IR 05000272/2015011

IR 05000272/2015011; July 20, 2015 - August 6, 2015; (Pseg)Salem Nuclear Generating Station, U1-License Renewal Team Inspection

ML15261A726
Person / Time
Site:	Salem
Issue date:	09/18/2015
From:	Mel Gray Engineering Region 1 Branch 1
To:	Braun R Public Service Enterprise Group
Modes M
References
IR 2015011
Download: ML15261A726 (34)

Text

R. Brau UNITED STATES NUCLEAR REGULATORY COMMISSION

REGION I

2100 RENAISSANCE BLVD., SUITE 100 KING OF PRUSSIA, PA 19406-2713 September 18, 2015 Mr. Robert President and Chief Nuclear Officer PSEG Nuclear LLC - N09 P.O. Box 236 Hancocks Bridge, NJ 08038 SUBJECT: SALEM NUCLEAR GENERATING STATION, UNIT 1 INSPECTION REPORT 05000272/2015011

Dear Mr. Braun:

On August 6, 2015, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at the Salem Nuclear Generating Station, Unit 1 subsequent to Unit 1 entering the period of extended operation at midnight August 16, 2016. The enclosed inspection report documents the inspection results, which were discussed on August 6, 2015, with Mr. John Perry, Salem Site Vice President, and other members of your staff.

The inspection verified your compliance with the license conditions added as part of the renewed operating license. The inspection verified your staff implemented regulatory commitments, selected aging management programs, and time limited aging analyses in accordance with Title 10 of the Code of Federal Regulations Part 54, Requirements for the Renewal of Operating Licenses for Nuclear Power Plants. The inspection verified the updated final safety analysis report included any newly identified systems, structures, and components that should have been within the scope of the license renewal program and subject to an aging management review or time limited aging analysis evaluation, pursuant to 10 CFR 54.37(b).

The inspection verified that the description of the aging management programs are contained in the Updated Final Safety Analysis Report and the description of the programs is consistent with the programs being implemented. The inspection verified that changes to the Updated Final Safety Analysis Report supplement were implemented, in accordance with Title 10 of the Code of Federal Regulations Part 50.59. Changes to commitments were also managed in accordance with applicable regulatory guidance.

In accordance with Title 10 of the Code of Federal Regulations (10 CFR) 2.390 of the NRCs Rules of Practice, a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRCs Public Document Room or from the Publicly Available Records component of the NRCs Agencywide Documents Access and Management System (ADAMS). ADAMS is accessible from the NRCs website at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Mel Gray, Chief Engineering Branch 1 Division of Reactor Safety Docket Nos. 50-272 License Nos. DPR-70

Enclosure:

Inspection Report 05000272/2015011 w/Attachment: Supplementary Information

REGION I==

Docket Nos. 50-272 License Nos. DPR-70 Report Nos. 05000272/2015011 Licensee: PSEG Nuclear LLC (PSEG)

Exelon Generating Company LLC Facility: Salem Nuclear Generating Station, Unit 1 Location: P.O. Box 236 Hancocks Bridge, NJ 08038 Dates: July 20 to August 6, 2015 Inspectors: M. Modes, Senior Reactor Inspector J. Kulp, Senior Reactor Inspector T. OHara, Reactor Inspector S. Chaudhary, Reactor Inspector Approved By: Mel Gray, Chief Engineering Branch 1 Division of Reactor Safety i Enclosure

SUMMARY

Inspection Report 05000272/2015011; July 20 to August 6, 2015; PSEG Nuclear LLC (PSEG)

Salem Nuclear Generating Station, Unit 1; License Renewal Team Inspection.

The inspection verified compliance with the license conditions added as part of the renewed operating license. The inspection verified that PSEG staff implemented regulatory commitments, selected aging management programs, and time limited aging analyses in accordance with Title 10 of the Code of Federal Regulations Part 54, Requirements for the Renewal of Operating Licenses for Nuclear Power Plants. The inspection verified that the updated final safety analysis report included any newly identified systems, structures, and components that should have been within the scope of the license renewal program and subject to an aging management review or time limited aging analysis evaluation, pursuant to 10 CFR 54.37(b). The inspection verified that the description of the aging management programs are contained in the Updated Final Safety Analysis Report and the description of the programs is consistent with the programs being implemented. The inspection verified that PSEG managed changes to the Updated Final Safety Analysis Report supplement in accordance with Title 10 of the Code of Federal Regulations Part 50.59; and managed changes to regulatory commitments in accordance with Nuclear Energy Institute 99-04, Guidelines for Managing NRC Commitment Changes, as endorsed by NRC Regulatory Issue Summary 2000-017.

No findings were identified. The NRC determined that the commitments reviewed associated with the license renewal application had been appropriately implemented.

iii

REPORT DETAILS

4OA2 Post-Approval Site Inspection for License Renewal (IP 71003)

In its August 18, 2009, submission letter, the applicant PSEG requested renewal of the operating licenses issued under Section 103 (Operating License Nos. DPR-70 and DPR-75) of the Atomic Energy Act of 1954, as amended, for a period of 20 years beyond the current expiration at midnight August 13, 2016, for Unit 1, and at midnight April 18, 2020, for Unit 2.

The reviewed commitments, license conditions, and enhanced aging management programs were selected based on several attributes including the results of previous license renewal audits and inspections of aging management programs; the complexity in implementing a commitment; and the extent to which the baseline inspection programs will inspect attributes of the commitment, license condition or aging management program. Consideration was given to the amount of time since the renewed license was granted and beginning of the period of extended operation.

The commitments reviewed by this inspection are recorded in NUREG-1201, Safety Evaluation Report Related to the License Renewal of Salem Nuclear Generating Station, Docket Numbers 50-272 and 50-311, Appendix A, Salem Nuclear Generating Station License Renewal Commitments, dated June 2011. For each commitment the inspectors reviewed supporting documents including completed surveillances, conducted interviews, performed visual inspection of structures and components and observed selected activities to verify the licensee completed the necessary actions to comply with the license conditions or commitments.

The inspectors selectively verified the licensee implemented the aging management programs, included in the NRC license renewal safety evaluation report, in accordance with Title 10 of the Code of Federal Regulations (CFR) Part 54, Requirements for the Renewal of Operating Licenses for Nuclear Power Plants. The inspectors verified a selected sample of licensee corrective actions that were the result of license renewal activities.

During this inspection the inspectors verified that changes, if any, to these commitments were identified and properly reviewed and approved. Because no changes were made prior to the beginning of this inspection, the inspectors reviewed the procedures developed by the licensee to ensure that commitment revision followed the guidance in NEI 99-04, Guidelines for Managing NRC Commitment Changes, for the license renewal commitment change process, including the elimination of commitments, and would properly evaluate, report, and approve where necessary, changes to license renewal commitments listed in the Updated Final Safety Analysis Report in accordance with 10 CFR 50.59. The inspectors also reviewed the licensees commitment tracking program to evaluate its effectiveness.

On a sampling basis, the inspectors verified that PSEG completed the necessary actions to comply with the license conditions that are a part of the renewed operating license, and had implemented the aging management programs included in the NRC staffs license renewal safety evaluation report. The following commitments, license conditions, and enhanced programs were reviewed.

.1 License Conditions

a. Inspection Scope

The inspectors noted the Salem Generating Station Updated Final Safety Analysis Report, Revision 26, dated May 21, 2012, Appendix B, License Renewal Final Safety Analysis Report Supplement, listed the aging management programs and time limited aging analyses. This supplement also included a summarized description of the aging management programs. A list of the License Renewal Commitments is also contained in Section A.5 of the supplement.

Renewed License No. DPR-70 2. c.

(20) All capsules in the reactor vessel that are removed and tested must meet the test procedures and reporting requirements of American Society for Testing and Materials E 185-82 to the extent practicable for the configuration of the specimens in the capsule.

Any changes to the capsule withdrawal schedule, including spare capsules, must be approved by the NRC prior to implementation. All capsules placed in storage must be maintained for future insertion. Any changes to storage requirements must be approved by the NRC. Changes to the withdrawal schedule or storage requirements shall be submitted to the NRC as a report in accordance with 10 CFR 50.4.

The inspectors verified, as part of the review of Commitment 19, below, that PSEG Nuclear LLC was in compliance with this condition of their license.

Renewed License No. DPR-70 2. c.

(21) PSEG Nuclear LLC shall take one core sample in the Unit 1 spent fuel pool west wall, by the end of 2013, and one core sample in the east wall where there have been indications of borated water ingress through the concrete, by the end of 2015. The core samples (east and west walls) will expose the rebar, which will be examined for signs of corrosion. Any sample showing signs of concrete degradation and/or rebar corrosion will be entered into the licensee's corrective action program for further evaluation. PSEG Nuclear LLC shall submit a report in accordance with 10 CFR 50.4 no later than three months after each sample is taken on the results, recommendations, and any additional planned actions.

The inspectors verified the required core samples were taken, analyzed, and reported to the NRC in keeping with the stipulated dates prescribed by the condition above.

Application of 10 CFR 54.37(b)

The inspectors reviewed the summary reports of the PSEG audits of design changes, modifications, licensing correspondence, and Final Safety Analysis Report change notices for the periods of May 1, 2010 - December 31, 2011; January 1, 2012 - May 31, 2013; and June 1, 2013 - January 31, 2015. The inspectors selected for detailed review a number of design modification descriptions from the 117 design modification descriptions reviewed by PSEG for the period of May 1, 2010 - December 31, 2011. For example, the inspectors reviewed change 80099683, which added approximately seven feet of 3/4 inch diameter vent pipe, with two globe valves, at the high point of the Residual Heat Removal system cross connect between 21RH19 and 22RH19 in 22 Residual Heat Removal System pump room.

b. Findings

No findings were identified.

.2 Commitment Management

a. Inspection Scope

Commitment 7 PWR Vessel Internals Program is a new program that will include the following activities.

Part 1: Participate in Industry Programs PSEG participated in the industry initiative to manage the aging effects of cracking, loss-of-material induced by wear and loss of fracture toughness due to both thermal and neutron irradiation. PSEG implemented Pressurized Water Reactor (PWR) Vessel internals that will include the following activities. Reactor Vessel Internals aging management program which applies the methodology and guidance in the NRC endorsed Materials Reliability Program (MRP) 227-A Materials Reliability Program:

Pressurized Water Reactor Internals Inspection and Evaluation Guidelines. This program is used to manage the effects of age-related degradation mechanisms that are applicable to the Salem Reactor Vessel internals.

Part 2: Evaluate and Implement the Industry Programs These aging effects evaluated by PSEG for applicability to Salem reactor internals include:

a. Various forms of cracking, including stress corrosion cracking (SCC), which also encompasses primary water stress corrosion cracking (PWSCC),irradiation-assisted stress corrosion cracking (IASCC), or cracking due to fatigue; b. Loss of material induced by wear; c. Loss of fracture toughness due to either thermal aging or neutron irradiation embrittlement; d. Changes in dimension due to void swelling; and e. Loss of preload due to thermal and irradiation-enhanced stress relaxation or creep Part 3: Upon completion of these programs, but not less than 24 months before entering the period of extended operation, submit an inspection plan for reactor internals to the NRC for review and approval.

For Part 1, the inspectors noted the use of the Materials Reliability Project procedures indicates industry participation.

For Part 2, the inspectors determined if the MRP-227-A guidance for selecting reactor vessel internal components for inclusion in the inspection sample, which is based on a four-step ranking process, was used to establish the inspection program.

For Part 3, the inspectors verified that PSEG submitted the inspections plan per PSEG Letter LR-N14-0183, dated August 11, 2014, Submittal of PWR Vessel Internals Inspection Plans for Aging Management of Reactor Internals at Salem Generating Station Units 1 and 2.

Commitment 9 Bolting Integrity Program is an existing program that will be enhanced to include:

1. In the following cases, bolting material should not be reused:

a. Galvanized bolts and nuts; b. ASTM A490 bolts; and c. Any bolt and nut tightened by the turn of nut method PSEG committed to enhance their existing Bolting Integrity Program to clearly exclude reuse of

(a) Galvanized Bolts and Nuts;

(b) ASTM A490 Bolts; and

(c) Any bolt and nut tightened by the Turn of Nut method before the start of Extended Operation of the plant.

By review of documentation included in the Structural Monitoring Program Procedure which covers non-American Society of Mechanical Engineer Code structural connections, and the plant Inservice Inspection program that covers code connections, the inspectors verified that the exclusion for reuse of bolts and nuts have been incorporated in the program requirements and the Final Safety Analysis Report.

Commitment 12 Closed-Cycle Cooling Water System is an existing program that will be enhanced to include:

1. The Component Cooling System is not currently analyzed for sulfates, which

is not consistent with the EPRI standard. The program will be enhanced to include monitoring this parameter as part of the Closed-Cycle Cooling Water program.

2. The emergency diesel generator jacket water system is not currently

analyzed for azole or ammonia, chlorides, fluorides, and microbiologically-influenced corrosion in accordance with the current EPRI standard. The program will be enhanced to include these parameters as part of the Closed-Cycle Cooling Water program.

3. The Closed-Cycle Cooling Water program for the Chilled Water System will

have a program or hardware change to bring the system chemistry parameters into compliance with EPRI 1007820, prior to the period of extended operation;

4. New recurring tasks will be established to enhance the performance

monitoring of selected heat exchangers cooled by Component Cooling System;

5. New recurring tasks will be established for enhancing the performance

monitoring of selected Chilled Water System components;

6. A one-time inspection of selected components will be established for Chilled

Water System piping to confirm the effectiveness of the Closed-Cycle Cooling Water program;

7. A one-time inspection of selected closed-cycle cooling water components in

stagnant flow areas will be conducted to confirm the effectiveness of the Closed-Cycle Cooling Water program;

8. A one-time inspection of selected closed-cycle cooling water chemical mixing

tanks and associated piping will be conducted to confirm the effectiveness of the closed cycle cooling water program on the interior surfaces of the tanks and associated piping;

9. The program will be enhanced such that the Heating Water and Heating

Steam System will have a pure water control program instituted, in accordance with EPRI 1007820, prior to the period of extended operation; 10. New recurring tasks will be established for enhancing the performance monitoring of selected Heating Water and Heating Steam System components; 11. A one-time inspection of selected Heating Water and Heating Steam System piping will be conducted to confirm the effectiveness of the Closed-Cycle Cooling Water program.

The inspectors reviewed the PSEG Closed Cooling Water Chemistry Program, CY-AP-120 400, to verify that revisions were made to make the program consistent with Electric Power Research Institute guideline TR-1007820, Closed Cooling Water Chemistry Guideline, for the emergency diesel generator cooling, component cooling, chilled water and heating steam systems. The inspectors reviewed the results of the completed one-time inspections of components and piping, as well as the work schedules for inspections not yet completed to ensure that they are scheduled to be completed prior to entering the period of extended operation. Additionally, the inspectors interviewed the closed cycle cooling water program engineer and reviewed recurring tasks that are used to monitor the performance of selected heat exchangers and system components.

Commitment 13 Inspection of Overhead Heavy Load and Light Load (Related to Refueling)

Handling Systems is an existing program that will be enhanced to include:

1. Visual inspection of structural components and structural bolts for loss of

material due to general, pitting, and crevice corrosion and structural bolting for loss of preload due to self-loosening.

2. Visual inspection of the rails in the rail system for loss of material due to

wear.

3. The acceptance criteria will be enhanced to require evaluation of significant

loss of material due to corrosion for structural components and structural bolts, and significant loss of material due to wear of rail in the rail system.

The inspectors reviewed MA-AA-716-021, PSEG Nuclear LLC Rigging and Lifting Program to verify that revisions were made to include visual inspections of structural components, rails and structural bolts for loss of material due to corrosion and loss of preload due to self-loosening. The inspectors also reviewed preventive maintenance procedures for individual handling systems to ensure the same revisions were incorporated to implement the visual inspections for corrosion and loss of preload on structural bolting. Additionally, the inspectors verified guidance that any identified significant loss of material due to corrosion is to be entered into the corrective action program for evaluation and corrective actions as needed.

Commitment 17 Above Ground Steel Tanks is an existing program that will be enhanced to include:

1. The program will be enhanced to include UT measurements of the bottom of

the tanks that are supported on concrete foundations (Fire Protection Water Storage Tanks). Measured wall thickness will be monitored and trended if significant material loss is detected. These thickness measurements of the tank bottom will be taken and evaluated against design thickness and corrosion allowance to ensure that significant degradation is not occurring and the component intended function would be maintained during the extended period of operation.

2. The program will be enhanced to provide routine visual inspections of the Fire

Protection Water Storage Tanks external surfaces. The visual inspection activities will include inspection of the grout or sealant between the tank bottom and the concrete foundation for signs of degradation.

The inspectors reviewed the results of the December 2010 internal inspections and ultrasonic testing of the tank bottoms of the fire protection water storage tanks. The inspectors also reviewed the results of the external inspection of the tanks completed in July 2015, ensuring that the visual inspection work orders included an inspection of the grouting between the tank bottom and concrete foundation. Additionally, the inspectors performed a walk-down of the external surfaces of the tanks with the system engineer.

Commitment 18 Fuel Oil Chemistry is an existing program that will be enhanced to include:

1. Equivalent requirements for fuel oil purity and fuel oil testing as described by

the Standard Technical Specifications.

3. Addition of biocides, stabilizers and corrosion inhibitors as determined by fuel

oil sampling or inspection activities.

5. Internal inspection of 350-gallon Fire Pump Day Tanks (S1DF-1DFE21 and

S1DF-1DFE23) using visual inspections and ultrasonic thickness examination of tank bottoms.

6. Sampling of new fuel oil deliveries for API gravity and flash point prior to off

load.

7. Internal inspection of the 30,000-gallon Fuel Oil Storage Tanks

(S1DF-1DFE1, S1DF-1DFE2, S2DF-2DFE1 and S2DF-2DFE2) using visual inspections and ultrasonic thickness examination of tank bottoms

8. To confirm the absence of any significant aging effects, a one-time inspection

of each of the 550-gallon Diesel Fuel Oil Day Tanks will be performed.

The inspectors reviewed PSEG document SC.OP-LB.DF-0001(Q), Diesel Fuel Oil Testing Program, to verify that it was revised to ensure new and stored fuel oil was tested for particulate contamination and periodically tested for bacteriological growth, with provisions for addition of biocides, stabilizers and corrosion inhibitors if conditions warrant. The inspectors also verified that new fuel was tested and met technical specification oil purity requirements prior to offload into the storage tanks. The inspectors also reviewed completed fuel oil storage tank visual inspection and ultrasonic testing results. The inspectors verified that the 30,000 gallon fuel oil storage tank visual inspections and ultrasonic tests are scheduled for completion prior to plant entry into the period of extended operations.

Commitment 19 Reactor Vessel Surveillance is an existing program that will be enhanced to include:

1. The Reactor Vessel Surveillance program will be enhanced to state the bounding

vessel inlet temperature (cold leg) limits and fluence projections, and to provide instructions for changes.

a. Inlet Temperature Range Limitation: 525°F (min) to 590°F (max)b. Fluence Limitation (max.): 1.00 x 1020 n/cm2 (E > 1.0 MeV)

2. The Reactor Vessel Surveillance program will be enhanced to describe the capsule

storage requirements and the need to retain future pulled capsules.

3. The Reactor Vessel Surveillance program will be enhanced to specify a scheduled

date for withdrawal of capsules including pulling one of the remaining four capsules during the period of extended operation to monitor the effects of long-term exposure to neutron embrittlement for each Salem Unit. Those dates shall be approved by the NRC prior to withdrawal of the capsules, in accordance with 10 CFR Part 50, Appendix H.

4. The Reactor Vessel Surveillance program will be enhanced to incorporate the

requirements for

(1) withdrawing the remaining capsules when the monitor capsule is withdrawn during the period of extended operation and placing them in storage for the purpose of reinstituting the Reactor Vessel Surveillance Program if required, i.e.,

if the reactor vessel exposure conditions (neutron flux, spectrum, irradiation temperature, etc.) are altered, and subsequently the basis for the projection to 60 years warrant the reinstitution, and

(2) changes to the reactor vessel exposure conditions and the potential need to re-institute a vessel surveillance program will be discussed with the NRC staff prior to changing the plant's licensing basis.

5. Enhancements to the current Reactor Vessel Surveillance program will be made to

require that if future plant operations exceed the limitations or bounds specified for cold leg temperatures (vessel inlet) or higher fluence projections, then the impact of plant operation changes on the extent of reactor vessel embrittlement will be evaluated and the NRC shall be notified.

a. Inlet Temperature Range Limitation: 525°F (min) to 590°F (max)b. Fluence Limitation (max.): 1.00 x 1020 n/cm2 (E > 1.0 MeV)

The inspectors verified the program changes, required by the commitment, were made.

The Inlet Temperature Range Limitation of 525°F to 590°F is stated in ER-SA-370-1001, Revision 0, Reactor Vessel Surveillance, 5.6.1., and the fluence limitation of 1.00 x 1020 n/cm2 (E > 1.0 MeV) is stated in ER-SA-370-1001, Revision 0, Reactor Vessel Surveillance, 5.6.2.

ER-SA-370-1001, Revision 0, Reactor Vessel Surveillance, 5.6.3 describes the capsule storage requirements and the need to retain future pulled capsules. An enhancement to the procedure to stipulate the requirement to withdraw a capsule during the extended period of operation was also confirmed by the inspectors.

Commitment 21 Selective Leaching of Materials is a new program that will include one-time inspections of a representative sample of susceptible components to determine where loss of material due to selective leaching is occurring. A sample size of 20% of susceptible components will be subjected to a one-time inspection with a maximum of 25 inspections for each of the susceptible material groups. Where selective leaching is identified, further aging management activities will be implemented such that the component intended function is maintained consistent with the current licensing basis through the period of extended operation.

The inspectors verified that selective leaching was identified in 6 of the 12 samples reviewed by the NRC. Copper Alloy with >15% zinc, subject to a treated water environment has not been inspected. The samples, for this combination, are scheduled to be tested in September 2015 and January 2016. The samples of Copper Alloy with

>15% zinc in a closed-cycle cooling water environment have shown no signs of leaching.

The samples affected by leaching were observed in gray cast iron subject to raw water.

The plant systems affected are the Fire Protection and Heating Water/Heating Steam.

One removed sample of pipe in the Fire Water system had a greater than 62% wall loss.

For the sample with this degree of loss, the inspectors verified the calculation supporting a minimum wall of 0.0200 for a design pressure of 125 psig. The inspectors also reviewed the results of the one-time inspections in the soil environment and noted that one opportunistic inspection was remaining, with no positive results for leaching in this environment to date.

Commitment 23 The one-time Inspection of (ASME) Code Class 1 Small Bore Piping aging management program is a new program that manages cracking due to thermal and mechanical loading or intergranular stress corrosion in stainless steel ASME Code Class 1 piping, fittings, and branch connections less than 4 inches nominal pipe size (NPS) and greater than or equal to NPS 1 (Table IWB-2500-1, Examination Category B-J, Examination Category B-J, Item No. B9.21)

This program is consistent with NUREG-1801 with the following exception and enhancement:

• Exception - Salem uses a more recent revision to the MRP issue regarding Thermal Fatigue; and;

• Enhancement - Salem Units 1 and 2 will perform four volumetric examinations, two per unit, from a population of 36 susceptible class 1 small-bore socket welds on Unit 1 and 34 susceptible class 1 small-bore socket welds on Unit 2. These inspections will be performed prior to entering the period of extended operation.

The inspectors reviewed program documentation, qualified inspection procedures, and observed a demonstration of the phased array ultrasonic examination methodology for these inspections, and discussed the status of implementation of the commitment with PSEG technical and management personnel. The inspectors verified that the implementation of the One-Time Inspection of American Society of Mechanical Engineers (ASME), Boiler and Pressure Vessel, Code Class 1 small-bore piping program will provide reasonable assurance that aging effects will be managed such that structures, systems, and components within the scope of this program will continue to perform their intended function(s) during the extended period of operation Commitment 24 External Surfaces Monitoring is a new program that directs visual inspections of components such as piping, piping components, ducting and other components in the scope of license renewal, exposed to an air environment, to manage aging effects.

The inspectors reviewed ER-AA-700-1012, Revision 0, External Surfaces Monitoring Aging Management Program and ER-AA-2030-1001, Revision 0, License Renewal System Manager Walk-downs. The inspectors noted the use of these procedures was initiated by Maintenance Item 13010521 which generated the implementing work order 30262596 to accomplish this commitment.

Commitment 25 The flux Thimble Tube Inspection Program is a new aging management program that manages the loss of material due to thinning/wear of the flux thimble tube wall materials through eddy current inspections of the thimble tube outer wall thickness and measurement of flux thimble tube wear rates. The flux thimble outer tube is part of the reactor coolant system pressure boundary. This program is consistent with NUREG-1801 and NRC Bulletin 88-09. This program will conduct baseline inspections of the flux thimble tubes during 1R25 (Fall 2017) for Unit 1 and 2R24 (Spring 2020) for Unit 2 using inspection methods, such as phased array eddy current testing, to be implemented throughout the period of extended operation.

Flux thimble tubes are subject to loss of material at locations in the reactor vessel where flow induced fretting causes wear at discontinuities in the path from the reactor vessel instrument nozzle to the fuel assembly instrument guide tube. The inspectors determined that Salem Flux Thimble Tube Program will measure and trend the outer tubing wall thickness (primary coolant pressure boundary) measurements and wear rates. Subsequent inspections will be scheduled based upon wear rate evaluations and/or tube replacements to ensure the intended function of the reactor coolant pressure boundary is maintained throughout the period of extended operation (PEO).

The inspectors verified that the implementation of the Flux Thimble Tube Inspection Program will provide reasonable assurance that the aging effects will be managed such that structures, systems, and components within the scope of this program will continue to perform their intended function(s) during the period of extended operation.

Commitment 28 ASME Section XI, Subsection IWE is an existing program that will be enhanced to include:

1. Inspection of a sample of the inaccessible liner covered by insulation and lagging

once prior to the period of extended operation and every 10 years thereafter. Should unacceptable degradation be found additional insulation will be removed as necessary to determine extent of condition in accordance with the corrective action process. Prior to the period of extended operation.

• The samples shall include 57 randomly selected containment liner insulation panels per unit.

• The randomly selected containment liner insulation panels will not include containment liner insulation panels previously removed to allow for inspection;

• The examination will be performed by either removing the containment liner insulation panels and performing a visual inspection, or by using a pulsed eddy current (PEC) remote inspection, with the containment liner insulation left in place, to detect evidence of loss of material. If evidence of loss of material is detected using PEC, the containment liner insulation panel will be subsequently removed to allow for visual and UT examinations;

• All inspections will be completed by August 2016 for both Salem Units.

Approximately one third of the 57 inspections will be completed during each refuel outage (Salem Unit 1 involves the following refuel outages: spring 2013, fall 2014, and spring 2016. Salem Unit 2 involves the following refuel outages:

Fall 2012, spring 2014, and fall 2015). It is acceptable to perform greater than one third of the inspections in any refuel outage to accelerate the inspection schedule.

During the period of extended operation:

• One containment liner insulation panel will be selected, at random, for removal from each quadrant, during each of the three periods in an Inspection Interval.

Therefore, a total of 12 containment liner insulation panels will be selected, in each unit, during each ten year Inspection Interval, to allow for examination of the containment liner behind the containment liner insulation;

• The randomly selected containment liner insulation panels in each quadrant will not include containment liner insulation panels previously selected.

2. Visual inspection of 100% of the moisture barrier, at the junction between the

containment concrete floor and the containment liner, will be performed in accordance with ASME Section XI, Subsection IWE program requirements, to the extent practical within the limitation of design, geometry, and materials of construction of the components. The bottom edge of the stainless steel insulation lagging will be trimmed, if necessary, to perform the moisture barrier inspections.

This inspection will be performed prior to the period of extended operation, and on a frequency consistent with IWE inspection requirements thereafter. Should unacceptable degradation be found, corrective actions, including extent of condition, will be addressed in accordance with the corrective action process.

As a follow-up to inspections performed during the 2009 refueling outage, the following specific corrective actions will be performed on Unit 2 prior to entry into the period of extended operation:

• Examine the accessible 3/4 knuckle plate. If corrosion is observed to extend below the surface of the moisture barrier, excavate the moisture barrier to sound metal below the floor level and perform examinations as required by IWE;

• Perform remote visual inspections, of the six capped vertical leak chase channels, below the containment floor to determine extent of condition;

• Remove the concrete floor and expose the 1/4 containment liner plate (floor) for a minimum of two of the vertical leak chase channels with holes. Perform examination of exposed 1/4 containment liner plate (floor) as required by IWE.

Additional excavations will be performed, if necessary, depending upon conditions found at the first two channels;

• Remove 1/2 containment liner insulation panels, adjacent to accessible areas where there are indications of corrosion, to determine the extent of condition of the existing corroded areas of the containment liner plate;

• Perform augmented examinations of the areas of the 1/2 containment liner plate behind insulation panels, where loss of material was previously identified, in accordance with IWE-2420;

• Examine 100% of the moisture barrier in accordance with IWE- 2310 and replace or repair the moisture barrier to meet the acceptance standard in IWE-3510.

As a follow-up to inspections performed during the 2010 refueling outage, the following specific corrective actions will be performed on Unit 1 prior to entry into the period of extended operation:

• Perform augmented examinations of the 3/4 containment liner (knuckle plate) at 78 elevation in accordance with IWE-2420;

• Perform augmented examinations of the areas of the 1/2 containment liner plate behind insulation panels, where loss of material was previously identified, in accordance with IWE-2420;

• Remove 1/2 containment liner insulation panels, adjacent to accessible areas where there are indications of corrosion, to determine the extent of condition of the existing corroded areas of the containment liner plate.

3. ASME Section XI, Subsection IWE program scope will be revised to include the

following welds that are currently exempted from Subsection IWE and governed under ASME Section XI, Subsection IWB or IWC. The scope of the revision will include the cap plate to penetrating pipe pressure boundary welds, for penetrating pipe constructed of stainless steel for those penetrations with a normal operating temperature greater than 140 degrees F.

4. Owner augmented inspections will be performed at the Salem Unit 1 and Unit 2 area

of the Containment liner, under the fuel transfer canal and behind the Containment liner insulation, which are subjected to leaks from the reactor cavity. These owner augmented inspections will be performed on a frequency of once per Containment Inservice Inspection Period, starting with the current Period. These owner augmented inspections will continue, under the IWE program, as long as leakage from the reactor cavity or fuel transfer canal is observed between the Containment liner and the Containment liner insulation, including during the PEO.

The inspectors selected and reviewed Notification 20603606, containing a technical evaluation of a laminar flaw discovered in the liner at Panel 61, Elevation 100 feet to determine the IWE program was being implemented.

1. The inspectors reviewed Order 20587461/60107638 containing IWE General Visual

Examination reports 820202, 820302, 860570, 860580 reporting the results of the visual examination of 34 visual examinations of randomly selected insulation panels.

The inspectors noted the area under each panel was also interrogated by ultrasonic thickness gauging. The inspectors reviewed Ultrasonic Thickness gauging report 850140, containing the results of the inspection of the area under thirty eight insulation liner panels. The inspectors reviewed the inspection plan, including a summary of all the inspections completed with the program owner and verified the number of randomly inspected panels exceed the 57 required by the commitment.

2. The inspectors reviewed Reports 820000, 820100, 820200, and 820300 reporting

the results of the visual examination of the containment bottom test channels. The inspectors also reviewed a sample of the reports detailing the inspections of the moisture barrier, at the junction between the containment concrete floor and the containment liner. The inspectors noted the bottom edge of the stainless steel insulation lagging was trimmed in all cases to facilitate inspection.

3. The inspectors reviewed PSEG procedure ER-AA-330, Revision 11, Conduct of

Inservice Inspection Activities, ER-AA-330-007, Revision 9, Visual Examination of Section XI Class MC Surfaces and Class CC Liner, and OU-AA-335-018, Revision 7, Detailed and General, VT-1 and VT-3 Visual Examination of ASME Class MC and CC Containment Surfaces and Components, to determine that the ASME Section XI, Subsection IWE program scope was revised to include the welds that are currently exempted from Subsection IWE and governed under Section XI, Subsection IWB or IWC. The inspectors confirmed the scope of the revision included the cap plate to penetrating pipe pressure boundary welds, for penetrating pipe constructed of stainless steel for those penetrations with a normal operating temperature greater than 140 degrees F.

4. The inspectors reviewed Notification 20597461 reporting the results of the Salem

Unit 1 augmented inspection of the containment liner subject to leaks from the reactor cavity and fuel transfer channel. The inspection interrogated 29 panels for signs of damage, by removing the insulations panel, performing a visual inspection, and ultrasonically determining the thickness of the liner. The inspectors noted this inspection was repeated for Salem Unit 2 under order 60100367.

Commitment 30 ASME Section XI, Subsection IWF The inspectors verified that PSEG complies with the requirements of ASME Section XI, Subsection IWF by reviewing ER-AA-330, Revision 11, Conduct of Inservice Inspection Activities, and ER-AA-330-003, Revision 7, Inservice Inspection of Section XI Component Supports. The inspectors reviewed selected work orders (WO 50132371, 50145481, 50158530, 50172501) to verify the program was being implemented.

Commitment 32 Masonry Wall is an existing program that will be enhanced to include:

3. Specify an inspection frequency of not greater than 5 years for masonry walls.

PSEG committed to enhance the scope of this program to include

(1) Fire Pump House, Masonry Wall Fire Barriers, the clean and controlled facilities buildings, SBO Yard Buildings, Service Building, and Turbine Building;

(2) Add an examination checklist for wall inspections; and

(3) Specify an inspection frequency of no greater than five

(5) years to be implemented before the period of extended operation.

By review of documentation included in the AMP B.2.1.32, and Structural Monitoring Procedure, which includes Masonry Walls inspection and assessment, and the work orders (WO# 30215601, 30265835, 30277793, 30222114, 30266085, and 30277734),the inspectors verified that the Masonry Wall program was revised with these enhancements.

Commitment 33 Structures Monitoring is an existing program that will be enhanced to include:

2. Concrete structures will be observed for a reduction in equipment anchor capacity

due to local concrete degradation. This will be accomplished by visual inspection of concrete surfaces around anchors for cracking and spalling;

3. Clarify that inspections are performed for loss of material due to corrosion and pitting

of additional steel components, such as embedments, panels and enclosures, doors, siding, metal deck, and anchors;

4. Require inspection of penetration seals, structural seals, and elastomers, for

degradations that will lead to a loss of sealing by visual inspection of the seal for hardening, shrinkage and loss of strength;

5. Require the following actions related to the spent fuel pool liner:

• Perform periodic structural examination of the Fuel Handling Building per ACI 349.3R to ensure structural condition is in agreement with the analysis;

• Monitor telltale leakage and inspect the leak chase system to ensure no blockage;

• Test water drained from the telltales and seismic gap for boron, chloride, iron, and sulfate concentrations; and pH. Acceptance criteria will assess any degradation from the borated water. Sample readings outside the acceptance criteria will be entered into and evaluated in the corrective action program;

• Perform one shallow core sample in each of the Unit 1 Spent Fuel Pool walls (east and west) that have shown ingress of borated water through the concrete.

The core samples will be examined for degradation from borated water. Also the core samples (east and west walls) will expose rebar, which will be examined for signs of corrosion. The core sample from the west wall will be taken by the end of 2013 and the core sample from the east wall will be taken by the end of 2015;

• Perform a structural examination per ACI 349.3R every 18 months of the Unit 1 Spent Fuel Pool wall in the sump room where previous inspections have shown ingress of borated water through the concrete.

6. Require monitoring of vibration isolators, associated with component supports other

than those covered by ASME XI, Subsection IWF;

8. Parameters monitored for wooden components will be enhanced to include:

Change in Material Properties, Loss of Material due to Insect Damage and Moisture Damage;

9. Specify an inspection frequency of not greater than 5 years for structures including

submerged portions of the service water intake structure.

10. Require individuals responsible for inspections and assessments for structures to have a B.S. Engineering degree and/or Professional Engineer license, and a minimum of four years of experience working on building structures.

11. Perform periodic sampling, testing, and analysis of ground water chemistry for pH, chlorides, and sulfates on a frequency of 5 years. Groundwater samples in the areas adjacent to Unit 1 containment structure and Unit 1 auxiliary building will also be tested for boron concentration.

12. Require supplemental inspections of the affected in scope structures within 30 days following extreme environmental or natural phenomena (large floods, significant earthquakes, hurricanes, and tornadoes).

13. Perform a chemical analysis of ground or surface water in-leakage when there is significant in-leakage or there is reason to believe that the in-leakage may be damaging concrete elements or reinforcing steel.

14. Implementing procedures will be enhanced to include additional acceptance criteria details specified in ACI 349.3R-96.

15. When the reactor cavity is flooded up, Salem will periodically monitor the telltales associated with the reactor cavity and refueling canal for leakage. If telltale leakage is observed, then the pH of the leakage will be measured to ensure that concrete reinforcement steel is not experiencing a corrosive environment. In addition, Salem will periodically inspect the leak chase system associated with the reactor cavity and refueling canal to ensure the telltales are free of significant blockage. Salem will also inspect concrete surfaces for degradation where leakage has been observed, in accordance with this Program.

PSEG committed to enhance the existing Structural Monitoring Program (SMP) to include

(1) additional structures and components (listed in AMP A.2.1.33);

(2) Observe/Assess structures for reduction in equipment anchor capacity due to local concrete degradation;

(3) performance loss/degradation in structural equipment and component (structural material/Steel) due to corrosion and/or pitting;

(4) inspection/assessment of penetration seals, structural seals, and elastomers for degradation;

(5) enhanced inspections/actions required for structures, equipment, and components (listed in AMP A.2.1.33) to effective aging manage of these structures, equipment, and components.

By review of relevant documents, visual examinations, and discussions with engineering and management personnel, the inspectors noted that the SMP was implemented by an overarching Procedure ER-AA-310-101, Condition Monitoring of Structures. The procedure includes inspection, examination, monitoring and assessments of all structures within the scope of aging management, e. g., Masonry Walls, Concrete, Structural Steel, Water Control (submerged and exposed) structures. The procedure prescribes monitoring requirements, examinations, documentation and acceptance criteria for inspections through specific program procedure attachments related to different items covered in the scope of aging management. Based on the review of documentation, examinations and discussions with cognizant personnel, the inspectors verified that PSEG has fulfilled the commitment to enhance the Structural Monitoring Program.

Commitment 36 The Electrical Cables and Connectors Not Subject to 10 CFR 50.49 Environmental Qualification Requirements program has been developed. This program is a new program to manage the aging of non-EQ cables and connections specifically in localized adverse environments where conditions are more severe than other areas of the plant.

These harsh environments include areas where cables and connections are subjected to environmental conditions which are in excess of 60 year service limiting environments (excessive heat, radiation or moisture). After an initial inspection of severe localized condition areas, PSE&G will conduct visual inspections on applicable cables and connections in those localized adverse environments on a ten year frequency throughout the period of extended operation.

The inspectors reviewed documentation and discussed the status of implementation of this commitment with the PSEG technical and management personnel. The inspectors verified that the applicant had established a program for the electrical cables and connectors not subject to 10 CFR 50.49 environmental qualification (EQ) requirements that are required for license renewal. The program will concentrate on inspecting accessible non-EQ cables and connectors located in adverse localized environments, where the effects of aging may be accelerated due to excessive heat, radiation, or moisture. The program required that visual inspections be performed prior to the period of extended operation and at least once every ten years, thereafter. The inspectors verified, through review of inspection results, that the appropriate inspections had been completed. The inspectors verified that the implementation of the Electrical Cables and Connectors Not Subject to 10 CFR 50.49 Environmental Qualification Requirements program has been developed and was being implemented.

Commitment 38 The Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Aging Management Program is a new program that manages the aging of inaccessible medium voltage cables exposed to significant moisture simultaneously with significant voltage. The scope of the program includes the cables for the 13 and 14 (23 and 24) Station Power Transformers, the Service Water Pumps, and the13 kv bus. The organic polymer materials of the cable insulation are subject to an adverse localized environment (standing water). The program provides for managing localized damage and breakdown of insulation leading to moisture intrusion and water trees.

The inspectors verified that this program is implemented through periodic inspections of cable vaults containing in-scope medium voltage cables to ensure they are free of standing water, and periodic tan-delta testing for insulation degradation for the in-scope cables. Cable vault inspections are determined by operating experience to ensure that the cables are not subjected to standing water, not to exceed one year. Tan-delta testing of cable insulation will be done on a six year frequency. The inspectors verified that The Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Aging Management Program was established and implemented.

Commitment 40 Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements is a new program used to confirm the slow progression or absence of aging effects with respect to electrical cable connection stressors. A representative sample of non-environmentally qualified electrical cable connections will be selected for one-time testing consideration in the following applications: (medium voltage and low voltage), (high circuit loading), and location, with respect to connection stressors.

Approximately 200 - 300 cable connectors will be tested for Salem Unit 1 and Salem Unit 2, with an acceptance resistance criteria of >125 micro-ohms. These inspections will be completed prior to the start of the period of extended operation at each Salem unit. Contact resistance testing is the primary examination technique, and thermography of metallic cable connections will supplement this sampling.

The inspectors reviewed documentation and discussed the status of implementation of this commitment with PSEG technical and management personnel. The inspectors verified that PSEG had established a program for the electrical cables and connectors not subject to 10 CFR 50.49 environmental qualification requirements that are required for license renewal. The program will concentrate on inspecting accessible non-environmentally qualified cables and connectors located in adverse localized environments, where the effects of aging may be accelerated due to excessive heat, radiation, or moisture. The program required that visual inspections be performed prior to the period of extended operation and at least once every ten years thereafter. The inspectors verified the appropriate inspections had been completed via review of recent inspection records. The inspectors verified that the implementation of the Electrical Cables and Connectors Not Subject to 10 CFR 50.49 Environmental Qualification Requirements program will provide reasonable assurance that the aging effects will be managed such that structures, systems, and components within the scope of this program will continue to perform their intended function(s) during the period of extended operation.

Commitment 43 Aboveground Non-Steel Tanks is a new program that will manage loss of material of outdoor non-steel tanks. The Aboveground Non-Steel Tanks program will include a UT wall thickness inspection of the bottom of the tanks. The UT measurements will be taken to ensure that significant degradation is not occurring and that the component intended function will be maintained during the extended period of operation.

The inspectors reviewed the results of PSEG work orders for the Auxiliary Feedwater, Refueling Water, Primary Water and Demineralized Water Storage Tanks to ensure that ultrasonic thickness testing of the tank bottoms was performed to provide a baseline for future corrosion rate determination and to ensure that significant degradation is not occurring. Additionally, the inspectors performed walk-downs of the external surfaces of the tanks to ensure that required seals between the tank bottom and foundation were present as well as observing the tank surfaces for signs of corrosion.

Commitment 45 Boral Monitoring is an existing program that will be enhanced to include:

The program will be enhanced to perform a neutron attenuation measurement on one each of the three (no vent holes, one vent holes and two vent holes) flat plate sandwich Boral test coupons during the first three two-year inspection frequency periods and every six years thereafter for the Exxon spent fuel storage rack assemblies.

The program will be enhanced to include acceptance criteria of the neutron attenuation measurement on the Boral test coupons for the Exxon spent fuel storage rack assemblies: A decrease of no more than 5% in Boron-10 content as determined by neutron attenuation measurements. The benchmark Boron-10 content used for comparison will be based on the nominal B-10 areal density in the design basis specification.

The inspectors reviewed the PSEG document S1.RE-PT.SF-0001(Q), Fuel Storage Cell Surveillance Program, to verify that neutron attenuation measurement of Exxon spent fuel pool storage rack boral test coupons had been incorporated into the surveillance program. The inspectors also verified that the acceptance criteria for the Exxon spent fuel pool storage rack boral test coupons was revised to reflect a decrease of no more than 5% in Boron-10 content as determined by the neutron attenuation measurements.

Commitment 49 Revised Pressure-Temperature (P-T) limits will be submitted to the NRC when necessary to comply with 10 CFR 50 Appendix G.

As noted in the Final Safety Analysis Report update, for Pressurized Thermal Shock at A.4.2.3, the reactor vessel materials that exceed a surface fluence of 1.0 E+17 c/cm2 at E > 1.0 MeV at 50 effective full power years (end of the extended period of operation)are below the RTpts screening criteria values of 270°F, for axially oriented welds and plates and forgings, and 300°F, for circumferentially oriented welds, at 50 effective full power years. This obviates the need, during the extended period of operation to revise the Pressure-Temperature limits. The inspectors observed the commitment is codified, however, in the updated Final Safety Analysis Report in the commitment listing at A.5.

Commitment 50 The Steam Generator Divider Plate Inspection Program is a new program being developed to address industry incidents of SG divider plate cracking. In response to foreign industry operating plant experience concerning SG divider plate cracking, the Electric Power Research Institute (EPRI) has concluded that Steam Generator Divider Plate cracking is not a safety concern. Current industry plans are to study the potential for divider plate crack growth propagation and develop an industry-applied resolution to the concern through the EPRI Steam Generator Management Program (SGMP)

Engineering and Regulatory Technical Advisory Group. This industry-led effort is expected to begin in 2011 and is expected to be completed within two years. PSE&G is committed to developing a program to complete inspections on each Salem Unit prior to the period of extended operation.

PSEG completed a Visual Test, Type 3, inspection of the divider plates in all four Unit 1 steam generators in a 2004 outage. These inspections did not show Alloy 600 degradation or weld cracks. In a 2010 outage, PSEG completed a visual examination of the Alloy 600 bottom bowl drain and found no evidence of boron leakage.

This inspection was performed in accordance with Code Case N-722 as amended by Title 10 of the Code of Federal Regulations part 50.55a.

Salem will perform an inspection of each of the four

(4) Unit 1 steam generators to assess the condition of the divider plate assembly. The examination technique(s) used will be capable of detecting primary water stress corrosion cracking (PWSCC) in the steam generator divider plate assemblies and the associated welds. The steam generator divider plate inspections will be completed within the first ten

(10) years of the Salem Unit 1 period of extended operation.

The inspectors verified that the implementation of the steam generator divider plate inspection program will provide reasonable assurance that the aging effects will be managed such that structures, systems, and components within the scope of this program will continue to perform their intended function(s) during the period of extended operation.

Commitment 51 The Steam Generator (SG) Tube-to-Tube Sheet Weld Cracking Program is a new program being developed to determine if Primary Water Stress Corrosion Cracking (PWSCC) is present in SG tube-to-tubesheet welds.

PSEG will develop a plan for each Unit to address the potential for cracking of the primary to secondary pressure boundary due to primary water stress corrosion cracking of the tube-to-tube sheet welds. The plan for Salem Unit 1 will consist of two options:

Option 1:

Analysis:

If the analysis option is chosen to implement the requirements of the plan, including obtaining any required NRC approvals by April 2018, for Unit 1, and by April 2028 for Unit 2. Salem Unit 1 will obtain permanent approval for Alternate Repair Criteria from the NRC, or Option 2: Inspection: If steam generator inspections are to be performed, they will be performed between April 2018 and April 2028.

Salem Unit 1 will perform a One-Time inspection of a representative number of tube-to-tube sheet welds in each of the four

(4) steam generators to determine if primary water stress corrosion cracking is present. If weld cracking is identified,

(a) the condition will be resolved through repair or engineering evaluation to justify continued service, as appropriate, and

(b) a periodic monitoring program will be established to perform routine tube-to-tube sheet inspections for the remaining life of the steam generators.

Based on the inspectors review of commitment documentation and review of PSEG plans for implementation, the inspectors verified that the implementation of the steam generator tube-to-tube sheet inspections or analysis options in this program will provide reasonable assurance that the aging effects contained in this program will be managed such that the structures, systems, and components within the scope of this program will continue to perform their intended function(s) during the period of extended operation.

Commitment 52 Salem will perform a review of design basis ASME Code Class 1 fatigue evaluations to determine whether the NUREG/CR-6260 based locations that have been evaluated for the effects of the reactor coolant environment on fatigue usage are the limiting locations for the Salem plant configuration. If more limiting locations are identified, the most limiting location will be evaluated for the effects of the reactor coolant environment on fatigue usage. If any of the limiting locations consist of nickel alloy, NUREG/CR-6909 methodology for nickel alloy will be used in the evaluation.

The inspectors reviewed CN-PAFM-13-78, Revision 0, Salem Units 1 and 2 Environmental Fatigue Screening Evaluation. This evaluation reviewed the design basis ASME Code Class 1 fatigue evaluations to determine whether the NUREG/CR-6260 locations, evaluated for the effects of reactor coolant environment on fatigue usage, are the limiting locations for the Salem plant configuration. The inspectors noted the analysis was performed in three phases. The first phase of the evaluation used criteria to screen out the non-limiting locations from further consideration. The second phase of the analysis reviewed the fatigue calculation, for the locations identified in the first phase as possibly limiting, to determine if the NUREG/CR-6260 locations were more limiting.

Phase 3 of the evaluation, which has not been performed yet, will perform a detailed environmentally assisted fatigue analysis for the components and locations that remain.

At this point the analysis will be performed on:

• Unit 2 CRDM Lower Joint

• Units 1 and 2 Normal Letdown 3 inch Valve Weld

• Units 1 and 2 Normal Letdown 12 inch by 3 inch Reducing Connection

• Units 1 and 2 Safety Injection Accumulator 10 inch by 3/4 inch Branch Connection

• (Pending piping load clarification) Units 1 and 2 Pressurizer Relief Valve Weld

• (Pending piping load clarification) Pressurizer Relief 3 inch by 3/4 inch Branch Connection Commitment 53 Salem Fatigue Calculations using WESTEMSTM program.

The inspectors noted that Salem will include written explanation and justification of any user intervention in future evaluations using the WESTEMS Design CUF (NB-3200 module).

Commitment 54 Salem Fatigue Calculations using WESTEMSTM program Salem will not use or implement the NB-3600 option (module) of the WESTEMS' program in future online fatigue monitoring and design calculations.

The inspectors reviewed CC-AA-309, Revision 10, Control of Design

Analysis.

The inspectors noted 4.3.16 contained prohibitions on the use of the WESTEMSTM program that reflected, verbatim, the commitment language.

b. Findings

No findings were identified in review of these commitments.

4OA6 Meetings

On August 6, 2015, the inspectors presented the inspection results to Mr. John Perry, Salem Site Vice President, and other members of the PSEG staff. The inspectors verified that no proprietary information was retained by the inspectors or documented in this report.

ATTACHMENT:

SUPPLEMENTARY INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

J. Perry, PSEG Nuclear Vice President, Salem Generating Station

C. Schwartz, PSEG Nuclear Vice President Corporate Operations

E. Blocher, STARS Alliance

A. Boyea, PSEG License Renewal Support Team

T. Cox, PSEG Nuclear License Renewal Support Team

P. Fabian, SG Program Engineer, PSE&G

A. Fakhar, PSEG Nuclear, Corporate Engineering Programs

T. Giles, PSEG Nuclear AMP Owner - ISI

K. Hall, PSEG Nuclear License Renewal Team Support

K. Hutko, PSEG Nuclear Hope Creek Aging Management Coordinator

S. Merciel, Ameren Missouri License Renewal at Callaway

M. Olsofsky, Eneron at Diablo Canyon

J. ORourke, PSEG Nuclear Corporate License Renewal Program Owner

J. Owad, PSEG Nuclear AMP Owner - Structures, Coatings

L. Rajkowski, PSEG Nuclear Director Engineering Services

S. Speer, PSEG Nuclear Salem Aging Management Coordinator