W3F1-2016-0070, Responses to Request for Additional Information Set 3 Regarding the License Renewal Application

Responses to Request for Additional Information Set 3 Regarding the License Renewal Application

ML16347A672
Person / Time
Site:	Waterford
Issue date:	12/12/2016
From:	Chisum M Entergy Operations
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
W3F1-2016-0070
Download: ML16347A672 (35)

Text

Entergy Operations, Inc.

17265 River Road Killona, LA 70057-3093 Tel 504-739-6660 Fax 504-739-6698 mchisum@entergy.com Michael R. Chisum Site Vice President Waterford 3 W3F1-2016-0070 December 12, 2016 U.S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, DC 20555-0001

SUBJECT:

Responses to Request for Additional Information Set 3 Regarding the License Renewal Application for Waterford Steam Electric Station, Unit 3 (Waterford 3)

Docket No. 50-382 License No. NPF-38

REFERENCES:

1. Entergy letter W3F1-2016-0012 License Renewal Application, Waterford Steam Electric Station, Unit 3 dated March 23, 2016.

2. NRC letter to Entergy Requests for Additional Information for the Review of the Waterford Steam Electric Station, Unit 3, License Renewal Application - Set 3 dated October 12, 2016.

3. Entergy letter W3F1-2016-0069 Responses to Request for Additional Information Set 2 Regarding the License Renewal Application to Waterford Steam Electric Station, Unit 3 dated November 10, 2016

Dear Sir or Madam:

By letter dated March 23, 2016, Entergy Operations, Inc. (Entergy) submitted a license renewal application (Reference 1).

In letter dated October 12, 2016 (Reference 2), the NRC staff made a Request for Additional Information (RAI) Set 3, needed to complete its review. Enclosure 1 provides the responses to the Set 3 RAIs. Also included in Enclosure 1 is the completed response to RAI 4.3.3-1 which was not completely addressed in Reference 3 due to requiring additional vendor support.

There are no new regulatory commitments contained in this submittal. If you require additional information, please contact the Regulatory Assurance Manager, John Jarrell, at 504-739-6685.

I declare under penalty of perjury that the foregoing is true and correct. Executed on December 12, 2016.

Sincerely, MRC/AJH

W3F1-2016-0070 Page 2 of 2

Enclosures:

1. Set 3 RAI Responses - Waterford 3 License Renewal Application cc: Kriss Kennedy RidsRgn4MailCenter@nrc.gov Regional Administrator U. S. Nuclear Regulatory Commission Region IV 1600 E. Lamar Blvd.

Arlington, TX 76011-4511 NRC Senior Resident Inspector Frances.Ramirez@nrc.gov Waterford Steam Electric Station Unit 3 Chris.Speer@nrc.gov P.O. Box 822 Killona, LA 70066-0751 U. S. Nuclear Regulatory Commission Phyllis.Clark@nrc.gov Attn: Phyllis Clark Division of License Renewal Washington, DC 20555-0001 U. S. Nuclear Regulatory Commission April.Pulvirenti@nrc.gov Attn: Dr. April Pulvirenti Washington, DC 20555-0001 Louisiana Department of Environmental Ji.Wiley@LA.gov Quality Office of Environmental Compliance Surveillance Division P.O. Box 4312 Baton Rouge, LA 70821-4312

Enclosure 1 to W3F1-2016-0070 Set 3 RAI Responses Waterford 3 License Renewal Application to W3F1-2016-0070 Page 1 of 32 RAI B.1.16-2

Background:

Section 54.21(a)(3) of 10 CFR requires the applicant to demonstrate that the effects of aging for structures and components will be adequately managed so that the intended function(s) will be maintained consistent with the current licensing basis for the period of extended operation. As described in SRP-LR, an applicant may demonstrate compliance with 10 CFR 54.21(a)(3) by referencing the GALL Report and when evaluation of the matter in the GALL Report applies to the plant.

LRA Section B.1.16 states that the Inservice Inspection - IWF Program, with enhancements, is consistent with GALL Report AMP XI.S3, ASME Section XI, Subsection IWF. The GALL Report AMP XI.S3, ASME Section XI, Subsection IWF states that the ASME Code,Section XI, Subsection IWF constitutes an existing mandated program applicable to managing aging of ASME Class 1, 2, 3 and MC component supports. The AMP monitoring and trending program element, states that examinations that reveal indications which exceed the acceptance standards and require corrective measures are extended to include additional examinations in accordance with IWF-2430. IWF-2420 states that to the extent practical, the same supports selected for examination during the first inspection interval shall be examined during each successive inspection interval. During its onsite audit, the staff reviewed operating experience and found:

1. For component supports and/or related hardware examined during IWF sampling inspections, degraded conditions were identified and, although conditions were acceptable-as-is, the components were re-worked/repaired to as-new condition or replaced. Since it was determined that the as-found condition did not affect the supports capability to perform its design function or exceed the threshold of ASME Section IWF-3400, Acceptance Criteria, the applicant determined the actions associated with ASME Sections IWF-2420, Successive Inspections, and IWF-2430, Additional Examinations, criteria were not required and thus did not apply those code provisions.

2. Component supports and/or related hardware where degraded conditions were identified and re-worked/repaired or replaced as the result of walkdowns or other activities and not directly tied to an ISI-IWF inspection. However, the staff did not find evidence of an evaluation to determine whether the supports repaired were supports that were part of the IWF sample that is periodically inspected by the ISI-IWF program. Conferencing with the applicant during the onsite audit indicated that such a process to identify whether repaired component supports are in the IWF inspection sample may not exist.

Issue:

Given that the program will manage aging of the entire ASME Code component support population through inspections of a representative population, any ISI-IWF sampled support that is re-worked to as-new condition or replaced would no longer be representative of other supports in the IWF component support population. Subsequent ISI-IWF inspections of the same sample may not represent the age-related degradation of the remaining population of supports that are not inspected.

to W3F1-2016-0070 Page 2 of 32 The applicants LRA and associated basis documents do not provide a discussion of how this issue is addressed in the AMP, or if the current processes consider expansion or change of the ASME-based IWF sample if a component support and/or related hardware within the IWF sample were electively reworked or replaced. In addition, it is not clear whether a re-worked component support that is part of the ISI-IWF sample but not identified through the ASME ISI-IWF inspection, (but rather via a walkdown, other program, or some other means), would continue to be included in the ISI-IWF AMP program sample. As a result, it is not clear how the program will ensure that the ISI-IWF AMP component support inspection sample reflects the age-related degradation of the remaining population of IWF supports that are not inspected.

Request:

For situations in which a component that is inspected under the IWF sample is re-worked such that it no longer represents age-related degradation of the entire population, describe how the Inservice Inspection - IWF Program will continue to be effective in managing the aging effects of similar/adjacent components that are not included in the IWF inspection sample.

Other RAIs applicable to TRP 043 but addressed under another TRP:

RAI B.1.6-1: TRP 041 (Containment Inservice Inspection - IWE)

RAI B.1.6-2: TRP 041 (Containment Inservice Inspection - IWE)

RAI B.1.1-2: TRP 019 (Bolting Integrity)

Waterford 3 Response Waterford 3 (WF3) Inservice Inspection (ISI)-IWF Program as described in the license renewal application (LRA) Section B.1.16 manages aging effects of IWF component supports. As described in the LRA, the program was developed in accordance with ASME Section XI as approved by 10 CFR 50.55a. The selection of component supports for examination is in accordance with Table IWF-2500-1. The Inservice Inspection IWF Program will be enhanced to include assessment of the impact on the inspection sample representativeness if components that are part of the sample population are reworked.

LRA Sections A.1.16 and B.1.16 are revised as follows. Additions are underlined .

A.1.16 Inservice Inspection - IWF Program

• Revise plant procedures to include assessment of the impact on the inspection sample representativeness if components that are part of the sample population are reworked.

to W3F1-2016-0070 Page 3 of 32 B.1.16 Inservice Inspection - IWF Program Enhancements Element Affected Enhancement

5. Monitoring and Trending Revise plant procedures to include assessment of the impact on the inspection sample representativeness if components that are part of the sample population are reworked.

to W3F1-2016-0070 Page 4 of 32 RAI B.1.29-1

Background:

LRA Section B.1.29 states that the One-Time Inspection - Small-Bore Piping Program will be consistent with GALL Report AMP XI.M35. It also states that this program provides a one-time volumetric or opportunistic destructive inspection of a 3-percent sample or maximum of 10 ASME Class 1 piping butt weld locations and a 3-percent sample or a maximum of 10 ASME Class 1 socket weld locations that are susceptible to cracking.

Issue:

LRA Section B.1.29 does not provide the total population of welds for each weld type or the total number of these welds that will be included in the volumetric examinations.

Request:

Characterize the inspection sample size by completing the table below.

Total Number of Total Number of Welds to Welds at WF3 Be Inspected Class 1 Small-Bore Piping Butt Welds Class 1 Small-Bore Piping Socket Welds Revise the summary description LRA Section A.1.29 to specify (a) the weld population, and (b) the inspection sample size.

Waterford 3 Response Total Number of Welds at Total Number of Welds to Be WF3 Volumetrically Inspected Class 1 Small-Bore Piping Butt Welds 371 10 Class 1 Small-Bore Piping Socket Welds 216 7 As described in NUREG 1801, Revision 2, XI.M35, a destructive examination of one socket weld can be considered equivalent to volumetric examination of two welds. Therefore, if destructive examination is used the number of socket weld volumetric inspections could be less than seven.

LRA Section A.1.29 and Section B.1.29 are revised as shown below. Additions are underlined and deletions are shown with strikethrough. In addition, minor clarifications to LRA Section A.1.29 and Section B.1.29 are included.

to W3F1-2016-0070 Page 5 of 32 A.1.29 One-Time Inspection - Small-Bore Piping Program The One-Time Inspection - Small-Bore Piping Program augments ASME Code,Section XI requirements and is applicable to small-bore ASME Code Class 1 piping and components with a nominal pipe size diameter less than 4 inches (NPS < 4) and greater than or equal to NPS 1 inch in systems that have not experienced cracking of ASME Code Class 1 small-bore piping. The program can also be used for systems that have experienced cracking but have implemented design changes to effectively mitigate cracking.

Ten of the 371 ASME Class 1 piping butt welds that meet the selection criteria will receive a one-time volumetric examination. Seven of the 216 ASME Class 1 socket welds that meet the selection criteria will receive a one-time volumetric or opportunistic destructive examination. The program provides a one-time volumetric or opportunistic destructive inspection of a 3 percent sample or maximum of 10 ASME Class 1 piping butt weld locations and a 3 percent sample or a maximum of 10 ASME Class 1 socket weld locations that are susceptible to cracking. Volumetric examinations are performed using a demonstrated technique that is capable of detecting the aging effects in the volume of interest. In the event the opportunity arises to perform a destructive examination of an ASME Class 1 small-bore socket weld that meets the susceptibility criteria, then the program takes credit for two volumetric examinations. The program includes pipes, fittings, branch connections, and full and partial penetration welds.

B.1.29 One-Time Inspection - Small-Bore Piping Program Description The One-Time Inspection - Small-Bore Piping Program is a new program that augments ASME Code,Section XI requirements and is applicable to small-bore ASME Code Class 1 piping and components with a nominal pipe size diameter less than 4 inches (NPS < 4) and greater than or equal to NPS 1 inch in systems that have not experienced cracking of ASME Code Class 1 small-bore piping. The program can also be used for systems that have experienced cracking but have implemented design changes to effectively mitigate cracking. WF3 has not experienced cracking of ASME Code Class 1 small-bore piping due to stress corrosion, cyclical (including thermal, mechanical, and vibration fatigue) loading, or thermal stratification and thermal turbulence.

Since WF3 has an extensive operating history (i.e., greater than 30 years), this program provides a one-time volumetric or opportunistic destructive inspection of a 3-percent sample or maximum of 10 of the 371 ASME Class 1 piping butt welds locations. In addition, the program provides a one-time volumetric or opportunistic destructive inspection of and a 3-percent sample or a maximum of 10 7 of the 216 ASME Class 1 socket welds locations that are susceptible to cracking. Volumetric examinations are performed using a demonstrated technique that is capable of detecting the aging effects in the volume of interest. In the event the opportunity arises to perform a destructive examination of an ASME Class 1 small-bore socket weld that meets the susceptibility criteria, then the program takes credit for two volumetric examinations. The program includes pipes, fittings, branch connections, and full and partial penetration welds.

to W3F1-2016-0070 Page 6 of 32 RAI B.1.30-3

Background:

LRA Table 3.3.2-7, Emergency Diesel Generator System, states that stainless steel expansion joints exposed to exhaust gas will be managed for cracking using the Periodic Surveillance and Preventive Maintenance program. The program description table in LRA Section B.1.30 states that the program inspection activity for the emergency generator system will be to monitor the surface condition of the expansion joint to verify the absence of cracking.

Issue:

It is unclear to the staff what inspection activities are included in monitoring the surface condition of the stainless steel expansion joints in order to verify the absence of cracking.

Request:

Provide details about the monitoring activities in the Periodic Surveillance and Preventive Maintenance program for the surface condition of the emergency diesel generator stainless steel expansion joints to verify the absence of cracking. Provide a discussion on any relevant parameters, such as, inspection technique/methodology, minimum detectable crack size, and allowable crack size based on the configuration. Also include any changes to the program description table and appropriate program elements to reflect any of these additional details.

Waterford 3 Response The emergency generator diesel exhaust expansion joint includes a stainless steel liner shielding the expansion joint convolutions from direct exhaust gases. The liner is welded to the expansion joint flange inside diameter on one end and extends to the opposite end flange with a gap of approximately 0.3 between the liner and the expansion joint convolutions preventing inspection of the internal surface of the convolutions. Action described in the program description table of LRA Section B.1.30 to monitor the surface condition of the expansion joint refers to remote visual inspection using a boroscope or direct visual inspection of the expansion joint external surface and expansion joint liner internal surface.

Identified cracks will be evaluated in accordance with 10 CFR Part 50, Appendix B, as described in LRA Section B.1.30 Elements 6 and 7, Acceptance Criteria and Corrective Actions, respectively. Any indication or relevant condition of degradation detected is evaluated.

The LRA is revised as follows. Additions are shown with underline and deletions with strikethrough.

A.1.30 Periodic Surveillance and Preventive Maintenance Program The Periodic Surveillance and Preventive Maintenance (PSPM) Program manages aging effects not managed by other aging management programs, including change in material properties, cracking, loss of material, and reduction of heat transfer.

Inspections occur at least once every 5 years during the period of extended operation.

to W3F1-2016-0070 Page 7 of 32 Credit for program activities has been taken in the aging management review of the following systems and structures.

Inspect submersible sump pumps and backup pumps for dry cooling towers.

Inspect emergency diesel generator system heat exchanger tubes.

Inspect external surface of stainless steel expansion joint and internal surface of stainless steel expansion joint liner in diesel exhaust.

Inspect tubes and fins of the CCW dry cooling tower radiator.

B.1.30 Periodic Surveillance and Preventive Maintenance Program Description System Inspection Emergency generator Perform a visual inspection of the surface condition of a system representative sample of EDG cooler heat exchanger tubes to manage loss of material due to wear.

Monitor Perform a visual inspection the surface condition of the expansion joint external surface and expansion joint liner internal surface to verify the absence of cracking due to stress corrosion/IGA.

to W3F1-2016-0070 Page 8 of 32 RAI B.1.30-4

Background:

LRA Table 3.3.2-7, Emergency Diesel Generator System, states that stainless steel heat exchanger tubes externally exposed to lubricating oil, fuel oil, and treated water will be managed for loss of material due to wear using the Periodic Surveillance and Preventive Maintenance program.

The program description table in LRA Section B.1.30 states that a visual inspection of the surface condition of a representative sample of stainless steel heat exchanger tubes will be performed to manage loss of material due to wear.

Issue:

Because access to the external surfaces of heat exchanger tubes is typically very limited, it is unclear to the staff whether a visual inspection of the tubes external surfaces can be reasonably expected to detect loss of material due to wear.

Request:

Justify the adequacy of the visual inspection in the Periodic Surveillance and Preventive Maintenance program to detect loss of material due to wear for emergency diesel generator cooler heat exchanger tubes. Provide information on any relevant parameters, such as, tube diameter, tube spacing, wear locations, access points for visual inspection.

Waterford 3 Response Wear could occur on the external side of the diesel generator heat exchanger tubes that may experience intermittent relative motion between the tubes and the tube support members of the heat exchanger. Wear, if applicable, is a design condition that would be detected early in life on heat exchangers in continuous service and would have likely been corrected such that it is not an issue for license renewal. Diesel generator heat exchangers, such as these, normally acquired relatively low service hours after forty years and may be subject to this aging effect.

External visual tube inspections require tube bundle removal, which is not the optimal inspection method. Therefore, the Periodic Surveillance and Preventive Maintenance Program is used to detect loss of material due to wear for emergency diesel generator cooler heat exchanger tubes using eddy current testing. These periodic inspections provide assurance that loss of material due to wear on the treated water, fuel oil, and lube oil sides of the tubes is adequately managed. A representative number of tubes will be inspected as described in LRA Section B.1.30. Any indication or relevant condition of degradation detected is evaluated in accordance with the requirements of 10 CFR Part 50, Appendix B.

LRA Section B.1.30 is revised as follows. Additions are indicated with underline and deletions with strikethrough.

to W3F1-2016-0070 Page 9 of 32 B.1.30 Periodic Surveillance and Preventive Maintenance Program Description System Inspection Emergency generator Perform a visual inspection NDE (eddy current) of the surface system condition of a representative sample of EDG cooler heat exchanger tubes to manage loss of material due to wear.

Monitor the surface condition of the expansion joint to verify the absence of cracking due to stress corrosion/IGA.

RAI B.1.30-5

Background:

LRA Table 3.3.2-3, Component Cooling and Auxiliary Component Cooling Water System, states that aluminum heat exchanger fins and carbon steel heat exchanger tubes exposed to condensation will be managed for reduction of heat transfer using the Periodic Surveillance and Preventive Maintenance program and loss of material using the External Surfaces Monitoring program.

The program description table in LRA Section B.1.30 states that visual or other NDE techniques will be used to inspect a representative sample of dry cooling tower radiator tubes and fins to manage loss of material and fouling that could result in a reduction of heat transfer capability.

Issue:

It is unclear to the staff if loss of material will be managed using the External Surfaces Monitoring or Periodic Surveillance and Preventive Maintenance program. If loss of material for the fins and tubes will be managed by the Periodic Inspection and Preventive Maintenance program, then it is unclear to the staff how a visual inspection can detect loss of material of carbon steel heat exchanger tubes due to limited visibility from fin attachment and tube spacing.

Request:

State if loss of material for the aluminum heat exchanger fins and carbon steel heat exchanger tubes will be managed using the External Surfaces Monitoring or the Periodic Surveillance and Preventive Maintenance program. If loss of material for the fins and tubes will be managed by the Periodic Surveillance and Preventive Maintenance program, justify the adequacy of a visual inspection to detect loss of material for the carbon steel heat exchanger tubes exposed to condensation. Provide information on any relevant parameters, such as, tube outside diameter, tube spacing, number of tube rows, fin outside diameter, fin spacing and attachment to the tube.

Waterford 3 Response The External Surfaces Monitoring Program manages loss of material for the aluminum heat exchanger fins and carbon steel heat exchanger tubes exposed to condensation in the component cooling and auxiliary component cooling water system. The Periodic Surveillance and Preventive Maintenance Program described in LRA Section B.1.30 does not manage loss of material for these components. The program description table in LRA Section B.1.30 is revised to remove loss of to W3F1-2016-0070 Page 10 of 32 material as an aging effect that the Periodic Surveillance and Preventive Maintenance Program manages.

The External Surfaces Monitoring Program employs visual inspections to manage loss of material.

For the aluminum heat exchanger fins and carbon steel heat exchanger tubes exposed to condensation in the component cooling and auxiliary component cooling water system, visual inspections will monitor the accessible surfaces of the tubes and fins. The outer rows of tubes are exposed to the same environment as tubes in the interior of the tube bundles. Therefore, the condition of the accessible outer tubes is representative of the interior tubes making the outer tubes a representative sample of the total population of tubes in the heat exchangers.

LRA Section B.1.30 is revised as follows. Deletions are indicated with strikethrough.

B.1.30 Periodic Surveillance and Preventive Maintenance Program Description There is no corresponding NUREG-1801 program.

The Periodic Surveillance and Preventive Maintenance (PSPM) Program includes periodic inspections and tests to manage aging effects not managed by other aging management programs, including change in material properties, cracking, loss of material, and reduction of heat transfer.

Inspections occur at least once every 5 years during the period of extended operation.

Credit for program activities has been taken in the aging management review of systems, structures and components as described below.

to W3F1-2016-0070 Page 11 of 32 System Inspection Plant drains Perform a visual inspection of the surface condition of a representative sample of the submersible sump pumps and the back-up pumps for the dry cooling towers.

Emergency generator Perform a visual inspection of the surface condition of a system representative sample of EDG cooler heat exchanger tubes to manage loss of material due to wear.

Monitor the surface condition of the expansion joint to verify the absence of cracking due to stress corrosion/IGA.

Component cooling and Use visual or other NDE techniques to inspect a representative auxiliary component sample of the tubes and fins of the CCW dry cooling tower radiator cooling water system to manage loss of material and fouling that could result in a reduction of heat transfer capability.

Perform a visual inspection of the internal surface of the portable UHS replenishment pump casing to manage loss of material.

RCP oil collection Visually inspect the inside surface of RCP oil collection components (RCPOC) (representative samples) in an environment of waste lube oil to manage loss of material.

to W3F1-2016-0070 Page 12 of 32 RAI B.1.34-2

Background:

The scope of program program element of GALL AMP XI.M31 states that the program includes all reactor vessel beltline materials as defined by 10 CFR 50, Appendix G, Section II.F. LRA Section 4.2.1 and Table 4.2-1 identify the Waterford Unit 3 reactor vessel beltline materials that are exposed to 60-year (55-EFPY) fluence greater than 1x1017 n/cm2 (E > 1 MeV). Specifically, LRA Table 4.2-1 indicates that 55-EFPY fluence for the following materials at the clad/metal interface (0T) is 5.82x1017 n/cm2 (E > 1 MeV): (a) upper shell plates M-1002-1, 2, and 3; (b) upper shell longitudinal welds 101-122A, B and C; and (c) upper to intermediate shell circumferential welds 106-121.

The 40-year (32-EFPY) fluence for these upper shell plates and associated welds is approximately estimated as 3.37x1017 n/cm2 (E > 1 MeV) by linear interpolation. The fluence estimate suggests that these upper shell materials are also identified as beltline materials for 32 EFPY.

Issue:

The upper shell materials discussed in the background section are not identified as beltline materials in the evaluation for the 32-EFPY pressure-temperature (P-T) limits described in WCAP-16088-NP, Revision 1, Waterford Unit 3 Reactor Vessel Heatup and Cooldown Limit Curves for Normal Operation, September 2003 (ADAMS ML041620063). Specifically, Table 2-2, Summary of the Waterford Unit 3 Reactor Vessel Beltline Material Chemistry Factors, in WCAP-16088-NP, Revision 1 does not identify these upper shell materials as reactor vessel beltline materials.

Identification of the upper shell materials as beltline materials between the 32-EFPY evaluation and 55-EFPY evaluation is unclear. In addition, consistent consideration of these upper shell materials as beltline materials in the 32-EFPY to 55-EFPY P-T limits should be assured.

Request:

Reconcile inconsistency in identifying the upper shell plates and welds as reactor vessel beltline materials between the 32-EFPY evaluation and 55-EFPY evaluation discussed in the issue section of this RAI.

Waterford 3 Response WCAP-16088-NP, Revision 1, September 2003 describes the method and results for the generation of pressure-temperature (P-T) limit curves at 32 effective full-power years (EFPY). As reported in WCAP-16088-NP, materials considered part of the beltline included three intermediate shell plates, three lower shell plates, intermediate shell plate longitudinal welds, lower shell plate longitudinal welds, and the intermediate to lower shell plate circumferential weld. The three upper shell plates M-1002-1, 2, and 3, three upper shell longitudinal welds 101-122A, B and C, and the upper to intermediate shell plate circumferential weld 106-121 were not considered part of the beltline.

The definition of beltline in 10 CFR 50, Appendix G is not simply those materials that are exposed to a fast neutron fluence of greater than 1.0 x 1017 n/cm2. The beltline is defined as the region of the reactor vessel (shell material including welds, heat affected zones, and plates or forgings) that directly surrounds the effective height of the active core and adjacent regions of the reactor vessel that are predicted to experience sufficient neutron radiation damage to be considered in the selection of the most limiting material with regard to radiation damage. In the 32 EFPY evaluation described in WCAP-16088-NP, Westinghouse did not identify the upper shell plates and associated welds as to W3F1-2016-0070 Page 13 of 32 part of the beltline because these materials were deemed materials that were not the most limiting with regard to radiation damage.

In addition, linear interpolation from the 55 EFPY fluence is not expected to yield an accurate estimate of the 32 EFPY fluence. The Waterford 3 power uprate in 2005 resulted not only in a higher average fluence in the core, but also a different flux distribution than evaluated in the 2003 determination of pressure-temperature limits documented in WCAP-16088-NP, Revision 1.

As indicated in the July 2015 WCAP-18002-NP, the materials that exceed 1.0 x 10 17 n/cm2 (E > 1.0 MeV) fast neutron fluence were evaluated to determine the effect of neutron irradiation embrittlement during the proposed license renewal period. This provides assurance that materials meeting the 10 CFR 50, Appendix G, definition of beltline at the end of the period of extended operation have been evaluated for the effects of neutron irradiation.

to W3F1-2016-0070 Page 14 of 32 RAI B.1.36-4

Background:

LRA Section B.1.36, Service Water Integrity, states that this program manages components as described in the Waterford 3 response to NRC Generic Letter 89-13 [Service Water System Problems Affecting Safety-Related Equipment]. Waterfords response to Generic Letter 89-13, dated January 29, 1990, for Action III (associated with establishing routine inspection of the open-cycle service water system to ensure that corrosion, erosion, silting, and biofouling cannot degrade the performance of systems supplied by service water), states:

The LP&L [the prior licensee] erosion/corrosion program for Waterford was thoroughly presented in its supplemental response to Generic Letter 89-08 (re W3P89-1592, dated November 17, 1989). Components from auxiliary component cooling water (ACCW) - the Waterford safety-related open service water system - will be added to that program before the start of the next refueling outage.

During its recent audit, the staff noted that condition report CR-WF3-2009-00614 and -00852 (which refer to an earlier occurrence in condition report CR-WF3-1997-1316), discuss cavitation erosion damage in piping spool pieces and in valves ACC-126A and -126B. The staff notes that the ACCW system is excluded in current system susceptibility evaluation for the Flow-Accelerated Corrosion program. In addition, although aging management program evaluation report WF3-EP-14-00007, Aging Management Program Evaluation Report Non-Class 1 Mechanical, Section 4.12, Service Water Integrity, cites Entergy Nuclear Management Manual procedure EN-DC-340, Microbiologically Influenced Corrosion (MIC) Monitoring Program, for implementation of some aspects in several program elements, it does not cite Entergy Nuclear Management Manual procedure EN-DC-315, Flow-Accelerated Corrosion, for managing erosion issues associated with Action III of Generic Letter 89-13.

Issue:

The staff notes that Generic Letter 89-08, Erosion/Corrosion-Induced Pipe Wall Thinning, (cited in the letter dated January 29, 1990), established the Flow-Accelerated Corrosion program, as discussed in the GALL Report AMP XI.M17. Because components from the auxiliary component cooling water system are currently not included in the implementation of the program associated with Generic Letter 89-08 (i.e., Flow-Accelerated Corrosion program), it is unclear to the staff what current Service Water Integrity program activities are associated with Generic Letter 89-13, Action III.

In addition, although there have been historical issues with cavitation erosion in portions of the auxiliary component cooling water system, it is unclear to the staff what existing program currently manages the associated loss of material due to erosion. The Service Water Integrity program shows the interrelationship with Entergy Nuclear Management Manual procedure EN-DC-340; however, that program does not appear to include erosion mechanisms. Also the current system susceptibility evaluation for the Flow-Accelerated Corrosion program does not include the auxiliary component cooling water system. The current associated Entergy Nuclear Management Manual Service Water Integrity program procedure EN-DC-184, NRC Generic Letter 89-13 Service Water Program, .2 [3] includes the Service Water System Piping / Component Inspection and Maintenance Program Element that corresponds to Generic Letter 89-13, Action III. However, .1 Procedural Interrelationships currently does not show any connection with the Flow-Accelerated Corrosion program, as implied by Waterfords original Generic Letter 89-13 response. In addition, there is no proposed enhancement to revise the Service Water Integrity to W3F1-2016-0070 Page 15 of 32 program procedures to credit the activities in the Flow-Accelerated Corrosion program as accomplishing portions of Generic Letter 89-13, Action III.

Request:

As it relates to statement in LRA Section B.1.36 regarding managing components as described in the [Waterford 3] response to NRC Generic Letter 89-13, a) Describe what current Service Water Integrity program activities are associated with Waterfords previous commitment for Generic Letter 89-13, Action III.

i) Include a discussion of how the existing program manages the loss of material due to erosion in portions of the ACCW system near valves ACC-126A and ACC-126B.

ii) Include a discussion of how the service water piping inspection program, as required under Entergy Nuclear Management Manual procedure EN-DC-184, Attachment 9.2[3](4) is currently implemented.

b) Clarify whether the planned enhancement to the Flow-Accelerated Corrosion will be credited as part of the Service Water Integrity program by accomplishing portions of Generic Letter 89-13, Action III. Either show that the Service Water Integrity program currently credits the Flow-Accelerated Corrosion program, or provide the bases for why an enhancement to the Service Water Integrity program is not needed Waterford 3 Response a) Commitments described in the response to GL 89-13 (W3P90-0207) are implemented via preventive maintenance activities and microbiologically influenced corrosion (MIC) inspections.

As stated in EN-DC-184, Section 5.0, In cases where EN-DC-184 procedural requirements conflict with docketed licensing commitments, the site licensing commitments shall take precedence. In the case of the auxiliary component cooling water (ACCW) system at Waterford 3, not every provision in EN-DC-184 is applicable to the Waterford 3 commitments for GL 89-13.

(i) Erosion is addressed today with preventive maintenance activities on ACCW valves ACC-126A and ACC-126B. The activities include removing valves from their respective lines, performing a visual inspection of valve and piping, and refurbishing the internal elastomers.

(ii) Entergy has established a routine inspection of the piping near valves ACC-126A and B in accordance with EN-DC-184, Attachment 9.2[3](4).

• Step [3](4)a refers to selection criteria guidance for NDE locations contained in Attachment 9.3. With the exception of areas with the potential for cavitation erosion (addressed in Attachment 9.3[9]), routine NDE inspections as addressed in Attachment 9.3 have not been necessary for the Waterford 3 ACCW system, because water in the ACCW system is demineralized water exposed to air-outdoor and the system was not operated infrequently.

• Step [3](4)b discusses addressing conditions under which ultrasonic testing (UT) or radiographic testing (RT) is to be performed to determine pipe wall thickness. For the Waterford 3 design of the ACCW system, routine NDE inspections as addressed in EN-DC184, Attachment 9.3, are not necessary because the water in the ACCW system is demineralized water exposed to outdoor air and there is only localized wall thinning due to cavitation erosion. Based on visual inspections for wall thinning due to cavitation erosion in and downstream of ACCW valves ACC-126 A and B, engineering evaluates to W3F1-2016-0070 Page 16 of 32 the need for ultrasonic or radiographic testing to ensure minimum wall thickness. The inspections of areas with known susceptibility to erosion specified in EN-DC-184, Attachment 9.2[3](4) are implemented via these routine inspections.

b) The SWI Program described in LRA Section B.1.36 credits established preventive maintenance activities for meeting commitments made in response to GL 89-13 for inspection of areas susceptible to loss of material. The program description indicates that the SWI Program manages loss of material as described in the WF3 response to NRC GL 89-13. Therefore, no enhancement to the SWI Program is needed.

The SWI Program description is also revised to remove references to GL 89-13 requirements that were satisfied with one-time activities, as described in NUREG-1801, XI.M20.

LRA Sections A.1.36 and B.1.36 are revised as shown below. Deletions are shown with strikethrough and additions with underline.

Section A.1.36 Service Water Integrity The Service Water Integrity Program manages loss of material and reduction of heat transfer for components fabricated from materials such as carbon steel, copper alloy, gray cast iron, or stainless steel, and in an environment of raw water as described in the WF3 response to NRC GL 89-13. The program includes (a) surveillance and control techniques to manage effects of biofouling, corrosion, erosion, protective coating failures, and silting; (b) inspection of critical components for signs of corrosion and biofouling; and (c) tests to verify heat transfer capability of heat exchangers important to safety; (c) system walkdowns to ensure compliance with the licensing basis; (d) routine inspections and maintenance; and (e) review of maintenance, operating and training practices and procedures. The program manages loss of material due to cavitation erosion through periodic visual inspections of susceptible locations supplemented with volumetric examinations as necessary based on results of the visual inspections.

Section B.1.36 Service Water Integrity The Service Water Integrity Program manages loss of material and reduction of heat transfer for components fabricated from materials such as carbon steel, copper alloy, gray cast iron, or stainless steel, and in an environment of raw water as described in the WF3 response to NRC GL 89-13. The program includes (a) surveillance and control techniques to manage effects of biofouling, corrosion, erosion, protective coating failures, and silting; (b) inspection of critical components for signs of corrosion and biofouling; and (c) tests to verify heat transfer capability of heat exchangers important to safety; (c) system walkdowns to ensure compliance with the licensing basis; (d) routine inspections and maintenance; and (e) review of maintenance, operating and training practices and procedures. The program manages loss of material due to cavitation erosion through periodic visual inspections of susceptible locations supplemented with volumetric examinations as necessary based on results of the visual inspections.

to W3F1-2016-0070 Page 17 of 32 RAI B.1.36-5

Background:

Applicant operating experience shows blockage due to sediment for a drain line in the ACCW system. Based on Entergy Nuclear Management Manual procedure EN-DC-184, Waterfords Generic Letter 89-13 service water program requires flushing and flow testing to ensure flow blockages do not form within infrequently used flow paths. However, LRA Section B.1.36 includes an enhancement to revise the Service Water Integrity program procedures to flush redundant, infrequently flowed, and stagnant lines to ensure there is no blockage and to inspect selected system low points such as drains.

Issue:

Although the ACCW system includes corrosion inhibitors and uses demineralized water for make-up, sufficient fouling to block drain lines existed within the system. It is unclear to the staff whether Waterford enhanced the Service Water Integrity program after finding the drain line blockage, in light of the enhancement described in the LRA.

Request:

Explain what changes were made to the Service Water Integrity program as a result of condition report CR-WF3-2009-00843 regarding the adequacy of flushing. If the current program includes the associated flushing program element from Entergy Nuclear Management Manual procedure EN-DC-184, clarify what portions of the Service Water Integrity Program procedures need to be revised for the enhancement.

Waterford 3 Response No changes were made to the Service Water Integrity (SWI) Program as a result of condition report CR-WF3-2009-00843 with respect to flushing required flow paths of the auxiliary component cooling water (ACCW) system.

GL 89-13, Article III, states, Ensure by establishing a routine inspection and maintenance program for open-cycle service water system piping and components that corrosion, erosion, protective coating failure, silting, and biofouling cannot degrade the performance of the safety-related systems supplied by service water. It was during preparation for this routine inspection, testing and maintenance that the blockage in the drain line was discovered. Specifically, Waterford 3 personnel were isolating and draining the system to allow entry for internal inspection. The system had been isolated and vented and therefore, only the head of water in the system was present at the drain line.

The drain line is a drain off of the bottom of a heat exchanger such that it will collect sediment in the system, but the sediment did not degrade the performance of the ACCW system.

EN-DC-184 indicates that flushing is intended to verify the critical flow paths do not develop flow blockage that could impact system functional requirements. The drain line identified in CR-WF3-2009-00843 is not in a flow path required for the ACCW system to perform its intended function, and therefore, the flushing provisions of EN-DC-184 do not apply.

to W3F1-2016-0070 Page 18 of 32 Waterfords Generic Letter 89-13 response (letter W3P90-0207 dated January 29, 1990) did not commit to flushing the ACCW system. The response explained that the ACCW system was started at least once per week to allow water chemistry testing. Also, the system was operated during the months of May to November, compensating for the naturally hot outside temperatures. Therefore, the provisions of EN-DC-184 step 5.0[6](a)(2) regarding flushing of infrequently used systems did not apply to the ACCW system.

For license renewal scoping, Entergy included in the ACCW system the backup water supply piping from the circulating water intake piping to the wet cooling tower basins and the piping from the ACCW system to the emergency feedwater system. The enhancement to the SWI Program was written to ensure that program procedures specify flushing of redundant, infrequently flowed sections, and stagnant lines as necessary to verify the ACCW can perform its intended functions.

Specifically, the two lines discussed above were identified as needing flushing in accordance with the provisions of EN-DC-184, Step 5.0[6](a)(2). The backup water supply piping from the circulating water intake to the wet cooling tower basins and the piping from the ACCW system to the emergency feedwater system are stagnant lines that are infrequently used. Entergy has developed procedures to perform flushing of the line between the ACCW system and the emergency feedwater system and of the backup water supply to the wet cooling tower basins from the circulating water system, which is a flow path that could be required in the event of a design basis tornado. The enhancement to the SWI Program makes these activities part of the program.

to W3F1-2016-0070 Page 19 of 32 RAI B.1.38-2

Background:

Section 54.21(a)(3) of 10 CFR requires the applicant to demonstrate that the effects of aging for structures and components will be adequately managed so that the intended function(s) will be maintained consistent with the current licensing basis for the period of extended operation. As described in SRP-LR, an applicant may demonstrate compliance with 10 CFR 54.21(a)(3) by referencing the GALL Report and when evaluation of the matter in the GALL Report applies to the plant. The SRP-LR also states that if an applicant takes credit for a program in the GALL Report, it is incumbent on the applicant to ensure that the conditions and operating experience at the plant is bounded by the conditions and operating experience for which the GALL Report program was evaluated.

LRA Section B.1.38, Structures Monitoring, states that the Structures Monitoring Program is an existing program, with enhancements, that will be consistent with GALL Report AMP XI.S6. The operating experience program element in LRA Section B.1.38 and the Structures Monitoring Section in WF3-EP-14-00003, Operating Experience Review Results - Aging Management Program Effectiveness, discuss plant-specific operating experience associated with concrete cracking, surface rust, deficiencies in sealant, and exposed steel reinforcement at several WF3 structures, and concludes that the program provides reasonable assurance that the effect of aging will be managed such that components will continue to perform their intended functions consistent with the current licensing basis through the period of extended operation.

During the AMP audit the staff reviewed condition reports CR-WF3-2006-00755, CR-WF3-2009-06945, and CR-WF3-2010-05582, that documented corrective actions to address several plant-specific operating experiences associated with corrosion on structural steel, supports and components. The staff also reviewed condition report CR-WF3-2015-00947 that assessed the history (since January 2010) of several conditions reports associated with the keyword corrosion.

The corrective actions associated with this condition report resulted in further inspections of areas susceptible to external corrosion and the development of an external corrosion and coating procedure (UNT-006-032 ) for safety related systems and components. During the walkdowns, the staff also observed corroded bolts/nuts from a structural steel column, exposed concrete rebars, and structural steel with different levels of corrosion in several structures located outdoors (e.g.,

CR-WF3-2016-4481, CR-WF3-2016-4482).

Issue:

Based on the staff review of this plant-specific operating experience and staff observed conditions during the audit walkdowns for outdoor structures, it is not clear to the staff (1) how the structures monitoring program captures the operating experience (i.e. the existing corrosion concerns from recent inspections) and whether the conditions and operating experience at the plant is bounded by the conditions and operating experience for which the GALL Report program was evaluated in Section XI.S6, and (2) whether and how the Structures Monitoring Program specified inspection frequency of 5 years remains adequate, considering the recent operating experience, to ensure no loss of intended functions during the period of extended operation for those structures with ongoing exterior corrosion concerns.

to W3F1-2016-0070 Page 20 of 32 Request:

1. Clarify the basis for the Structures Monitoring Program specified inspection frequency of 5 years, considering the most recently presented operating experience, to ensure no loss of intended function during the period of extended operation. Response should include, as a minimum:

a. a summary of the plant-specific operating experience associated with existing corrosion concerns from recent inspections of structures and structural supports in scope of license renewal, including the actions taken to address and disposition this operating experience, and

b. how the structures monitoring program captures this operating experience (i.e. the existing corrosion concerns) to ensure that the conditions and operating experience at the plant is bounded by the conditions and operating experience for which the GALL Report program was evaluated.

2. Update the LRA and FSAR supplement, as appropriate, to be consistent with the response to the above requests.

Waterford 3 Response

1. Recent WF3 operating experience (OE) associated with corrosion of structures and structural components was documented in numerous condition reports written for varying levels of corrosion on various plant components, commodities and structural supports within the scope of license renewal. Actions taken as a result of corrosion concerns included preparation of a site procedure for monitoring coatings and corrosion. The procedure sets forth management expectations for identifying corrosion, for classifying the extent of corrosion and for prioritizing the corrective actions to remediate adverse issues. Implementation of this procedure is expected to raise the standards for maintenance of protective coatings and prevention of corrosion.

Waterford 3 (WF3) Structures Monitoring Program (SMP) inspection frequency is established based on Regulatory Guide (RG) 1.160, Monitoring the Effectiveness of Maintenance at Nuclear Power Plants. As described in license renewal application (LRA) Section B.1.38, the WF3 SMP is an existing program, which with enhancements, will be consistent with NUREG-1801 aging management program (AMP) XI.S6. NUREG 1801 AMP XI.S6 Element 4, Detection of Aging Effects states in part:

The inspection frequency depends on safety significance and the condition of the structure as specified in NRC RG 1.160, Rev. 2. In general, all structures and ground water quality are monitored on a frequency not to exceed 5 years.

Inspection frequency of WF3 in-scope structures under SMP was compared to that recommended in NUREG-1801, Element 4. The WF3 SMP, with enhancement, will be consistent with NUREG-1801 to ensure structures are inspected at least once every five years. The program includes provisions for more rigorous monitoring of structures and components categorized as (a)(1) in accordance with 10 CFR 50.65, the maintenance rule. This is consistent with the recommendation provided in NUREG 1801 AMP XI.S6 Element 4.

Although more frequent inspections are performed under the WF3 procedure for monitoring coatings and corrosion, the SMP inspection frequency of at least once every five years for structures within the scope of license renewal has been shown adequate to ensure no loss of to W3F1-2016-0070 Page 21 of 32 intended function. SMP inspections have not identified loss of function of structures inspected under the program during the once per 5-year inspections. From 2003 through March 2016, no structure degradation to the extent constituting a functional failure had occurred at WF3.

Therefore, the once per 5-year inspection frequency has proven adequate to manage the effects of aging.

The more frequent coating and corrosion inspections were implemented at WF3 not because the 5-year interval for the SMP inspections was inadequate. Rather, more frequent inspections were established to ensure that degraded conditions due to corrosion are identified during routine plant operation and are entered into the corrective action program. The inspections are also intended to confirm that degraded coating and corrosion conditions are corrected in a timely manner.

The SMP procedure states that where existing site programs are in effect (e.g., Coating and Corrosion Program) credit may be taken for the examinations performed by these station programs. This review of existing program activities under the WF3 SMP provides further assurance that loss of material due to corrosion is adequately managed to ensure there is no loss of intended function of structures during the period of extended operation.

2. Consistent with the response above, no change to the LRA or FSAR supplement is necessary.

to W3F1-2016-0070 Page 22 of 32 RAI 3.1.1.74-2

Background:

LRA item 3.1.1-74 addresses aging of steam generator upper assembly and separators. During its review of LRA item 3.1.1-74, the staff noted an applicant inspection report for steam generator components which indicated that feedwater pipe vibrations were observed during Cycle 19: 180 Day Steam Generator Tube Inspection Report for the 19th Refueling Outage Waterford Steam Electric Station, Unit 3, November 06, 2014, page 10 (ADAMS No. ML14314A032).

The applicant inspection report also indicated that, due to observed feedwater pipe vibrations, the applicant performed a visual inspection of feedring structural supports during which no anomalies were noted. The observed vibrations can cause loss of material due to wear in the feedwater ring and supports within the steam generator.

Issue:

The LRA does not clearly address which aging management review (AMR) items are used to manage loss of material due to wear for steam generator feedwater ring and supports. In addition, the LRA does not address applicants evaluations or actions to minimize the feedwater piping vibrations for aging management.

Request:

1. Clarify whether loss of material due to wear is an aging effect requiring management for steam generator feedwater ring and supports. If so, describe AMR items which are used to manage loss of material for these components, including aging management programs.

2. Discuss applicants evaluations or actions to minimize feedwater piping vibrations that can promote aging degradation of feedwater piping components within the steam generator.

Waterford 3 Response

1. Excessive vibrations were observed on feedwater piping exterior to the steam generators following steam generator (SG) replacement. However, feedwater pipe vibrations external to the steam generators would not be expected to produce significant loss of material due to wear on the feedring and supports. Feedwater piping is welded to the feedwater inlet nozzle as it enters the SG. In addition, the feedring is welded to supports that are pinned to supports welded to the perimeter of the SG. This design presents no opportunity for wear on the pressure boundary of the feedring. Specifically, pinned feedring support joints are the only components within the feedring and supports that could have relative motion to produce loss of material due to wear.

As a result of the observed feedwater piping vibration, feedwater feedring supports were inspected for wear during the first steam generator outage after steam generator replacement and no anomalies were found.

Therefore, loss of material due to wear is not an aging effect requiring management for steam generator feedwater ring supports during the period of extended operation.

2. As described above, inspections have shown that piping vibrations have not caused observable wear on steam generator internals. Nevertheless, actions taken to minimize feedwater piping vibrations include installation of dampeners on feedwater piping, which reduced vibration at the installed locations.

to W3F1-2016-0070 Page 23 of 32 RAI 4.2.1-1

Background:

LRA Section 4.2.1 describes Waterford Unit 3 reactor vessel neutron fluence calculations and that the methods used satisfy the criteria set forth in Regulatory Guide (RG) 1.190. The LRA also states that these methods have been approved by the NRC and are described in detail in WCAP-14040-A, Revision 4, and WCAP-16083-NP-A, Revision 0.

The staff noted that WCAP-18002-NP, Revision 0 describes neutron embrittlement TLAAs related to Waterford Unit 3 reactor vessel integrity. Specifically, Section 2 of WCAP-18002-NP, Revision 0 indicates the following:

• WCAP-14040-A, Revision 4, and WCAP-16083-NP-A, Revision 0 describe NRC-approved fluence methods, which include the one-dimensional/two-dimensional (1D/2D) flux synthesis technique to obtain a three-dimensional (3D) neutron flux. These WCAP reports also mention the 3D neutron transport calculation code, TORT.

• The neutron fluence values of Waterford Unit 3 reactor vessel were calculated using a Westinghouse-developed code, RAPTOR-M3G similar to TORT.

Issue:

It is not clear whether the applicants fluence method, which uses the RAPTOR-M3G code, has been incorporated into the current licensing basis including staffs review and approval.

Request:

1. Clarify whether the applicants fluence method, which uses the RAPTOR-M3G code, has been incorporated into the current licensing basis.

2. If RAPTOR-M3G is not part of the current licensing basis:

a. Provide justification for the use of the code.

b. Clarify how the plant-specific dosimetry data of Waterford Unit 3 were used in measurement benchmarks to confirm the adequacy of use of the RAPTOR-M3G code for Waterford Unit 3 reactor vessel fluence calculations.

Waterford 3 Response Response to RAI 4.2.1-1 to accompany SET 6 RAI 4.7.4-1 response expected to be submitted in early February 2017 as discussed in email from P. Clark (NRC) to A. Harris (Entergy) dated 11/21/2016.

to W3F1-2016-0070 Page 24 of 32 RAI 4.3.1-2

Background:

LRA Sections 4.7.2 and 4.7.3 describe the TLAAs associated with the Leak-Before-Break Analysis and Postulation of High Energy Line Break (HELB) Locations, respectively. The LRA states that transient cycles were analyzed for both of the TLAAs and that the transients will be monitored using the Fatigue Monitoring Program. The applicant dispositioned these TLAAs in accordance with 10 CFR 54.21(c)(1)(iii).

Issue:

LRA Sections 4.7.2 and 4.7.3 did not clarify which transient will be monitored for these TLAAs. The staff is unclear if these transients are within the scope of the Fatigue Monitoring Program.

Request:

For both the Leak-Before-Break Analysis TLAA and Postulation of High Energy Line Break (HELB)

Locations TLAA:

a) Identify which transients were used in the analyses.

b) Confirm that these transients will be monitored under the Fatigue Monitoring Program.

Waterford 3 Response a) Identified below are the transients utilized in the Leak-Before-Break (LBB) Analyses and the determination of whether the transient is tracked by the Fatigue Monitoring Program. These are used for the leak before break evaluations of the main coolant loop and the pressurizer surge line.

• RCS heatups and cooldowns - Tracked (see LRA Table 4.3-1).

• Plant loading and unloading at 5% per minute, and unloading at 10% step load increase and decrease - Do not require tracking since WF3 is operated as a base-loaded plant and the number of analyzed cycles is large (17,000 cycles total).

• Normal plant variation - Does not require tracking since the transient does not have fatigue significance.

• Leak test - Leak testing is only performed in the course of normal heatups and adds no additional stress beyond that from the heatup.

• Reactor trip - Tracked (see LRA Table 4.3-1).

• Loss of load - Tracked (see LRA Table 4.3-1).

• Loss of reactor coolant flow - Tracked (see LRA Table 4.3-1).

• Loss of secondary pressure - Level C (Emergency) transient that can be excluded from fatigue analysis per ASME Code,Section III, sub-paragraph NB-3224.5.

• Pressurizer heatup and cooldown - Tracked (see LRA Table 4.3-1).

• Hydrostatic test - WF3 does not perform periodic hydrostatic testing so tracking this transient is unnecessary.

to W3F1-2016-0070 Page 25 of 32

• Pressurizer insurges and outsurges (pressurizer surge line) - The postulated cycles and ranges were based on the site experiencing 200 pressurizer heatups and cooldowns. The pressurizer heatups and cooldowns are tracked (see LRA Table 4.3-1).

• Thermal stratification (pressurizer surge line) - The postulated cycles and ranges were based on the site experiencing 200 pressurizer heatups and cooldowns. The pressurizer heatups and cooldowns are tracked (see LRA Table 4.3-1).

• Operating basis earthquakes - Tracked (see LRA Table 4.3-1).

The fatigue analyses used in the HELB evaluation are the same fatigue analyses discussed in LRA Section 4.3.1. As indicated in LRA Section 4.3.1, the Fatigue Monitoring Program described in LRA Appendix B will monitor the transient cycles necessary to ensure the continuing validity of fatigue TLAAs. This includes the subset of fatigue TLAAs discussed in LRA Section 4.3.1 that were used in the evaluation of potential HELB locations, that is, the same TLAAs discussed in LRA Section 4.7.3.

b) The transients that are identified in LRA Table 4.3-1 are monitored under the Fatigue Monitoring Program.

to W3F1-2016-0070 Page 26 of 32 RAI 4.3.3-2

Background:

LRA Section 4.3.3 discusses the applicants evaluation of the effects of the reactor water environment on fatigue life. The LRA states that design basis ASME Code Class 1 component fatigue evaluations will be reviewed to ensure that the most limiting components within the reactor coolant pressure boundary will be included in its environmental fatigue evaluations.

Issue:

The staff lacks sufficient information on how the applicant will identify and evaluate the plant-specific locations that may be more limiting than the locations identified in NUREG/CR-6260. It is unclear to the staff what methodology the applicant will use to ensure that the most limiting locations will be evaluated for environmental effects such that the effects of environmentally affected fatigue will be managed throughout the period of extended operation.

Request:

a) Provide the methodology that will be used to identify plant-specific component locations in the reactor coolant pressure boundary that may be more limiting than the components identified in NUREG/CR-6260.

b) Justify that each step of the methodology used to identify the plant-specific limiting locations is bounding and representative of the plant.

Waterford 3 Response a) The methodology that will be used to identify plant-specific component locations in the reactor coolant pressure boundary that may be more limiting than the components identified in NUREG/CR-6260 will be based on the non-proprietary EPRI report 1024995, August 2012, Environmentally Assisted Fatigue Screening, Process and Technical Basis for Identifying EAF Limiting Locations. This screening will determine a set of sentinel locations which are representative, will bound and appropriately represent the behavior of components in each thermal zone. The basic features of the EPRI approach for environmentally assisted fatigue (EAF) screening follow.

• Identify thermal zones in the systems containing these components wherein the thermal transients are similar.

• Within each thermal zone, compute an estimated EAF value (known as Uen*) for each component. The Uen* is the product of a cumulative usage factor (CUF) value and an environmentally assisted fatigue correction factor (Fen) summed on a load pair basis.

o This computation is done using the design CUF values multiplied by the conservatively determined Fen fatigue correction factors (average of Fen determined for the strain rate of the predominant thermal transient and the maximum Fen determined by the minimum strain rate).

o The CUF values are determined on a common basis (i.e., unbundled transients) so that valid relative rankings can be achieved.

to W3F1-2016-0070 Page 27 of 32

• These relative rankings are examined and a set of one to three of the highest U en*

components are identified as potential sentinel locations for further study. The selection of one, two or three components are a result of how close-coupled the component Uen* values are.

• These sentinel locations are determined using the set of design transients, in both number of cycles and severity of cycles.

b) Sentinel locations are identified as the locations with the highest U en* values, which are determined from plant-specific design CUF values multiplied by plant-specific conservative Fen values. Therefore, these sentinel locations are bounding and representative of the plant.

LRA Appendix B.1.11 is amended as shown below. Additions are underlined.

LRA Sections and Tables Affected Section B.1.11

1. Scope of Program Develop a set of fatigue usage calculations that consider the effects of the reactor water environment for a set of sample reactor coolant system components. This sample shall include the locations identified in NUREG/CR-6260 and additional plant-specific component locations in the reactor coolant pressure boundary if they are found to be more limiting than those considered in NUREG/CR-6260.

Fen factors shall be determined using the formulae listed in LRA Section 4.3.3.

The methodology will be based on EPRI report 1024995 Environmentally Assisted Fatigue Screening, Process and Technical Basis for Identifying EAF Limiting Locations.

to W3F1-2016-0070 Page 28 of 32 RAI 4.3.3-3

Background:

LRA Section 4.3.3 discusses the applicants evaluation of the effects of the reactor water environment on fatigue life. The LRA states that the environmental effects on fatigue for a set of critical components will be evaluated using NUREG/CR-6909, Effect of LWR Coolant Environments on the Fatigue Life of Reactor Materials.

Appendix A of NUREG/CR-6909 states the following:

For the case of a constant strain rate and a linear temperature response, an average temperature (i.e., average of the maximum and minimum temperatures for the transients) may be used to calculate Fen. In general, the average temperature that should be used in the calculations should produce results that are consistent with the results that would be obtained using the modified rate approach described in Section 4.2.14 of this report. The maximum temperature can be used to perform the most conservative evaluation.

The method used to calculate the average temperature is dependent on whether the minimum transient temperature exceeds the temperature threshold value of the material. When the minimum temperature exceeds the threshold temperature, the maximum and minimum temperature values of the stress cycle or load set pair are used to calculate the average temperature. When the minimum temperature is below the threshold temperature, the maximum and threshold temperature are used to calculate the average temperature. Sections 4.2.4 and 5.2.7 of NUREG/CR-6909 provide examples of determining average temperatures.

As noted above, NUREG/CR-6909 also states that the average temperature may be used to calculate the environmentally assisted fatigue correction factor (Fen) values for transients with a constant strain rate and a linear temperature response, which are defined as simple transients.

Use of an average temperature may not be appropriate for more complex transients that have multiple or non-linear temperature variations. For complex transients, the modified rate approach should be used to validate Fen calculations.

Issue:

If the applicant will use NUREG/CR-6909 to calculate the F en values, the staff needs confirmation that the average transient temperatures were calculated appropriately considering the threshold temperatures. The staff also needs confirmation that the average temperatures were limited to simple transients.

Request:

a) Identify all locations that used NUREG/CR-6909 AND the average temperature to calculate the Fen value. For each location, provide the following:

i. The material of construction.

ii. A description of how the average temperature was calculated.

iii. A description of all transients associated with the use of average temperatures and demonstration that the transients are simple transients.

to W3F1-2016-0070 Page 29 of 32 b) Justify that the guidelines of NUREG/CR-6909 were followed when calculating the F en and environmentally-adjusted cumulative usage factors (CUFen) and will continue to be followed for future Fen and CUFen calculations.

Waterford 3 Response a) Entergy has not performed any EAF analysis using NUREG/CR-6909.

b) When the EAF analyses are completed, Entergy will ensure the EAF analyses that use NUREG/CR 6909:

• Will not use average temperature for complex transients and

• For simple transients that use average temperature, when the minimum temperature is below the threshold temperature, the maximum and threshold temperature will be used to calculate the average temperature.

LRA Section 4.3.3, Appendix A.2.2.3 and Appendix B.1.11 are amended as shown below. Additions are underlined.

LRA Section 4.3.3 (New paragraph following the listing of the NUREG/CR formulae)

An EAF analysis using NUREG/CR-6909 will not use average temperature for complex transients.

For simple transients that use average temperature, when the minimum temperature is below the threshold temperature, the maximum and threshold temperature will be used to calculate the average temperature.

LRA Section A.2.2.3 (new paragraph)

An EAF analysis using NUREG/CR-6909 will not use average temperature for complex transients.

For simple transients that use average temperature, when the minimum temperature is below the threshold temperature, the maximum and threshold temperature will be used to calculate the average temperature.

to W3F1-2016-0070 Page 30 of 32 LRA Section B.1.11

1. Scope of Program Develop a set of fatigue usage calculations that consider the effects of the reactor water environment for a set of sample reactor coolant system components. This sample shall include the locations identified in NUREG/CR-6260 and additional plant-specific component locations in the reactor coolant pressure boundary if they are found to be more limiting than those considered in NUREG/CR-6260.

Fen factors shall be determined using the formulae listed in LRA Section 4.3.3.

An environmentally assisted fatigue analysis using NUREG/CR-6909 will not use average temperature for complex transients. For simple transients that use average temperature, when the minimum temperature is below the threshold temperature, the maximum and threshold temperature will be used to calculate the average temperature.

to W3F1-2016-0070 Page 31 of 32 RAI 4.3.3-1

Background

LRA Section 4.3.3 discusses the applicants evaluation of the effects of the reactor water environment on fatigue life. The LRA states that environmental screening evaluations were performed for the sample set of Combustion Engineering components provided in NUREG/CR 6260.

The LRA states that using bounding environmental correction factors (Fen), two locations have a projected 60-year environmentally-adjusted cumulative usage factor (CUFen) greater than the design limit of 1.0. The LRA further states that for these two locations, refined environmental evaluations will be performed prior to the period of extended operation as part of the Fatigue Monitoring Program.

Issue The LRA does not provide enough information on how the bounding Fen values were calculated.

The staff is unclear how the applicant will ensure that these Fen values will remain bounding for the period of extended operation. The staff is also unclear what refinement methods will be used for the CUFen evaluations.

Request a) Describe how the bounding Fen values were determined for evaluating the NUREG/CR 6260 locations for environmental fatigue. Justify how it will be assured that the variables and inputs for these Fen values will remain bounding throughout the period of extended operation.

b) Describe what method(s) will be used to refine the CUFen evaluations. Justify that the refinements will be appropriate.

Waterford 3 Response a) Two bounding environmentally assisted fatigue correction factor (F en) values were used in determining the values shown in LRA Table 4.3-2. For low alloy steel locations, a bounding Fen of 2.45 was calculated using NUREG/CR-6583 Eq. 6.5b as follows.

Fen (las)= exp (0.929-0.00124T-0.101 S*T*O*e*)

T = 25°C Reference temperature for original fatigue curves S* = S 0 < S (Sulfur) 0.015 wt%

S* = 0.015 S > 0.015 wt%

T* = T-150 T = 150-350°C O* = 0 DO (Dissolved Oxygen) < 0.05 ppm

• = ln(0.001) ( < 0.001%/s)

Dissolved oxygen at less than 0.05 ppm results in the equation reducing to a constant value of 2.45.

to W3F1-2016-0070 Page 32 of 32 Fen (LAS) = exp(0.929-0.00124(25)-0) = exp(0.898) = 2.45 For stainless steel locations, a bounding Fen of 15.36 was calculated using NUREG/CR-5704 Equation 13 as follows.

Fen = exp(0.935-T*O* *)

T¢=1.0 (>200C)

O¢ (All)= 0.260 RCS dissolved oxygen is 50 ppb

¢ (all)=-6.91 Assume bounding strain rate Fen (SS) = exp(0.935-(1.0)(0.260)(-6.91)) = 15.36 The dissolved oxygen in the WF3 RCS during normal operation is maintained less than the 50 ppb (0.05 ppm) threshold identified for oxygen by the Water Chemistry Control-Primary and Secondary Program (LRA Section B.1.14). The portion of the NUREG/CR-6583 equation, (-0.101 S*T*O*e* ), will be a zero term as long as oxygen is less than 50 ppb, so the Fen value will not increase above 2.45. The strain rate which generates the highest Fen value was utilized in the stainless steel evaluation so the value will not increase above 15.36. For a low oxygen environment, these Fen values will remain bounding throughout the period of extended operation.

b) The following are methods that may be used to refine the environmentally assisted fatigue evaluations.

• The refined fatigue analysis may evaluate a number of cycles based on the actual projected number of cycles with margin instead of evaluating the full number of originally assumed cycles. This is a more accurate input of cycles based on actual plant experience. Cycles will be tracked by the Fatigue Monitoring Program to verify they remain below the number of cycles used in the analysis.

• The refined fatigue analysis may unbundle transients that had been bundled together for simplicity in the previous analyses. This allows for a more accurate determination of fatigue usage by evaluating each load set transient pair. This analysis is in accordance with ASME Code provisions.

• The refined fatigue analyses may use a more rigorous method. The reanalysis will be performed in accordance with ASME Code provisions.

• The refined CUFen analysis may review the specific loading and not just assume the worst case strain rate.

• The refined CUFen analysis may utilize the actual metal sulfur content instead of assuming the bounding value.

These refinements provide more component-specific details to the reanalysis and are in accordance with ASME Code provisions and the recommendations of NUREG/CR-5704, 6583 or 6909.