ML102980472

Email from Cline, Leonard to Ohara, Timothy, Et Al, Salem AFW Finding.Email from Cline, Leonard to O'Hara, Timothy, Et Al, Salem AFW Finding

ML102980472
Person / Time
Site:	Salem
Issue date:	07/28/2010
From:	Leonard Cline Reactor Projects Branch 3
To:	Conte R, O'Hara T Engineering Region 1 Branch 1
References
FOIA/PA-2010-0334, IR-10-003
Download: ML102980472 (29)

Text

Conte,-Richard From: Cline, Leonard Q-1 Sent: Wednesday, July 28, 2010 8:19 AM To: OHara, Timothy; Conte, Richard Cc: Burritt, Arthur

Subject:

Salem AFW finding Attachments: Salem 1-(2010003)(OHara)(ISI-Rpt)(7-21-201 0)wbr3editsmorebr3comments.docx As we discussed yesterday attached are the Branch 3 comments on the feeder.

1 C/ (ý

A REUNITED STATES NUCLEAR REGULATORY COMMISSION r' *REGION I 475 ALLENDALE ROAD KING OF PRUSSIA, PA 19406-1415.

July 22, 2010 MEMORANDUM TO: Arthur L. Burritt, Chief Projects Branch 3 Division of Reactor Projects THRU: Richard J. Conte, Chief Engineering Branch 1 Division of Reactor Safety FROM: Timothy L. OHara, Reactor Inspector Engineering Branch 1 Division of Reactor Safety

SUBJECT:

INSERVICE INSPECTION ACTIVITIES INSPECTION FEEDER FOR SALEM UNIT 1, INSPECTION REPORT 05000272/2010003, REVISION OF July 21, 2010 The enclosed feeder contains input for the subject report resulting from inspection of Inservice Inspection (ISI) activities during the period from April 5, 2010 to June 28, 2010, at Salem Unit 1.

The inspection was conducted using Inspection Procedure 71111.08, Inservice Inspection Activities and Temporary Instruction (TI) 2515/172, Reactor Coolant System Dissimilar Metal Butt Welds. The results of this inspection were presented to Mr. Ed Eilola, Salem Plant Manager, at an exit meeting on June 28, 2010.

Sugqgqested Cover Letter Input This feeder documents one NRC-identified finding of very low safety significance (Green). This finding was determined to be a violation of an NRC requirement. This feeder also documents a licensee-identified violation, which was determined to be of very low safety significance, in section 40A7 of this report. Because these violations are of very low safety significance and because the issues were entered into your corrective action process, these findings are being treated as non-cited violations (NCVs) consistent with Section VI.A.1 of the NRC Enforcement Policy.

Issue of Agency Concern: Buried, Safety Related Piping:

Because of an ongoing issue of Agency Concern about the degradation of buried piping, this issue is being documented as a licensee-identified finding in Section 40A7, in accordance with the guidance of IMC 0612-10.

2 No specific action is needed for this concern in light of industry initiatives on buried piping and the NRC Buried Piping Action Plan.

Since this issue, as noted below, is licensee identified, a long discussion was not permitted by IMC0612 format requirements. Documenting an issue of agency wide concern appears to only apply to minor findings, however, this issue is more than minor and licensee identified.

The following finding of very low safety significance was identified by PSEG and is a violation of 10 CFR 50, Appendix B, Criterion III, 'Design Control, an NRC requirement. PSEG did not provide an effective protective coating for the buried AFW piping. This issue has been evaluated via IMC 0609, Attachment 4, Initial Screening and Characterization of Findings and IMC 0612, Appendix B, Issue Screening.

During a planned excavation and inspection of the Unit 1 AFW buried piping to SG #12 and SG

1. 14, PSEG identified corrosion (significantly below minimum wall thickness for a design pressure of 1950 psi) of the safety related, ASME Class 3, Seismic Class 1 piping. PSEG repaired or replaced the affected Unit 1 buried AFW piping before returning the plant to operation. Portions of the Unit 1 and Unit 2 Auxiliary Feedwater (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. 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 lowest wall thickness measured in the affected piping was 0.077".

Preliminarily, PSEG representatives believe that there was an inadvertent omission of coating during construction days. PSEG plans on excavating the Unit 2 buried piping to inspect the condition during the next Unit 2 outage scheduled for the spring of 2011. Although no leakage was evident for these conditions, the inspector questioned if periodic pressure test had been conducted on this underground piping and this resulted in an NRC identified finding, as noted in this feeder, along with an operability determination for Unit 2 and as risk assessment for waiting to do the above noted inspection. This analysis resulted in a revised pipe design rating for Unit 2 down to 1275 psig.

10 CFR 50, Appendix B, Criterion III, Design Control, states, in part, "Measures shall be established to assure that applicable regulatory requirements and the design basis ... for those structures, systems, and components to which this appendix applies are correctly translated into specifications, drawings, procedures, and instructions. These measures shall include provisions to assure that appropriate quality standards are specified and included in design documents and that deviations from such standards are controlled. Measures shall also be established for the selection and review for suitability of application of materials, parts, equipment, and processes that are essential to the safety-related functions of the structures, systems and -components."

3 Contrary to these requirements, PSEG did not provide engineering evaluations, vendor certification, or testing data to demonstrate that the specified coating would protect the buried AFW piping for the design lifetime of the plant. Also, PSEG did not assure appropriate quality standards which assure that deviations from such standards were controlled. Additionally, PSEG did not provide measures for the selection and review for suitability of the coating materials for the buried AFW piping application, for periodic inspections to ensure that the applied coating was protecting the buried AFW piping, and did not provide engineering details demonstrating the ability of the coating to protect the buried AFW piping for the design life of the plant.

This licensee identified finding affects the mitigating systems cornerstone by affecting the secondary, short term decay heat removal capability. Because the finding did not result in loss of operability or functionality the inspector determined that the finding was of very low safety significance, Green. The inspector determined that this licensee identified finding is more than minor, and that a Cross Cutting Aspect did not exist because the issue was not indicative of current performance because the condition existed since 1977. Specifically, the section of piping under question was identified with degradation that put the system outside its original design basis (1950 psi design rating); and PSEG was required to make significant revisions to the system design analysis to take credit for available margin to show that the system remained operable.

Because PSEG entered this condition into the corrective action process (Notification 20456999) and because the issue is of very low safety significance (Green), this issue is being treated as a licensee identified non-cited violation consistent with Section VI.A. 1 of the NRC Enforcement Policy.

Follow up Comments for Future PI&R Sample Because PSEG had not completed the EQ:ACE for the corroded AFW.piping, had not completed the Root Cause Evaluation for missing the IWA-5244 pressure tests, and had not completed it's evaluation of Notification 20462034, it was agreed that an annual PI&R sample would be completed to review these documents to determine that the following comments/observations have been addressed by PSEG. It is anticipated that this sample will be performed in September 2010 depending upon PSEG completion of the cause determinations and Notification actions.

The inspector made other observations related to the finding on the AFW pressure testing issue and degradation noted in the AFW yard piping. PSEG intends to address the following observations/comments in the cause determinations and Notification evaluations.

(1) The PSEG buried piping inspection procedure did not document how a representative inspection sample is selected and did not enumerate the basis for the inspection sample selection(s).

(2) The PSEG buried piping inspection procedure does not provide a threshold criteria for inspection conditions which must be entered into the corrective action process for evaluation, potential resolution and/or tracking.

4 (3) PSEG has not defined a design life for the new coating on the replaced buried AFW piping for Unit 1. Also, PSEG has not determined an excavation and inspection frequency for the newly coated, replaced Unit 1 buried piping.

(4) Notification 20459689 reported the failure to perform the ASME, Section Xl, paragraph IWA-5244 required pressure tests on the buried AFW piping for Unit 1 and Unit 2. This Notification states, "The system pressure test boundary drawing (S2-SPT-336-0) identifies the piping as YARD piping not buried piping." It is not clear what PSEG is doing to ensure that other system drawings which may contain the same YARD markings and are potentially not being treated as buried piping and components.

(5) PSEG Buried Piping Program assumes that buried piping is protected by a coating system to protect the piping from degradation/corrosion for the design life of the plant.

However, the Unit 1 AFW piping was discovered to not have been coated or protected. It is not clear what PSEG is doing to confirm or verify that other buried piping is protected with an effective coating which will protect the piping for the plant life.

(6) PSEG agreed to provide the ASME, NIS-2 forms with ANI approval for the completion of the repair/replacement of the Unit 1 AFW piping.

(7) 'PSEG has initiated Notification 20462034 to investigate and confirm the basis of the 1950 psig design pressure of the AFW system. Actions included in this Notification were in progress when the inspection ended on June 28, 2010.

Enclosure:

Feeder for Salem Unit 1, Inspection Report No. 05000272/2010003, 05000311/2010003

5 cc w/

Enclosure:

(VIA E-MAIL)

A. Burritt, DRP L. Cline, DRP D. Schroeder, DRP, SRI - Salem Unit 1 T. O'Hara, DRS R. Hardies, NRR DRS Files SUNSI Review Complete: TLOIRJC (Reviewer's Initials)

Non-Public Designation Category: MD 3.4 Non-Public A.7 DOCUMENT NAME: g:\DRS\EB1\ohara\salem1-(2010003)(ohara)(isi-rpt)(7 2010)wbr3edits.doc After declaring this document An Official Agency Record" it will not be released to the Public.

To receive a copy of this document, indicate in the box: "C" = Copy without attachment/enclosure "E" = Copy with attachment/enclosure "N" = No copy OFFICE RI/DRS RI/DRS R1/DRS NAME TO'Hara/TLO WSchmidt/wac for RConte/RJC DATE 07/21/2010 07/21/2010 07/22/2010 FFI CE NAME DATE OFFICIAL RECORD COPY

SUMMARY

OF FINDINGS Reactor Safety Cornerstone: Mitigating Systems Qreen. The inspector identified a non-cited violation (NCV) of very low safety significance (Green) for PSEG's failure to perform auxiliary feedwater system (AFW) discharge piping 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 and Salem Unit 2. The required tests are intended to p-evide -

eAvidere-efdemonstrate the structural integrity of the buried piping portions of the system. I------- Comment [L1]: iC 0612 requires the summary of findings to discuss the immediate corrective actions and to state that the issue The affected piping is safety related, ASME Class 3, Seismic Class 1 piping. This was entered into the CAP.

performance deficiency is more than minor because the condition affected the Equipment Performance attribute (availability and reliability) of the mitigating systems cornerstone objective to ensure the availability, reliability and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damagei). The only A&ME

.. 88 and.2 010 r Un.it 1 and Un.it 2.. No Cross Cutting Aspect is assigned to this violation Comment [L2]: This sentence appears to be because this condition is not indicative of current performance*l- Ts--f*in-*-ing-isdescribe-di-- n out of place in accordance with MC 0612 the second paragraph should include the following:

Section 1ROB.

Second paragraph - Summarize significance as discussed in Analysis, why greater than minor, effect on cornerstone, why not greater than green, cross-cutting area, component and One violation of very low safety significance, which was identified by PSEG, was aspect, alpha numeric identifier. If no cross-reviewed by the inspector. Corrective actions taken or planned by PSEG were entered into cutting aspect state. Reference section of report.

the corrective action program. The violation and corrective action (notification) tracking See MC 0612 pg 28 and 29..

number is described in Section 40A7 of this report.

Comment [L3]: I believe in accordance with the applicable section of MC 0612 this paragraph is still missing information (see above). Specifically, why the finding screens to green.

ii

REPORT DETAILS 1R08 Inservice Inspection (ISI) (7111108- 1 Sample)

a. Inspection Scope The inspector observed a selected sample of nondestructive examination (NDE) activities in process. Also, the inspector reviewed the records of selected additional samples of completed NDE 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.

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.

2 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.

Boris Acid Corrosion Control Progqram 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 Xl 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 (approximately 20,000) 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 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 14:_4portions of the Unit 2 AFWpiping in response to the conditions observed on Unit Comment [L4]: I still believe that no matter 1 piping in ord6e-r-todete-rrmine-if-si-gn-ificant-degradation existed on the Unit 2 buriedAFW- where you move this to, itisstill purple.

piping.

Reiectable 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 1 R20. The inspector reviewed the additional wall thickness data taken to further define the condition and

3 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 The inspector identified the following violation related to ASME, Section Xl testing of buried Unit 1 and Unit 2 buried AFW piping.

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 Xl, paragraph IWA-5244 for PSEG's failure to perform required pressure tests of buried components. This piping is safety related, 4.0" ID, ASME Class 3, Seismic Class 1 piping.

Description. Portions of the Unit 1 and Unit 2 Auxiliary Feedwater (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. 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". PSEG plans on excavating the Unit 2 buried piping to inspect the condition during the next Unit 2 outage scheduled for the spring of 2011. The affected Unit 1 piping was replaced.

Although no leakage was evident for these conditions, the inspector questioned if 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 Xl. Paragraph IWA-5244 of Section Xl requires licensees to perform 1pressure tests ion buried components to demonstrate the structural integrity of . . Comment[I.]: Accordingtothecodeit the tested piping. The pressure test required by IWA-5244 is considered to be an appears to require a "rate of pressure loss" test.

I understand that there are some differences in inservice inspection and is part of Section Xl.Section XI and IWA-5244 do not specify what the code said then and now but we other non-destructive examinations (NDE) on buried components to demonstrate the probably need to make all the write-up sections existence of structural integrity. [PSEG did not perform the required tests for Unit 1 consistent. Ifthe Enforcement section says during the 1't period t perate of pressure loss maybe the whole write-up 3rd In Service (5/19/01 Inspection to 6/3/04)

Interval, and forand Unit2 nd2 period for the (6/24/04 1st periodto(5/19/01 5/20/08)toperiods 6/3/04)ofand the should sy raite of pressure loss.

2 nd period (6/24/04 to 5/20/08) of the 3T In Service Inspection Interval.l Thus, PSEG ..... Comment C [L6]: Should delete as long as fregIerteGdid not to perform the only inservice inspection intended to ------- .------ included in the Enforcement section.

efdemonstrate the structural integrity of this safety related buried piping. Comment [L7]: Purple PSEG 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 performan alternate flow test in 1991 for Unit 1. However, [PSEG did not perform the proposed alternate tests during the 2 nd inservice interval and during the 1st (5/19/01 to 6/3/04) and 2 nd (6/24/04 to 5/20/08) periods of the 3r In Service Inspection Interval for Unit 1. Also, PSEG did not request relief from the required tests or perform perform the proposed alternate tests on the Unit 2 buried piping during the 1st period (5/19/01 to 6/3/04) and sComment [L.]: Should delete as long as 2 nd period (6/24/04to 5/20/08) of the 3rd In Service Inspection Intervals.!1..ThuJsF PSEG .--l cludent Enforemet selon.

4 missed an opportunity to identify and correct this performance deficiency which affects Comment [L9]: Not sure I understand this the Un it 1 a nd Un it 2 .[------------------------------------------------------------------------------------- way you have it written here. Wouldn't a better argument be that it was within their ability to forsee and correct because it was a

ýAsecond opportunity to identify and correct this performance deficiency was missed in requirement that we know that they were aware of because they sought relief from the 2002 when a similar condition (failure to perform buried piping pressure tests) was requirement for Unit 1 in 1991.

documented in NRC Inspection Report 05000286-01-011 for Indian Point Unit 3 as NCV 50-286/2001-011-02. PSEG's review of NRC inspection reports did not identify that the Comment [LI0]: We do not require same condition existed at Unit 1 and Unit 2.1 ----------------------------------------------------------- licensee's to review and take action on inspection reports written to document issues at other sites. So unless their procedure requires PSEG replaced the affected buried Unit 1 piping during the refueling outage in April/May this we should probably back away. Again I 2010. The required pressure tests were successfully completed after the replacement of believe that we can say that it was within their ability to forsee and correct because it was a the Unit 1 buried piping. Because the AFW system functioned as required during the requirement that we know that they were aware plant shutdown prior to the start of 1R20 (April 2010), the system did not loose of because they sought relief from the operability. requirement for Unit 1 in 1991.

lFor Unit 2, PSEG completed an Operability Determination and a Risk Assessment for Comment [L11]: Use this statement to support a not more than minor violation for Unit continued operation until the next scheduled refueling outage scheduled for spring 2011 2 based on the information currently provided to for this issue. These evaluations determined that the condition was acceptable for us by PSEG in the OD and RA. This may change during the next Unit 2 outage depending continued operation until spring 2011.! on what they find with the piping on Unit 2, but we can deal with that during the U2 outage.

Analysis. IPSEG's failure to perform the required pressure test on this safety related Comment [L12]: I think that we missed the buried piping is a performance deficiency for each Salem Unit. This condition was the point here. As defined in MC 0612 a result of the licensee's failure to meet the regulatory requirements of 10 CFR performance deficiency is an issue that is the result of a licensee not meeting a requirement 50.55a(g)(4) and the ASME Code, Section Xl, paragraph IWA-5244. .his p.erformance_ or standard where the cause was reasonably deficiency was reasonably within the licensee's ability to foresee and correct and should within the licensee's ability to forsee and correct, and therefore should have been have been prevented, based on the above noted missed opportunities. LPSEG did not ------ prevented. PSEG did not meet the CFR perform the only inservice inspection (IWA-5244), intended to provide evidno because they did not perform the testing, not demonstrate the structural integrity of this safety related buried piping. the other way around. What was the result/the impact on the safety of the public by not performing the required testing? It is

ýhe inspector determined that the performance deficiency was more than minor because necessary to define thise result in order to this condition affected the Equipment Performance attribute (availability and reliability) of evaluate the significance - that is why th*

the mitigating systems cornerstone objective to ensure the availability, reliability and Comment [L13]: As stated above the issue capability of systems that respond to initiating events to prevent undesirable was within their ability to forsee and correct because it was a requirement that we know that consequences (i.e., core damage). L'f'th;'*,*;i*f*l*oefGt*.d,' this c'd-itio - Rul- c dh they were aware of because they sought relief proult"d in a moro signifirant condition duo to undtoto cr ion tIut from the requirement for Unit 1.

prossuro teSting for leakage. Comment [L14]: Since, as of today, there was no consequence for the lack of testing, the easier approach for "more than minor" is the left The inspector screened this performance deficiency using IMC 0609, Attachment uncorrected approach. So, in accordance with 0609.04, "Phase I Initial.Screening and Characterization of Findings." This finding MC 0612, we need to state the cornerstone impacts the mitigating systems cornerstone by adversely affecting the secondary, short affected and then define why if left uncorrrected this PD would result in a more significant safety term decay heat removal capability. Because the finding did not result in loss of concern..

operability or functionality, the inspector determined that the finding screened to Green, Comment [L15]: This does not meet the a very low safety significance.I ............................................................................ -, MC 0612 documentation requirements.

Needs to address all the screening criteria. A more appropriate statement would be

ýhe inspector determined that a Cross Cutting Aspect did not exist because the issue something like this. The inspectors was not indicative of current performance because the condition existed since 1991, determined the issue was of very low safety more than 3 years ago. Specifically, the failure to perform these pressure tests began in significance (Green) because the finding was not a design or qualification deficiency 1988 when PSEG requested relief from the requirement and neglected to incorporate the actions of the relief when it was granted in 1991.1 --................................ .o.-1 Comment [L16]: Would like more information here if possible, but understand that MC 0612 defines present performance as occurred within the last three years. -

5 Enforcement. 1i0 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, 41()that -F-er-for buried components whoreraa- 2 viScual examinatien cmnnt be pe4nrimed-,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 c o m po ne nts . ---------------------------------------------------------------------------------

. Comment [L17]: Originally, without the deletion that you recommended TIM, the way this was cited was not clear. However, Contrary to these requirements, PSEG did not perform the required pressure tests of the recommended deletion would address my buried AFW piping to the #12 SG and #14 SG at Salem Unit 1 during the 2 nd In Service earlier comment.

Lnspection 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 3d In Service Inspection Interval (5/19/01 to 5/19/11).

Also, contrary to these requirements, PSEG did not perform the required pressure tests of the buried piping to the #22 SG and #24 SG for Unit 2 for the 1st period (5/19/01 to 6/3/04) and 2 nd period (6/24/04 to 5/20/08) of the 3r In Service Inspection Interval.

Consequently, from 2/27/88 to 4/20/07) the required pressure tests were not performed to demonstrate structural integrity on the affected buried Unit 1 AFW piping.

Because PSEG entered this condition into the corrective action process (Notification 20459686) and because it is 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 50-272/2010-?? and NCV 50-31112010-??

40A2 Identification and Resolution of Problems (71152)

a. Inspection Scope The inspectors reviewed a sample of corrective action reports (notifications), listed in Attachment 2 which involved in-service inspection related issues, to ensure that issues are being promptly identified, reported and resolved.

b. Findings No findings of significance were identified.

40A5 Temporary 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.

6 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 for the IR'05000272/2010003 section 40A5 are included in this report as Attachment "B-I".

b. Findings No findings of significance were identified.

40A6 Meetings, including Exit The inspectors presented the ISI inspection and TI 2515/172 inspection results to Mr. Ed Eilola, Salem Plant Manager, and other members of the PSEG staff at the conclusion of the inspection at an exit meeting on June 28, 2010 for Salem Unit 1. The licensee acknowledged the conclusions and observations presented. Some proprietary information was reviewed during this inspection and was properly destroyed. No proprietary information is contained in this report.

40A7 Licensee Identified Violations The following finding of very low safety significance was identified by PSEG. The finding is a violation of 10 CFR 50, Appendix B, Criterion III, Design Control that 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. PSEG did not provide an effective protective coating for the buried AFW piping on Unit 1.

PSEG identified general corrosion that reduced the wall thickness of the safety related Comment [118]: Not necessary and I believe piping to less than the design minimum wall thickness of 0.278" for the system design confuses the write-up.

pressure of 1950 psig. The lowest measured wall thickness was 0.077". An FEA for the Comment [L19]: This discussion should degraded piping was able to demonstrate past operability at a reduced operating clearly include: cornerstone affected, justification for more than minor, and pressure of 1275 psigl. However, the reqr**ed design pressure for the ANA! sycteom is justification for screen to green based on Phase

-Ack-A - -A-U.-O - 1-kF:F::R9.1 ...... 1 questions in MC 0609. Probably need a little more detail here on how the phase 1 questions were answered.. See MC 0612 requirements This finding was associated with the mitigating systems cornerstone, specifically the for LIV documentation:

short term decay heat removal capability. The finding was determined to be Green Include the requirement(s) violated, describe because it was a design or gualification deficiency that was confirmed not to result in how it was violated, identify the licensees loss of o erability it did not reSUlt in loe9of operability Or funRcionali' of the AFWV corrective action tracking number(s), and syste m.------------------------------------------------------------------------------------------------- .. provide a very brief justification why the violation is not greater than Green. A complete reconstruction of the SDP logic is not required.

Because PSEG entered this condition into the corrective action process (Notification However, Section 40A7 must include the following introductory paragraph:

20456999) and because the issue is of very low safety significance (Green), this issue is being treated as a non-cited violation consistent with Section VI.A. 1 of the NRC The following violations of very low safety Enforcement Policy. NCV 50-27212010003-?? significance (Green) or Severity Level IV were identified by the licensee and are violations of NRC requirements which meet the criteria of the NRC Enforcement Policy, for being dispositioned as a Non-Cited Violation.

A-1 ATTACHMENT SUPPLEMENTAL INFORMATION KEY CONTACTS Licensee Personnel:

Howard Berrick, PSEG Pat Fabian, PSEG Mohammad Ahmed, PSEG Tony Oliveri, PSEG Tom Roberts, PSEG Ali Fakhar, PSEG Len Rajkowski, PSEG Dave Mora, PSEG Edley Giles, PSEG Walter Sheets, PSEG Bob Montgomery, PSEG Jim Mellchiona, PSEG Bill Mattingly, PSEG Pat Van Horn, PSEG Jim Barnes, PSEG Justin Werne, PSEG Rick Villar, PSEG Matthew Murray, PSEG LIST OF DOCUMENTS REVIEWED 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 Evaluation (EQ;ACE) Charter 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, UI Containment Liner Corrosion at 78' El.*

A-2 20459259, Ul 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) 1 R20 FAC(N 18) 14# elbow below Tmin 20456828, (66) valve has visible boron buildup 1R20 20459232, Heavy Dry White Boron Vlv Packing (1 R20) 20456834, Heavy Dry White Boron Vlv Packing (1 R20) 20456840, Medium Dry White Boron Vlv Packing (1R20) 20456839, Medium Dry White Boron Vlv Packing (1R20) 20389147, Recordable ISI Indications on CVC Tank 20344017, Inspect Steel Liner in 1R19 @ Containment Sump 20235636, NRC Noted Water Running Down Containment Wall 20392631, ARMA From ISI 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 ISI NRC Violation 20397518, A1CVC-1CV180 Chk VIv 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 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 Ul ISI Relief Request Book - PI&R review 20449447, Update Salem Unit 1 ISI 10 Yr Plan - PI&R review 20449744, Update Salem Unit 1 Containment ISI 10 Yr Plan - PI&R review 20449442, Update Salem Unit 2 Containment ISI 10 Yr Plan - PI&R review 20449554, Salem U2 RFO18 ISI Scope - PI&R review 20416605, INPO PSIRV Alloy 600 Program - PI&R review 20404057, Unit 2 ISI (MSIP) - PI&R review 20392631, ARMA FROM ISI 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 ISI Weld Exam Limitations - PI&R review 20416605, INPO PSIRV Alloy 600 Program - PI&R review 20449442, Update Salem 2 Containment ISI 10 yr. Plan - PI&R review 20449554, Salem Unit 2 RFO18 ISI Scope - PI&R review

L A-3 20449747, Update Salem 2 ISI 10 Yr. Plan - PI&R review 20401542, Perform ISI BMV Exam on RPV Upper Head - PI&R review 20449063, SA U1 Service Inspec- ISI & U1 TI 2515 - PI&R review 20389147, Recordable ISI Indications on CVC Tank - PI&R review 20392145, Update U1 ISI Relief Request Book - PI&R review 20449744, Update Salem Ul Containment ISI 10 Yr. Plan - PI&R review 20409943, NRC RIS 2009-04 SG Tube Insp Rqmts - PI&R review 20459851, Section Xl 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 Xl 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 S1SJ-13SJ25 W.O. 60089848, 80101382 Advanced Work Authorization #2 FTTA Replace Aux. Feedwater Pipe W.O. 60089561, 80101381 Advanced Work Authorization - Replace Aux. FW U/G Piping, 4/9/10 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 80101381 RO, Buried Pipe, Replaced AFW Piping Arrangement 207483A8923-1 1, Salem Nuclear Generating Station, Unit No. 1 - Reactor Containment Auxiliary Feedwater, Plans & Sections - Elev. 78' 10" & 100' 0", Mechanical Arrangement, Revision 8, 9/3.1/86

ýL A-4 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 ,

207610A8896-12, Salem Nuclear Generating Station, Unit No. 1 -Auxiliary Building & Reactor Containmnet Compressed Air Piping, Aux. Building El. 84 East & React. Contain. El. 78, Mechanical Arrangement, Revision 8, 9/31/86 Design Change Packages/Equivalent Change Packages 80101382, Revision 2, Replace Salem Unit 1 AFW Piping from the Unit Mechanical Penetration Area El. 78'-0" to the Unit 1 Fuel Transfer Tube Area El. 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 System & Program Health Reports & Self-Assessments:

Salem Boric Acid Corrosion Control Program Focused Area Self-Assessment, 1/2010 70106830, Salem S1R20 NRC ISI 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 X1,1998 Edition, 2000 Addenda, IWA-5244 Buried Components OAR-i, Owner's Activity Report, #S1RFO19, 1/15/09

L.

A-5 Procedures DETAILED AND GENERAL, VT-1 AND VT-3 VISUAL EXAMINATION OF ASME CLASS MC AND CC CONTAINMENT SURFACES AND COMPONENTS SHRA - 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 Xl 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 (VE) 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, 7/29/09 S2.OP-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 NDE Examination Reports & Data Sheets 003753, VT-10-113, PRV nozzle sliding support 003754, VT-10-114, 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%)

A-6 033100, UT-1 0-032, 4-PS-1 131-25 (100%)

032300, UT-1 0-033, 4-PS-1 131-17 (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-1 0-024, 14-BF-2141-20 (100%)

836300, IWE: VT-10-338, PNL-Sl-343-1 836400, IWE: VT-1i0-333, ALK-Sl-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 FTTA, 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: ISI Perform PORV Check Order 50118090, ST 550D, Surveillance: OPS Perform PORV Check W.O. 60089848, VT-2 Visual Examination Record, 12/14 AFW in FTTA, 4/26/10 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 FTTA 401600, VE-04-198; Hope Creek system pressure test CST to HPCI/RCIC and Core Spray, 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

A-7 Eddy Current Testinq Personnel Qualification Records A2421 C2028 R6452 T5616 B8731 C4596 R8002 R9311 B0500 C3340 S7752 G4943 B5127 D3858 T8251 C5542 B5128 H6267 V3197 F0075 B2576 H0282 R4142 F6623 F3961 14048 R6279 F3453 C1560 J1978 G3380 G4943 D7895 2010983302133 B3720 G1311 D9573 P6459 R6900 H7791 D6502 R0830 A9608 J9141 H2039 Ri164 N2574 M0950 K5380 S0608 13805 M2665 M9460 2509981330193 T2170 M7006 E0427 K5858 N4815 M9459 M6664 1007951330114 M0945 M7007 B4260 L9168 P2963 M9082 A3502 L4332 M9715 N7035 J9815 F7460 K1903 N9952 P5436 F0037 D5318 R9311 M6042 3107943330158 W6070 S9098 B8589 6206070744 M5096 T5616 B4014 6507061922 J1945 T5565 G2573 1803983330125 L4588 W2639 V8530 2709977301226 C8042 W7912 W3368 P5304 N5330 M4305 P4006 L8267 B4052 R4201 F3453 K6975 G3910 H0268 L3025 P1465 B8079 G1756 C8071 6410058746 B5371 H2131 2909965330076

A-8 Engineering Analyses & Calculations & Standards Calculation 6SO-1882, Revision 1; 8/30/96; Qualification of Safety-Related Buried Commodities For Tornado Missle and Seismic Evaluation Calculation No. S-C-AF-MDC-1 789; 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 S1CVC-1 CV277 70109232/20459230; Boric Acid evaluation of leakage from S1 CVC-ICV2 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 1R20 and Preliminary Operational Assessment For Cycles 21 And 22, 4/20/10 SA-SURV-2010-001, 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. 1000494.301, Evaluation of Degraded Underground Auxiliary Feedwater Piping (Between Unit 1 FTTA and OPA), 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. 1000498.301, 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

A-9 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 Multiple Weld History Record: 74586

A-10 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)

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

A-i 1 MPR Associates Report, Technical Input To Operability of Potential Containment Liner Corrosion, Revision 0, 10/30/09 Transmittal of Design Information #S-TODI-2010-0005, 4/20/2010 Transmittal of Design Information #S-TODI-2010-0004, 4/16/2010 OQ950315126, 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 1 R20, 4/30/10 UNTAGGING WORKLIST 4274351, 12 AF Underground Piping 1R20, 4/30/10 LIST OF ACRONYMS ASME American Society of Mechanical Engineers BAST Boric Acid Storage Tank CEA Control Element Assembly CEDM Control Element Drive Mechanism CFR Code of Federal Regulations EDG Emergency Diesel Generator EPRI Electric Power Research institute EQ;ACE Equipment Apparent Cause Evaluation EQ Environmental Qualification ER Engineering Request FEA Finite Element Analysis FTTA Fuel Transfer Tube Area IMC Inspection Manual Chapter IP Inspection Procedure IR NRC Inspection Report LER Licensee Event Report LOCA Loss of Coolant Accident MT Magnetic Particle Testing MSIP Mechanical Stress Improvement Process NCV Non-cited Violation Notification Corrective Action Notification NRC Nuclear Regulatory Commission NDE Nondestructive Examination OE Operating Experience PDI Performance Demonstration Initiative PI&R Problem Identification and Resolution PSEG Public Service Electric & Gas, LLC PWSCC Primary Water Stress Corrosion Cracking PQR Procedure Qualification Record (Welding Procedures)

RCS Reactor Coolant System RT Radiographic Test (Radiography)

PT Dye Penetrant Testing SDP Significance Determination Process SE Safety Evaluation

A-12 SG Steam Generator SI Stress Improvement SSC Structure, System, and Component TS Technical Specifications UT Ultrasonic Test UFSAR Updated Final Safety Analysis Report VT Visual Examination WPS Weld Procedure Specification

'I .

A-13 INSPECTION SAMPLE COMPLETION STATUS PROCEDURE MINIMUM CURRENT RPS PROCEDURE RPS or TI REQUIRED INSPECTION TOTAL STATUS UPDATED SAMPLES SAMPLES SAMPLES OPEN (O) (Y) (N)

Annual (A) TO DATE CLOSED (C)

Biennial (B) 7111108 (G) 1 Y 2515/172 1 YES

A-14 Attachment B-1 TI 172 MSIP Documentation Questions Salem Unit I

==

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 MSIP for the IR 05000311/2009005 section 40A5 are included in this Attachment "B-I".

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.

TI 2515/172 requires the followinq questions to be answered for MRP-139 MSIP inspections:

Question 1: For each mechanical stress improvement used by the licensee during the Salem Ul 1 R20 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 Ul 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 Xl, Appendix VIII was performed prior to and after the application of the MSIP?

Response: Question d.3.: No MSIP activities were conducted on Ul during 1 R20.

A-1 5 Question d.4.: Does the SI qualification report address limiting flaw sizes that may be found during pre-SI and post-SI inspections and that any flaws identified during the volumetric examination are to be within the limiting flaw sizes established by the SI qualification report?

Response: Question d.4.: No MSIP activities were conducted on U1 during 1 R20.

Question d.5.: Was the MSIP performed such that deficiencies were identified, dispositioned, and resolved?

Response Question d.5.: No MSIP activities were conducted on U1 during 1 R20.

Page 4: [1] Comment [L12] LMC1 7/28/2010 8:06:00 AM I think that we missed the point here. As defined in MC 0612 a performance deficiency is an issue that is the result of a licensee not meeting a requirement or standard where the cause was reasonably within the licensee's ability to forsee and correct, and therefore should have been prevented. PSEG did not meet the CFR because they did not perform the testing, not the other way around. What was the result/the impact on the safety of the public by not performing the required testing? It is necessary to define thise result in order to evaluate the significance - that is why the definition is written that way. Not using the following words exactly one suggestion for defining the result would be - due to the condition of the pipe and coating identified during the excavation, it is clear that the failure to perform required testing would have ultimately resulted a loss of structural integrity for the pipe impacting the operability of the affected AFW trains.

Page 4: [2] Comment [L15] LMC1 7/27/2010 4:41:00 PM This does not meet the MC 0612 documentation requirements. Needs to address all the screening criteria. A more appropriate statement would be something like this. The inspectors determined the issue was of very low safety significance (Green) 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.