
20457854, see Equipment Apparent Cause Evaluation (EQ: ACE) Charter
20457869, Air Line Leak, in Equipment Apparent Cause Evaluation EQ: ACE Charter
20458147, see Equipment Apparent Cause Evaluation (EQ: ACE) Charter
20458148, see Equipment Apparent Cause Evaluation (EQ: ACE) Charter
20458568, see Equipment Apparent Cause Evaluation (EQ: ACE) Charter
20458554, 11 CA HDR Line In Fuel Xfer Area Degraded'
20458761, 1R20 CA Buried Pipe Coating Repair'
20458925, 1R20 SA Buried Pipe Coating Repair'
20457262, (88) 1R20 AF Buried Pipe Inspection Results'
20460624, Need Heat Trace on AF lines in FFT Area
20457877, U1 Containment Liner Corrosion at 78' EI.'
20459259, U1 Corrosion on Containment Liner'
20459303, #14 AF pipe damaged penetration seal'
20459304, #12 AF pipe damaged penetration seal'
20459454, Request for Additional UT Data, 4/18/10 (due to 0.077" reading)'
20344017, Inspect steel liner in 1R19
20235636, NRC noted water running down containment wall
20459189, Question on location of RFO-14 location of a PZR shell weld
20290560, Replace section of 15B FWH shell-S1-R18
20457879, (184) 1R20 FAC(N18) 14# elbow below Tmin
20456828, (66) valve has visible boron buildup 1R20
20459232, Heavy Dry White Boron Vlv Packing (1R20)
20456834, Heavy Dry White Boron Vlv Packing (1 R20)
20456840, Medium Dry White Boron Vlv Packing (1 R20)
20456839, Medium Dry White Boron Vlv Packing (1 R20)
20389147, Recordable lSI Indications on CVC Tank
20344017, Inspect Steel Liner in 1R19 @ Containment Sump
20235636, NRC Noted Water Running Down Containment Wall
20392631, ARMA From lSI Program Audit 2008
20460624, Need Heat Trace on AF lines in FTT Area
20333050, Response to NRC NOV EA-07-149
20322039, 2 nd Interval lSI NRC Violation
20397518, A1CVC-1CV180 Chk Vlv Stuck Open - PI&R review
20444514, Boric Acid Leak from Drain Line - PI&R review
20445314, boron leak - PI&R review
20448241, Minor Packing Leak - BAC - PI&R review
20435861, 21SJ313 Has Boric Acid Leakage - PI&R review
20417331, Boric Acid Leak at 11 CV156 - PI&R review
20411151, Tubing leak on 1SS653 - PI&R review
Attachment A
A-4
20414343, 12 Charging Pump seal inj. Line - PI&R review
20395346, 12 Bat PP Seal Leak - PI&R review
20450330, Containment Liner Corrosion - PI&R review
20385733, Severe Corrosion on FP Valve - PI&R review
20438320, (217) Op Eval. Of Containment Corrosion - PI&R review
20387897, Significant outlet pipe corrosion - PI&R review
20397225, MIC Corrosion Causing Through Wall Leak - PI&R review
20436836, Repair Cracks in Battery Cells - PI&R review
20392145, Update U1 lSI Relief Request Book - PI&R review
20449447, Update Salem Unit 1 ISI10 Yr Plan - PI&R review
20449744, Update Salem Unit 1 Containment lSI 10 Yr Plan - PI&R review
20449442, Update Salem Unit 2 Containment ISI10 Yr Plan - PI&R review
20449554, Salem U2 RF018 lSI Scope - PI&R review
20416605, INPO PSIRV Alloy 600 Program - PI&R review
20404057, Unit 2 lSI (MSIP) - PI&R review
20392631, ARMA FROM lSI PROGRAM AUDIT 2008 - PI&R review
20388065, Water leaking in decon room - PI&R review
20439023, 23 CFCU Head Leakage - PI&R review
20439022, SW Header Leakage 23 CFCU - PI&R review
20389148, 1R19 lSI Weld Exam Limitations - PI&R review
20416605, INPO PSIRV Alloy 600 Program - PI&R review
20449442, Update Salem 2 Containment ISI10 yr. Plan - PI&R review
20449554, Salem Unit 2 RF018 lSI Scope - PI&R review
20449747, Update Salem 2 lSI 10 Yr. Plan - PI&R review
20401542, Perform lSI BMV Exam on RPV Upper Head - PI&R review
20449063, SA U1 Service Inspec - lSI & U1 TI 2515 - PI&R review
20389147, Recordable lSI Indications on CVC Tank - PI&R review
20392145, Update U1 lSI Relief Request Book - PI&R review
20449744, Update Salem U1 Containment ISI10 Yr. Plan - PI&R review
20409943, NRC RIS 2009-04 SG Tube Insp Rqmts - PI&R review
20459851,Section XI Exams Limited to 90% or Less - PI&R review
20450520, Recoat Affected Areas of Liner 2R18 - PI&R review
20457388, Excavation Issues - PI&R review
'Denotes this Notification was generated as a result of this inspection
Section XI Repair/Replacement Samples:
W.O. 60079414, 14" carbon Steel Elbow FAC indication below minimum wall
W.O. 60084266, Salem U1 AF Buried Piping Inspection
W.O. 60089561, 80101381: Replace Aux FW U/G Piping
W.O. 60064104, Repair 15B FWH Area
W.O. 60084375, BACC Program repair to 1PS1
W.O. 60089612, BACC Program repair to S1CVC-14CV392
W.O. 60089615, BACC Program repair to S1 SJ-13SJ25
W.O. 60089848, 80101382 Advanced Work Authorization #2 FDA Replace Aux. Feedwater
Pipe
W.O. 60089561,80101381 Advanced Work Authorization - Replace Aux. FW U/G Piping,
4/9/10
Attachment A
A-5
Non-Code Repair
W.O. 60089848, Repair Non-nuclear, safety related CA Pipe, Unit 1 FTTA
W.O. 60089757, Test Non-nuclear, safety related CA Pipe Repair, Unit 1 FTTA
Miscellaneous Work Orders:
W.O. 60089917, Penetrations for CA & SA Lines, 4/23/10
W.O. 941017262, Activity 04, Excavate and Examine Auxiliary Feedwater Piping, Unit 2,12/94
W.O. 941017262, Activity 03, Excavate and Examine Auxiliary Feedwater Piping, Unit 2,12/94
W.O. 941017262, Activity 02, Excavate and Examine Auxiliary Feedwater Piping, Unit 2, 12/94
W.O. 941017262, Activity 01, Excavate and Examine Auxiliary Feedwater Piping, Unit 2, 12/94
W.O. 60089561, Flush New AFW piping 12 and 14
Drawings & Sketches:
205236A8761-54, Salem Nuclear Generating Station, Unit No.1, Auxiliary Feedwater
Salem Unit 1 Aux Feed Piping, Allan Johnson, 4/10/10
80101381RO, Buried Pipe, Replaced AFW Piping Arrangement
207483A8923-11, Salem Nuclear Generating Station, Unit No.1 - Reactor Containment
Auxiliary Feedwater, Plans & Sections - Elev. 78' 10" & 100' 0", Mechanical
Arrangement, Revision 8, 9/31/86
207483A8923-28, Sheet 1 of 4, Salem Nuclear Generating Station, Unit No.1 - Reactor
Containment Auxiliary Feedwater, Plans & Sections - Elev. 84',Mechanical
Arrangement, Revision 8, 9/31/86
207483A8923-31, Sheet 2 of 4, Salem Nuclear Generating Station, Unit No.1 - Reactor
Containment Auxiliary Feedwater, Plans & Sections - Elev. 84', Mechanical
Arrangement, Revision 8, 9/31/86
207483A8923-28, Sheet 3 of 4, Salem Nuclear Generating Station, Unit No.1 - Reactor
Containment Auxiliary Feedwater, Plans & Sections - Elev. 84',Mechanical
Arrangement, Revision 8, 9/31/86
207483A8923-30, Salem Nuclear Generating Station, Unit No.1 - Reactor
Containment Auxiliary Feedwater, Plans & Sections - Elev. 84',Mechanical
Arrangement, Revision 8, 9/31/86
20761 OA8896-12, Salem Nuclear Generating Station, Unit No.1 - Auxiliary Building & Reactor
Containment Compressed Air Piping, Aux. Building EI. 84 East & React. Contain. EI. 78,
Mechanical Arrangement, Revision 8, 9/31/86
Design Change Packages/Equivalent Change Packaqes
80101382, Revision 2, Replace Salem Unit 1 AFW Piping from the Unit Mechanical Penetration
Area EI. 78'-0" to the Unit 1 Fuel Transfer Tube Area EI. 100'-0"
80101381, Revision 1, Replace in-kind the Salem Unit 1 AF Piping that runs underground from
the Unit 1 Fuel Transfer Tube Area to the Unit 1 Main Steam Outer Penetration Area
50.59 Applicability Reviews, Screenings & Evaluations
80101382; Salem Unit 1 12/14 AF Piping Reroute; 4/24/10
Attachment A
A-6
System & Program Health Reports & Self-Assessments:
Salem Boric Acid Corrosion Control Program Focused Area Self-Assessment, 1/2010
70106830, Salem S1R20 NRC lSI Inspection Check-In Self Assessment
70095327, Salem Boric Acid Corrosion Control Program Focused Area Self-Assessment,
4/29/09
Program Documents
PSEG Nuclear Salem Units 1 & 2, Alloy 600 Management Plan, Long Term Plan (LTP),
Revision 2, Integrated Strategic Plan For Long Term Protection from Primary Water
Stress Corrosion Cracking (PWSCC), 10/15/09
ASME,Section XI, 1998 Edition, 2000 Addenda, IWA-5244 Buried Components
OAR-1, Owner's Activity Report, #S1 RF019, 1/15/09
Procedures
DETAILED AND GENERAL, VT-1 AND VT-3 VISUAL EXAMINATION OF ASME CLASS MC
AND CC CONTAINMENT SURFACES AND COMPONENTS
SH.RA - AP.ZZ - 8805(Q) - Revision 4, 8/31/06; Boric Acid Corrosion Management Program
ER - AP - 331, Revision 4, Boric Acid Corrosion Control (BACC) Program
ER - AP - 331 - 1001, Revision 2, Boric Acid Corrosion Control (BACC) Inspection Locations,
Implementation And inspection Guidelines
ER - AP - 331 - 1002, Revision 3, Boric Acid Corrosion Control (BACC) Program Identification,
Screening, and Evaluation
ER - AP - 331 - 1003, Revision 1, RCS Leakage Monitoring And Action Plan
ER - AP - 331 - 1004, Revision 2, Boric Acid Corrosion Control (BACC) Program Training and
Qualification
ER - AA - 330 - 001, Revision 7, SECTION XI PRESSURE TESTING
LS - AA - 125, Revision 13; Corrective Action Program (CAP) Procedure
LS - AA - 120, Revision 8; Issue Identification And Screening Process
SH.RA-IS.zZ-0005(Q)-Revision 6; VT-2 Visual Examination Of Nuclear Class 1, 2 and 3
Systems
SH.RA-IS.zZ-0150(Q) - Revision 8, 10/19/04; Nuclear Class 1, 2, 3 and MC Component
Support Visual Examination
OU-AP-335-043, Revision 0; BARE METAL VISUAL EXAMINATION (VEl OF CLASS 1 PWR
COMPONENTS CONTAINING ALLOY 600/82/182 AND CLASS 1 PWR REACTOR
VESSEL UPPER HEADS
OU-AA-335-015, Revision 0; VT 2 - VISUAL EXAMINATION
Areva NP, Inc., Engineering Information Record 51-9118973-000; Qualified Eddy Current
Examination Techniques for Salem Unit 1 Areva Steam Generators, 10/15/09
AREVA NP 03-9123233, Revision 000,10/13/09; Salem Unit 2 RVCH Flange Repair
SC.MD-GP.ZZ-0035(Q) - Revision 9, PRESSURE TESTING OF NUCLEAR CLASS 2 AND 3
COMPONENTS AND SYSTEMS, 02/02/10
SH.MD-GP.ZZ-0240(Q) - Revision 10, SYSTEM PRESSURE TEST AT NORMAL OPERATING
PRESSURE AND TEMPERATURE, 7/29109
S2.0P-AF-0007(Q)-Revision 20, 12/23/09; INSERVICE TESTING AUXILIARY FEEDWATER
VALVES, MODE 3
ER-AA-5400-1002, Revision 1, BURIED PIPING EXAMINATION GUIDE
Specification No. S-C-MPOO-MGS-0001; Piping Schedule SPS54, Auxiliary Feedwater,
Revision 6
PSEG Test Procedure 10-H-8-R1, Unit 2 Auxiliary Feedwater 2100/2150 Hydro; 9/21/78
Attachment A
A-7
NDE Examination Reports & Data Sheets
003753, VT-10-113, PRV nozzle sliding support
003754, VT-1 0-114, RPV nozzle sliding support
006325, UT-10-041 , PZR longitudinal shell weld J (100%)
007500, UT-10-132, PZR surge line nozzle (100%)
007901, UT -10-028, 13 SG lower head to tubesheet weld (67%)
006073, VE-10-026, CRDM TO VESSEL PENETRATION WELD, 4/12/10
008001, VE-10-027, 31-RCN-1130-IRS
008026, VE-10-028, 29-RCN-1130-IRS
009070, VE-10-030, 12-STG Channel Head Drain (100%)
033300, UT-10-027, 4-PS-1131-27 (100%)
033200, UT-10-029, 4-PS-1131-26 (100%)
033100, UT-10-032, 4-PS-1131-25 (100%)
032300, UT-10-033, 4-PS-1131-17 (100%)
031700, UT-10-040, 4-PS-1131-12 (100%)
032600, UT-10-034, 4-PS-1131-20 (100%)
047600, UT-10-045, 29-RC-1140-3 (100%)
051200, UT-10-048, 29-RC-1120-3 (100%)
203901, UT-10-047, 32-MSN-2111-1 (100%)
204001, UT-10-046, 16-BFN-2111-1 (70.64%)
210586, UT-10-025, 14-BF-2141-19 (100%)
210588, UT-10-024, 14-BF-2141-20 (100%)
836300, IWE: VT-10-338, PNL-S1-343-1
836400, IWE: VT-10-333, ALK-S1-100-tubing
840000, IWE: Vert Leak Channels 1 -14
006073, VE-10-026, RPV Upper Head Inspection
006051, PT-10-004, CRDM Housing Weld Exams, penetrations #66, 67, and 72
Salem Unit 1, VT-2, Visual Examination Record, 12/14 AF FDA, W.O. 60089848, 4/26/10 (VT)
Salem Unit 1, VT-2, CA Repair Snoop Test, W.O. 60089575, 4/27/10
Salem Unit 1, UT, W.O. 60084266, Yard AF, 4/18/10
Salem Unit 2, UT, W.O.60089851, Exam of containment liner
Salem Unit 1, UT 1-SGF-31-L2 FW elbow below min. wall
Salem Unit 1, UT, W.O. 30176541, 1-SGF-31-L2 FW elbow below min. wall
Salem Unit 1, UT, W.O. 60084266, AFW .
Order 50113214, ST 550D, Surveillance: lSI Perform PORV Check
Order 50118090, ST 550D, Surveillance: OPS Perform PORV Check
W.O. 60089848, VT-2 Visual Examination Record, 12/14 AFW in FDA, 4126/10
W.O. 941017262, Activity 02; Salem Unit 2, Excavate and Examine Auxiliary Feedwater Piping,
12/2/94
W.O. 60084266, UT Unit 1 AFW (thinnest area), 4/20/10
UT Analysis, Component 1-SGF-31-L2 (14" FW Elbow below Minimum wall), 4/10/10
W.O. 60089851, Unit 2 Containment Liner blister UT measurements, 4/21/10
W.O. 60086175, Unit 1 Containment corrosion 78' elevation
W.O. 60084266, Unit 1 AFW piping UT measurements, 4/12/10
W.O. 30176541, Unit 1 AFW piping UT measurements, 4/12/10
W.O. 60084266, Unit 1 AFW piping UT measurements, 4/7/10
W.O. 60084266, Unit 1 AFW piping UT measurements, 4/5/10
W.O. 60084266, Unit 1 AFW pipe UT measurements at supports, 4/18/10
W.O. 30176541, Unit 1 CA piping UT measurements in FDA
401600, VE-04-198; Hope Creek system pressure test CST to HPCI/RCIC and Core Spray,
Attachment A
A-8
11/5/04
VT-2, Salem Unit 1 AF 12 & 14 Pressure Test, 4/25/10
W.O. 60089661, UT measurements, Unit 2 AFW Piping #24 in FTTA, 4/25/10
W.O. 60089661, UT measurements, Unit 2 AFW Piping #22 in FTTA, 4/26/10
Eddy Current Testing Personnel Qualification Records
A2421 2509981330193 L8267
B8731 K5858 F3453
B0500 1007951330114 T5616
B5127 L9168 R9311
B5128 L4332 G4943
B2576 F7460 C5542
F3961 F0037 F0075
C1560 3107943330158 F6623
D7895 6206070744 F3453
D9573 6507061922 G4943
D6502 1803983330125 G1311
H2039 2709977301226 H7791
K5380 P5304 J9141
M9460 P4006 M0950
E0427 R4201 M2665
M6664 R6452 M7006
B4260 R8002 M9459
A3502 S7752 M7007
J9815 T8251 M9082
P5436 V3197 N7035
M6042 R4142 N9952
B8589 R6279 R9311
B4014 G3380 . S9098
G2573 B3720 T5616
V8530 R6900 T5565
W3368 A9608 W2639
M4305 N2574 W7912
B4052 13805 K6975
C2028 T2170 G3910
C4596 N4815 H0268
C3340 M0945 L3025
D3858 P2963 P1465
H6267 M9715 B8079
H0282 K1903 G1756
14048 D5318 C8071
J1978 W6070 6410058746
2010983302133 M5096 B5371
P6459 J1945 H2131
R0830 L4588 2909965330076
R1164 C8042
S0608 N5330
Attachment A .
A-9
Engineering Analyses & Calculations & Standards
Calculation 6S0-1882, Revision 1, 8/30/96; Qualification of Safety-Related Buried Commodities
For Tornado Missle and Seismic Evaluation
Calculation No. S-C-AF-MDC-1789; Salem Auxiliary Feedwater Thermal Hydraulic Flow Model,
10/4/00
70087436, Steam Generator Degradation & Operational Assessment Validation, Salem Unit 1
Refueling Outage 18 (1R18) & Cycles 19/20, 9/2008
51-9052270-000, Update - Salem Unit 1 SG Operational Assessment At 1R18 For Cycles 19
and 20, 10/1/08
51-9048311-002, Salem Unit 1 SG Condition Monitoring For 1R18 And Preliminary Operational
Assessment For Cycles 19 and 20, 10/30/07
701086998-0050, Maximum Pressure in Underground Auxiliary Feedwater Piping
60089575-130, Past Operability Determination for the leak in the one inch air line to air operated
valves in Unit 1 South Penetration Area
70109233/20459231; Boric Acid evaluation of leakage from S1 CVC-1 CV277
70109232/20459230; Boric Acid evaluation of leakage from S1 CVC-1 CV2
70109230/20459228; Boric Acid evaluation of leakage from S2RC-1 PS1
70109234/20459232; Boric Acid evaluation of leakage from S1SJ-13SJ25
70108698/30, Operating Experience Report for degraded Unit 1 AFW piping
51-9135923-000, AREVA; Salem unit 1 SG Condition Monitoring For 1 R20 and Preliminary
Operational Assessment For Cycles 21 And 22, 4/20/10
SA-SURV-201 0-001, Revision 1; Risk Assessment of Missed Surveillance - Auxiliary
Feedwater discharge line underground piping pressure testing, 4/23/10
CQ9503151526; SCI-94-0877, EXCAVATED AUXILIARY PIPING WALKDOWN/DISPOSITION
OF COATING REQUIREMENTS; 12/16/94
Specification No. S-C-M600-NDS-019, COATINGS INTERIOR/EXTERIOR SURFACES
CARBON STEEL SERVICE WATER PIPING, NO. 12 COMPONENT COOLING HEAT
EXCHANGER ROOM AUXILIARY BUILDING (ELEVATION 84)
Structural Integrity Associates, Inc. Calculation File No.1 000494.301, Evaluation of Degraded
Underground Auxiliary Feedwater Piping (Between Unit 1 FTTA and OPAl, 4/23/10
Technical Evaluation 60089575-0140, Acceptability of CA Piping in the Fuel Transfer Area,
4/29/10
Technical Evaluation 60089848-0960, Auxiliary Feedwater Piping Missle Barrier Exclusion,
4/29/10
Structural Integrity Associates, Inc. Calculation File No.1 000498.301, Evaluation of Thinned
Feedwater Elbow, 4/22/10
Technical Evaluation 70108698-0050, Maximum Pressure in Underground Auxiliary Feedwater
Piping, 4/29/10
SPECIFICATION NO. S-C-MPOO-MGS-0001, Piping Schedule SPS54 AUXILIARY
FEEDWATER, Revision 6
OpEval. #10-005, Salem Unit 2 Operability Evaluation, Received 5/18/10
Technical Evaluation 60084266-105-20, Alternative Exterior Coatings for Buried Piping, AF, CA,
SA and Pipe Supports Under W.O. 60084266, 4/2/10
Technical Evaluation H-1-EA-PEE-1871, Hope Creek Service Piping Coatings Alternatives,
80075587, Revision 0,10/15/04
PSEG Nuclear, LLC, Technical Standard, Coating Systems and Color Schedules, Revision 5,
4/3/06
Attachment A
A-10
Weld Records AFW Piping Repair (W.O. #'s 60084266. 60089561, 60089798, 60089848)
Multiple Weld History Record: 74626
Multiple Weld History Record: 74556
Multiple Weld History Record: 74557
Multiple Weld History Record: 74558
Multiple Weld History Record: 74559
Multiple Weld History Record: 74560
Multiple Weld History Record: 74561
Multiple Weld History Record: 74562
Multiple Weld History Record: 74563
Multiple Weld History Record: 74564
Multiple Weld History Record: 74565
Multiple Weld History Record: 74566
Multiple Weld History Record: 74567
Multiple Weld History Record: 74627
Multiple Weld History Record: 74569
Multiple Weld History Record: 74599
Multiple Weld History Record: 74623
Multiple Weld History Record: 74600
Multiple Weld History Record: 74630
Multiple Weld History Record: 74622
Multiple Weld History Record: 74578
Multiple Weld History Record: 74596
Multiple Weld History Record: 74601
Multiple Weld History Record: 74602
Multiple Weld History Record: 74603
Multiple Weld History Record: 74604
Multiple Weld History Record: 74605
Multiple Weld History Record: 74598
Multiple Weld History Record: 74606
Multiple Weld History Record: 74607
Multiple Weld History Record: 74608
Multiple Weld History Record: 74609
Multiple Weld History Record: 74610
Multiple Weld History Record: 74611
Multiple Weld History Record: 74612
Multiple Weld History Record: 74613
Multiple Weld History Record: 74614
Multiple Weld History Record: 74615
Multiple Weld History Record: 74597
Multiple Weld History Record: 74616
Multiple Weld History Record: 74579
Multiple Weld History Record: 74580
Multiple Weld History Record: 74581
Multiple Weld History Record: 74582
Multiple Weld History Record: 74583
Multiple Weld History Record: 74595
Multiple Weld History Record: 74584
Multiple Weld History Record: 74585
Attachment A
A-11
Multiple Weld History Record: 74586
Multiple Weld History Record: 74587
Multiple Weld History Record: 74588
Multiple Weld History Record: 74589
Multiple Weld History Record: 74590
Multiple Weld History Record: 74591
Multiple Weld History Record: 74592
Multiple Weld History Record: 74593
Multiple Weld History Record: 74577
Multiple Weld History Record: 74625
Multiple Weld History Record: 74574
Multiple Weld History Record: 74624
Multiple Weld History Record: 74573
Multiple Weld History Record: 74572
Multiple Weld History Record: 74570
Multiple Weld History Record: 74571
Multiple Weld History Record: 74623
Multiple Weld History Record: 74622
Multiple Weld History Record: 74621
Multiple Weld History Record: 74537
Multiple Weld History Record: 74538
Multiple Weld History Record: 74537
Welder Stamp Number: P-664
Welder Stamp Number: P-65
Welder Stamp Number: P-466
Welder Stamp Number: P-57
Welder Stamp Number: E-64
Welder Stamp Number: P-710
Welder Stamp Number: P-207
Welder Stamp Number: P-666
Welder Stamp Number: P-708
Welder Stamp Number: E-89
Welder Stamp Number: P-84
Welder Stamp Number: P-228
Surface Exam Record: 60089561-0041
Surface Exam Record: 60089848-0001
Surface Exam Record: 60089848-0001
Surface Exam Record: 60089561-0041
Surface Exam Record: 60089561-0860
Miscellaneous Documents
Salem Unit 1 & Salem Unit 2 Technical Specification, 3.4.11 STRUCTURAL INTEGRITY, ASME
CODE CLASS 1, 2 AND 3 COMPONENTS
Electric Power Research Institute (EPRI), Steam Generator Integrity Assessment Guidelines,
Technical Report 1012987, Revision 2, July 2006
NRC Letter dated 3/11/91; FIRST TEN-YEARINSPECTION INTERVAL, INSERVICE
INSPECTION PROGRAM RELIEF REQUEST, SALEM NUCLEAR GENERATING
STATION, UNIT 1 (TAC NOS. 66013 AND 71101)
Attachment A
A-12
PSEG Nuclear, Salem Unit 1 & 2 Alloy 600 Management Plan, Long Term Plan (LTP), Revision
2,10/15/09
Salem Unit 1 - Buried Piping Risk Ranking
MPR Associates Report, Technical Input To Operability of Potential Containment Liner
Corrosion, Revision 0, 10/30109
Transmittal of Design Information #S-TODI-201 0-0005, 4/20/2010
Transmittal of Design Information #S-TODI-201 0-0004, 4/16/2010
00950315126, PSEG Itr. Dated 12/16/94; Excavated Auxiliary Feedwater Piping
Walkdown/Disposition of Coating Requirements
PSEG letter LR-N07-0224 dated 9/13/2007; REPLY TO NOTICE OF VIOLATION EA-07-149
UNTAGGING WORKLIST 4274446, 14 AF Underground Piping 1R20, 4/30/10
UNTAGGING WORKLIST 4274351, 12 AF Underground Piping 1 R20, 4/30/10
Section 1 R 11: Licensed Operator Regualification Program
Procedures
TO-AA-301, Simulator Configuration Management, Revision 13
2-EOP-TRIP-1, Reactor Trip or Safety Injection, Revision 27
2-EOP-TRIP-2, Reactor Trip Response, Revision 27
Section 1R12: Maintenance Effectiveness
Procedures
ER-AA-310, Implementation of the Maintenance Rule, Revision 7
ER-AA-310-1001, Maintenance Rule - Scoping, Revision 4
ER-AA-310-1003, Maintenance Rule - Performance Criteria Selection, Revision 4
ER-AA-310-1004, Maintenance Rule - Performance Monitoring, Revision 7
ER-AA-310-1005, Maintenance Rule - Dispositioning Between (a)(1) and (a)(2), Revision 7
Notifications
20442453 20456501 20465774 20416718 20409963 20406324
20447948 20373131 20382756 20417863 20377572 20437243
20381571 20444082 20409557
Orders
70104875 70106673 70108607 70108825 70108907 70097082
Other Documents
Salem Nuclear Generating Station Maintenance Rule System Function and Risk Radiation
Monitoring Report, dated May 26, 2010
Salem 1 Narrative Log, dated May 26, 2010
Salem 2 Narrative Log, dated May 26, 2010
Salem 1 and Salem 2, System Health Report (04-2009), Radiation Monitoring System
Section 1R13: Maintenance Risk Assessments and Emergent Work Control
Procedures
S1.0P-S0.4KV-0002, 1B 4KV Vital Bus Operation, Revision 33
S1.0P-SO.SF-0002, Spent Fuel Cooling System Operation, Revision 20
OU-AA-103, Shutdown Safety Management Program, Revision 12
Attachment A
A-13
SC.OM-AP.ZZ-0001, Shutdown Safety Management Program - Salem Annex, Revision 4
ER-AA-600-1016, ORAM-Sentinel and Paragon Tool Update, Revision 6
S1.0P-ST.4KV-0001, Electrical Power Systems 4KV Vital Bus Transfer, Revision 13
S1.0P-AB.4KV-0003, Loss of 1C 4KV Vital Bus, Revision 8
S1.0P-AB.460-0003, Loss of 1C 460/230V Vital Bus, Revision 7
S1.MD-FR.SF-0001, Alternate Power Source for No. 11 & 12 Spent Fuel Pool Cooling Pumps,
Revision 6
Drawings
203049 203110 203111 203112 203113 203072
Notifications
20458435 20459055 20459059
Other Documents
Salem Unit 1 Shutdown Risk Status Sheet, April 5, 2010 @ 17:00
SGS Unit 2 PRA Risk Evaluation Form for Work Week 014 (March 28 to April 3, 2010), Revision
2
SGS Unit 2 PRA Risk Evaluation Form for Work Week 015 (April 4 to 10, 2010), Revision 0
Salem Unit 1 Shutdown Risk Status Sheet, April 8, 2010 @ 17:00
Tagging Work List 4265994,12 SFP Pump Alt Feed 1R20, April 12, 2010 @ 19:11
SOD-201 0-013, Salem Operations Directive re: Mid-loop Operations, dated April 16, 2010
Salem 1 Narrative Log, dated April 16, 2010
Section 1R15: Operability Evaluations
Procedures
S1.0P-ST.CVC-0008, Reactivity Control Systems - Boration, Revision 7
S1.0P-ST.CVC-0009, Reactivity Control Systems - Boration, Revision 18
S1.MD-ST.SW-0002, Service Water Bays 1 and 3 Outage Inspection and Repair, Revision 4
S1.0P-ST.4KV-0001, Electrical Power Systems 4KV Vital Bus Transfer, Revision 13
S1.0P-AB.4KV-0003, Loss of 1C 4KV Vital Bus, Revision 8
S 1. OP-AB.460-0003, Loss of 1C 460/230V Vital Bus, Revision 7
S1.0P-AB.SG-0001(Q), Steam Generator Tube Leak, Revision 19
S2.0P-PM.CC-0021(Q), 21 Component Cooling Heat Exchanger High Flow Flush and
Alignment, Revision 19
Drawings
223678 223677 223676
Notifications
20435078 20456624 20456318 20153925 20457213 20457563
20457677 20459689 20462034 20461785 20459454 20459204
20458761 20458925 20463859 20463695 20460078 20460278
20464903 20460285
Orders
70108864 70110454 70109482 70108698 70109522
Attachment A
A-14
Other Documents
Calculation Number 267747, Service Water Pumphouse Piping - Bay 1, Revision 9
SWPS-0005, Design Calculation for SWPS-5, Revision 2
SA-SURV-201 0-001, Risk Assessment of Missed Surveillance - Auxiliary Feedwater Discharge
Line Underground Piping Pressure Testing, Revision 1
Section 1R18: Plant Modifications
Procedures
S1.MD-FR.SF-0001, Alternate Power Source for No. 11 & 12 Spent Fuel Pool Cooling Pumps,
Revision 6
Design Changes
Design Change No. 80098748, Modify Pressurizer Spray Valve Internals, Revision 0
Notifications
20458361 20466937
Drawings
D-401193, Revision 1 D-401194, Revision 5
Orders
70104696 80101774
Other Documents
S2010-183, 50.59 Screening for TCCP 1ST-012, Revision 0
TCCP 1ST1 0-012, Plug 13BF19-AO Air Supply Regulator Weep Hole, Revision 0
Section 1R19: Post-Maintenance Testing
Procedures
MA-AA-716-012, Post Maintenance Testing, Revision 14
SC.MD-PM.115-0001, 10/12 KVA Vital Instrument Bus Inverter Preventive Maintenance,
Revision 12
S1.0P-ST.4KV-0002, Electrical Power Systems AC Distribution, Revision 22
S2.0P-PM.CC-0022(Q), 22 Component Cooling Heat Exchanger High Flow Flush and
Alignment, Revision 16
SC.MD-PM.SW-0010(Q), Disassembly, Inspection and Repair of Masoneilan Butterfly Valve
Mark # AA-103, Revision 2
S2.0P-PM.CC-0021 (Q), 21 Component Cooling Heat Exchanger High Flow Flush and
Alignment, Revision 19
SH.IC-GP.ZZ-0003(Q), Removal and Installation of Masoneilan Domotor Actuator, Revision 2
S2.0P-ST.AF-0002(Q), Inservice Testing - 22 Auxiliary Feedwater Pump, Revision 18
S2. OP-ST.SJ-0001 (Q), Inservice Testing - 21 Safety Injection Pump, Revision 19
Notifications
20296405 20463859 20464983 20463639 20463658
Orders
30156599 30152753 60090391 60090348 60088790
Attachment A
A-15
Drawings
A-6207
Other Documents
1A VIB Inverter, Rectifier Inverter Parts Replacement & Test Plan
1A VIB Inverter, Regulator & Static Switch Parts Replacement & Test Plan
Salem 2 Narrative Log, dated May 10, 2010
Salem 2 Narrative Log, dated May 19, 2010
Prompt Investigation Report, 21 CC Heat Exchanger Unexpected Low Flow during High Flow
Flush
Salem 2 Narrative Log, dated May 21,2010
PMI Tool, Template for 21 SW122
Section 1 R20: Refueling and Outage Activities
Procedures
S1.0P-SO.RC-0006(Q), Draining the Reactor Coolant System <101 Ft. Elevation with Fuel in
the Vessel, Revision 26
S1.0P-IO.ZZ-0005(Q), Minimum Load to Hot Standby, Revision 18
S1.0P-IO.ZZ-0006(Q), Hot Standby to Cold Shutdown, Revision 33
Notifications
20453674 20461909 20460492 20460347 20460313 20453797
Orders
70107017
Other Documents
Fatigue Assessments and Waivers, January 1, 2010 - April 21, 2010
ORAM Contingency Plan, RCS at Mid-Loop Post-Refueling
1R20 Outage Risk Assessment Report, Initial Schedule Approval, Revision 0
Salem 1R20 Level 2 with Operations Testing Chart
Salem 1R20 Major Work Scope List
Section 1R22: Surveillance Testing
Procedures
S1.0P-ST.RHR-0005, Residual Heat Removal Valves and Orifices, Revision 6
S1.0P-ST.MS-0003, Steam Line Isolation and Response Time Testing, Revision 9
S1.0P-ST.TRB-0002, Turbine Protection System - Full Functional Test, Revision 17
S1.0P-ST.MS-0002, Inservice Testing - Main Steam and Feedwater Valves, Revision 11
ER-AA-321, Administrative Requirements for Inservice Testing, Revision 10
S1.0P-ST.SJ-0015, Intermediate head Hot Leg Throttling Valve Flow Balance Verification,
Revision 18
S1.MD-AP.ZZ-0012, Salem Mode Change Requirements, Revision 14
SC.MD-DC.RC-0003, Calibration of Pressurizer Safety Relief Valve Indicating Switches,
Revision 5
S1.0P-LR.FP-0001(Q), Type C Leak Rate Test 1FP147 and 1FP148, Revision 0
S1.0P-LR.CVC-0003(Q), Type C Leak Rate Test 1CV116, 1CV284 and 1CV296, Revision 0
S2.0P-ST.SJ-0001(Q), Inservice Testing - 21 Safety Injection Pump, Revision 19
S1.0P-ST.AF-0007(Q), Inservice Testing Auxiliary Feedwater Valves Mode 3, Revision 19
Attachment A
A-16
S1.RA-ST.AF-0007(0), Inservice Testing Auxiliary Feedwater Valves Mode 3 Acceptance
Criteria, Revision 7
Drawings
EHC-1: Simple EHC, Revision2
Notifications
20321206 20460597 20461042 20458712 20457236 20458026
20444513 20462371 20462544 20456929
Other Documents
PR #971003209, MSIV Emergency Hydraulic Override Not Tested
Salem 2 Narrative Log, dated April 24, 2010
Salem 2 Narrative Log, dated May 8,2010
Adverse Condition Monitoring and Contingency Plan, 21 Safety Injection Outboard Bearing
Housing Oil Leak Rate
Section 1EP6: Drill Evaluation
Procedures
NC.EP-EP-0102, Emergency Coordinator Response, Revision 14
1-EOP-TRIP-1, Reactor Trip or Safety Injection, Revision 26
Other Documents
Emergency Preparedness NRC Graded Exercise S1 0-03 Critique Report
Salem Event Classification Guides
SGS EALIRAL Technical Basis, Salem Generating Station Emergency Action Level/Reporting
Action Level Technical Basis Document, Revision 8
S10-03, Salem Graded Exercise Scenario Synopsis
Section 2RS1: Radiological Hazard Assessment and Exposure Controls
Other Documents
Radiation Work Permit #1 Tasks: 4040; 1210404; 23; 27
Section 2RS2: Occupational ALARA Planning and Controls
Other Documents
Daily ALARA Dose Summary Reports, 1 R20, dated April 12-16, 2010
ALARA Reviews: 1/4040; 1/1210404; 1/23; 1/27
Section 40A1: Performance Indicator Verification
Other Documents
Salem 1 and Salem 2, 10/2010 Performance Indicators, Unplanned Scrams per 7000 Critical
Hrs
Salem 1 and Salem 2,10/2010 Performance Indicators, Unplanned Power Changes per 7000
Critical Hrs
Salem 1 and Salem 2,10/2010 Performance Indicators, Unplanned Scrams with Complications
Attachment A
A-17
Section 40A2: Identification and Resolution of Problems
Procedures
SC.MD-PM.13-0003(Q), Westinghouse 13/4KV Power Transformers 11,12 & 21 Preventive
Maintenance, Rev. 4
Notifications
20329373 20330305 20342653 20350143 20370234 20430448
20443177 20443537
Orders
70078697 70101758
Other Documents
Nuclear Oversight Assessment Report, January thru April 2010
Salem Top Ten Low Margin Issues List, Approved June 9, 2010
Salem Critical Component Failure Clock, dated June 18, 2010
Level 1 - 4 Notifications List, December 2009 - May 2010
Salem Top 10 Equipment Issues List, dated May 4, 2010
Salem Units 1 and 2 40 Non-Outage List, dated June 18, 2010
LIST OF ACRONYMS
ADAMS Agency-wide Documents Access and Management System
ALARA As Low As Reasonably Achievable
AOV Air Operated Valve
CAP Corrective Action Program
CC Component Cooling
CCW Component Cooling Water
CFR Code of Federal Regulation
EDG Emergency Diesel Generator
ESOC Electrical System Operations Center
GL Generic Letter
HX Heat Exchanger
IMC Inspection Manual Chapter
NCV Non-cited Violation
NEI Nuclear Energy Institute
NRC Nuclear Regulatory Commission
OSP Off-site power
OOS Out-of-Service
PARS Publicly Available Records
PI Performance Indicator
PMT Post-Maintenance Testing
PSEG Public Service Enterprise Group Nuclear LLC
RFO Refueling Outage
RWP Radiation Work Permit
Attachment A
A-18
SDP Significance Determination Process
SFP Spent Fuel Pool
TS Technical Specifications
WO Work Order
Attachment A
8-1
Attachment 8
T1172 MSIP Documentation Questions Salem Unit 1
Introduction:
The Temporary Instruction (TI), 2515/172 provides for confirmation that owners of
pressurized-water reactors (PWRs) have implemented the industry guidelines of the
Materials Reliability Program (MRP) -139 regarding nondestructive examination and
evaluation of certain dissimilar metal welds in the RCS containing nickel based Alloys
600/82/182. This TI requires documentation of specific questions in an inspection report.
The questions and responses for MSI P for the IR 05000311/2009005 section 40A5 are
included in this Attachment.
In summary the Salem Units 1 and 2 have MRP-139 applicable Alloy 600/82/182 RCS
welds in the four hot and four cold leg piping to reactor pressure vessel nozzle
connections for each plant.
For Unit 1 during the 1R20 refueling outage in April 2010 PSEG inspected one dissimilar metal
weld, a SG channel head drain line weld. No indications were reported from this inspection.
PSEG plans on replacing this valve, and the dissimilar metal weld, during refueling outage
1R22.
T12515/172 requires the following questions to be answered for MRP-139 MSIP inspections:
Question 1: For each mechanical stress improvement used by the licensee during the Salem U1
1R20 outage, was the activity performed in accordance with a documented qualification report
for stress improvement processes and in accordance with demonstrated procedures?
Response Question 1: No MSIP activities were conducted on U1 during 1R20.
Question d.1: Are the nozzle, weld, safe end, and pipe configurations, as applicable, consistent
with the configuration addressed in the stress improvement (SI) qualification report?
Response - Question d.1: No MSIP activities were conducted on U1 during 1R20.
Question d.2.: Does the SI qualification report address the location radial loading is applied, the
applied load, and the effect that plastic deformation of the pipe configuration may have on the
ability to conduct volumetric examinations?
Response Question d.2: No MSIP activities were conducted on U1 during 1R20.
Question d.3.: Do the licensee's inspection procedure records document that a volumetric
examination per the ASME Code,Section XI, Appendix VIII was performed prior to and after the
application of the MSIP?
Response: Question d.3.: No MSIP activities were conducted on U1 during 1 R20.
Attachment 8