NL-12-174, Official Exhibit - ENT000597-00-BD01 - NL-12-174, Letter from Fred Dacimo, Vice President, IPEC, to NRC Document Control Desk, Additional Clarification of Underground Piping Information Provided in Letter NL-12-149 Regarding the .

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Official Exhibit - ENT000597-00-BD01 - NL-12-174, Letter from Fred Dacimo, Vice President, IPEC, to NRC Document Control Desk, Additional Clarification of Underground Piping Information Provided in Letter NL-12-149 Regarding the .
ML13039A452
Person / Time
Site: Indian Point  Entergy icon.png
Issue date: 11/29/2012
From: Dacimo F
Entergy Nuclear Northeast
To:
Atomic Safety and Licensing Board Panel, Document Control Desk
SECY RAS
References
RAS 23852, 50-247-LR, 50-286-LR, ASLBP 07-858-03-LR-BD01, NL-12-174
Download: ML13039A452 (29)
v • d • e


Text

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

SUBJECT:

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

REFERENCE:

(1) Entergy letter (NL-12-149), Clarification of Underground Piping Information Provided in Letter NL-11-032 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-1801 Section XI.M41 guidance for underground piping which will ensure the effects of aging are adequately managed. The NUREG-1801 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-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).

ENT000597 Submitted: December 6 , 2012 United States Nuclear Regulatory Commission Official Hearing Exhibit In the Matter of

Entergy Nuclear Operations, Inc. (Indian Point Nuclear Generating Units 2 and 3)

ASLBP #:07-858-03-LR-BD01 Docket #:05000247 l 05000286 Exhibit #:

Identified:

Admitted: Withdrawn:

Rejected: Stricken: Other: ENT000597-00-BD0112/10/2012 1/15/2013

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 NL-12-174Page 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 deletions and underlines for additions.

  1. COMMITMEN TIMPLEMENTATION SCHEDULESOURCERELATEDLRA SECTION / AUDIT ITEM 1 Enhance the Aboveground Steel Tanks Program for IP2 and IP3 to perform thickness measurements of the bottom surfaces of the condensate storage tanks, city water tank, and fire water tanks once during the first ten years of the period of extended operation. Enhance the Aboveground Steel Tanks Program for IP2 and IP3 to require trending of thickness measurements when material loss is detected. IP2: September 28, 2013 IP3: December 12, 2015 NL-07-039A.2.1.1 A.3.1.1 B.1.1 2 Enhance the Bolting Integrity Program for IP2 and IP3 to clarify that actual yield strength is used in selecting materials for low susceptibility to SCC and clarify the prohibition on use of lubricants containing MoS 2 for bolting. The Bolting Integrity Program manages loss of preload and loss of material for all external bolting. IP2: September 28, 2013 IP3: December 12, 2015 NL-07-039 NL-07-153A.2.1.2 A.3.1.2 B.1.2 Audit Items 201, 241, 270 NL-12-174Page 2 of 21
  1. COMMITMEN TIMPLEMENTATION SCHEDULESOURCERELATEDLRA SECTION / 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. IP2: September 28, 2013 IP3: December 12, 2015 NL-07-039 NL-07-153 NL-09-106 NL-09-111 NL-11-101A.2.1.5 A.3.1.5 B.1.6 Audit Item 173 NL-12-174Page 3 of 21
  1. COMMITMEN TIMPLEMENTATION SCHEDULESOURCERELATEDLRA SECTION / 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 biological activity is confirmed. IP2: September 28, 2013 IP3: December 12, 2015 NL-07-039 NL-07-153 NL-08-057A.2.1.8 A.3.1.8 B.1.9 Audit items 128, 129, 132, 491, 492, 510 NL-12-174Page 4 of 21
  1. COMMITMEN TIMPLEMENTATION SCHEDULESOURCERELATEDLRA SECTION / AUDIT ITEM 5 Enhance the External Surfaces Monitoring Program for IP2 and IP3 to include periodic inspections of systems in scope and subject to aging management review for license renewal in accordance with 10 CFR 54.4(a)(1) and (a)(3). Inspections shall include areas surrounding the subject systems to identify hazards to 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). IP2: September 28, 2013 IP3: December 12, 2015 NL-07-039A.2.1.10 A.3.1.10 B.1.11 6 Enhance the Fatigue Monitoring Program for IP2 to monitor steady state cycles and feedwater cycles or perform an evaluation to determine monitoring is not required. Review the number of allowed events and resolve discrepancies between reference documents and monitoring procedures. Enhance the Fatigue Monitoring Program for IP3 to include all the transients identified. Assure all fatigue analysis transients are included with the lowest limiting numbers. Update the number of design transients accumulated to date. IP2: September 28, 2013 IP3: December 12, 2015 NL-07-039 NL-07-153A.2.1.11 A.3.1.11 B.1.12, Audit Item 164 NL-12-174Page 5 of 21
  1. COMMITMEN TIMPLEMENTATION SCHEDULESOURCERELATEDLRA SECTION / 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 CO 2 fire suppression system for signs of degradation, such as corrosion and mechanical damage at least once every six months. IP2: September 28, 2013 IP3: December 12, 2015 NL-07-039 A.2.1.12 A.3.1.12 B.1.13 NL-12-174Page 6 of 21
  1. COMMITMEN TIMPLEMENTATION SCHEDULESOURCERELATEDLRA SECTION / 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. IP2: September 28, 2013 IP3: December 12, 2015 NL-07-039 NL-07-153 NL-08-014A.2.1.13 A.3.1.13 B.1.14 Audit Items 105, 106 NL-12-174Page 7 of 21
  1. COMMITMEN TIMPLEMENTATION SCHEDULESOURCERELATEDLRA SECTION / 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. IP2: September 28, 2013 IP3: December 12, 2015 NL-07-039A.2.1.15 A.3.1.15 B.1.16 NL-12-174Page 8 of 21
  1. COMMITMEN TIMPLEMENTATION SCHEDULESOURCERELATEDLRA 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. IP2: September 28, 2013 IP3: December 12, 2015 NL-07-039 NL-07-153 NL-09-018A.2.1.16 A.3.1.16 B.1.17, Audit Item 52 11 Deleted NL-09-056 NL-11-101 NL-12-174Page 9 of 21
  1. COMMITMEN TIMPLEMENTATION SCHEDULESOURCERELATEDLRA SECTION / AUDIT ITEM 12 Enhance the Masonry Wall Program for IP2 and IP3 to specify that the IP1 intake structure is included in the program. IP2: September 28, 2013 IP3: December 12, 2015 NL-07-039A.2.1.18 A.3.1.18 B.1.19 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. IP2: September 28, 2013 IP3: December 12, 2015 NL-07-039NL-07-153NL-08-057A.2.1.19 A.3.1.19 B.1.20 Audit Items124, 133, 519 14 Implement the Non-EQ Bolted Cable Connections Program for IP2 and IP3 as described in LRA Section B.1.22. IP2: September 28, 2013 IP3: December 12, 2015 NL-07-039A.2.1.21 A.3.1.21 B.1.22 NL-12-174Page 10 of 21
  1. COMMITMEN TIMPLEMENTATION SCHEDULESOURCERELATEDLRA SECTION / AUDIT ITEM 15 Implement the Non-EQ Inaccessible Medium-Voltage Cable Program for IP2 and IP3 as described in LRA Section B.1.23. This new program will be implemented consistent with the corresponding program described in NUREG-1801 Section XI.E3, Inaccessible Medium-Voltage Cables Not Subject To 10 CFR 50.49 Environmental Qualification Requirements. IP2: September 28, 2013 IP3: December 12, 2015 NL-07-039 NL-07-153 NL-11-032 NL-11-096 NL-11-101A.2.1.22 A.3.1.22 B.1.23 Audit item 173 16 Implement the Non-EQ Instrumentation Circuits Test Review Program for IP2 and IP3 as described in LRA Section B.1.24. This new program will be implemented consistent with the corresponding program described in NUREG-1801 Section XI.E2, Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits. IP2: September 28, 2013 IP3: December 12, 2015 NL-07-039 NL-07-153A.2.1.23 A.3.1.23 B.1.24 Audit item 173 17 Implement the Non-EQ Insulated Cables and Connections Program for IP2 and IP3 as described in LRA Section B.1.25. This new program will be implemented consistent with the corresponding program described in NUREG-1801 Section XI.E1, Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements. IP2: September 28, 2013 IP3: December 12, 2015 NL-07-039 NL-07-153A.2.1.24 A.3.1.24 B.1.25 Audit item 173 NL-12-174Page 11 of 21
  1. COMMITMEN TIMPLEMENTATION SCHEDULESOURCERELATEDLRA SECTION / AUDIT ITEM 18 Enhance the Oil Analysis Program for IP2 to sample and analyze lubricating oil used in the SBO/Appendix R diesel generator consistent with the oil analysis for other site diesel generators. Enhance the Oil Analysis Program for IP2 and IP3 to sample and analyze generator seal oil and turbine 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. IP2: September 28, 2013 IP3: December 12, 2015 NL-07-039 NL-11-101A.2.1.25 A.3.1.25 B.1.26 19 Implement the One-Time Inspection Program for IP2 and IP3 as described in LRA Section B.1.27. This new program will be implemented consistent with the corresponding program described in NUREG-1801,Section XI.M32, One-Time Inspection. IP2: September 28, 2013 IP3: December 12, 2015 NL-07-039 NL-07-153A.2.1.26 A.3.1.26 B.1.27 Audit item 173 20 Implement the One-Time Inspection - Small Bore Piping Program for IP2 and IP3 as described in LRA Section B.1.28. This new program will be implemented consistent with the corresponding program described in NUREG-1801,Section XI.M35, One-Time Inspection of ASME Code Class I Small-Bore Piping. IP2: September 28, 2013 IP3: December 12, 2015 NL-07-039 NL-07-153A.2.1.27 A.3.1.27 B.1.28 Audit item 173 21 Enhance the Periodic Surveillance and Preventive Maintenance Program for IP2 and IP3 as necessary to assure that the effects of aging will be managed such that applicable components will continue to perform their intended functions consistent with the current licensing basis through the period of extended operation. IP2: September 28, 2013 IP3: December 12, 2015 NL-07-039A.2.1.28 A.3.1.28 B.1.29 NL-12-174Page 12 of 21
  1. COMMITMEN TIMPLEMENTATION SCHEDULESOURCERELATEDLRA SECTION / AUDIT ITEM 22 Enhance the Reactor Vessel Surveillance Program for IP2 and IP3 revising the specimen capsule withdrawal schedules to draw and test a standby capsule to cover the peak reactor vessel fluence expected through the end of the period of extended operation. Enhance the Reactor Vessel Surveillance Program for IP2 and IP3 to require that tested and untested specimens from all capsules pulled from the reactor vessel are maintained in storage. IP2: September 28, 2013 IP3: December 12, 2015 NL-07-039A.2.1.31 A.3.1.31 B.1.32 23 Implement the Selective Leaching Program for IP2 and IP3 as described in LRA Section B.1.33. This new program will be implemented consistent with the corresponding program described in NUREG-1801,Section XI.M33 Selective Leaching of Materials. IP2: September 28, 2013 IP3: December 12, 2015 NL-07-039 NL-07-153A.2.1.32 A.3.1.32 B.1.33 Audit item 173 24 Enhance the Steam Generator Integrity Program for IP2 and IP3 to require that the results of the condition monitoring assessment are compared to the operational assessment performed for the prior operating cycle with differences evaluated. IP2: September 28, 2013 IP3: December 12, 2015 NL-07-039A.2.1.34 A.3.1.34 B.1.35 25 Enhance the Structures Monitoring Program to explicitly specify that the following structures are included in the program. Appendix R diesel generator foundation (IP3) Appendix R diesel generator fuel oil tank vault (IP3) Appendix R diesel generator switchgear and 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 (IP2) IP2: September 28, 2013 IP3: December 12, 2015 NL-07-039 NL-07-153 NL-08-057 A.2.1.35 A.3.1.35 B.1.36 Audit items 86, 87, 88, 417 NL-12-174Page 13 of 21
  1. COMMITMEN TIMPLEMENTATION SCHEDULESOURCERELATEDLRA 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 NL-12-174Page 14 of 21
  1. COMMITMEN TIMPLEMENTATION SCHEDULESOURCERELATEDLRA SECTION / 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 period of extended operation. NL-08-127 NL-11-032 NL-11-101Audit Item 360 Audit Item 358 26 Implement the Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) Program for IP2 and IP3 as described in LRA Section B.1.37. This new program will be implemented consistent with the corresponding program described in NUREG-1801,Section XI.M12, Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) Program. IP2: September 28, 2013 IP3: December 12, 2015 NL-07-039 NL-07-153A.2.1.36 A.3.1.36 B.1.37 Audit item 173 NL-12-174Page 15 of 21

  1. COMMITMEN TIMPLEMENTATION SCHEDULESOURCERELATEDLRA SECTION / AUDIT ITEM 27 Implement the Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel (CASS) Program for IP2 and IP3 as described in LRA Section B.1.38. This new program will be implemented consistent with the corresponding program described in NUREG-1801 Section XI.M13, Thermal Aging and Neutron Embrittlement of Cast Austenitic Stainless Steel (CASS) Program. IP2: September 28, 2013 IP3: December 12, 2015 NL-07-039 NL-07-153A.2.1.37 A.3.1.37 B.1.38 Audit item 173 28 Enhance the Water Chemistry Control - Closed Cooling Water Program to maintain water chemistry of the IP2 SBO/Appendix R diesel generator cooling system per EPRI guidelines. Enhance the Water Chemistry Control - Closed Cooling Water Program to maintain the IP2 and IP3 security generator and fire protection diesel cooling water pH and glycol within limits specified by EPRI guidelines. IP2: September 28, 2013 IP3: December 12, 2015 NL-07-039 NL-08-057A.2.1.39 A.3.1.39 B.1.40 Audit item 509 29 Enhance the Water Chemistry Control - Primary and Secondary Program for IP2 to test sulfates monthly in the RWST with a limit of <150 ppb. IP2: September 28, 2013 NL-07-039A.2.1.40 B.1.41 30 For aging management of the reactor vessel internals, IPEC will (1) participate in the industry programs for investigating and managing aging effects on reactor internals; (2) evaluate and implement the results of the industry programs as applicable to the reactor internals; and (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. IP2: September 28, 2011 IP3: December 12, 2013 Complete NL-07-039 NL-11-107A.2.1.41 A.3.1.41 31 Additional P-T curves will be submitted as required per 10 CFR 50, Appendix G prior to the period of extended operation as part of the Reactor Vessel Surveillance Program. IP2: September 28, 2013 IP3: December 12, 2015 NL-07-039A.2.2.1.2 A.3.2.1.2 4.2.3 32 As required by 10 CFR 50.61(b)(4), IP3 will submit a plant-specific safety analysis for plate B2803-3 to the NRC three years prior to reaching the RTPTSscreening criterion. Alternatively, the site may choose to implement the revised PTS rule when approved. IP3: December 12, 2015 NL-07-039 NL-08-127A.3.2.1.4 4.2.5 NL-12-174Page 16 of 21
  1. COMMITMEN TIMPLEMENTATION SCHEDULESOURCERELATEDLRA SECTION / 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 (IP2) 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 IP3: December 12, 2013 Complete NL-07-039 NL-07-153 NL-08-021 NL-10-082A.2.2.2.3 A.3.2.2.3 4.3.3 Audit item 146 34 IP2 SBO / Appendix R diesel generator will be installed and operational by April 30, 2008. This committed change to the facility meets the requirements of 10 CFR 50.59(c)(1) and, therefore, a license amendment pursuant to 10 CFR 50.90 is not required. April 30, 2008 Complete NL-07-078 NL-08-074 NL-11-1012.1.1.3.5 NL-12-174Page 17 of 21

  1. COMMITMEN TIMPLEMENTATION SCHEDULESOURCERELATEDLRA SECTION / AUDIT ITEM 35 Perform a one-time inspection of representative sample area of IP2 containment liner affected by the 1973 event behind the insulation, prior to entering the period of extended operation, to assure liner degradation is not occurring in this area. Perform a one-time inspection of representative sample area of the IP3 containment steel liner at the juncture with the concrete floor slab, prior to entering the period of extended operation, to assure liner degradation is not occurring in this area. Any degradation will be evaluated for updating of the containment liner analyses as needed. IP2: September 28, 2013 IP3: December 12, 2015 NL-08-127 NL-11-101 NL-09-018Audit Item 27 36 Perform a one-time inspection and evaluation of a sample of potentially affected IP2 refueling cavity 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 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 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. IP2: September 28, 2013 NL-08-127 NL-11-101 NL-09-056 NL-09-079Audit Item 359 37 Enhance the Containment Inservice Inspection (CII-IWL) Program to include inspections of the containment using enhanced characterization of degradation (i.e., quantifying the dimensions of noted indications through the use of optical aids) during the period of extended operation. The enhancement 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. IP2: September 28, 2013 IP3: December 12, 2015 NL-08-127Audit Item 361 NL-12-174Page 18 of 21
  1. COMMITMEN TIMPLEMENTATION SCHEDULESOURCERELATEDLRA SECTION / AUDIT ITEM 38 For Reactor Vessel Fluence, should future core loading patterns invalidate the basis for the projected values of RTpts or C VUSE, updated calculations will be provided to the NRC. IP2: September 28, 2013 IP3: December 12, 2015 NL-08-1434.2.1 39 Deleted NL-09-07940 Evaluate plant specific and appropriate industry operating experience and incorporate lessons learned in establishing appropriate monitoring and inspection frequencies to assess aging effects for the new aging management programs. Documentation of the operating experience evaluated for each new program will be available on site for NRC review prior to the period of extended operation. IP2: September 28, 2013 IP3: December 12, 2015 NL-09-106B.1.6 B.1.22 B.1.23 B.1.24 B.1.25 B.1.27 B.1.28 B.1.33 B.1.37 B.1.38 41 IPEC will inspect steam generators for both units to assess the condition of the divider plate assembly. The examination technique used will be capable of detecting PWSCC in the steam generator divider plate assembly. The IP2 steam generator divider plate inspections will be completed within the first ten years of the period of extended operation (PEO). The IP3 steam generator divider plate inspections will be completed within the first refueling outage following the beginning of the PEO. IP2: After the beginning of the PEO and prior to September 28, 2023 IP3: Prior to the end of the first refueling outage following the beginning of the

PEO.NL-11-032 NL-11-074 NL-11-090 NL-11-101N/A NL-12-174Page 19 of 21

  1. COMMITMEN TIMPLEMENTATION SCHEDULESOURCERELATEDLRA SECTION / 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. IP2: Prior to March 2024 IP3: Prior to the end of the first refueling outage following the beginning of the PEO. IP2: Between March 2020 and March 2024 IP3: Prior to the end of the first refueling outage following the beginning of the PEO. NL-11-032 NL-11-074 NL-11-090 NL-11-096N/A NL-12-174Page 20 of 21
  1. COMMITMEN TIMPLEMENTATION SCHEDULESOURCERELATEDLRA SECTION / AUDIT ITEM 43 IPEC will review design basis ASME Code Class 1 fatigue evaluations to determine whether the NUREG/CR-6260 locations that have been evaluated for the effects of the reactor coolant environment on fatigue usage are the limiting locations for the IP2 and IP3 configurations. If more limiting locations are identified, the most limiting location will be evaluated 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. IP2: Prior to September 28, 2013 IP3: Prior to December 12, 2015 NL-11-032 NL-11-101 4.3.3 44 IPEC will include written explanation and justification of any user intervention in future evaluations using the WESTEMS Design CUF module. IP2: Prior to September 28, 2013 IP3: Prior to December 12, 2015 NL-11-032 NL-11-101N/A 45 IPEC will not use the NB-3600 option of the WESTEMS program in future design calculations until the issues identified during the NRC review of the program have been resolved. IP2: Prior to September 28, 2013 IP3: Prior to December 12, 2015 NL-11-032 NL-11-101N/A 46 Include in the IP2 ISI Program that IPEC will perform twenty-five volumetric weld metal inspections of socket welds during each 10-year ISI interval scheduled as specified by IWB-2412 of the ASME Section XI 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. IP2: Prior to September 28, 2013 NL-11-032 NL-11-074 N/A NL-12-174Page 21 of 21
  1. COMMITMEN TIMPLEMENTATION SCHEDULESOURCERELATEDLRA SECTION / AUDIT ITEM 47 IPEC will perform and submit analyses that demonstrate that the lower support column bodies will maintain their functionality during the period of extended operation considering the possible loss of fracture toughness due to thermal and irradiation embrittlement. The analyses will be consistent with the IP2/IP3 licensing basis. IP2: Prior to September 28, 2013 IP3: Prior to December 12, 2015 NL-12-089 N/A 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-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). IP2: Prior to September 28, 2013 IP3: Prior to December 12, 2015 NL-12-174N/A 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 NL-12-174Page 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-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). NL-12-174Page 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). NL-12-174Page 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 Program 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
  • Fire protection
  • Fuel oil
  • Security generator
  • City water
  • Plant drains
  • 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 NL-12-174Page 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.g., increased inspection frequency, repair, replacement). The program will be implemented prior to the period of extended operation.
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