NL-13-098, Board Notification Buried Piping RAI Response

Board Notification Buried Piping RAI Response

ML13206A452
Person / Time
Site:	Indian Point
Issue date:	07/25/2013
From:	Bessette P, Dennis W, Glew W, Sutton K Entergy Nuclear Operations, Entergy Services, Morgan, Morgan, Lewis & Bockius, LLP
To:	Kennedy M, Lawrence Mcdade, Richard Wardwell Atomic Safety and Licensing Board Panel
SECY RAS
References
RAS 24851, 50-247-LR, 50-286-LR, ASLBP 07-858-03-LR-BD01, NL-13-098
Download: ML13206A452 (21)

Text

Morgan, Lewis & Bockius LLP 1111 Pennsylvania Avenue, NW Washington, DC 20004 Tel. 202.739.3000 Fax: 202.739.3001 www.morganlewis.com Kathryn M. Sutton Partner 202.739.5738 ksutton@MorganLewis.com Paul M. Bessette Partner 202.739.5796 pbessette@MorganLewis.com July 25, 2013 Lawrence G. McDade, Chairman Dr. Michael F. Kennedy Dr. Richard E. Wardwell Atomic Safety and Licensing Board U.S. Nuclear Regulatory Commission Washington, DC 20555-0001 Docket: Entergy Nuclear Operations, Inc. (Indian Point Nuclear Generating Units 2 and 3), Docket Nos. 50-247-LR and 50-286-LR RE: Notification and Transmittal of Entergy Letter NL-13-098

Dear Administrative Judges:

On July 22, 2013, Entergy Nuclear Operations, Inc. (Entergy) submitted the Applicants Supplemental Filing Related to Contention NYS-5. On page 5 of that filing, Entergy informed the Board and the parties that it soon would be filing Entergy letter NL-13-098, which contains Entergys responses to NRC Staff requests for additional information (RAIs) issued in June 2013 principally concerning cathodic protection practices at Indian Point Energy Center (IPEC). NL-13-098 also responds to unrelated RAIs involving Entergys Selective Leaching Program and Periodic Surveillance and Preventive Maintenance Program.

Entergy filed NL-13-098 on July 24, 2013. A copy of the submission is attached. Entergys responses to RAI 3.0.3.1.2-4 contain information related to completed direct visual inspections of buried piping, backfill conditions, and cathodic protection at IPEC that the Board and parties may view as relevant to Contention NYS-5, which concerns Entergys aging management program for in-scope IPEC buried piping containing or potentially containing radioactive fluids.

Administrative Judges July 25, 2013 Page 2

Attachment:

As stated cc: Service List Respectfully submitted, Executed in accord with 10 C.F.R. § 2.304(d)

Kathryn M. Sutton, Esq.

Paul M. Bessette, Esq.

MORGAN, LEWIS & BOCKIUS LLP 1111 Pennsylvania Avenue, N.W.

Washington, D.C. 20004 Phone: (202) 739-3000 Fax: (202) 739-3001 E-mail: ksutton@morganlewis.com E-mail: pbessette@morganlewis.com William B. Glew, Jr., Esq.

William C. Dennis, Esq.

ENTERGY SERVICES, INC.

440 Hamilton Avenue White Plains, NY 10601 Phone: (914) 272-3202 Fax: (914) 272-3205 E-mail: wglew@entergy.com E-mail: wdennis@entergy.com Counsel for Entergy Nuclear Operations, Inc.

Docket Nos. 50-247 & 50-286 NL-13-098 Page 2 of 2

Attachment:

Reply to NRC Request for Additional Information Regarding the License Renewal Application 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 Ms. Kimberly Green, 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 Inspectors Office Mr. Francis J. Murray, Jr., President and CEO NYSERDA

ATTACHMENT TO NL-13-098 REPLY TO NRC REQUEST FOR ADDITIONAL INFORMATION REGARDING THE LICENSE RENEWAL APPLICATION ENTERGY NUCLEAR OPERATIONS, INC.

INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 & 3 DOCKET NOS. 50-247 AND 50-286

Docket Nos. 50-247 & 50-286 NL-13-098 Attachment Page 1 of 15 INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL APPLICATION (LRA)

REQUESTS FOR ADDITIONAL INFORMATION (RAI)

RAI 3.0.3.1.2-4

Background

The response to RAI 3.0.3.1.2-1 stated that the only cathodically protected, in-scope buried piping is the city water line in the vicinity of the Algonquin gas pipelines. However, the staff understands that cathodic protection (CP) has been recently installed on portions of the auxiliary feedwater system and is being considered for installation on the service water system.

As stated in letter NL-09-106 dated July 27, 2009, the Indian Point 2 auxiliary feedwater return line to the condensate storage tank developed a leak due to deleterious materials in the backfill.

Subsequent inspections of excavated buried pipe did not reveal debris in the backfill. However, several recent inspections conducted in December 2012 (i.e., 6-inch fire protection, 1.5-inch weld channel line, 2-inch city water, 24-inch service water lines) revealed that rocks were present in the backfill, although not in contact with the pipe. In one of the three service water lines excavations, debris was found in the backfill.

Issue

1. Because safety-related systems, such as auxiliary feedwater and service water, have been included into the scope of systems that are or will be protected by CP, the staff seeks to understand the parameters to be monitored and the acceptance criteria that will be used to evaluate the effectiveness and availability of the CP system, and the applicants plans to credit the CP system in the risk ranking process for buried piping inspections.

CP is an effective means to prevent corrosion of buried piping where coatings may be degraded or have been damaged. However, additional information is needed for the staff to understand how this preventive action will be incorporated into the Buried Piping and Tanks Inspection Program. The staff reviewed EN-DC-343, Underground Piping and Tanks Inspection and Monitoring Program, CEP-UPT-0100, Underground Piping and Tanks Inspection and Monitoring, and SEP-UIP-IPEC, Underground Components Inspection Plan.

The only reference to performance monitoring of the CP system is in SEP-UIP-IPEC, Section H, Inspection Strategy and Methodologies, Strategy for Cathodic Protection, which states, "[o]nce the system modifications are implemented, the system will be maintained via recurring PMs [preventive maintenance activities] based on vendor recommendations." In the absence of further information, the staff notes that the following monitoring parameters and acceptance criteria have been employed at various other facilities:

a) CP systems are typically surveyed on an annual basis to determine the level of protection being provided by the system.

Docket Nos. 50-247 & 50-286 NL-13-098 Attachment Page 2 of 15 b) Pipe-to-soil and CP currents are typically monitored during CP surveys to determine the effectiveness of the CP system.

c) In order for the CP system to protect the buried pipe system, it must be available for the majority of the time.

d) In order for the CP system to protect the buried pipe system, it must provide effective protection for the majority of the time. This can be accomplished by determining the percentage of survey points that met acceptance criteria during annual surveys or by other means.

e) NACE SP0169-2007, Standard Practice Control of External Corrosion on Underground or Submerged Metallic Piping System, Section 6, Criteria and Other Considerations for CP, states three acceptance criteria for determining the effectiveness of the CP system. Two of these methods, instant on negative 850 mV relative to a copper/copper sulfate reference electrode and the 100 mV polarization criteria, have limitations. The staff believes that the instant off negative 850 mV criterion relative to a copper/copper sulfate reference electrode is the most effective acceptance criterion for evaluating the effectiveness of a CP system.

f) Excessive levels of CP can result in coating disbondment, which can be addressed by setting an upper level of CP voltage acceptance (i.e., no more negative than) criterion.

g) Parameters such as potential differences and current measurements are trended to detect a change in the protection provided to buried in-scope piping.

h) If the CP system is credited in an applicant's buried piping inspection program or the risk ranking of buried piping segments to be inspected, the Updated Final Safety Analysis Report supplement should reflect that CP is a preventive measure for the program.

2. Recent excavated direct visual inspections of buried piping at the site found rocks in the backfill (a non-conforming condition) at a number of inspection sites. Although no damage to piping or pipe coatings was found to be associated with these conditions, the multiple instances in which rocks were found in the backfill suggests that an extent of condition evaluation may be warranted if future buried piping inspections detect deleterious materials in the backfill that have damaged the coating.

Request

1. Respond to the following related to CP:

a) State how often CP surveys will be conducted.

b) State what parameters will be monitored during CP surveys.

c) State how the availability of the CP system will be monitored and state the associated availability acceptance criterion that will be used in order to credit the CP system during the risk ranking process.

Docket Nos. 50-247 & 50-286 NL-13-098 Attachment Page 3 of 15 d) State how the effectiveness of the CP system will be monitored and state the associated effectiveness acceptance criterion that will be used in order to credit the CP system during the risk ranking process.

e) State the following:

Whether an instant on negative 850 mV relative to a copper/copper sulfate reference electrode, instant off negative 850 mV relative to a copper/copper sulfate reference electrode, 100 mV minimum polarization, or alternative acceptance criteria will be used to demonstrate the effectiveness of the CP system.

If the instant on negative 850 mV relative to a copper/copper sulfate reference electrode criterion is used, state how voltage drops other than those across the structure-to-electrolyte boundary will be determined.

If the 100 mV minimum polarization criterion is used, state how it is known that the effects of mixed potentials (e.g., presence of a copper grounding grid) are minimal and why the most anodic metal in the system is adequately protected.

If an alternative means of demonstrating the effectiveness of the CP system is used, state the alternative acceptance criteria.

f) State the upper level voltage acceptance criterion (i.e., no more negative than) for CP and the basis for the value.

g) State what CP system parameters will be trended.

h) Appropriately revise License Renewal Application Sections A.2.1.5 and A.3.1.5 to reflect crediting the CP system as a preventive measure for portions of the buried in-scope piping.

2. State what criteria will be used to conduct an extent of condition evaluation if non-conforming backfill is found to cause damage to buried piping coatings.

Response to Information in Background and Issue Sections of RAI 3.0.3.1.2-4 Entergy provides the information below concerning the use of cathodic protection (CP), the buried piping inspection program, and backfill-related operating experience (OE) at IPEC in response to the NRC Staff background and issue statements above.

Recent and Planned (Near-Term) Installations of CP Systems at IPEC IP2 City Water Piping: In October 2008, PCA Engineering, Inc. (PCA) performed a corrosion/CP field survey and assessment of underground structures at IPEC. See Engineering Report No. IP-RPT-09-00011, Rev. 0, Corrosion/Cathodic Protection Field Survey and Assessment of Underground Structures at Indian Point Energy Center Unit Nos. 2 and 3 During October 2008 (Dec. 2, 2008). PCA recommended that Entergy mitigate the stray current affecting the city water piping where that piping crosses over the Algonquin natural gas pipeline.

In November 2009, Entergy installed CP to protect the affected portions of the IP2 16-inch city water line.

IP2/IP3 Aux Feedwater/Condensate Piping: Based on IPEC operating experience, Entergy installed CP for portions of the IP2 auxiliary feedwater/condensate buried piping in early 2012.

Docket Nos. 50-247 & 50-286 NL-13-098 Attachment Page 4 of 15 Specifically, Entergy installed CP to protect portions of the Unit 2 condensate storage tank lines

1. 1505 and #1509 (12-inch to AFW and 8-inch return to the CST, respectively). Entergy is completing installation of CP to protect portions of the Unit 3 condensate storage tank lines

1. 1070 and #1080 (12" to AFW and 8-inch return to the CST, respectively).

IP2 Service Water Piping: Based on the results of guided wave testing of buried piping, Entergy initiated plans to install CP on a portion of the IP2 24-inch service water piping near the primary auxiliary building (PAB). However, inspections of this piping in December 2012 showed only limited coating degradation on lines 24-SW-405 and 24-SW-408, and ultrasonic testing (UT) of those lines showed acceptable wall thicknesses. No coating degradation was observed on line 24-SW-409. Consequently, Entergy is evaluating whether installation of CP on the IP2 24-inch service water lines is necessary.

Relationship between the Use of Cathodic Protection at IPEC and the License Renewal Buried Piping and Tanks Inspection Program (BPTIP)

As discussed in response to RAI 3.0.3.1.2-4(1)(h) below, CP is not credited as a preventive measure for the purpose of reducing the number of inspections of in-scope buried piping at IPEC. NUREG-1801, Rev. 2, AMP XI.M41, as revised by Final LR-ISG-2011-03, recognizes that CP is not available at all plants, and that other measures may be taken to protect buried piping and tanks without cathodic protection. Specifically, AMP XI.M41 provides that soil testing and augmented inspections constitute an acceptable alternative to installing site-wide cathodic protection. In addition to further soil testing, Entergy has committed to perform a minimum of 94 total direct visual inspections of in-scope buried piping.

CP systems installed to protect license renewal in-scope buried piping represent actions to minimize possible corrosion of buried piping identified as susceptible to potential corrosion based on the results of indirect inspection methods (i.e., guided wave testing and APEC surveys). The protective coatings and wrappings applied to the external surfaces of those buried pipes still provide the primary protection against corrosion and constitute the applicable preventive measure under the BPTIP. Coupled with the soil testing and numerous direct visual inspections of buried piping (and associated backfill) specified by the BPTIP, these coatings provide reasonable assurance that Entergy will adequately manage the effects of aging on in-scope buried components during the period of extended operation (PEO).

Backfill Quality As of the date of this response, Entergy has completed direct visual inspections of more than two dozen IPEC buried piping segments that are in-scope for license renewal. Entergy also has completed direct visual inspections of other buried piping segments that are not in-scope for license renewal but are subject to Entergys 10 C.F.R. Part 50 Underground Piping and Tanks Inspection and Monitoring Program. Figure 1 shows the locations of the excavated direct visual inspections completed to date. For each excavation number shown in the figure, Table 1 identifies the applicable line number(s) and inspection date.

Docket Nos. 50-247 & 50-286 NL-13-098 Attachment Page 5 of 15 Figure 1. Locations of Excavated Direct Visual Inspections of IPEC Buried Piping Completed (as of July 2013)

Table 1. Chronological Listing of Completed Excavated Direct Visual Inspections of IPEC Buried Piping (as of July 2013)

Excavation No. Line Number(s) Inspection (Note 1) Date IP2 2008 Upper: 12 AFW suction line (12-AFW-1505) Nov. 2008 8 AFW recirculation line (8-AFW-1509) 10 CST overflow corrugated metal pipe (CMP) (10-AFW-OF-2)

Lower: 12 AFW suction line (12-AFW-1505) 8 AFW recirculation line (8-AFW-1509) 10 CST overflow CMP (10-AFW-OF-2)

IP2 2009 8 CST leak (8-AFW-1509) Feb. 2009 Opportunistic IP2 2009 10& 16 Circ Water (10-CW-CWST) & (16-CW-CWST) Oct. 2009 Opportunistic IP2 2009 10 Fire Protection (10-FP-1) Nov. 2009 Opportunistic IP3 2011 6 Fire Protection (6-FP-3) included the header and a 6 Aug. 2011 Opportunistic branch to the PAB

Docket Nos. 50-247 & 50-286 NL-13-098 Attachment Page 6 of 15 Excavation No. Line Number(s) Inspection (Note 1) Date 8 Fire Protection (8-FP-2) 1.5 Administrative Air (1.5-AA-1) 2 Demineralized Water (2-DW-1) 2 Potable Water-Cold (2-PWC-1)

EXC2-2 24 SW Lines (24-SW-408 & 24-SW-409) Nov. 2011 2 Service Air (2-SA-2) at EXC2-2 84 Circ Water (84-CW-26)

EXC3-3 12 Aux Boiler Feed (12-AF-1070) Dec. 2011 8 Aux Boiler Feed (8-AF-1080)

IP3 2012 2 Instrument Air (2-AA-1156) June 2012 A, B, C & D Three 3 Service Water lines (3-SW-1196, 3 SW-1197, Opportunistic and 3-SW-1200) 1 City Water (1-CW-1) 6 Sanitary Sewer (6-SS-20)

IP2 2012 8 Service Water (8-SW-463) Oct. 2012 Opportunistic 8 HP Fire Protection (8-FP-7) 8 City Water (8-CW-1502)

EXC4-2 24 Service Water (24-SW-408) Dec. 2012 24 Service Water (24-SW-409) 24 Service Water (24-SW-405) 6 Fire Protection (6-FP-7) 2 City Water (2-CW-1511) 8 City Water (8-CW-1502) 11/2 Weld Channel (1.5-WCP-1) 3 Station Air (3-SA-1) 3 Primary Water (3-SW-163) 2 Instrument Air (2-IA-2)

EXC1-3 1.5 Admin Air (1.5-AA-2) May 2013 2 Potable Water (2-PW-(C)-1) 2 Demineralized Water (2-DW-1) 8 Fire Protection (8-FP-2) 6 Fire Protection (6-FP-5) 8 guard pipe containing 2 Liquid Waste Disposal (2-LWD-2) 6 Waste Disposal (6-WD-252) 3 Safety Injection (3-SI-161-3, 3-SI-161-4) 12 Safety Injection (12-SI-181-3, 12-SI-181-4) 16 Safety Injection (16-SI-155-3, 16-SI-155-4) 16 guard pipe containing 6 Steam (6-SI-561) and 2 Condensate (2-SI-678)

Notes:

1. EXC (SEQUENCE#-UNIT) = Planned Excavation The direct visual inspections performed to date do not indicate that poor backfill quality or metal loss caused by external corrosion is a systemic issue at IPEC. There has been only one

Docket Nos. 50-247 & 50-286 NL-13-098 Attachment Page 7 of 15 instance in which non-conforming backfill was determined to be the likely cause of significant metal loss in a buried pipe (i.e., the 2009 leak from the IP2 CST return line).

The numerous direct visual inspections performed since February 2009 have not revealed evidence of damage to pipe coatings caused by rocks or debris in the backfill. The October 2012 inspections (opportunistic inspections in the oil containment moat area) and December 2012 inspections (inspections within EXC4-2 at the inlet to the IP2 PAB) identified some rocks in the backfill. Both sets of inspections were conducted in the IP2 transformer yard, which, as Figure 1 shows, is only one of numerous locations at which Entergy has visually inspected buried piping (and found the backfill to be of acceptable quality). During the October 2012 inspections (8-inch service water, fire protection, and city water lines), inspectors observed some small rocks (less than 2 inches in diameter) in contact with the outer wrap but no associated damage. The December 2012 inspections detected some rocks in the backfill, but the rocks were not in contact with the pipes. Entergy performed ultrasonic testing (UT) on all three pipes inspected in October 2012 and on the majority of the pipes inspected in December 2012. The UT examinations confirmed acceptable pipe wall thicknesses. See UT inspection reports UT-12-030, UT-13-001, UT-13-002, UT-13-003, UT-13-004, UT-13-005, and UT-13-006.

Entergy has performed soil testing, guided wave testing, and an APEC survey to further assess soil conditions, buried pipe coating condition, and corrosion potential at IPEC. See Structural Integrity Associates, Inc. (SIA), Report No. 0900235.401.R0, G-Scan Assessment of Various Buried Piping (Nov. 2009); SIA Report No. 0900271, Rev. 0, Indian Point Energy Center APEC Survey (Sept. 2011); SIA Report No. 1000820.401.R0, GWT/UT Assessment at Indian Point Nuclear Entergy Center (Units 2 and 3) (Mar. 2012). The data obtained from those activities indicate that IPEC soils are non-aggressive (i.e., negligible degree of corrosivity) and that degradation, if any, of buried piping is progressing slowly.

Responses to Specific Information Requests in RAI 3.0.3.1.2-4

1. The following specific RAI responses are provided:

a) Entergy will implement CP monitoring prior to the PEO. As part of current plant operations, IPEC is strategically applying CP to provide supplemental corrosion protection for buried piping on which localized areas of coating degradation have been observed. The location and output from a particular rectifier/anode bed combination (aka CP system) is based on the surface area of pipe to be protected. The extent of pipe protected by each CP system is determined during the CP system commissioning process. This monitoring program will include CP surveys under IPECs PM program performed at least once every twelve (12) months (NACE SP0169-2007 Section 10) within these defined CP system protection regions.

b) The CP monitoring plan will measure the instant-off pipe-to-soil potentials within the regions defined as receiving protection from the respective CP impressed current system(s) in accordance with SP0169-2007, Section 6.2.2.1.2.

Docket Nos. 50-247 & 50-286 NL-13-098 Attachment Page 8 of 15 c) For the areas in which CP systems are installed to supplement corrosion control, a minimum availability of 85% (LR-ISG-2011-03 page A-7) will be used as the acceptance criterion for crediting the CP system during the BPTIP risk ranking process. The percent of system availability will be calculated by determining the percent of the time the rectifiers are in service providing cathodic protection. In service is defined as rectifier current output values greater than zero amps or zero volts. The time the system is out of service for testing is not included in the calculation of system availability. Failure to meet this acceptance criterion will result in no credit being taken for the CP system in the risk ranking process required by the license renewal BPTIP. These CP systems have not been credited to reduce the number of direct visual inspections of in-scope buried piping that Entergy has committed to perform before and during the PEOs for IP2 and IP3.

d) CP system effectiveness will be monitored by measuring the soil-to-pipe potential when using a saturated copper/copper sulfate reference electrode at defined locations (i.e.,

test stations) within each CP system coverage area. The system will first be evaluated against the NACE SP0169-2007 Section 6.2.2.1.2 negative polarized potential of at least 850 mV (instant off) criterion. A test point that doesnt meet this criterion will be tested against the 100 mV polarization criterion (NACE SP0169-2007 Section 6.2.2.1.3; LR-ISG-2011 pages A-13 to A-14), provided that the potential influence of mixed metals located in proximity to the soil-to-pipe potential measurement is evaluated. A minimum of 80% (LR-ISG-2011-03 page A-7) of the test locations must meet the NACE SP0169 acceptance criteria to meet the IPEC sites CP system effectiveness criteria. The percent of CP effectiveness will be calculated by using the last measured values at each test station and dividing the total number of CP survey points that meet the required acceptance criteria by the total number of points surveyed during the monitoring period.

Failure to meet these acceptance criteria will result in no credit being taken for the CP system in the BPTIP risk ranking process.

e) The following responses are provided to the bulleted requests.

A soil-to-pipe potential of instant-off -850 mV relative to a copper/copper sulfate reference electrode will be used as the preferred acceptance criterion for establishing the effectiveness of the CP system.

The instant-on negative 850 mV relative to a copper/copper sulfate reference electrode criterion will not be used.

The 100mV polarization criterion may be used to establish the CP system effectiveness at IPEC when the instant-off 850 mV criteria is not met. When using the 100 mV criterion, the native potential in the area is measured either through depolarization decay or by monitoring the polarization formation following a new CP system installation, as prescribed by Section 10 of NACE Standard TM0497, Measurement Techniques Related to Criteria for Cathodic Protection on Underground or Submerged Metallic Piping Systems. In addition, the effect of mixed metal potentials in the measurement area is evaluated. For new CP system installations, the absence of exposed copper grounding is confirmed, to the extent practicable, during the excavations to install the systems. For existing CP systems, corrosion monitoring probes may be installed near pipe depth to

Docket Nos. 50-247 & 50-286 NL-13-098 Attachment Page 9 of 15 ensure that the pipe of concern is being adequately protected given the possible presence of mixed metal potentials. On a related note, the 100 mV polarization criterion also is a metric monitored as part of an APEC survey, which, in addition to measuring the native and instant-off potentials, considers the location of ferrous pipe relative to the copper grounding grid.

Entergy does not anticipate using an alternative means for demonstrating the effectiveness of the CP system. The failure to meet the 100 mV polarization criterion (which is not uncommon in dry, high-resistance soils) during a new CP system commissioning would prompt further investigation. For example, in that circumstance, corrosion coupons or corrosion probes can be used to confirm the low corrosivity of the in situ soils, such that CP and compliance with the NACE SP0169 CP system effectiveness criteria are not necessary. Specifically, CP systems are required, or effective, only when supplemental corrosion protection is needed at localized areas of coating degradation in corrosive soil environments.

f) The CP monitoring plan will evaluate the buried pipe materials within the regions protected by the CP systems. The site will use an upper voltage acceptance criterion of 1200 mV for instant-off measurements (LR-ISG-2011-03 page A-13). Measured values exceeding this upper limit will be entered into the corrective action program for evaluation and determination of corrective actions.

g) Three key parameters will be trended: (1) rectifier current output, (2) test station potential measurements, and (3) rectifier voltage output.

h) The IPEC CP systems will not be credited as preventive measures for the in-scope buried piping. CP systems installed to protect license renewal in-scope buried piping will be used to minimize corrosion in areas that have been found susceptible to corrosion based on indirect inspections (i.e., guided wave inspections) or testing (e.g., APEC surveys). To the extent they are proven effective, the CP systems at IPEC will be considered in risk ranking to ensure that the in-scope buried piping systems that are more susceptible to external corrosion continue to receive a higher risk ranking when determining inspection priority. Therefore, no revision to License Renewal Application Sections A.2.1.5 and A.3.1.5 is necessary because Entergy is not crediting the CP system as a preventive measure for in-scope buried piping.

2. As discussed above, Entergy observed small rocks in the backfill during the Fall 2012 excavations in the IP2 transformer yard. However, there was no indication that the rocks had compromised the protective coatings on the inspected buried pipes. Further, the condition of the buried pipe coatings observed during the numerous other direct visual conditions performed since February 2009 indicates that the backfill adjacent to the piping is not damaging the coatings or contributing to corrosion of the piping.

If future inspections reveal significant coating damage caused by non-conforming backfill, then Entergy will double the inspection sample size. If adverse indications are found in the expanded inspection sample, then Entergy will determine the extent of condition and the extent of cause. The size of the follow-up inspection sample will be determined based on the

Docket Nos. 50-247 & 50-286 NL-13-098 Attachment Page 10 of 15 extent of condition and the extent of cause. The timing of the additional examinations will be based on the severity of the degradation and will be commensurate with the consequences of a leak or loss of function from the affected pipe. In all cases, the expanded sample inspections will be completed within the 10-year interval in which the original adverse indication was identified. Sample size expansion may be limited by the extent of piping or tanks subject to the observed degradation mechanism.

RAI 3.0.3.1.13-1

Background

By letter dated March 18, 2013, Entergy revised LRA Section B.1.33, "Selective Leaching," to state that the inspection sample size will be at least 20 percent of each material-environment population or a maximum of 25 components, consistent with NUREG-1801, "Generic Aging Lessons Learned (GALL) Report," Revision 2, Aging Management Program (AMP) XI.M33, "Selective Leaching." Previously, the sample size in the Selective Leaching Program was based on a method that demonstrates a 90 percent confidence that 90 percent of the population does not experience degradation.

GALL Report, Revision 2, AMP XI.M33 states that the representative sample population focuses on the bounding or lead components most susceptible to aging due to time in service, severity of operating conditions, and lowest design margin.

Issue The revision to the sampling criterion in the Selective Leaching Program incorporated the recommended sample size from the GALL Report, Revision 2; however, the recommendation to focus on components most susceptible to aging was not included. The staff considers the focus on most-susceptible locations as the most effective means to demonstrate the absence of selective leaching.

Request State the criteria that will be used to select the inspection locations within the Selective Leaching Program. If the selected locations will not be those most susceptible to selective leaching, provide the technical justification for the alternative sampling methodology.

Response to RAI 3.0.3.1.13-1 Inspections include a representative sample of the system population and focus on the bounding or leading components most susceptible to aging due to time in service, severity of operating conditions, and lowest design margin. Where possible, low flow/stagnant areas, drains, and low points are inspected since these locations are considered the most susceptible to aging effects.

Docket Nos. 50-247 & 50-286 NL-13-098 Attachment Page 11 of 15 RAI 3.4A.2.3.5-1

Background

As amended by letter dated September 26, 2012, LRA Table 3.4.2-5-7-IP2 states that plastic tube sheets exposed to treated water and condensation have no aging effect and no recommended AMP.

Issue Plastic materials have different material properties that vary depending on chemical composition. Therefore, aging effects might be applicable to the specific type of plastic due to the impact of factors such as ultraviolet light, ozone, high temperatures, chemicals, or radiation.

It is not clear where these components are located. Therefore, the staff cannot evaluate the potential environmental impacts on these materials.

Request Provide the specific type of plastic material used for the components referenced above, state any applicable aging effects for their given environment including potential radiation effects, and state the basis for why these specific components do not require aging management.

Response to RAI 3.4A.2.3.5-1 The tube sheet in question is internal to the instrument air (IA) after-cooler. It is made of micarta (a phenolic resin laminate). With respect to environmental conditions, the tube sheet is exposed to condensation in the IA system and treated water. The air temperature is less than 200 degrees Fahrenheit (F), and the treated water side is exposed to 70 to 110 degrees F. The IA compressors and after-cooler are normally in a standby mode. In the standby mode, the air side is exposed to less than 110 degree ambient temperature. The tube sheets are not exposed to ultraviolet light, ozone, high temperatures, aggressive chemicals, or radiation.

Micarta is a hard dense material that is highly resistant to degradation in the above environments, as confirmed by industry operating experience (documented in the EPRI Non-Class 1 Mechanical Implementation Guideline and Mechanical Tools, Revision 4). In addition, IPEC has no site operating experience involving degradation of the tube sheets. Therefore, age-related degradation of the tube sheet is not expected. Nevertheless, IPEC will conservatively manage the effects of aging on the tube sheet by inspecting both sides of the tube sheet at least once every five years under the Periodic Surveillance and Preventive Maintenance Program.

Accordingly, Entergy is revising the LRA as shown below. Additions are shown with underline and deletions with strikethrough.

Docket Nos. 50-247 & 50-286 NL-13-098 Attachment Page 12 of 15 Table 3.4.2-5-7-IP2 Instrument Air System Components Required to Support AFW Pump Room Fire Event Summary of Aging Management Review Heat Pressure Plastic Treated water None None -- -- F exchanger boundary (int) Change in Periodic (tube Material Surveillance sheets) Properties and Preventive Maintenance Heat Pressure Plastic Condensation None NonePeriodic -- -- F exchanger boundary (ext) Change in Surveillance (tube Material and sheets) Properties Preventive Maintenance A.2.1.28 Periodic Surveillance and Preventive Maintenance Program The Periodic Surveillance and Preventive Maintenance Program is an existing program that includes periodic inspections and tests that manage aging effects not managed by other aging management programs. In addition to specific activities in the plant's preventive maintenance program and surveillance program, the Periodic Surveillance and Preventive Maintenance Program includes enhancements to add new activities. The preventive maintenance and surveillance testing activities are generally implemented through repetitive tasks or routine monitoring of plant operations.

Surveillance testing and periodic inspections using visual or other non-destructive examination techniques verify that the following components are capable of performing their intended function.

• reactor building cranes (polar and manipulator), crane rails, and girders, and refueling platform

• recirculation pump motor cooling coils and housing

• city water system strainer housings and valve bodies

• charging pump casings

• plant drain components and backwater valves

• station air containment penetration piping

• HVAC duct flexible connections

• HVAC stored portable blowers and flexible trunks

• EDG exhaust components

• EDG duct flexible connections

• EDG air intake and aftercooler components

• EDG air start components

• EDG cooling water makeup supply valves

• security generator exhaust components

• security generator radiator tubes

Docket Nos. 50-247 & 50-286 NL-13-098 Attachment Page 13 of 15

• SBO/Appendix R diesel exhaust components

• SBO/Appendix R diesel turbochargers and aftercoolers

• SBO/Appendix R diesel cooling water heat exchangers

• SBO/Appendix R diesel fuel oil cooler

• diesel fuel oil trailer transfer tank and associated valves

• auxiliary feedwater components

• containment cooling duct flexible connections

• containment cooling fan units internals

• control room HVAC condensers and evaporators

• control room HVAC ducts and drip pans

• control room HVAC duct flexible connections

• circulating water, city water, intake structure system, emergency diesel generator, fresh water cooling, instrument air, integrated liquid waste handling, lube oil, miscellaneous, radiation monitoring, river water, station air, waste disposal, wash water, and water treatment plant system piping, piping components, and piping elements

• pressurizer relief tank

• main steam safety valve tailpipes

• atmospheric dump valve silencers

• feedwater system sight glass housings

• off-site power feeder, 138 kV underground transmission cable

• main condenser tube internal surfaces and condensate system expansion joints

• instrument air aftercooler tube internal surfaces, tube sheets and filters

• fresh water/river water heat exchanger internal and external surfaces

• circulating water system expansion joints, and pump casings

• river water system pump casings

• wash water system pump casings

• station air, compressor casings, filter housings, heat exchanger tubes, strainer housings, tanks, and traps The Periodic Surveillance and Preventive Maintenance Program will be enhanced as follows.

• Program activity guidance documents will be developed or revised 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.

Enhancements will be implemented prior to the period of extended operation.

B.1.29 PERIODIC SURVEILLANCE AND PREVENTIVE MAINTENANCE Program Description The Periodic Surveillance and Preventive Maintenance Program is an existing program that includes periodic inspections and tests that manage aging effects not managed by other aging management programs. In addition to specific activities in the plant's preventive maintenance program and surveillance program, the Periodic Surveillance and Preventive Maintenance Program includes enhancements to add new activities. The preventive maintenance and surveillance testing activities are generally implemented through repetitive tasks or routine

Docket Nos. 50-247 & 50-286 NL-13-098 Attachment Page 14 of 15 monitoring of plant operations. Credit for program activities has been taken in the aging management review of the following systems and structures. All activities are new unless otherwise noted.

Instrument air system Use visual or other NDE techniques to internally inspect heat exchanger tubes on the instrument air aftercoolers to manage loss of material and fouling,. Visually inspect filters exposed to indoor air, and tubing, piping and valve bodies exposed to condensation to manage loss of material.

Visually inspect tubesheets on the instrument air aftercoolers to manage change in material properties.

4. Detection of Aging Effects Parameters Monitored and Inspection Methods for Specific Aging Effects and Mechanisms Aging Aging Parameter Inspection Effect Mechanism Monitored Method Loss of Crevice Surface Visual (VT-1 or equivalent) or Material Corrosion condition or Volumetric (RT or UT)

Wall thickness Loss of Galvanic Surface Visual (VT-3 or equivalent) or Material Corrosion condition or Volumetric (RT or UT)

Wall thickness Loss of General Surface Visual (VT-3 or equivalent) or Material Corrosion condition or Volumetric (RT or UT)

Wall thickness Loss of MIC Surface Visual (VT-3 or equivalent) or Material condition or Volumetric (RT or UT)

Wall thickness Loss of Pitting Surface Visual (VT-1 or equivalent) or Material Corrosion condition or Volumetric (RT or UT)

Wall thickness Loss of Erosion Surface Visual (VT-3 or equivalent) or Material condition or Volumetric (RT or UT)

Wall thickness Cracking SCC or Cyclic Cracks Enhanced Visual (VT-1 or Loading equivalent) or Volumetric (RT or UT)

Cracking (for elastomers) Cracks Visual (VT-3 or equivalent)

Change in Material Hardening and Visual (VT-3 or equivalent)

Properties (for elastomers) Cracks Change in material Cracking, Visual (VT-3 or equivalent) properties (for fiberglass blistering and and plastic/micarta) change in color

Docket Nos. 50-247 & 50-286 NL-13-098 Attachment Page 15 of 15

6. Acceptance Criteria Periodic Surveillance and Preventive Maintenance Program acceptance criteria are defined in specific inspection and testing procedures. Acceptance criteria include appropriate temperature, no significant wear, corrosion, cracking, change in material properties (for elastomers), and significant fouling based on applicable intended functions established by plant design basis. Any indications or relevant conditions of degradation are reported and submitted for further evaluation as part of the corrective action program. This evaluation is performed against criteria which ensure that the structure or component intended function(s) are maintained under all current licensing basis design conditions during the period of extended operation. These criteria include no unacceptable wear, corrosion, cracking, change in material properties (for elastomers), or change in material properties (for fiberglass and plastic/micarta) or significant fouling. Specific quantitative or qualitative criteria for acceptability are contained in manufacturer information or vendor manuals for some individual components. The engineering review process is used in situations where appropriate manufacturer data is unavailable.

RAI 3.4.2.1.9-1

Background

As amended by letter dated September 26, 2012, LRA Table 3.4.2-5-13-IP2 states that gray cast iron compressor and strainer housings exposed to condensation (internal) will be managed for loss of material using the Periodic Surveillance and Preventative Maintenance Program.

Issue Sufficient information is not available to determine whether selective leaching could occur because of the potential accumulation of condensation in the gray cast iron compressor and strainer housing.

Request Could sufficient condensation accumulate in any portions of the gray cast iron compressor and strainer housings such that selective leaching could occur? If selective leaching could occur in these components, how will the aging effect be managed?

Response to RAI 3.4.2.1.9-1 The gray cast iron compressor and strainer housings in Table 3.4.2-5-13 IP2 would not accumulate sufficient condensation that could result in selective leaching as they are drained by trap systems. Selective leaching in a condensation environment has not been observed at IPEC.

UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION BEFORE THE ATOMIC SAFETY AND LICENSING BOARD In the Matter of ) Docket Nos. 50-247-LR and

) 50-286-LR ENTERGY NUCLEAR OPERATIONS, INC. )

)

(Indian Point Nuclear Generating Units 2 and 3) )

) July 25, 2013 CERTIFICATE OF SERVICE Pursuant to 10 C.F.R. § 2.305 (as revised), I certify that, on this date, a copy of Entergys letter to the Administrative Judges regarding NL-13-098 was served upon the Electronic Information Exchange (the NRCs E-Filing System), in the above-captioned proceeding.

Signed (electronically) by Lance A. Escher Lance A. Escher, Esq.

MORGAN, LEWIS & BOCKIUS LLP 1111 Pennsylvania Ave. NW Washington, DC 20004 Phone: (202) 739-5080 Fax: (202) 739-3001 E-mail: lescher@morganlewis.com DB1/ 75111752.1