ML12354A314

Additional Clarification of Underground Piping Information Provided in Letter NL-12-149 Regarding the License Renewal Application

ML12354A314
Person / Time
Site:	Indian Point
Issue date:	11/29/2012
From:	Dacimo F Entergy Nuclear Northeast
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
NL-12-174
Download: ML12354A314 (29)

Text

SEntergy Enterqy Nuclear Northeast Indian Point Energy Center 450 Broadway, GSB P.O. Box 249 Buchanan, NY 10511-0249 Tel (914) 254-2055 Fred Dacimo Vice President Operations License Renewal NL-12-174 November 29, 2012 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001

REFERENCE:

Additional Clarification of Underground Piping Information Provided in Letter NL-12-149 Regarding the License Renewal Application Indian Point Nuclear Generating Unit Nos. 2 & 3 Docket Nos. 50-247 and 50-286 License Nos. DPR-26 and DPR-64 (1) Entergy letter (NL-12-149), "Clarification of Underground Piping Information Provided in Letter NL-1 1-032 Regarding the License Renewal Application," dated October 18, 2012

Dear Sir or Madam:

Reference 1 provided information on underground piping (piping below grade in air with restricted access) in the IPEC Unit 2 and Unit 3 fuel oil systems, and in the IPEC Unit 3 service water and city water systems. In this letter it was stated that "The above piping will be periodically inspected under the Buried Piping and Tanks Inspection Program at a frequency that meets or exceeds NUREG-1 801 Section XI.M41 guidance for underground piping which will ensure the effects of aging are adequately managed." The NUREG-1 801 recommendation for an inspection frequency of at least once every ten years is provided for piping with preventive measures consisting of coatings in accordance with XI.M41 Table 2b or approved alternative.

The underground piping at IPEC is not provided with such coatings.

Therefore, Entergy is making the following commitment to perform inspections at a frequency of at least once every two years.Commitment 48 Entergy will visually inspect IPEC underground piping within the scope of license renewal and subject to aging management review prior to the period of extended operation and then on a frequency of at least once every two years during the period of extended operation.

This inspection frequency will be maintained unless the piping is subsequently coated in accordance with the preventive actions specified in NUREG-1801 Section XI.M41 as modified by LR-ISG-2011-03. Visual inspections will be supplemented with surface or volumetric non-destructive testing if indications of significant loss of material are observed.

Consistent with revised NUREG-1 801 Section XI.M41, such adverse indications will be entered into the plant corrective action program for evaluation of extent of condition and for determination of appropriate corrective actions (e.g., increased inspection frequency, repair, replacement).

NL-12-174 Page 2 of 2 Commitment 48 is included in the latest list of regulatory commitments provided in Attachment

1. In addition, Attachment 2 identifies associated changes to the Indian Point LRA Updated Final Safety Analysis Report Supplement (Appendix A) and Aging Management Programs and Activities (Appendix B).If you have any questions, or require additional information, please contact Mr. Robert Walpole 914-254-6710.

I declare undor penalty of perjury that the foregoing is true and correct. Executed on Sincpe FRD/rw

Attachment:

1. License Renewal Application IPEC List of Regulatory Commitments Revision 19.2. Changes to the Indian Point LRA Updated Final Safety Analysis Report Supplement (Appendix A) and Aging Management Programs and Activities (Appendix B).cc: Mr. William Dean, Regional Administrator, NRC Region I Mr. Sherwin E. Turk, NRC Office of General Counsel, Special Counsel Mr. Dave Wrona, NRC Branch Chief, Engineering Review Branch I Mr. John Daily, NRC Sr. Project Manager, Division of License Renewal Mr. Douglas Pickett, NRR Senior Project Manager Ms. Bridget Frymire, New York State Department of Public Service NRC Resident Inspector's Office Mr. Francis J. Murray, Jr., President and CEO NYSERDA ATTACHMENT 1 TO NL-12-174 LICENSE RENEWAL APPLICATION IPEC LIST OF REGULATORY COMMITMENTS Rev. 19 ENTERGY NUCLEAR OPERATIONS, INC.INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 & 3 DOCKET NOS. 50-247 AND 50-286 Attachment 1 NL-12-174 Page 1 of 21 List of Regulatory Commitments Rev. 19 The following table identifies those actions committed to by Entergy in this document.Changes are shown as strikethroughs for dele8iGRs and underlines for additions.

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION/ AUDIT ITEM 1 Enhance the Aboveground Steel Tanks Program for IP2: NL-07-039 A.2.1.1 IP2 and IP3 to perform thickness measurements of September 28, A.3.1.1 the bottom surfaces of the condensate storage tanks, 013 B.1.1 city water tank, and fire water tanks once during the lP3: first ten years of the period of extended operation.

December 12, Enhance the Aboveground Steel Tanks Program for 2015 IP2 and IP3 to require trending of thickness measurements when material loss is detected.2 Enhance the Bolting Integrity Program for IP2 and IP3 IP2: NL-07-039 A.2.1.2 to clarify that actual yield strength is used in selecting 2eptember 28, A.3.1.2 to013 B.1.2 materials for low susceptibility to SCC and clarify the prohibition on use of lubricants containing MoS 2 for IP3: NL-07-153 Audit Items bolting. ecember 12, 201,241, The Bolting Integrity Program manages loss of 2015 270 preload and loss of material for all external bolting. I I Attachment 1 NL-12-174 Page 2 of 21 COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION I I_ I/ AUDIT ITEM 3 Implement the Buried Piping and Tanks Inspection Program for IP2 and IP3 as described in LRA Section B.1.6.This new program will be implemented consistent with the corresponding program described in NUREG-1801 Section XI.M34, Buried Piping and Tanks Inspection.

Include in the Buried Piping and Tanks Inspection Program described in LRA Section B.1.6 a risk assessment of in-scope buried piping and tanks that includes consideration of the impacts of buried piping or tank leakage and of conditions affecting the risk for corrosion.

Classify pipe segments and tanks as having a high, medium or low impact of leakage based on the safety class, the hazard posed by fluid contained in the piping and the impact of leakage on reliable plant operation.

Determine corrosion risk through consideration of piping or tank material, soil resistivity, drainage, the presence of cathodic protection and the type of coating. Establish inspection priority and frequency for periodic inspections of the in-scope piping and tanks based on the results of the risk assessment.

Perform inspections using inspection techniques with demonstrated effectiveness.

P2: September 28, 2013 P3: December 12,?015 NL-07-039 NL-07-153 NL-09-106 NL-09-111 A.2.1.5 A.3.1.5 B.1.6 Audit Item 173 NL-11-101 Attachment 1 NL-12-174 Page 3 of 21# COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION I _I / AUDIT ITEM 4 Enhance the Diesel Fuel Monitoring Program to include cleaning and inspection of the IP2 GT-1 gas turbine fuel oil storage tanks, IP2 and IP3 EDG fuel oil day tanks, IP2 SBO/Appendix R diesel generator fuel oil day tank, and IP3 Appendix R fuel oil storage tank and day tank once every ten years.Enhance the Diesel Fuel Monitoring Program to include quarterly sampling and analysis of the IP2 SBO/Appendix R diesel generator fuel oil day tank, IP2 security diesel fuel oil storage tank, IP2 security diesel fuel oil day tank, and IP3 Appendix R fuel oil storage tank. Particulates, water and sediment checks will be performed on the samples. Filterable solids acceptance criterion will be less than or equal to 10mg/l. Water and sediment acceptance criterion will be less than or equal to 0.05%.Enhance the Diesel Fuel Monitoring Program to include thickness measurement of the bottom of the following tanks once every ten years. IP2: EDG fuel oil storage tanks, EDG fuel oil day tanks, SBO/Appendix R diesel generator fuel oil day tank, GT-1 gas turbine fuel oil storage tanks, and diesel fire pump fuel oil storage tank; IP3: EDG fuel oil day tanks, EDG fuel oil storage tanks, Appendix R fuel oil storage tank, and diesel fire pump fuel oil storage tank.Enhance the Diesel Fuel Monitoring Program to change the analysis for water and particulates to a quarterly frequency for the following tanks. IP2: GT-1 gas turbine fuel oil storage tanks and diesel fire pump fuel oil storage tank; IP3: Appendix R fuel oil day tank and diesel fire pump fuel oil storage tank.Enhance the Diesel Fuel Monitoring Program to specify acceptance criteria for thickness measurements of the fuel oil storage tanks within the scope of the program.Enhance the Diesel Fuel Monitoring Program to direct samples be taken and include direction to remove water when detected.Revise applicable procedures to direct sampling of the onsite portable fuel oil contents prior to transferring the contents to the storage tanks.Enhance the Diesel Fuel Monitoring Program to direct the addition of chemicals including biocide when the presence of bioloqical activity is confirmed.

I P2: September 28, 2013 1 P3: December 12,_01.5 NL-07-039 NL-07-153 NL-08-057 A.2.1.8 A.3.1.8 B.1.9 Audit items 128,129, 132, 491,492, 510_______ A- A A Attachment 1 NL-12-174 Page 4 of 21# COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION/ AUDIT ITEM 5 Enhance the External Surfaces Monitoring Program eP2: NL-07-039 A.2.1.10 for IP2 and IP3 to include periodic inspections of eptember 28, A.3.1.10 systems in scope and subject to aging management 013 B.1.11 review for license renewal in accordance with 10 CFR IP3: 54.4(a)(1) and (a)(3). Inspections shall include areas December 12, surrounding the subject systems to identify hazards to 015 those systems. Inspections of nearby systems that could impact the subject systems will include SSCs that are in scope and subject to aging management review for license renewal in accordance with 10 CFR 54.4(a)(2).

6 Enhance the Fatigue Monitoring Program for IP2 to .P2 NL-07-039 A.2.1.11 monitor steady state cycles and feedwater cycles or eptember 28, A.3.1.11 perform an evaluation to determine monitoring is not 013 B.1.12, required.

Review the number of allowed events and NL-07-153 Audit Item resolve discrepancies between reference documents 164 and monitoring procedures.

Enhance the Fatigue Monitoring Program for IP3 to 1P3: include all the transients identified.

Assure all fatigue December 12, analysis transients are included with the lowest 2015 limiting numbers. Update the number of design transients accumulated to date.

Attachment 1 NL-12-174 Page 5 of 21# COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION I_ I / AUDIT ITEM 7 Enhance the Fire Protection Program to inspect external surfaces of the IP3 RCP oil collection systems for loss of material each refueling cycle.Enhance the Fire Protection Program to explicitly state that the IP2 and IP3 diesel fire pump engine sub-systems (including the fuel supply line) shall be observed while the pump is running. Acceptance criteria will be revised to verify that the diesel engine does not exhibit signs of degradation while running;such as fuel oil, lube oil, coolant, or exhaust gas leakage.Enhance the Fire Protection Program to specify that the IP2 and IP3 diesel fire pump engine carbon steel exhaust components are inspected for evidence of corrosion and cracking at least once each operating cycle.Enhance the Fire Protection Program for IP3 to visually inspect the cable spreading room, 480V switchgear room, and EDG room C02 fire suppression system for signs of degradation, such as corrosion and mechanical damage at least once every six months.I P2: September 28, 2013 I P3: December 12, 2015 NL-07-039 A.2.1.12 A.3.1.12 B.1.13 Attachment 1 NL-12-174 Page 6 of 21 COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION I_ I I / AUDIT ITEM 8 Enhance the Fire Water Program to include inspection of IP2 and IP3 hose reels for evidence of corrosion.

Acceptance criteria will be revised to verify no unacceptable signs of degradation.

Enhance the Fire Water Program to replace all or test a sample of IP2 and IP3 sprinkler heads required for 10 CFR 50.48 using guidance of NFPA 25 (2002 edition), Section 5.3.1.1.1 before the end of the 50-year sprinkler head service life and at 10-year intervals thereafter during the extended period of operation to ensure that signs of degradation, such as corrosion, are detected in a timely manner.Enhance the Fire Water Program to perform wall thickness evaluations of IP2 and IP3 fire protection piping on system components using non-intrusive techniques (e.g., volumetric testing) to identify evidence of loss of material due to corrosion.

These inspections will be performed before the end of the current operating term and at intervals thereafter during the period of extended operation.

Results of the initial evaluations will be used to determine the appropriate inspection interval to ensure aging effects are identified prior to loss of intended function.Enhance the Fire Water Program to inspect the internal surface of foam based fire suppression tanks.Acceptance criteria will be enhanced to verify no significant corrosion.

I P2: September 28, 2013 IP3: December 12, 2015 NL-07-039 NL-07-153 NL-08-014 A.2.1.13 A.3.1.13 B.1.14 Audit Items 105, 106 Attachment 1 NL-12-174 Page 7 of 21# COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION I_ / AUDIT ITEM 9 Enhance the Flux Thimble Tube Inspection Program for IP2 and IP3 to implement comparisons to wear rates identified in WCAP-12866.

Include provisions to compare data to the previous performances and perform evaluations regarding change to test frequency and scope.Enhance the Flux Thimble Tube Inspection Program for IP2 and IP3 to specify the acceptance criteria as outlined in WCAP-12866 or other plant-specific values based on evaluation of previous test results.Enhance the Flux Thimble Tube Inspection Program for IP2 and IP3 to direct evaluation and performance of corrective actions based on tubes that exceed or are projected to exceed the acceptance criteria.

Also stipulate that flux thimble tubes that cannot be inspected over the tube length and cannot be shown by analysis to be satisfactory for continued service, must be removed from service to ensure the integrity of the reactor coolant system pressure boundary.I P2: September 28, 2013 1P3: December 12, 2015 NL-07-039 A.2.1.15 A.3.1.15 B.1.16 a. I I I Attachment 1 NL-12-174 Page 8 of 21# COMMITMENT IMPLEMENTATION1 SOURCE RELATED SCHEDULE LRA SECTION/ AUDIT ITEM 10 Enhance the Heat Exchanger Monitoring Program for IP2 and IP3 to include the following heat exchangers in the scope of the program.* Safety injection pump lube oil heat exchangers

• RHR heat exchangers" RHR pump seal coolers" Non-regenerative heat exchangers" Charging pump seal water heat exchangers

• Charging pump fluid drive coolers* Charging pump crankcase oil coolers* Spent fuel pit heat exchangers

• Secondary system steam generator sample coolers" Waste gas compressor heat exchangers

• SBO/Appendix R diesel jacket water heat exchanger (IP2 only)Enhance the Heat Exchanger Monitoring Program for IP2 and IP3 to perform visual inspection on heat exchangers where non-destructive examination, such as eddy current inspection, is not possible due to heat exchanger design limitations.

Enhance the Heat Exchanger Monitoring Program for IP2 and IP3 to include consideration of material-environment combinations when determining sample population of heat exchangers.

Enhance the Heat Exchanger Monitoring Program for IP2 and IP3 to establish minimum tube wall thickness for the new heat exchangers identified in the scope of the program. Establish acceptance criteria for heat exchangers visually inspected to include no indication of tube erosion, vibration wear, corrosion, pitting, fouling, or scaling.I P2: September 28, 2013 I P3: December 12, 2015 NL-07-039 NL-07-153 NL-09-018 A.2.1.16 A.3.1.16 B.1.17, Audit Item 52 11 Deleted NL-09-056 NL-1 1-101 Attachment 1 NL-12-174 Page 9 of 21# COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION/ AUDIT ITEM 12 Enhance the Masonry Wall Program for IP2 and IP3 IP2: NL-07-039 A*2.1.18 to specify that the IP1 intake structure is included in September 28, A.3.1.18 the program. 2013 B.1.19 IP3: December 12, 2_015 13 Enhance the Metal-Enclosed Bus Inspection Program to add IP2 480V bus associated with substation A to the scope of bus inspected.

Enhance the Metal-Enclosed Bus Inspection Program for IP2 and IP3 to visually inspect the external surface of MEB enclosure assemblies for loss of material at least once every 10 years. The first inspection will occur prior to the period of extended operation and the acceptance criterion will be no significant loss of material.Enhance the Metal-Enclosed Bus Inspection Program to add acceptance criteria for MEB internal visual inspections to include the absence of indications of dust accumulation on the bus bar, on the insulators, and in the duct, in addition to the absence of indications of moisture intrusion into the duct.Enhance the Metal-Enclosed Bus Inspection Program for IP2 and IP3 to inspect bolted connections at least once every five years if performed visually or at least once every ten years using quantitative measurements such as thermography or contact resistance measurements.

The first inspection will occur prior to the period of extended operation.

The plant will process a change to applicable site procedure to remove the reference to "re-torquing" connections for phase bus maintenance and bolted connection maintenance.

I P2:; eptember 28, 013 1P3: December 12, 2015 NL-07-039 NL-07-153 NL-08-057 A.2.1.19 A.3.1.19 B.1.20 Audit Items 124, 133, 519 14 Implement the Non-EQ Bolted Cable Connections P2: NL-07-039 A.2.1.21 Program for IP2 and IP3 as described in LRA Section September 28, A.3.1.21 B. 1.22. 2013 B.1.22 I P3: IDecember 12, 1_ _ __2__ 015 1 1 Attachment 1 NL-12-174 Page 10 of 21# COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION/ AUDIT ITEM 15 Implement the Non-EQ Inaccessible Medium-Voltage 1P2: NL-07-039 A.2.1.22 Cable Program for IP2 and IP3 as described in LRA September 28, A.3.1.22 Section B.1.23. 2013 B.1.23 NL-07-153 Audit item This new program will be implemented consistent with IP3: 173 the corresponding program described in NUREG- December 12, NL-1 1-032 1801 Section XI.E3, Inaccessible Medium-Voltage 2015 Cables Not Subject To 10 CFR 50.49 Environmental NL-1 1-096 Qualification Requirements.

NL-11-101 1P2: NL-07-039 A.2.1.23 16 Implement the Non-EQ Instrumentation Circuits Test ept e 20, A.3.1.23 Review Program for IP2 and IP3 as described in LRA eptember 28, Section B.1.24. 2013 B.1.24 NL-07-153 Audit item This new program will be implemented consistent with IP3: 173 the corresponding program described in NUREG- December 12, 1801 Section XI.E2, Electrical Cables and 2015 Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits.17 Implement the Non-EQ Insulated Cables and IP2: NL-07-039 A.2.1*24 Connections Program for IP2 and iP3 as described in September 28, A.3.1.24 LRA Section B.1.25. 2013 B.1.25 NL-07-153 Audit item This new program will be implemented consistent with IP3: 173 the corresponding program described in NUREG- December 12, 1801 Section XI.E1, Electrical Cables and 2015 Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements.

Attachment 1 NL-12-174 Page 11 of 21# COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION/ AUDIT ITEM 18 Enhance the Oil Analysis Program for IP2 to sample IP2: NL-07-039 A.2.1.25 and analyze lubricating oil used in the SBO/Appendix September 28, A.3.1.25 an naye013 NL-1 1-101 B.1.26 R diesel generator consistent with the oil analysis for other site diesel generators.

IP3: Enhance the Oil Analysis Program for IP2 and IP3 to December 12, sample and analyze generator seal oil and turbine 2015 hydraulic control oil.Enhance the Oil Analysis Program for IP2 and IP3 to formalize preliminary oil screening for water and particulates and laboratory analyses including defined acceptance criteria for all components included in the scope of this program. The program will specify corrective actions in the event acceptance criteria are not met.Enhance the Oil Analysis Program for IP2 and IP3 to formalize trending of preliminary oil screening results as well as data provided from independent laboratories.

19 Implement the One-Time Inspection Program for IP2 IP2: NL-07-039 A.2.1.26 and IP3 as described in LRA Section B.1.27. September 28, A.3.1.26 2013 B.1.27 This new program will be implemented consistent with NL-07-153 Audit item the corresponding program described in NUREG- IP3: 173 1801,Section XI.M32, One-Time Inspection.

December 12, 2015 20 Implement the One-Time Inspection

-Small Bore IP2: NL-07-039 A.2.1.27 Piping Program for IP2 and IP3 as described in LRA September 28, A.3.1.27 Section B.1.28. 2013 B.1.28 NL-07-153 Audit item This new program will be implemented consistent with IP3: 173 the corresponding program described in NUREG- December 12, 1801,Section XI.M35, One-Time Inspection of ASME 2015 Code Class I Small-Bore Piping.21 Enhance the Periodic Surveillance and Preventive IP2: NL-07-039 A.2.1.28 Maintenance Program for IP2 and IP3 as necessary eptember 28, A.3.1.28 to assure that the effects of aging will be managed such that applicable components will continue to perform their intended functions consistent with the D e r1 current licensing basis through the period of extended De r1 operation.

015 Attachment 1 NL-12-174 Page 12 of 21 COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION/ AUDIT ITEM 22 Enhance the Reactor Vessel Surveillance Program for 1P2: NL-07-039 A.2.1.31 IP2 and IP3 revising the specimen capsule withdrawal September 28, A.3.1.31 schedules to draw and test a standby capsule to 013 B.1.32 cover the peak reactor vessel fluence expected IP3: through the end of the period of extended operation.

December 12, Enhance the Reactor Vessel Surveillance Program for 2015 IP2 and IP3 to require that tested and untested specimens from all capsules pulled from the reactor vessel are maintained in storage.23 Implement the Selective Leaching Program for IP2 IP2: NL-07-039 A.2.1.32 and IP3 as described in LRA Section B.1.33. September 28, A.3.1.32 2013 B.1.33 This new program will be implemented consistent with NL-07-153 Audit item the corresponding program described in NUREG- IP3: 173 1801,Section XI.M33 Selective Leaching of Materials.

December 12, 2015 24 Enhance the Steam Generator Integrity Program for IP2: NL-07-039 A.2.1.34 IP2 and IP3 to require that the results of the condition September 28, A.3.1.34 monitoring assessment are compared to the 2013 B. 1.35 operational assessment performed for the prior I P3: operating cycle with differences evaluated.

ecember 12, 2015 25 Enhance the Structures Monitoring Program to IP2: NL-07-039 A.2.1.35 explicitly specify that the following structures are September 28, A.3.1.35 included in the program. 2013 B.1.36" Appendix R diesel generator foundation (IP3) NL-07-153* Appendix R diesel generator fuel oil tank vault IP3: Audit items (IP3) December 12, 86, 87, 88," Appendix R diesel generator switchgear and 2015 NL-08-057 417 enclosure (IP3)" city water storage tank foundation

• condensate storage tanks foundation (IP3)" containment access facility and annex (IP3)* discharge canal (IP2/3)* emergency lighting poles and foundations (IP2/3)" fire pumphouse (IP2)* fire protection pumphouse (IP3)* fire water storage tank foundations (IP2/3)* gas turbine 1 fuel storage tank foundation

• maintenance and outage building-elevated passageway (I P2)

Attachment 1 NL-12-174 Page 13 of 21 COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION_ / AUDIT ITEM" new station security building (IP2)* nuclear service building (IP1)* primary water storage tank foundation (IP3)" refueling water storage tank foundation (IP3)" security access and office building (IP3)* service water pipe chase (IP2/3)* service water valve pit (IP3)* superheater stack* transformer/switchyard support structures (IP2)* waste holdup tank pits (IP2/3)Enhance the Structures Monitoring Program for IP2 and IP3 to clarify that in addition to structural steel and concrete, the following commodities (including their anchorages) are inspected for each structure as applicable.

• cable trays and supports" concrete portion of reactor vessel supports* conduits and supports* cranes, rails and girders* equipment pads and foundations

• fire proofing (pyrocrete)

• HVAC duct supports* jib cranes" manholes and duct banks" manways, hatches and hatch covers" monorails" new fuel storage racks" sumps, sump screens, strainers and flow barriers Enhance the Structures Monitoring Program for IP2 and IP3 to inspect inaccessible concrete areas that are exposed by excavation for any reason. IP2 and IP3 will also inspect inaccessible concrete areas in environments where observed conditions in accessible areas exposed to the same environment indicate that significant concrete degradation is occurring.

Enhance the Structures Monitoring Program for IP2 and IP3 to perform inspections of elastomers (seals, gaskets, seismic joint filler, and roof elastomers) to Attachment 1 NL-12-174 Page 14 of 21# COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION I_ / AUDIT ITEM identify cracking and change in material properties and for inspection of aluminum vents and louvers to identify loss of material.Enhance the Structures Monitoring Program for IP2 and IP3 to perform an engineering evaluation of groundwater samples to assess aggressiveness of groundwater to concrete on a periodic basis (at least once every five years). IPEC will obtain samples from at least 5 wells that are representative of the ground water surrounding below-grade site structures and perform an engineering evaluation of the results from those samples for sulfates, pH and chlorides.

Additionally, to assess potential indications of spent fuel pool leakage, IPEC will sample for tritium in groundwater wells in close proximity to the IP2 spent fuel pool at least once every 3 months.Enhance the Structures Monitoring Program for IP2 and IP3 to perform inspection of normally submerged concrete portions of the intake structures at least once every 5 years. Inspect the baffling/grating partition and support platform of the IP3 intake structure at least once every 5 years.Enhance the Structures Monitoring Program for IP2 and IP3 to perform inspection of the degraded areas of the water control structure once per 3 years rather than the normal frequency of once per 5 years during the PEO.Enhance the Structures Monitoring Program to include more detailed quantitative acceptance criteria for inspections of concrete structures in accordance with ACI 349.3R, "Evaluation of Existing Nuclear Safety-Related Concrete Structures" prior to the Deriod of extended ooeration.

NL-08-127 NL-1 1-032 NL-1 1-101 Audit Item 360 Audit Item 358 26 Implement the Thermal Aging Embrittlement of Cast IP2: NL-07-039 A.2.1.36 Austenitic Stainless Steel (CASS) Program for IP2 September 28, A.3.1.36 and _P3 as described in LRA Section B.1.37. 013 B.1.37 NL-07-153 Audit item This new program will be implemented consistent with IP3: 173 the corresponding program described in NUREG- December 12, 1801,Section XI.M12, Thermal Aging Embrittlement 015 of Cast Austenitic Stainless Steel (CASS) Program.

Attachment 1 NL-12-174 Page 15 of 21# COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION/ AUDIT ITEM 27 Implement the Thermal Aging and Neutron Irradiation lP2: NL-07-039 A.2.1.37 Embrittlement of Cast Austenitic Stainless Steel September 28, A.3.1.37 (CASS) Program for IP2 and IP3 as described in LRA 013 B.1.38 Section B.1.38. NL-07-153 Audit item I P3: 173 This new program will be implemented consistent with ecember 12, the corresponding program described in NUREG- 2015 1801 Section XI.M13, Thermal Aging and Neutron Embrittlement of Cast Austenitic Stainless Steel (CASS) Program.28 Enhance the Water Chemistry Control -Closed 1P2: NL-07-039 A.2.1.39 Cooling Water Program to maintain water chemistry of September 28, A.3.1.39 2013 B.1.40 the IP2 SBO/Appendix R diesel generator cooling NL-08-057 Audit item system per EPRI guidelines.

IP3: 509 Enhance the Water Chemistry Control -Closed December 12, Cooling Water Program to maintain the IP2 and IP3 2015 security generator and fire protection diesel cooling water pH and glycol within limits specified by EPRI guidelines.

29 Enhance the Water Chemistry Control -Primary and IP2: NL-07-039 A.2.1.40 Secondary Program for IP2 to test sulfates monthly in September 28, B.1.41 the RWST with a limit of <150 ppb. 013 30 For aging management of the reactor vessel internals, IP2: NL-07-039 A.2.1.41 IPEC will (1) participate in the industry programs for September 28, A.3.1.41 investigating and managing aging effects on reactor 011 internals; (2) evaluate and implement the results of IP3: the industry programs as applicable to the reactor December 12, internals; and (3) upon completion of these programs, 013 but not less than 24 months before entering the period of extended operation, submit an inspection plan for Complete NL-1 1-107 reactor internals to the NRC for review and approval.

Copee NL1-0 31 Additional P-T curves will be submitted as required IP2: NL-07-039 A.2.2.1.2 per 10 CFR 50, Appendix G prior to the period of September 28, A.3.2.1.2 extended operation as part of the Reactor Vessel 2013 4.2.3 Surveillance Program. IP3: December 12, 2015 32 As required by 10 CFR 50.61 (b)(4), IP3 will submit a IP3: NL-07-039 A.3.2.1.4 plant-specific safety analysis for plate B2803-3 to the December 12, 4.2.5 NRC three years prior to reaching the RTpTs 2015 NL-08-127 screening criterion.

Alternatively, the site may choose to implement the revised PTS rule when approved.

Attachment 1 NL-12-174 Page 16 of 21 COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION_ __ 1 / AUDIT ITEM 33 At least 2 years prior to entering the period of extended operation, for the locations identified in LRA Table 4.3-13 (1P2) and LRA Table 4.3-14 (IP3), under the Fatigue Monitoring Program, IP2 and IP3 will implement one or more of the following:

(1) Consistent with the Fatigue Monitoring Program, Detection of Aging Effects, update the fatigue usage calculations using refined fatigue analyses to determine valid CUFs less than 1.0 when accounting for the effects of reactor water environment.

This includes applying the appropriate Fen factors to valid CUFs determined in accordance with one of the following:

1. For locations in LRA Table 4.3-13 (IP2) and LRA Table 4.3-14 (IP3), with existing fatigue analysis valid for the period of extended operation, use the existing CUF.2. Additional plant-specific locations with a valid CUF may be evaluated.

In particular, the pressurizer lower shell will be reviewed to ensure the surge nozzle remains the limiting component.

3. Representative CUF values from other plants, adjusted to or enveloping the IPEC plant specific external loads may be used if demonstrated applicable to IPEC.4. An analysis using an NRC-approved version of the ASME code or NRC-approved alternative (e.g., NRC-approved code case) may be performed to determine a valid CUF.(2) Consistent with the Fatigue Monitoring Program, Corrective Actions, repair or replace the affected locations before exceeding a CUF of 1.0.IP2: September 28, 2011 1P3: December 12, 2013 Complete NL-07-039 NL-07-153 NL-08-021 NL-10-082 A.2.2.2.3 A.3.2.2.3 4.3.3 Audit item 146 34 1 P2 SBO/Appendix R diesel generator will be April 30, 2008 NL-07-078 2.1.1.3.5 installed and operational by April 30, 2008. This Complete NL-08-074 committed change to the facility meets the requirements of 10 CFR 50.59(c)(1) and, therefore, a NL-1 1-101 license amendment pursuant to 10 CFR 50.90 is not required.

Attachment 1 NL-12-174 Page 17 of 21# COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION/ AUDIT ITEM 35 Perform a one-time inspection of representative lP2: NL-08-127 Audit Item sample area of IP2 containment liner affected by the September 28, 27 1973 event behind the insulation, prior to entering the 013 period of extended operation, to assure liner degradation is not occurring in this area. NL-1 1-101 Perform a one-time inspection of representative IP3: sample area of the IP3 containment steel liner at the December 12, juncture with the concrete floor slab, prior to entering 2015 the period of extended operation, to assure liner degradation is not occurring in this area.Any degradation will be evaluated for updating of the NL-09-018 containment liner analyses as needed.1P2: NL-08-127 Audit Item 36 Perform a one-time inspection and evaluation of a ept r NL-08-101 359 sample of potentially affected IP2 refueling cavity 2810 concrete prior to the period of extended operation.

The sample will be obtained by core boring the refueling cavity wall in an area that is susceptible to exposure to borated water leakage. The inspection will include an assessment of embedded reinforcing steel.Additional core bore samples will be taken, if the NL-09-056 leakage is not stopped, prior to the end of the first ten years of the period of extended operation.

A sample of leakage fluid will be analyzed to NL-09-079 determine the composition of the fluid. If additional core samples are taken prior to the end of the first ten years of the period of extended operation, a sample of leakage fluid will be analyzed.37 Enhance the Containment Inservice Inspection (CII- IP2: NL-08-127 Audit Item IWL) Program to include inspections of the September 28, 361 containment using enhanced characterization of 2013 degradation (i.e., quantifying the dimensions of noted lP3: indications through the use of optical aids) during the December 12, period of extended operation.

The enhancement 015 includes obtaining critical dimensional data of degradation where possible through direct measurement or the use of scaling technologies for photographs, and the use of consistent vantage points for visual inspections.

Attachment 1 NL-12-174 Page 18 of 21# COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION I AUDIT ITEM IP2: NL-08-143 4.2.1 38 For Reactor Vessel Fluence, should future core loading patterns invalidate the basis for the projected September 28, values of RTpts or CRUSE, updated calculations will 013 be provided to the NRC. IP3: December 12, 2015 39 Deleted NL-09-079 40 Evaluate plant specific and appropriate industry eP2: NL-09-106 B. 1.6 operating experience and incorporate lessons learned eptember 28, B.1.22 in establishing appropriate monitoring and inspection 013 B.1.23 frequencies to assess aging effects for the new aging B.1.24 management programs.

Documentation of the r12, B.1.27 operating experience evaluated for each new program D_015 B.1.28 will be available on site for NRC review prior to the B 1.33 period of extended operation.

B. 1.33 B.1.37 B.1.38 1P2: NL-11-032 N/A 41 IPEC will inspect steam generators for both units to Pte the assess the condition of the divider plate assembly.

eg oth The examination technique used will be capable of Peginning of the detecting PWSCC in the steam generator divider plate )EO and prior to assembly.

The IP2 steam generator divider plate September 28, inspections will be completed within the first ten years of the period of extended operation (PEO). The IP3 iP3: NL-11-090 steam generator divider plate inspections will be Prior to the end completed within the first refueling outage following of the first NL-11-101 the beginning of the PEO. refueling outage ollowing the eginning of the PEO. E_

Attachment 1 NL-12-174 Page 19 of 21 COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION I_ I / AUDIT ITEM 42 IPEC will develop a plan for each unit to address the potential for cracking of the primary to secondary pressure boundary due to PWSCC of tube-to-tubesheet welds using one of the following two options.Option 1 (Analysis)

IPEC will perform an analytical evaluation of the steam generator tube-to-tubesheet welds in order to establish a technical basis for either determining that the tubesheet cladding and welds are not susceptible to PWSCC, or redefining the pressure boundary in which the tube-to-tubesheet weld is no longer included and, therefore, is not required for reactor coolant pressure boundary function.

The redefinition of the reactor coolant pressure boundary must be approved by the NRC as a license amendment request.Option 2 (Inspection)

IPEC will perform a one-time inspection of a representative number of tube-to-tubesheet welds in each steam generator to determine if PWSCC 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. An ongoing monitoring program will be established to perform routine tube-to-tubesheet weld inspections for the remaining life of the steam generators.

NL-1 1-032 NL-1 1-074 NL-1 1-090 NL-1 1-096 N/A IP2: Prior to March 2024 IP3: Prior to the and of the first refueling outage following the Deginning of the PEO.I P2: Between March 2020 and March 2024 IP3: Prior to the and of the first refueling outage Following the Jeginning of the PEO.

Attachment 1 NL-12-174 Page 20 of 21# COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION/ AUDIT ITEM IP2: NL-11-032 4.3.3 43 IPEC will review design basis ASME Code Class 1 Pro to fatigue evaluations to determine whether the NUREG/CR-6260 locations that have been evaluated September 28, 2013 for the effects of the reactor coolant environment on NL-1 1-101 fatigue usage are the limiting locations for the IP2 and IP3: Prior to IP3 configurations.

If more limiting locations are December 12, identified, the most limiting location will be evaluated 2015 for the effects of the reactor coolant environment on fatigue usage.IPEC will use the NUREG/CR-6909 methodology in the evaluation of the limiting locations consisting of nickel alloy, if any.44 IPEC will include written explanation and justification IP2: NL-11-032 N/A of any user intervention in future evaluations using the Prior to WESTEMS "Design CUF" module. eptember 28, NL-11-101 2013 lP3: Prior to December 12, 2015 IP:NL-11-032 N/A 45 IPEC will not use the NB-3600 option of the lP2: WESTEMS program in future design calculations until Prior to the issues identified during the NRC review of the September 28, NL-1 1-101 program have been resolved.

2013 IP3: Prior to December 12, 2015 IP2: NL-11-032 N/A 46 Include in the IP2 ISI Program that IPEC will perform Prior to twenty-five volumetric weld metal inspections of Pteor 21 socket welds during each 10-year ISI interval eptember 28, NL-11-074 scheduled as specified by IWB-2412 of the ASME 2013 Section Xl Code during the period of extended operation.

In lieu of volumetric examinations, destructive examinations may be performed, where one destructive examination may be substituted for two volumetric examinations.

Attachment 1 NL-12-174 Page 21 of 21# COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION! AUDIT ITEM 1P2: NL-12-089 N/A 47 IPEC will perform and submit analyses that Pro to demonstrate that the lower support column bodies will maintain their functionality during the period of September 28, extended operation considering the possible loss of 013 fracture toughness due to thermal and irradiation IP3: Prior to embrittlement.

The analyses will be consistent with December 12, the IP2/IP3 licensing basis. 2015 48 Entergy will visually inspect IPEC underground piping IP2: NL-12-174 N/A-4 within the scope of license renewal and subject to Prior to aging management review prior to the period of September 28, extended operation and then on a frequency of at 2013 least once every two years during the period of extended operation.

This inspection frequency will be IP3: Prior to maintained unless the piping is subsequently coated December 12, in accordance with the preventive actions specified in 2015 NUREG-1801 Section XI.M41 as modified by LR-ISG-2011-03. Visual inspections will be supplemented with surface or volumetric non-destructive testing if indications of significant loss of material are observed.

Consistent with revised NUREG-1 801 Section XI.M41, such adverse indications will be entered into the plant corrective action program for evaluation of extent of condition and for determination of appropriate corrective actions (e.g., increased inspection frequency, repair, replacement).

ATTACHMENT 2 TO NL-12-174 CHANGES TO THE INDIAN POINT LRA UPDATED FINAL SAFETY ANALYSIS REPORT SUPPLEMENT (APPENDIX A)AND AGING MANAGEMENT PROGRAMS AND ACTIVITIES (APPENDIX B)ENTERGY NUCLEAR OPERATIONS, INC.INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 & 3 DOCKET NOS. 50-247 AND 50-286 Attachment 2 NL-12-174 Page 1 of 4 INDIAN POINT NUCLEAR GENERATING UNIT NO. 2 CHANGES TO THE INDIAN POINT LRA UPDATED FINAL SAFETY ANALYSIS REPORT SUPPLEMENT (APPENDIX A)The LRA is revised as described below (underline

-added)A.2.1.5 Buried Piping and Tanks Inspection Program The Buried Piping and Tanks Inspection Program is a new program that includes (a) preventive measures to mitigate corrosion and (b) inspections to manage the effects of corrosion on the pressure-retaining capability of buried and underground carbon steel, gray cast iron, and stainless steel components.

Preventive measures are in accordance with standard industry practice for maintaining external coatings and wrappings.

Buried components are inspected when excavated during maintenance.

If trending within the corrective action program identifies susceptible locations, the areas with a history of corrosion problems are evaluated for the need for additional inspection, alternate coating, or replacement.

IP2 will perform 20 direct visual inspections of buried piping during the 10 year period prior the PEO. IP2 will perform 14 direct visual inspections during each 10-year period of the PEO. Soil samples will be taken prior to the PEO and at least once every 10 years in the PEO. Soil will be tested at a minimum of two locations at least three feet below the surface near in-scope piping to determine representative soil conditions for each system. If test results indicate the soil is corrosive then the number of piping inspections will be increased to 20 during each 10-year period of the PEO.The Buried Piping and Tanks Inspection Program will be implemented prior to the period of extended operation.

This new program will be implemented consistent with the corresponding program described in NUREG-1801 Section XI.M34, Buried Piping and Tanks Inspection with the following modification.

The Buried Piping and Tanks Inspection Program will be modified based on operating experience to include a risk assessment of in-scope buried piping and tanks that includes consideration of the impacts of buried piping or tank leakage and of conditions affecting the risk for corrosion.

The program will classify pipe segments and tanks as having a high, medium or low impact of leakage based on the safety class, the hazard posed by fluid contained in the piping and the impact of leakage on reliable plant operation.

Corrosion risk will be determined through consideration of piping or tank material, soil resistivity, drainage, the presence of cathodic protection and the type of coating. Inspection priority and frequency for periodic inspections of the in-scope piping and tanks will be based on the results of the risk assessment.

Inspections will be performed using qualified inspection techniques with demonstrated effectiveness.

Inspections will begin prior to the period of extended operation.

Underground piping within the scope of license renewal and subject to aging management review will be visually inspected prior to the period of extended operation and then on a frequency of at least once every two years during the period of extended operation.

This inspection frequency will be maintained unless the piping is subsequently coated in accordance with the preventive actions specified in NUREG-1801 Section XI.M41 as modified by LR-ISG-2011-03.

Visual inspections will be supplemented with surface or volumetric non-destructive testing if indications of significant loss of material are observed.

Consistent with revised NUREG-1 801 Section XI.M41, such adverse indications will be entered into the plant corrective action program for evaluation of extent of condition and for determination of appropriate corrective actions (e.g., increased inspection frequency, repair, replacement).

Attachment 2 NL-12-174 Page 2 of 4 INDIAN POINT NUCLEAR GENERATING UNIT NO. 3 CHANGES TO THE INDIAN POINT LRA UPDATED FINAL SAFETY ANALYSIS REPORT SUPPLEMENT (APPENDIX A)The LRA is revised as described below (underline

-added)A.3.1.5 Buried Piping and Tanks Inspection Program The Buried Piping and Tanks Inspection Program is a new program that includes (a) preventive measures to mitigate corrosion and (b) inspections to manage the effects of corrosion on the pressure-retaining capability of buried and underground carbon steel, gray cast iron, copper alloy and stainless steel components.

Preventive measures are in accordance with standard industry practice for maintaining external coatings and wrappings.

Buried components are inspected when excavated during maintenance.

If trending within the corrective action program identifies susceptible locations, the areas with a history of corrosion problems are evaluated for the need for additional inspection, alternate coating, or replacement.

IP3 will perform 14 direct visual inspections of buried piping during the 10 year period prior the PEO. IP3 will perform 16 direct visual inspections during each 10-year period of the PEO. Soil samples will be taken prior to the PEO and at least once every 10 years into the PEO. Soil will be tested at a minimum of two locations at least three feet below the surface near in-scope piping to determine representative soil conditions for each system. If test results indicate the soil is corrosive then the number of piping inspections will be increased to 22 during each 10-year period of the PEO.The Buried Piping and Tanks Inspection Program will be implemented prior to the period of extended operation.

This new program will be implemented consistent with the corresponding program described in NUREG-1801 Section XI.M34, Buried Piping and Tanks Inspection with the following modification.

The Buried Piping and Tanks Inspection Program will be modified based on operating experience to include a risk assessment of in-scope buried piping and tanks that includes consideration of the impacts of buried piping or tank leakage and of conditions affecting the risk for corrosion.

The program will classify pipe segments and tanks as having a high, medium or low impact of leakage based on the safety class, the hazard posed by fluid contained in the piping and the impact of leakage on reliable plant operation.

Corrosion risk will be determined through consideration of piping or tank material, soil resistivity, drainage, the presence of cathodic protection and the type of coating. Inspection priority and frequency for periodic inspections of the in-scope piping and tanks will be based on the results of the risk assessment.

Inspections will be performed using qualified inspection techniques with demonstrated effectiveness, Inspections will begin prior to the period of extended operation.

Underground piping within the scope of license renewal and subject to aging management review will be visually inspected prior to the period of extended operation and then on a frequency of at least once every two years during the period of extended operation.

This inspection frequency will be maintained unless the piping is subsequently coated in accordance with the preventive actions specified in NUREG-1801 Section XI.M41 as modified by LR-ISG-2011-03.

Visual inspections will be supplemented with surface or volumetric non-destructive testing if indications of significant loss of material are observed.

Consistent with revised NUREG-1801 Section XI.M41, such adverse indications will be entered into the plant corrective action program for evaluation of extent of condition and for determination of appropriate corrective actions (e.g., increased inspection frequency, repair, replacement).

Attachment 2 NL-12-174 Page 3 of 4 INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 CHANGES TO THE INDIAN POINT LRA AGING MANAGEMENT PROGRAMS AND ACTIVITIES (APPENDIX B)The LRA is revised as described below (underline

-added)B.1.6 BURIED PIPING AND TANKS INSPECTION Proaram Description The Buried Piping and Tanks Inspection Program is a new program that includes (a) preventive measures to mitigate corrosion and (b) inspections to manage the effects of corrosion on the pressure-retaining capability of buried and underground carbon steel, gray cast iron, copper alloy and stainless steel components.

Preventive measures are in accordance with standard industry practice for maintaining external coatings and wrappings.

Buried components are inspected when excavated during maintenance.

If trending within the corrective action program identifies susceptible locations, the areas with a history of corrosion problems are evaluated for the need for additional inspection, alternate coating, or replacement.

The program applies to buried components in the following systems." Safety injection" Service water" Fire protection

• Fuel oil" Security generator* City water* Plant drains* Auxiliary feedwater* Containment isolation support* River water service (IP1)* Circulating Water System (IP2)Of these systems, only the safety injection system contains radioactive fluids during normal operations.

The safety injection system buried components are stainless steel. Stainless steel is used in the safety injection system for its corrosion resistance.

This program also applies to underground components in the IP3 service water and city water systems and the IP2 and IP3 fuel oil systems.The Buried Piping and Tanks Inspection Program will be modified based on operating experience to include a risk assessment of in-scope buried piping and tanks that includes consideration of the impacts of buried piping tank or tank leakage and of conditions affecting the risk for corrosion.

The program will classify pipe segments and tanks as having a high, medium or low impact of leakage based on the safety class, the hazard dosed by fluid contained in the piping and the impact of leakage on reliable plant operation.

Corrosion Attachment 2 NL-12-174 Page 4 of 4 risk will be determined through consideration of piping or tank material, soil resistivity, drainage, the presence of cathodic protection and the type of coating. Inspection priority and frequency for periodic inspections of the in-scope piping and tanks will be based on the results of the risk assessment.

Inspections will be performed using qualified inspection techniques with demonstrated effectiveness.

Inspections will begin prior to the period of extended operation.

Prior to entering the period of extended operation, plant operating experience will be reviewed and multiple inspections will be completed Within the past ten years. Additional periodic inspections will be performed within the first ten years of the period of extended operation.

Underground piping within the scope of license renewal and subject to aging management review will be visually inspected prior to the period of extended operation and then on a frequency of at least once every two years during the period of extended operation.

This inspection frequency will be maintained unless the piping is subsequently coated in accordance with the preventive actions specified in NUREG-1801 Section XI.M41 as modified by LR-ISG-2011-03. Visual inspections will be supplemented with surface or volumetric non-destructive testing if indications of significant loss of material are observed.

Consistent with revised NUREG-1801 Section XI.M41, such adverse indications will be entered into the plant corrective action program for evaluation of extent of condition and for determination of appropriate corrective actions (e.a.. increased insoection freauencv.

reoair. reolacement).

The program will be implemented prior to the period of extended operation.