Text

Supplement 50, Response to Request for Additional Information for the Review of License Renewal Application Providing Changes to Buried and Underground Piping and Tank Recommendations
	ML16333A407
Person / Time
Site:	Seabrook
Issue date:	11/23/2016
From:	Mccartney E; NextEra Energy Seabrook
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	CAC ME4028, SBK-L-16186
	Download: ML16333A407 (42)
	v • d • e

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I.I I

f'\.JcXTera ENERGYe SEABROOK November 23, 2016 10 CFR 54 SBK-L-16186 Docket No. 50-443 U.S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, DC 20555-0001 Seabrook Station Supplement 50 - Response to Requests for Additional Information for the Review of the Seabrook Station License Renewal Application (CAC NO. ME4028) - Changes to Buried and Underground Piping and Tank Recommendations

References:

1. NextEra Energy Seabrook LLC, letter SBK-L-10077, "Seabrook Station Application for Renewed Operating License," May 25, 2010 (Accession Number ML 10150099).

2. License Renewal Interim Staff Guidance, LR-ISG-2015-01 "Changes to Buried and Underground Piping and Tank Recommendations."

3. NextEra Energy Seabrook, LLC letter SBK-L-16156, "Response to Issuance of LR-ISG-2015-01, Changes to Buried and Underground Piping and Tank Recommendations,"

October 07, 2016 (Accession Number ML16286A631).

4. NRC, "Requests for Additional Information for the Review of the Seabrook Station License Renewal Application (CAC NO. ME4028);" November 14, 2016 (Accession Number ML16301A428).

U.S. Nuclear Regulatory Commission SBK-L-16186 I Page 2 In Reference 1, NextEra Energy Seabrook submitted an application for a renewed facility operating license for Seabrook Station Unit 1 in accordance with the Code of Federal Regulations, Title 10, Parts 50, 51, and 54.

In Reference 2, the NRC issued License Renewal Interim Staff Guidance, LR-ISG-2015 Changes to Buried and Underground Piping and Tank Recommendations. The guidance provided within this ISG was utilized to develop the NextEra Energy Seabrook's Buried Piping and Tanks Inspection Aging Management Program.

In Reference 3, NextEra Energy provided the Staff with letter SBK-L-16156, "Response to Issuance of LR-ISG-2015-01, Changes to Buried and Underground Piping and Tank Recommendations."

In Reference 4, the NRC requested additional information related to the latest Buried and Underground Piping and Tank Aging Management Program submittal (Reference 3). Enclosure 1 provides the responses to the request for additional information.

Provided in this Supplement are changes to the LRA. To facilitate understanding, the changes are explained, and where appropriate, portions of the LRA are repeated with the change highlighted by strikethroughs for deleted text and balded italics for inserted text.

This letter contains one revised Commitment, #64. Enclosure 2 provides the revised LRA Appendix A - Updated Final Safety Analysis Report Supplement Table A.3, License Renewal Commitment List.

)

If there are any questions or additional information is needed, please contact Mr. Edward J.

Carley, Engineering Supervisor - License Renewal, at (603) 773-7957.

If you have any questions regarding this correspondence, please contact Mr. Kenneth Browne, Licensing Manager, at (603) 773-7932.

I declare under penalty of perjury that the foregoing is true and correct.

- .

l Executed on November *t-? , 2016.

Sincerely, NextEra Energy Seabrook, LLC

~-vY/c~.

cMCCartney (\'

Site Vice President

U.S. Nuclear Regulatory Commission SBK-L-16186 I Page 3 Enclosures Enclosure 1: NextEra Energy Seabrook's Response to Requests for Additional Information for the Review of the Seabrook Station License Renewal Application - Changes to Buried and Underground Piping and Tank Recommendations Enclosure 2: LRA Appendix A - Final Safety Report Supplement Table A.3, License Renewal Commitment List Update to Commitment #64, Soil Sampling Schedule cc: D. H. Dorman NRC Region I Administrator J.C. Poole NRC Project Manager P. C. Cataldo NRC Senior Resident Inspector T. Tran NRC Project Manager, License Renewal L. M. James NRC Project Manager, License Renewal Mr. Perry Plummer Director Homeland Security and Emergency Management New Hampshire Department of Safety Division of Homeland Security and Emergency Management Bureau of Emergency Management 33 Hazen Drive Concord, NH 03305 Mr. John Giarrusso, Jr., Nuclear Preparedness Manager The Commonwealth of Massachusetts Emergency Management Agency 400 Worcester Road Framingham, MA 01702-5399

Enclosure 1 to SBK-L-16186 NextEra Energy Seabrook's Response to Requests for Additional Information for the Review of the Seabrook Station License Renewal Application - Changes to Buried and Underground Piping and Tank Recommendations

U.S. Nuclear Regulatory Commission SBK-L-16186/Enclosure 1/ Page 2 RAI A.2.1.22-1

Background:

As amended by letter dated October 7, 2016, License Renewal Application (LRA)

Section A.2.1.22, "Buried Piping and Tanks Inspection," (Updated Final Safety Analysis Report (UFSAR) summary description for the Buried Piping and Tanks Inspection program) was revised in response to the issuance of LR-ISG-2015-01, "Changes to Buried and Underground Piping and Tank Recommendations."

The UFSAR summary description issued in LR-ISG-2015-01 includes the following recommendations:

The number of inspections is based on the effectiveness of the preventive and mitigative actions.

Annual cathodic protection surveys are conducted.

For steel components, where the acceptance criteria for the effectiveness of the cathodic protection is other than -850 mV instant off, loss of material rates are measured.

Inspections are conducted by qualified individuals.

Where the coatings, backfill or the condition of exposed piping does not meet acceptance criteria such that the depth or extent of degradation of the base metal could have resulted in a loss of pressure boundary function when the loss of material rate is extrapolated to the end of the period of extended operation, an increase in the sample size is conducted.

If a reduction in the number of inspections recommended in GALL Report, AMP Xl.M41, Table Xl.M41-2 is claimed based on a lack of soil corrosivity as determined by soil testing, then soil testing is conducted once in each 10-year period starting 1O years prior to the period of extended operation.

Issue:

The staff noted that aspects of the UFSAR summary description issued in LR-ISG-2015-01 (bulletized above) were not included in the revised LRA Section A.2.1.22. It is unclear to the staff why these' aspects of the UFSAR summary description issued in LR-ISG-2015-01 were not included in the revised LRA Section A.2.1.22.

Request:

State the basis for not including aspects of the UFSAR Summary Description issued in LR-ISG-2015-01 (bulletized above) in the revised LRA Section A.2.1.22.

NextEra Energy Seabrook Response to RAI A.2.1.22-1 LRA Section A.2.1.22 has been revised to ~ncorporate LR-ISG-2015-01, Appendix A, SRP-LR Table 3.0-1, FSAR Supplement for AMP Xl.M41. Revisions to A.2.1.22 are shown below.

. A.2.1.22 BURIED PIPING AND TANKS INSPECTION The Buried Piping and Tanks Inspection Program is a condition monitoring program that manages the aging effects associated with loss of material from the external surfaces of buried, underground, and inaccessible submerged piping, steel, stainless

U.S. Nuclear Regulatory Commission SBK-L-16186/Enclosure 1/ Page 3 steel, Copper Alloy (>15% Zinc), and polymer piping and components such as loss of material, cracking,. and changes in material properties. It addresses piping composed of steel, stainless steel, and polymer. Copper alloy (>15% zinc) components associated with inaccessible submerged Ser\tice Water piping are also within the scope of this program. The plant has no buried tanks in scope for license renewal.

Depending on the material, the program includes external coatings, cathodic protection, analyses for soil corrosivity, and quality of backfill as preventive measures to mitigate and mitigative actions corrosion. The number of inspections is based on the effectiveness of the preventive and mitigative actions. Annual cathodic protection surveys are conducted. Steel components utilizing cathodic protection have an effectiveness acceptance criterion of -850 m V instant off.

Inspections are conducted by qualified individuals. The program includes provisions for visual inspections of the protective wraps and coatings on buried steel and stainless steel piping. If damage to the protective wraps or coatings is found and the piping surface is exposed, the pipe is inspected for loss of material due to general, pitting, crevice or microbiologically-influenced corrosion. If corrosion has occurred, the wall thickness will be determined. Steel and stainless steel piping will be inspected for stress corrosion cracking using volumetric non-destructive examination techniques.

Polymer piping is inspected for changes in material properties and for indication of cracking and blistering. Where the coatings, backfill or the condition of exposed piping does not meet acceptance criteria such that the depth or extent of degradation of the base metal could have resulted in a loss of pressure boundary function when the loss of material rate is extrapolated to the end of the period of extended operation, an increase in the sample size is conducted. If a reduction in the number of inspections recommended in the Buried Piping and Tanks Inspection Aging Management Plan, Table 3, is claimed based on a lack of soil corrosivity, as determined by soil testing, then soil testing is conducted once in each 10-year period starting 10 years prior to the period of extended operation.

The program includes verification of the effectiveness of the cathodic protection system, non-destructive evaluation of the pipe wall thicknesses, hydrostatic pressure testing of the pipe, internal inspections, and monitoring of the fire protection system jockey pump operation.

This program also manages the aging effects (loss of material and loss of preload) of buried, underground, or inaccessible submerged piping system bolting.

U.S. Nuclear Regulatory Commission SBK-L-16186/Enclosure 1/ Page 4 RAI B.2.1.22-1

Background:

The following Request for Additional Information (RAI) addresses three staff identified inconsistencies within the LRA, warranting clarification.

1) GALL Report AMP XI.M41, Table XI.M41-2, as modified by LR-ISG-2015-01, states that in order to demonstrate that the soil is not corrosive, the applicant must obtain a minimum of three sets of soil samples in each soil environment in the vicinity in which in-scope components are buried.

As amended by letter dated October 7, 2016, the "detection of aging effects" program element of LRA Section B.2.1.22 states that soil samples will be taken at a minimum of two locations in the vicinity of in-scope, non-cathodically protected steel piping to obtain representative soil conditions for each system.

As amended by letter dated October 7, 2016, LRA Section B.2.1.22, Table 3, states that Seabrook will obtain a minimum of three sets of soil samples in each soil environment in the vicinity in which in-scope components are buried.

2) As amended by letter dated October 7, 2016, the "parameters monitored or inspected" program element of LRA Section B.2.1.22 states that steel will be inspected for loss of material and cracking due to stress corrosion cracking.

As amended by letter dated October 7, 2016, the "detection of aging effects" program element of LRA Section B.2.1.22 states that metallic piping is inspected for loss of material due to all forms of corrosion and, for stainless steel, cracking due to stress corrosion cracking.

GALL Report AMP XI.M41, as modified by LR-ISG-2015-0.1, states that inspections for cracking due to stress corrosion cracking for steel utilize a method that has been demonstrated to be capable of detecting cracking.

3) LRA Section A.2.1.22 states that the Buried Piping and Tanks Inspection program manages loss of material from the external surfaces of buried, underground, and inaccessible submerged steel, stainless steel, copper alloy >15% zinc, and polymer piping and components. In addition LRA Section B.2.1.22, Table 2, lists copper alloy >15% zinc.

The LRA Section B.2.1.22, "scope of program" program element states that the program is required to support the aging management activities for buried steel, stainless steel, polymeric piping, and inaccessible submerged steel piping. In addition, the LRA Section B.2.1.22 "monitoring and trending" program element states that results of previous inspections will be evaluated, and used to assess the condition of the external surfaces of other buried or underground steel, stainless steel and polymer components. Furthermore, the LRA Section B.2.1.22 "detection of aging effects" program element states pipe to soil potential and the cathodic protection current are monitored for steel piping.

Issue:

1) It is unclear to the staff, due to conflicting wording in the LRA, if two or three sets of soil samples will be obtained in each soil environment in the vicinity in which in-scope components are buried.

2) It is unclear to the staff, due to conflicting wording in the LRA, if steel components will be managed for loss of material and cracking, or loss of material.

U.S. Nuclear Regulatory Commission SBK-L-16186/Enclosure 1/ Page 5

3) It is unclear to the staff if copper alloy >15% zinc is included within the scope of the Buried Piping and Tanks Inspection program due to conflicting wording in the LRA.

Request:

1) Reconcile the apparent discrepancy between the quantities of soil samples that will be obtained in each soil environment in the vicinity in which in-scope components are buried. If two sets of soil samples in each soil environment in the vicinity in which in scope components are buried will be obtained, justify the adequacy of two sets of soil samples in lieu of three sets as recommended in GALL Report AMP XI.M41, Table Xl.M41-2, as modified by LR-ISG-2015-01.

2) State if steel components will be managed for loss of material and cracking, or loss of material, and revise the LRA as appropriate. If steel components will only be managed for loss of material, justify why cracking will not be managed as recommended in GALL Report AMP Xl.M41, as modified by LR-ISG-2015-01.

3) State if copper alloy >15% zinc is included within the scope of the Buried Piping and Tanks Inspection program and revise the LRA as appropriate.

NextEra Energy Seabrook Response to RAI B.2.1.22-1

1) The following paragraph from B.2.1.22, Element 4 - Detection of Aging Effects, has been revised to address the discrepancy between the quantities of soil samples that will be obtained in each soil environment in the vicinity in which in-scope components are buried.

Soil samples will be taken prior to entering the period of extended operation (PEO) to confirm that the soil conditions are not corrosive. The corrosivity of the soil will be used as a factor in determining the number of locations or percentage of piping to be inspected for non-cathodically protected steel piping. If the initial survey shows the soil to be non-corrosive, additional soil samples will be taken at least once every 10 years during the PEO to confirm the initial sample results. Soil samples will be taken at a minimum of twe three locations in the vicinity of in-scope, non-cathodically protected steel piping to obtain representative soil conditions for each system (except for Fire Protection if the integrity of that system is monitored by jockey pump performance). The parameters monitored will be utilized to obtain a comparative corrosion index (corrosivity) for the piping within the systems monitored. Corrosivity will be determined using established soil analysis methodology such as EPRI Report 1021470, "Balance of Plant Corrosion - The Buri~d Pipe Reference Guide", Chapter 8, "Soil Analysis." The EPRI report arrives at a corrosion index using combined values for soil resistivity, pH, redox potential, sulfides, and moisture in accordance with American Water Works Association standard C105, and considers the soil to be corrosive if the combined value of 1O or greater.

2) B.2.1.22, Element 3 - Parameters Monitored or Inspected, has been revised to clarify that steel components will be managed for loss of material as well as cracking, and can be seen below.

U.S. Nuclear Regulatory Commission SBK-L-16186/Enclosure 1/ Page 6 ELEMENT 3 - Parameters Monitored or Inspected Visual inspections of: (a) the external surface condition of buried or underground piping; (b) the external surface condition of associated coatings: (c) external surfaces of controlled low strength material backfill are performed. Monitoring of the surface condition of the component is conducted to ensure that the aging effects below are not present or have not progressed to such a degree where a loss of intended function could occur.

Visual inspections of the external surface condition of the component should detect:

Loss of material due to general, pitting, crevice, and microbiologically-influenced corrosion (MIC) for aluminum alloy (MIC is not applicable for aluminum alloys), copper alloy, steel, stainless steel, super austenitic, and titanium alloy components.

Loss of material due to wear for polymeric materials.

Cracking, blistering, change in color due to water absorption for high-density polyethylene and fiberglass components.

Steel and stainless steel piping will be inspected for degradation of coating materials.

Should damage or other degradation of coating materials so as to expose the base material be noted, the condition will be documented, evaluated, and corrected in accordance with the Seabrook Station corrective action program. 'Nhen such damage or degradation of coating materials is found, the affected area 'Nill be visually inspected to detect loss of material by external corrosion by surface or volumetric non destructive examination techniques to detect cracking due to stress corrosion cracking in stainless steel piping or loss of pipe wall thickness in stainless steel and steel piping.

Polymer piping will be inspected, by manual examinations, for changes in material properties, and by visual inspection for signs of cracking, blistering or damage. Any changes in material properties, or signs of cracking, blistering or damage, 'Nill be documented, evaluated, and, corrected in accordance with the Seabrook Station corrective action program.

Visual inspections of: (a) the external surface condition of buried or underground piping; (b) the external surface condition of associated coatings; or (c) external surfaces of controlled low strength material backfill are performed. Monitoring of the surface condition of the component is conducted to ensure that the aging effects are not present or have not progressed to such a degree where a loss of intended function could occur.

Monitoring of the surface condition of coatings is conducted to ensure that the coatings are intact, well adhered, and otherwise sound; such that aging effects v:ould not be expected for the base material of the component. Monitoring of the external surfaces of controlled low strength material backfill is conducted to ensure that there are no cracks present that could admit groundwater to the surface of the component.

Volumetric nondestructive examination techniques as well as pit depth gages or calipers may be used for measuring wall thickness as long as: (a) they have been demonstrated

U.S. Nuclear Regulatory Commission SBK-L-16186/Enclosure 1/ Page 7 to be effective for the material, environment, and conditions (e.g., remote methods) during the examination; and (b) they are capable of quantifying general wall thickness and the depth of pits. Wall thickness measurements are conducted to ensure that minimum wall thickness requirements are met.

Inspections for cracking due to stress corrosion cracking for steel, stainless steel and susceptible aluminum alloy materials will utilize a method that has been demonstrated to be capable of detecting cracking. Coatings that: (a) are intact, well-adhered, and

otherwise sound for the remaining inspection interval; and (b) exhibit small blisters that are few in number and completely surrounded by sound coating bonded to the substrate do not have to be removed. Inspections for cracking are conducted to assess the impact of cracks on the pressure boundary function of the component.

Two additional parameters, the Pipe to soil potential and the cathodic protection current, will be monitored to determine the effectiveness of cathodic protection systems. aA9, thereby, the effectiveness of corrosion mitigation.

This program provides an alternate means to test the integrity of the buried piping systems at Seabrook Station in lieu of external visual inspections. These alternate means are pressure testing, internal inspection, as well as flow testing, jockey pump monitoring, or annual system leakage rate testing of fire mains. These inspection and testing techniques have been demonstrated to provide reliable indication of the piping integrity, are preferable to excavation and visual inspection.

To credit pressure testing in lieu of visual inspection, at least 25% of the p1p1ng constructed from the material under consideration must be pressure tested to 110 percent of the design pressure of any component within the boundary with test pressure being held for eight hours and on an interval not to exceed 5 years. Such testing will identify boundary leakage in significantly larger portions of the respective piping system than excavation and visual inspection of coating integrity.

To credit internal inspection, at least 25% of the piping constructed from the material under consideration is internally inspected by a method capable of determining pipe wall thickness. The inspection method must be capable of detecting both general and pitting corrosion and must be qualified by Seabrook Station and accepted by the NRC. Internal inspections are to be conducted at an interval not to exceed 1O years.

Fire mains may be excluded from the visual inspections if subjected to a flow test as described in section 7.3 of NFPA 25, at a frequency of at least one test in each one year period, or the jockey pump operation (e.g., pump starts, run time) is monitored for unexplained changes in pump activity at an interval not to exceed once a month.

At Seabrook Station, the fire protection jockey pump maintains the fire mains pressurized. Starts and running time of the fire protection jockey pumps are monitored and treated as an indicator of possible system leakage. This method of continuous monitoring of pressure losses in the fire mains will identify pipe boundary leakage in significantly larger portions of the fire protection piping system than excavation and visual inspection of coating integrity. At a minimum, a flow test will be conducted by the end of the next refueling outage or as directed by current licensing basis, whichever is shorter, when unexplained changes in jockey pump activity (or equivalent parameter) are observed.

U.S. Nuclear Regulatory Commission SBK-L-16186/Enclosure 1/ Page 8 This program also provides for management of the aging effects (loss of material) on buried, underground, and inaccessible submerged piping system bolting. Bolted connections in buried, underground, and inaccessible submerged piping will be inspected for indication of leakage caused by loss of preload when the associated piping is inspected by this program. In instances where pressure testing, flow testing, or fire protection jockey pump monitoring are used in lieu of visual inspections, these methods will also be credited to identify leakage caused by loss of preload at bolted connections.

Element 4 - Detection of Aging Effects, has also been revised to clarify that steel components will be managed for loss of material as well as cracking, and can be seen below.

The Seabrook Station Buried Piping and Tanks Program consists of inspection activities that are designed to detect degradation due to aging effects prior to loss of intended function. For buried and underground steel and stainless steel piping, opportunistic or directed visual inspections will be performed to confirm that coating and wrapping are intact. In the event that the coating has been compromised and bare metal exposed, metallic the piping is inspected for loss of material, due to all forms of corrosion and, for stainless steel, cracking due to and stress corrosion cracking utilizing a method that has been demonstrated to be capable of detecting cracking. Wall thickness is determined by a non-destructive examination technique such as ultrasonic testing (UT).

For buried polymer piping, opportunistic or directed visual inspections are augmented with manual examinations to detect hardening, softening, or other changes in material properties.

3) The following changes to Element 1 - Scope of Program, Element 5 - Monitoring and Trending, and Element 4 - Detection of Aging Effects have been revised to reflect that components with a material of Copper Alloy >15% zinc are included within the scope of the Buried Piping and Tanks Inspection program.

ELEMENT 1 - Scope of Program This program is used to manage the effects of aging for buried, underground, and inaccessible submerged piping within the scope of license renewal. The program addresses aging effects such as loss of material, cracking, and changes in material properties.

The Seabrook Station Buried Piping and Tanks Inspection Program includes (a) preventive measures to mitigate corrosion and (b) inspections to manage aging effects on in-scope piping. This program requires opportunistic or directed inspection of each piping material within the scope of this program be performed within ten years prior to entering the period of extended operation. Periodic inspections are performed every 10 years after entering the period of extended operation.

Loss of material due to corrosion of buried, underground, and inaccessible submerged piping system bolting within the scope of license renewal is managed using this program. This program will also manage loss of preload in pressure retaining bolting within the scope of this program by visual inspection for evidence of leakage when the associated piping is inspected by this program.

U.S. Nuclear Regulatory Commission SBK-L-16186/Enclosure 1/ Page 9 The program is required to support the aging management activities for buried steel, stainless steel, polymeric piping, copper alloy (>15% zinc), and inaccessible submerged steel piping. The following systems are within the scope of license renewal, and have components that are age managed by this program;

AB Auxiliary Boiler

ASC Auxiliary Steam Condensate

ASH Auxiliary Steam Heating

CBA Control Building Air Handling

co Condensate

DF Plant Floor Drain

DG Diesel Generator

IA Instrument Air

FW Feedwater

FP Fire Protection

SW Service Water Implementation of the final design change replacing the piping associated with the above-ground fuel oil storage tank will be completed prior to the period of extended operation. The design for buried portions of the system will include a pipe-within-pipe configuration with leak detection capability. Portions of that buried piping that are in-scope for license renewal will be included in the Seabrook Station Buried Piping and Tanks Inspection Program. Portions of that final design that are above-ground, including tanks, will be evaluated in accordance with the License Renewal Rule, 10 CFR 54, and age managed under the appropriate programs through the period of extended operation ELEMENT 5 - Monitoring and Trending The results of previous inspections will be evaluated, and used to assess the condition of the external surfaces of other buried, BF underground, or inaccessible submerged steel, stainless steel, aA9 polymeric, and copper alloy (>15% zinc) components,; and to identify susceptible locations that may warrant further inspections.

2nd Paragraph of ELEMENT 4 - Detection of Aging Effects Pipe to soil potential and the cathodic protection current are monitored for steel piping in contact with soil to determine the effectiveness of cathodic protection systems and, thereby, the effectiveness of corrosion mitigation. There is no cathodic protection for in scope copper alloy (>15% zinc) material as there are only in-scope components, not piping. Drain valves on the spools in the Service Water vault and valve pit are constructed of aluminum bronze (categorized as "copper alloy >15% zinc") with aluminum bronze body to bonnet bolting. These components will be inspected for loss of material when the respective Service Water spool piping is inspected by this program.

U.S. Nuclear Regulatory Commission SBK-L-16186/Enclosure 1/ Page 10 RAI B.2.1.22-2

Background:

As amended by letter dated October 7, 2016, the "acceptance criteria" program element of LRA Section B.2.1.22 states that cracking or blistering of polymer piping and unexplained changes in jockey pump activity are evaluated under the corrective action program.

GALL Report AMP Xl.M41, as modified by LR-ISG-2015-01, states that acceptance criteria associated with this AMP are cracking is absent in rigid polymeric components and changes in jockey pump activity that cannot be attributed to leakage are not occurring.

Issue: It is unclear to the staff why cracking of polymer piping and unexplained changes in jockey pump activity are evaluated under the corrective action program in lieu of being not acceptable.

Request: State the basis for why cracking of polymer piping and unexplained changes in jockey pump activity are evaluated under the corrective action program in lieu of being not acceptable as recommended in GALL Report AMP Xl.M41, as modified by LR-ISG-2015-01.

NextEra Energy Seabrook Response to B.2.1.22-2 Element 6 - Acceptance Criteria, has been revised to address this request and changes can be seen below.

ELEMENT 6 - Acceptance Criteria For coated piping, there should be either no evidence of coating degradation or the type and extent of coating degradation should be insignificant as evaluated by an individual possessing a NACE Coating Inspector Program Level 2 or 3 inspector qualification, or an individual who has attended the EPRI Comprehensive Coatings Course and completed the EPRI Buried Pipe Condition Assessment and Repair Training Computer Based Training Course, or a coatings specialist qualified in accordance with an ASTM standard endorsed in Regulatory Guide 1.54, Rev. 2, "Service Level I, II, and Ill Protective Coatings Applied to Nuclear Power Plants.".

Where damage to the coating has been evaluated as significant and the damage was caused by non-conforming backfill, an extent of condition evaluation should be conducted to ensure that the as-left condition of backfill in the vicinity of observed damage will not lead to further degradation. Any coating and wrapping degradation will be documented and evaluated under the corrective action program. Where the protective coating consists of paint with no other coating or wrapping (e.g., drop-out spools in the Service Water vault), inspection of the painted surface should confirm no evidence of coating degradation (exposed metal) or degradation of the pipe surface due to corrosion.

Cracking or blistering of polymer piping is evaluated under the corrective action program.

U.S. Nuclear Regulatory Commission SBK-L-16186/Enclosure 1/ Page 11 Cracking is absent in rigid polymeric components. Blistering, gouges, or wear of nonmetallic piping is evaluated.

Criteria for pipe to soil potential when using a saturated copper/copper sulfate reference electrode for steel piping is -850 mV relative to a CSE, instant off. To prevent damage to the coating, the limiting critical potential should not be more negative than -1200 mV.

Alternatives to the -850 mV criterion for steel piping include the following:

100 mV minimum polarization.

-750 mV relative to a CSE, instant off where so.ii resistivity is greater than 10,000 ohm-cm to less than 100,000 ohm-cm.

-650 mV relative to a CSE, instant off where soil resistivity is greater than 100,000 ohm-cm.

Verify less than 1 mpy loss of material. Loss of material rates in excess of 1 mpy may be acceptable if an engineering evaluation demonstrates that the corrosion rate would not result in a loss of intended function prior to the end of the period of extended operation.

When using the 100 mV, -750 mV, or-650 mV polarization criteria as an alternative to the -850 mV criterion for steel piping, means to verify the effectiveness of the protection of the most anodic metal is incorporated into the program. One acceptable means to verify the effectiveness of the cathodic protection system, or to demonstrate that the loss of material rate is acceptable, is to use installed electrical resistance corrosion rate probes. The external loss of material rate is verified:

Every year when verifying the effectiveness of the cathodic protection system by measuring the loss of material rate.

Every 2 years when using the 100 mV minimum polarization.

Every 5 years when using the -750 or -650 criteria associated with higher resistivity soils. The soil resistivity is verified every 5 years.

As an alternative to verifying the effectiveness of the cathodic protection system every 5 years, soil resistivity testing is conducted annually during a period of time when the soil resistivity would be expected to be at its lowest value (e.g., maximum rainfall periods).

Upon completion of 10 annual consecutive soil samples, soil resistivity testing can be extended to every 5 years if the results of the soil sample tests consistently verified that the resistivity did not fall outside of the range being credited (e.g., for the -750 mV relative to a CSE, instant off criterion, all soil resistivity values were greater than 10,000 ohm-cm).

When electrical resistance corrosion rate probes will be used, the application identifies:

U.S. Nuclear Regulatory Commission SBK-L-16186/Enclosure 1/ Page 12 I

The qualifications of the individuals that will determine the installation locations of the probes and the methods of use (e.g., NACE CP4, "Cathodic Protection Specialist").

How the impact of significant site features (e.g., large cathodic protection current collectors, shielding due to large objects located in the vicinity of the protected piping) and local soil conditions will be factored into placement of the probes and use of probe data. Soil corrosivity is determined by soil analysis. If the calculated corrosion index value is greater than 10 points (i.e., corrosive soil) the number of inspection locations for non-cathodically protected steel piping is increased as shown in Element 4 above.

Backfill is consistent with SP0169-2007 section 5.2.3. Backfill located within 6 inches of steel and stainless steel pipe that meets ASTM D 448-08 size number 67 meets the objectives of SP0169-2007. Backfill located within 6 inches of polymeric pipe that meets ASTM D 448-08 size number 10 meets the objectives of SP0169-2007. Backfill quality may be demonstrated by plant records or by examining the backfill while conducting the inspections conducted in accordance with this program. Backfill not meeting this standard, in either the initial or subsequent inspections, is acceptable if the inspections conducted in accordance with this program do not reveal evidence of mechanical damage to pipe coatings due to the backfill.

Flow test results for fire mains, if credited in lieu of visual inspections, are in accordance with NFPA 25 section 7.3.

Changes in jockey pump activity (or similar parameter) that cannot be attributed to causes other than leakage from buried piping are not occurring.

Unexplained changes in jockey pump activity (or similar parameter), if credited in lieu of visual inspections, are evaluated under the corrective action program.

When fire water system leak rate testing is conducted, leak rates are within acceptance limits of plant-specific documents.

For pressure tests, the test acceptance criteria is no visible indications of leakage and no drop in pressure within the isolated portion of the piping that is not accounted for by a temperature change in the test media or quantified leakage across test boundary valves.

Evaluation of all adverse indications (e.g., leaks, cracks, material thickness less than minimum, coarse backfill with accompanying coating degradation, and general or local degradation of coatings so as to expose the base material) is conducted in accordance with the corrective action program. Any expansion of the inspection sample size is one facet of this evaluation when determining extent of condition.

If coated or uncoated metallic piping or tanks show evidence of corrosion, the remaining wall thickness in the affected area is determined to ensure that the minimum wall thickness is maintained. This may include different values for large area minimum wall thickness, and local area wall thickness.

Measured wall thickness projected to the end of the period of extended operation meets minimum wall thickness requirements, or proper corrective actions are in place prior to reaching the projected minimum wall thickness requirements.

U.S. Nuclear Regulatory Commission SBK-L-16186/Enclosure 1/ Page 13 RAI 8.2.1.22-3 .

Background:

GALL Report AMP Xl.M41, as modified by LR-ISG-2015-01, states that Inspection Category D may be used for those portions of in-scope buried piping where it has been demonstrated, in accordance with the "preventive actions" program element of this Aging Management Program (AMP), that external corrosion control is not required.

As amended by letter dated October 7, 2016, the "detection of aging effects" program element of LRA Section B.2.1.22 cites inspection Category D.

Issue:

While the submittal describes soil conditions, it is unclear to the staff how inspection Category D is applicable given that other key parameters are not described (e.g., pipe to soil potential measurements) to demonstrate external corrosion control is not required for those portions of in-scope buried piping claiming to meet inspection Category D.

Request:

State the basis for how inspection Category D is applicable for those portions of in-scope buried piping where the applicant claims that external corrosion control is not required.

NextEra Energy Seabrook Response to RAI 8.2.1.22-3 NextEra Energy Seabrook will not be utilizing Inspection Category D as described within Section 4 - Detection of Aging Effects within LR-ISG-2015-01. Tables 2 and 3 within B.2.1.22 have been revised to reflect this change and can be seen below.

Directed Inspections - Inaccessible Submerged Pipe The number of inspections required during each 10 year interval is shown in the tables below. With the exception of backfill and soil resistivity criteria, inaccessible submerged piping will be inspected to the same extent as buried piping. The aluminum bronze drain valves attached to these piping segments will also be inspected for loss of material when the associated pipe segment is inspected.

Table 2 - Inspections of Buried, Underground Piping and Inaccessible Submerged Piping Prevention Action 12 Systems Currently in Material Inspections

Categories Category Stainless Steel 1 Inspection CO,DG Backfill is in accordance with Polymeric preventive actions program 1 Inspection FP element 3

U.S. Nuclear Regulatory Commission SBK-L-16186/Enclosure 1/ Page 14 Table 2 - Inspections of Buried, Underground Piping and Inaccessible Submerged Piping The smaller of 1%

Backfill is not in accordance of the length of with preventive actions pipe or 2 program category 3 inspections The smaller of 0.5% of the piping c length or 1 inspection

+t:ie smalleF ef ~ %

ef tl=le 13i13iR§! leR§!tR D

eF 2 iRs13ectieRs CBA, IA, FP, SW 6 , AB Steel NIA 4

, CO, OF, DG, FW, The smaller of 5% ASC,ASH E of the piping length or 3 inspections The smaller of 10%

F of the piping length or 6 inspections

U.S. Nuclear Regulatory Commission SBK-L-16186/Enclosure 1/ Page 15 Table 2 - Inspections of Buried, Underground Piping and Inaccessible Submerged Piping The smaller of 0.5% of the piping c length or 1 inspection The smaller of 1%

of the piping length D

Copper Alloy or 2 inspections SW 7

>15% Zinc NIA The smaller of 5%

E of the piping length or 3 inspections The smaller of 10%

F of the piping length or 6 inspections GENERAL NOTES:

1. When the inspections are based on the number of inspections in lieu of percentage of piping length, IO feet of piping is exposed for each inspection.

2. When the percentage of inspections for a given material type results in an inspection quantity of less than 10 feet, then 10 feet of piping is inspected. If the entire run of piping of that material type is less than 10 feet in total length, then the entire run of piping is inspected.

3. The adequacy of backfill will be determined by the condition of coatings and base materials noted during inspections. If damage to the coatings or base materials is determined to have been caused by the backfill, the backfill will be considered to be "inadequate" (for the purpose of this program).

4. This line is not in use. It has been drained and flushed and is awaiting replacement. The inspection criteria for the replacement piping will be determined based material selection, coating, cathodic protection, and quality of backfill.

5. If Fire Protection piping is inspected by excavation in lieu of by alternative testing (e.g., flow test, jockey pump monitoring), and the extent of examinations is not based on the percentage of piping in the material group, the Not-to-Exceed (NTE) value will be increased by 1 inspection, if normally less than 10, or 2 inspections, if normally 10 or greater.

6. The Service Water vault located north of the cooling tower contains four 24" lines approximately 15' long. The valve pit located north of the cooling tower contains one 32" line less than 10' long.

7. Drain valves on the spools in the Service Water vault and valve pit are constructed of aluminum bronze (categorized as "copper alloy > 15% zinc") with aluminum bronze body to bonnet bolting. These components will be inspected for loss of material when the respective Service Water spool piping is inspected by this program.

U.S. Nuclear Regulatory Commission SBK-L-16186/Enclosure 1/ Page 16 Table 3 - Preventive Action Categories C: Category C Applies when:

a. Cathodic protection was installed or refurbished 5 years prior to the end of the inspection period of interest; and

b. Cathodic protection has operated at least 85 percent of the time since either 10 years prior to the period of extended operation or since installation I refurbishment, whichever is shorter. Time periods in which the cathodic protection system is off-line for testing do not have to be included in the total non-operating hours; and

c. Cathodic protection has provided effective protection for buried piping as evidenced by meeting the acceptance criteria in Section 3.6 of this AMP at least 80 percent of the time since either 10 years prior to the period of extended operation or since installation/refurbishment, whichever is shorter. As found results of annual surveys are to be used to demonstrate locations within the plant's population of buried pipe where cathodic protection acceptance criteria have, or have not, been met.

D: Inspection criteria provided for Category D piping may be used for those portions of in scope buried piping where it has been demonstrated, in accordance 'Nith the "preventive actions" program element of this AMP, that external corrosion control is not required. Inspection Category D will not be used.

E: Inspection criteria provided for Category E piping may be used for those portions of the population of buried piping where:

a. An analysis, conducted in accordance with the "preventive actions" program element of this AMP, has demonstrated that installation or operation of a cathodic protection system is impractical; or

b. A cathodic protection system has been installed but all or portions of the piping covered by that system fail to meet any of the criteria of Category C piping above, provided:

i. Coatings and backfill are provided in accordance with the "preventive actions" program element of this AMP; and ii. Plant-specific operating experience is acceptable (i.e., no leaks in buried piping due to external corrosion, no significant coating degradation or metal loss in more than 1O percent of inspections conducted); and

U.S. Nuclear Regulatory Commission SBK-L-16186/Enclosure 1/ Page 17 iii. Soil has been demonstrated to not be corrosive for the material type (e.g., AWWA C105, "Polyethylene Encasement for Ductile-Iron Pipe Systems," Table A.1, "Soil-Test Evaluation"). In order to demonstrate that the soil is not corrosive, Seabrook will:

1) Obtain a minimum of three sets of soil samples in each soil environment (e.g., moisture content, soil composition) in the vicinity in which in-scope components are buried.

2) Tests the soil for soil resistivity, corrosion accelerating bacteria, pH, moisture, chlorides, sulfates, and redox potential.

3) Determines the potential soil corrosivity for each material type of buried in-scope piping. In addition to evaluating each individual parameter, the overall soil corrosivity is determined.

4) Conduct soil testing once in each 10-year period starting 10 years prior to the period of extended operation.

F: Inspection criteria provided for Category F piping is used for those portions of in-scope buried piping which cannot be classified as Category C, D, or E (e.g. Buried or Underground piping that do not meet recommendations within the Preventive Action Table 1).

U.S. Nuclear Regulatory Commission SBK-L-16186/Enclosure 1/ Page 18 RAI 8.2.1.22-4

Background:

GALL Report AMP Xl.M41, as modified by LR-ISG-2015-01, states that when electrical resistance corrosion rate probes will be used, the application identifies:

1) The qualifications of the individuals that will determine the installation locations of the probes and the methods of use (e.g., NACE CP4, "Cathodic Protection Specialist").

2) How the impact of significant site features (e.g., large cathodic protection current collectors, shielding due to large objects located in the vicinity of the protected piping), and local soil conditions will be factored into placement of the probes and use of probe data.

As amended by letter dated October 7, 2016, the "acceptance criteria" program element of LRA Section B.2.1.22 states that soil corrosivity is determined by soil analysis and that if the calculated corrosion index value is greater than 10 points (i.e., corrosive soil) the number of inspection locations for non-cathodically protected steel piping is increased.

Issue:

The staff noted that the submittal did identify how local soil conditions will be factored into placement of the probes and use of probe data; however it did not address:

(1) The qualifications of the individuals that will determine the installation locations of the probes and the methods of use.

(2) How the impact of significant site features will be factored into the placement of the probes and use of probe data.

Request:

Provide additional information to address the two issues noted above regarding the use of electrical resistance corrosion rate probes.

NextEra Energy Seabrook Response to RAI .2.1.22-4 NextEra Energy Seabrook plans to utilize the -850 mV criterion for steel piping, and to not implement the use of electrical resistance corrosion rate probes as an alternative to this criterion. Aging Management Program B.2.1.22, Element 6 - Acceptance Criteria, is revised as follows.

ELEMENT 6 - Acceptance Criteria For coated piping, there should be either no evidence of coating degradation or the type and extent of coating degradation should be insignificant as evaluated by an individual possessing a NACE Coating Inspector Program Level 2 or 3 inspector qualification, or an individual who has attended the EPRI Comprehensive Coatings Course and completed the EPRI Buried Pipe Condition Assessment and Repair Training Computer Based Training Course, or a coatings specialist qualified in accordance with an ASTM standard endorsed in Regulatory Guide 1.54, Rev. 2, "Service Level I, II, and Ill Protective Coatings Applied to Nuclear Power Plants.".

U.S. Nuclear Regulatory Commission SBK-L-16186/Enclosure 1/ Page 19 Where damage to the coating has been evaluated as significant and the damage was caused by non-conforming backfill, an extent of condition evaluation should be conducted to ensure that the as-left condition of backfill in the vicinity of observed damage will not lead to further degradation. Any coating and wrapping degradation will be documented and evaluated under the corrective action program. Where the protective coating consists of paint with no other coating or wrapping (e.g., drop-out spools in the Service Water vault), inspection of the painted surface should confirm no evidence of coating degradation (exposed metal) or degradation of the pipe surface due to corrosion.

Cracking or blistering of polymer piping is evaluated under the corrective action program.

Cracking is absent in rigid polymeric components. Blistering, gouges, or wear of nonmetallic piping is evaluated.

Criteria for pipe to soil potential when using a saturated copper/copper sulfate reference electrode for steel piping is -850 mV relative to a CSE, instant off. To prevent damage to the coating, the limiting critical potential should not be more negative than -1200 mV.

Alternatives to the 850 mV criterion for steel piping include the following:

100 mV minimum polarization.

750 mV relative to a CSE, instant off where soil resistivity is greater than 10,000 ohm cm to less than 100,000 ohm cm.

650 mV relative to a CSE, instant off 'Nhere soil resistivity is greater than 100,000 ohm cm.

Verify less than 1 mpy loss of material. Loss of material rates in excess of 1 mpy may be acceptable if an engineering evaluation demonstrates that the corrosion rate would not result in a loss of intended function prior to the end of the period of extended operation.

When using the 100 mV, 750 mV, or 650 mV polarization criteria as an alternative to the 850 mV criterion for steel piping, means to verify the effectiveness of the protection of the most anodic metal is incorporated into the program. One acceptable means to verify the effectiveness of the cathodic protection system, or to demonstrate that the loss of material rate is acceptable, is to use installed electrical resistance corrosion rate probes. The external loss of material rate is verified:

Every year when verifying the effectiveness of the cathodic protection system by measuring the loss of material rate.

Every 2 years when using the 100 mV minimum polarization.

Every 5 years 'Nhen using the 750 or 650 criteria associated with higher resistivity soils. The soil resistivity is verified every 5 years.

As an alternative to verifying the effectiveness of the cathodic protection system every 5 years, soil resistivity testing is conducted annually during a period of time when the soil

U.S. Nuclear Regulatory Commission SBK-L-16186/Enclosure 1/ Page 20 resistivity would be expected to be at its lowest value (e.g., maximum rainfall periods).

Upon completion of 10 annual consecutive soil samples, soil resistivity testing can be extended to every 5 years if the results of the soil sample tests consistently verified that the resistivity did not fall outside of the range being credited (e.g., for the 750 mV relative to a CSE, instant off criterion, all soil resistivity values were greater than 10,000 ohm cm).

VVhen electrical resistance corrosion rate probes 1Nill be used, the application identifies:

1 The qualifications of the individuals that 'Nill determine the installation locations of the probes and the methods of use (e.g., NACE CP4, "Cathodic Protection Specialist").

How the impact of significant site features (e.g., large cathodic protection current collectors, shielding due to large objects located in the vicinity of the protected piping) and local soil conditions will be factored into placement of the probes and use of probe data. Soil corrosivity is determined by soil analysis. If the calculated corrosion index value is greater than 10 points (i.e., corrosive soil) the number of inspection locations for non cathodically protected steel piping is increased as shovvn in Element 4 above.

Backfill is consistent with SP0169-2007 section 5.2.3. Backfill located within 6 inches of steel and stainless steel pipe that meets ASTM D 448-08 size number 67 meets the objectives of SP0169-2007. Backfill located within 6 inches of polymeric pipe that meets ASTM D 448-08 size number 10 meets the objectives of SP0169-2007. Backfill quality may be demonstrated by plant records or by examining the backfill while conducting the inspections conducted in accordance with this program. Backfill not meeting this standard, in either the initial or subsequent inspections, is acceptable if the inspections conducted in accordance with this program do not reveal evidence of mechanical damage to pipe coatings due to the backfill.

Flow test results for fire mains, if credited in lieu of visual inspections, are in accordance with NFPA 25 section 7.3.

Changes in jockey pump activity (or similar parameter) that cannot be attributed to causes other than leakage from buried piping are not occurring.

Unexplained changes in jockey pump activity (or similar parameter), if credited in lieu of visual inspections, are evaluated under the corrective action program.

When fire water system leak rate testing is conducted, leak rates are within acceptance limits of plant-specific documents.

For pressure tests, the test acceptance criteria is no visible indications of leakage and no drop in pressure within the isolated portion of the piping that is not accounted for by a temperature change in the test media or quantified leakage across test boundary valves.

Evaluation of all adverse indications (e.g., leaks, cracks, material thickness less than minimum, coarse backfill with accompanying coating degradation, and general or local degradation of coatings so as to expose the base material) is conducted in accordance with the corrective action program. Any expansion of the inspection sample size is one facet of this evaluation when determining extent of condition.

U.S. Nuclear Regulatory Commission SBK-L-16186/Enclosure 1/ Page 21 If coated or uncoated metallic piping or tanks show evidence of corrosion, the remaining wall thickness in the affected area is determined to ensure that the minimum wall thickness is maintained. This may include different values for large area minimum wall thickness, and local area wall thickness.

Measured wall thickness projected to the end of the period of extended operation meets minimum wall thickness requirements, or proper corrective actions are in place prior to reaching the projected minimum wall thickness requirements.

Enclosure 2 to SBK-L-16186 LRA Appendix A - Final Safety Report Supplement Table A.3, License Renewal Commitment List Update to Commitment #64, Soil Sampling Schedule

A.3 LICENSE RENEWAL COMMITMENT LIST UFSAR No. PROGRAM or TOPIC COMMITMENT SCHEDULE LOCATION Provide confirmation and acceptability of the implementation ofMRP-227-A by addressing the plant-

1. PWR Vessel Internals A.2.1.7 Complete specific Applicant/Licensee Action Items outlined in section 4.2 of the NRC SER.

Enhance the program to include visual inspection for Prior to the period of extended

2. Closed-Cycle Cooling Water cracking, loss of material and fouling when the in-scope A.2.1.12 operation.

systems are opened for maintenance.

Inspection of Overhead Heavy Enhance the program to monitor general corrosion on the Load and Light Load (Related Prior to the period of extended

3. crane and trolley structural components and the effects of A.2.1.13 to Refueling) Handling operation.

wear on the rails in the rail system.

Systems Inspection of Overhead Heavy Load and Light Load (Related Prior to the period of extended

4. Enhance the program to list additional cranes for monitoring. A.2.1.13 to Refueling) Handling operation.

Systems Enhance the program to include an annual air quality test Prior to the period of extended

5. Compressed Air Monitoring requirement for the Diesel Generator compressed air sub A.2.1.14 operation.

system.

Enhance the program to perform visual inspection of Prior to the period of extended

6. Fire Protection A.2.1.15 penetration seals by a fire protection qualified inspector. operation.

Enhance the program to add inspection requirements such as spalling, and loss of material caused by freeze-thaw, Prior to the period of extended

7. Fire Protection A.2.1.15 chemical attack, and reaction with aggregates by qualified operation.

inspector.

U.S. Nuclear Regulatory Commission SBK-L-16186/Enclosure 2/Page 2 Enhance the program to include the performance of visual Prior to the period of extended

8. Fire Protection inspection of fire-rated doors by a fire protection qualified A.2.1.15 operation.

inspector.

Enhance the program to include NFPA 25 (2011 Edition) guidance for "where sprinklers have been in place for 50 Prior to the period of extended

9. Fire Water System years, they shall be replaced or representative samples from A.2.1.16 operation.

one or more sample areas shall be submitted to a recognized testing laboratory for field service testing".

Enhance the program to include the performance of periodic Prior to the period of extended

10. Fire Water System flow testing of the fire water system in accordance with the A.2.1.16 operation.

guidance ofNFPA 25 (2011 Edition).

Enhance the program to include the performance of periodic visual or volumetric inspection of the internal surface of the fire protection system upon each entry to the system for routine or corrective maintenance to evaluate wall thiclmess and inner diameter of the fire protection piping ensuring that corrosion product buildup will not result in flow blockage due to fouling. Where surface irregularities are detected, follow-up volumetric examinations are performed. These Within ten years prior to the

11. Fire Water System A.2.1.16 inspections will be documented and trended to determine if a period of extended operation.

representative number of inspections have been performed prior to the period of extended operation. If a representative number of inspections have not been performed prior to the period of extended operation, focused inspections will be conducted. These inspections will commence during the ten year period prior to the period of extended operation and continue through the period of extended operation

U.S. Nuclear Regulatory Commission SBK-L-16186/Enclosure 2/Page 3 Enhance the program to include 1) In-scope outdoor tanks, except fire water storage tanks, constructed on soil or concrete, 2) Indoor large volume storage tanks (greater than 100,000 gallons) designed to near-atmospheric internal pressures, sit on concrete or soil, and exposed internally to water, 3) Visual, surface, and volumetric examinations of the Within 10 years prior to the

12. Aboveground Steel Tanks outside and inside surfaces for managing the aging effects of A.2.1.17 period of extended operation.

loss of material and cracking, 4) External visual examinations to monitor degradation of the protective paint or coating, and

5) Inspection of sealant and caulking for degradation by performing visual and tactile examination (manual manipulation) consisting of pressing on the sealant or caulking to detect a reduction in the resiliency and pliability.

Enhance the program to perform exterior inspection of the fire water storage tanks annually for signs of degradation and include an ultrasonic inspection and evaluation of the Within ten years prior to the

13. Fire Water System A.2.1.16 internal bottom surface of the two Fire Protection Water period of extended operation.

Storage Tanks per the guidance provided in NFPA 25 (2011 Edition).

Enhance program to add requirements to 1) sample and analyze new fuel deliveries for biodiesel prior to offloading Prior to the period of extended

14. Fuel Oil Chemistry to the Auxiliary Boiler fuel oil storage tank and 2) A.2.1.18 operation.

periodically sample stored fuel in the Auxiliary Boiler fuel

oil storage tank.

Enhance the program to add requirements to check for the Prior to the period of extended

15. Fuel Oil Chemistry presence of water in the Auxiliary Boiler fuel oil storage tank A.2.1.18 operation.

at least once per quarter and to remove water as necessary.

U.S. Nuclear Regulatory Commission SBK-L-16186/Enclosure 2/Page 4 Enhance the program to require draining, cleaning and Prior to the period of extended

16. Fuel Oil Chemistry inspection of the diesel fire pump fuel oil day tanks on a A.2.1.18 operation.

frequency of at least once every ten years.

Enhance the program to require ultrasonic thickness measurement of the tank bottom during the 10-year draining, cleaning and inspection of the Diesel Generator fuel oil Prior to the period of extended

17. Fuel Oil Chemistry A.2.1.18 storage tanks, Diesel Generator fuel oil day tanks, diesel fire operation.

pump fuel oil day tanks and auxiliary boiler fuel oil storage tank.

Enhance the program to specify that all pulled and tested Prior to the period of extended

18. Reactor Vessel Surveillance capsules, unless discarded before August 31, 2000, are A.2.1.19 operation.

placed in storage.

Enhance the program to specify that if plant operations exceed the limitations or bounds defined by the Reactor Vessel Surveillance Program, such as operating at a lower Prior to the period of extended

19. Reactor Vessel Surveillance cold leg temperature or higher fluence, the impact of plant A.2.1.19 operation.

operation changes on the extent of Reactor Vessel embrittlement will be evaluated and the NRC will be notified.

Enhance the program as necessary to ensure the appropriate withdrawal schedule for capsules remaining in the vessel such that one capsule will be withdrawn at an outage in which the capsule receives a neutron fluence that meets the Prior to the period of extended

20. Reactor Vessel Surveillance A.2.1.19 schedule requirements of 10 CFR 50 Appendix Hand ASTM operation.

E185-82 and that bounds the 60-year fluence, and the remaining capsule(s) will be removed from the vessel unless determined to provide meaningful metallurgical data.

Enhance the program to ensure that any capsule removed, without the intent to test it, is stored in a manner which Prior to the period of extended

21. Reactor Vessel Surveillance A.2.1.19 maintains it in a condition which would permit its future use, operation.

including during the period of extended operation.

U.S. Nuclear Regulatory Commission SBK-L-16186/Enclosure 2/Page 5 Within ten years prior to the

22. One-Time Inspection Implement the One Time Inspection Program. A.2.1.20 period of extended operation.

Implement the Selective Leaching of Materials Program. The program will include a one-time inspection of selected Selective Leaching of Within five years prior to the

23. components where selective leaching has not been identified A.2.1.21 Materials period of extended operation.

and periodic inspections of selected components where selective leaching has been identified.

Implement the Buried Piping And Tanks Inspection Buried Piping And Tanks Program. Within ten years prior to the

24. A.2.1.22 Inspection period of extended operation One-Time Inspection of Implement the One-Time Inspection of ASME Code Class 1 Within ten years prior to the

25. ASME Code Class 1 Small A.2.1.23 Small Bore-Piping Program. period of extended operation.

Bore-Piping Enhance the program to specifically address the scope of the program, relevant degradation mechanisms and effects of Prior to the period of extended

26. External Surfaces Monitoring interest, the refueling outage inspection frequency, the A.2.1.24 operation.

training requirements for inspectors and the required periodic reviews to determine program effectiveness.

Inspection of Internal Surfaces Implement the Inspection ofinternal Surfaces in Prior to the period of extended

27. in Miscellaneous Piping and A.2.1.25 Miscellaneous Piping and Ducting Components Program. operation.

Ducting Components Enhance the program to add required equipment, lube oil Prior to the period of extended

28. Lubricating Oil Analysis analysis required, sampling frequency, and periodic oil A.2.1.26 operation.

changes.

Enhance the program to sample the oil for the Reactor Prior to the period of extended

29. Lubricating Oil Analysis A.2.1.26 Coolant pump oil collection tanks. operation.

U.S. Nuclear Regulatory Commission SBK-L-16186/Enclosure 2/Page 6 Enhance the program to require the performance of a one-time ultrasonic thickness measurement of the lower portion Prior to the period of extended

30. Lubricating Oil Analysis A.2.1.26 of the Reactor Coolant pump oil collection tanks prior to the operation.

period of extended operation.

ASME Section XI, Subsection Enhance procedure to include the definition of"Responsible Prior to the period of extended

31. A.2.1.28 IWL Engineer". operation.

Enhance procedure to add the aging effects, additional Prior to the period of extended

32. Structures Monitoring Program locations, inspection frequency and ultrasonic test A.2.1.31 operation.

requirements.

Enhance procedure to include inspection of opportunity Prior to the period of extended

33. Structures Monitoring Program when planning excavation work that would expose A.2.1.31 operation.

inaccessible concrete.

Electrical Cables and Implement the Electrical Cables and Connections Not Connections Not Subject to 10 Prior to the period of extended

34. Subject to 10 CFR 50.49 Environmental Qualification A.2.1.32 CFR 50.49 Environmental operation.

Requirements program.

Qualification Requirements Electrical Cables and Connections Not Subject to 10 Implement the Electrical Cables and Connections Not CFR 50.49 Environmental Prior to the period of extended

35. Subject to 10 CFR 50.49 Environmental Qualification A.2.1.33 Qualification Requirements operation.

Requirements Used in Instrumentation Circuits program.

Used in Instrumentation Circuits Inaccessible Power Cables Not Implement the Inaccessible Power Cables Not Subject to 10 Subject to 10 CFR 50.49 Prior to the period of extended

36. CFR 50.49 Environmental Qualification Requirements A.2.1.34 Environmental Qualification operation.

program.

Requirements Prior to the period of extended

37. Metal Enclosed Bus Implement the Metal Enclosed Bus program. A.2.1.35 operation.

U.S. Nuclear Regulatory Commission SBK-L-16186/Enclosure 2/Page 7 Prior to the period of extended

38. Fuse Holders Implement the Fuse Holders program. A.2.1.36 operation.

Electrical Cable Connections Implement the Electrical Cable Connections Not Subject to Not Subject to 10 CFR 50.49 Prior to the period of extended

39. 10 CFR 50.49 Environmental Qualification Requirements A.2.1.37 Environmental Qualification operation.

program.

Requirements Prior to the period of extended

40. 345 KV SF6 Bus Implement the 345 KV SF6 Bus program. A.2.2.1 operation.

Metal Fatigue of Reactor Enhance the program to include additional transients beyond Prior to the period of extended

41. A.2.3.1 Coolant Pressure Boundary those defined in the Technical Specifications and UFSAR. operation.

Enhance the program to implement a software program, to Metal Fatigue of Reactor Prior to the period of extended

42. count transients to monitor cumulative usage on selected A.2.3.1 Coolant Pressure Boundary operation.

components.

The updated analyses will be Pressure -Temperature Limits, Seabrook Station will submit updates to the P-T curves and submitted at the appropriate

43. including Low Temperature LTOP limits to the NRC at the appropriate time to comply A.2.4.1.4 time to comply with 10 CFR Overpressure Protection Limits with 10 CFR 50 Appendix G. 50 Appendix G, Fracture Toughness Requirements.

U.S. Nuclear Regulatory Commission SBK-L-16186/Enclosure 2/Page 8 NextEra Seabrook will perform a review of design basis ASME Class 1 component fatigue evaluations to determine whether the NUREG/CR-6260-based components that have been evaluated for the effects of the reactor coolant environment on fatigue usage are the limiting components for the Seabrook plant configuration. If more limiting components are identified, the most limiting component will be evaluated for the effects of the reactor coolant environment on fatigue usage. If the limiting location identified consists of nickel alloy, the environmentally-assisted fatigue calculation for nickel alloy will be performed using the rules ofNUREG/CR-6909.

(1) Consistent with the Metal Fatigue of Reactor Coolant Pressure Boundary Program Seabrook Station will update the fatigue usage calculations using refined fatigue analyses, if necessary, to determine acceptable CUFs (i.e., less than 1.0) when accounting for the effects of the reactor water Environmentally-Assisted environment. This includes applying the appropriate Fen At least two years prior to the

44. A.2.4.2.3 Fatigue Analyses (TLAA) factors to valid CUFs determined from an existing fatigue period of extended operation.

analysis valid for the period of extended operation or from an analysis using an NRC-approved version of the ASME code or NRC-approved alternative (e.g., NRC-approved code case).

(2) If acceptable CUFs cannot be demonstrated for all the selected locations, then additional plant-specific locations will be evaluated. For the additional plant-specific locations, if CUF, including environmental effects is greater than 1.0, then Corrective Actions will be initiated, in accordance with the Metal Fatigue of Reactor Coolant Pressure Boundary Program, B.2.3.1. Corrective Actions will include inspection, repair, or replacement of the affected locations before exceeding a CUF of 1.0 or the effects of fatigue will be managed by an inspection program that has been reviewed and approved by the NRC (e.g., periodic non-destructive examination of the affected locations at inspection intervals to be determined by a method accepted by the NRC).

U.S. Nuclear Regulatory Commission SBK-L-16186/Enclosure 2/Page 9

45. Number Not Used Protective Coating Monitoring Enhance the program by designating and qualifying an Prior to the period of extended

46. A.2.1.38 and Maintenance Inspector Coordinator and an Inspection Results Evaluator. operation.

Enhance the program by including, "Instruments and Equipment needed for inspection may include, but not be Protective Coating Monitoring limited to, flashlight, spotlights, marker pen, mirror, Prior to the period of extended

47. A.2.1.38 and Maintenance measuring tape, magnifier, binoculars, camera with or operation.

without wide angle lens, and self sealing polyethylene sample bags."

Protective Coating Monitoring Enhance the program to include a review of the previous two Prior to the period of extended

48. A.2.1.38 and Maintenance monitoring reports. operation.

Enhance the program to require that the inspection report is Protective Coating Monitoring to be evaluated by the responsible evaluation personnel, who Prior to the period of extended

49. A.2.1.38 and Maintenance is to prepare a summary of findings and recommendations operation.

for future surveillance or repair.

Baseline inspections were completed during OR16.

Perforrµ UT of the accessible areas of the containment liner ASME Section XI, Subsection Repeat containment liner UT

50. plate in the vicinity of the moisture barrier for loss of A.2.1.27 IWE thickness examinations at material. Perform opportunistic UT of inaccessible areas.

intervals of no more than five (5) refueling outages.

51. Number Not Used Implement measures to maintain the exterior surface of the ASME Section XI, Subsection

52. Containment Structure, from elevation -30 feet to +20 feet, in A.2.1.28 Complete IWL a dewatered state.

Replace the spare reactor head closure stud(s) manufactured Prior to the period of extended

53. Reactor Head Closure Studs from the bar that has a yield strength> 150 ksi with ones that A.2.1.3 operation.

do not exceed 150 ksi.

U.S. Nuclear Regulatory Commission SBK-L-16186/Enclosure 2/Page 10 NextEra will address the potential for cracking of the primary to secondary pressure boundary due to PWSCC of tube-to-tubesheet welds using one of the following two options:

1) Perform a one-time inspection of a representative sample oftube-to-tubesheet welds in all steam generators to determine if PWSCC cracking is present and, if cracking is identified, resolve the condition through engineering evaluation justifying continued operation or repair the condition, as appropriate, and establish an ongoing monitoring program to perform routine tube-to-tubesheet Steam Generator Tube

54. weld inspections for the remaining life of the steam A.2.1.10 Complete Integrity generators, or

2) Perform an analytical evaluation showing that the structural integrity of the steam generator tube-to-tubesheet interface is adequately maintaining the pressure boundary in the presence oftube-to-tubesheet weld cracking, or redefining the pressure boundary in which the tube-to-tubesheet weld is no longer included and, therefore, is not required for reactor coolant pressure boundary function. The redefinition of the reactor coolant pressure boundary must be

. approved by the NRC as part of a license amendment request.

Steam Generator Tube Seabrook will perform an inspection of each steam generator Within five years prior to the

55. A.2.1.10 Integrity to assess the condition of the divider plate assembly. period of extended operation.

Revise the station program documents to reflect the EPRl Closed-Cycle Cooling Water Prior to the period of extended

56. Guideline operating ranges and Action Level values for A.2.1.12 System operation.

hydrazine and sulfates.

Revise the station program documents to reflect the EPRl Closed-Cycle Cooling Water Prior to the period of extended

57. Guideline operating ranges and Action Level values for A.2.1.12 System operation.

Diesel Generator Cooling Water Jacket pH.

U.S. Nuclear Regulatory Commission SBK-L-16186/Enclosure 2/Page 11 Update Technical Requirement Program 5.1, (Diesel Fuel Oil Prior to the period of extended

58. Fuel Oil Chemistry Testing Program) ASTM standards to ASTM D2709-96 and A.2.1.18 operation.

ASTM D4057-95 required by the GALL Xl.M30 Rev 1 The Nickel Alloy Aging Nozzles and Penetrations program Nickel Alloy Nozzles and Prior to the period of extended

59. will implement applicable Bulletins, Generic Letters, and A.2.2.3 Penetrations operation.

staff accepted industry guidelines.

Implement the design change replacing the buried Auxiliary Buried Piping and Tanks Prior to the period of extended

60. Boiler supply piping with a pipe-within-pipe configuration A.2.1.22 Inspection operation.

with leak detection capability.

Compressed Air Monitoring Replace the flexible hoses associated with the Diesel Within ten years prior to the

61. A.2.1.14 Program Generator air compressors on a frequency of every 10 years. period of extended operation.

Enhance the program to include a statement that sampling Prior to the period of extended

62. Water Chemistry frequencies are increased when chemistry action levels are A.2.1.2 operation.

exceeded.

Ensure that the quarterly CVCS Charging Pump testing is continued during the PEO. Additionally, add a precaution to the test procedure to state that an increase in the eves Prior to the period of extended

63. Flow Induced Erosion A.2.1.2 Charging Pump mini flow above the acceptance criteria may operation.

be indicative of erosion of the mini flow orifice as described in LER 50-275/94-023.

Soil analysis shall be performed prior to entering the period of extended operation to determine the corrosivity of the soil in the vicinity of non-cathodically protected steel pipe within Within ten years prior to the

64. Buried Piping and Tanks A.2.1.22 the scope of this program. If the initial analysis shows the period of extended operation.

Inspection soil to be non-corrosive, this analysis will be re-performed every ten years thereafter.

Implement measures to ensure that the movable incore Prior to the period of extended

65. Flux Thimble Tube detectors are not returned to service during the period of NIA operation. - In Progress extended* operation.

U.S. Nuclear Regulatory Commission SBK-L-16186/Enclosure 2/Page 12

66. Number Not Used Perform one shallow core bore in an area that was continuously wetted from borated water to be examined for concrete degradation and also expose rebar to detect any

67. Structures Monitoring Program A.2.1.31 Complete degradation such as loss of material. The removed core will also be subjected to petrographic examination for concrete degradation due to ASR per ASTM Standard Practice C856.

Perform sampling at the leak off collection points for

68. Structures Monitoring Program A.2.1.31 Complete chlorides, sulfates, pH and iron once every three months.

Replace the Diesel Generator Heat Exchanger Plastisol PVC Open-Cycle Cooling Water

69. lined Service Water piping with piping fabricated from A.2.1.11 Complete System AL6XN material.

Inspect the piping downstream of CC-V-444 and CC-V-446 Closed-Cycle Cooling Water to determine whether the loss of material due to cavitation Within ten years prior to the

70. A.2.1.12 System induced erosion has been eliminated or whether this remains period of extended operation.

an issue in the primary component cooling water system.

NextEra has completed testing at the University of Texas Ferguson Structural Engineering Laboratory which Alkali-Silica Reaction (ASR) demonstrates the parameters being monitored and acceptance Monitoring Program I criteria used are appropriate to manage the effects of ASR. A.2.l.31A Prior to the period of extended

71. Building Deformation operation.

NextEra !implement the Alkali-Silica Reaction (ASR) A.2.l.31B Monitoring Program Monitoring Program and Building Deformation Monitoring Program described in B.2.1.3 lA and B.2.1.3 lB of the License Renewal Application.

Enhance the program to include management of wall Prior to the period of extended

72. Flow-Accelerated Corrosion A.2.1.8 thinning caused by mechanisms other than F AC. operation.

U.S. Nuclear Regulatory Commission SBK-L-16186/Enclosure 2/Page 13 Enhance the program to include performance of focused Inspection of Internal Surfaces examinations to provide a representative sample of 20%, or a

73. in Miscellaneous Piping and maximum of25, of each identified material, environment, A.2.1.25 Prior to the period of extended Ducting Components and aging effect combinations during each 10 year period in operation.

the period of extended operation.

Enhance the program to perform sprinkler inspections annually per the guidance provided in NFP A 25 (2011 Edition). Inspection will ensure that sprinklers are free of corrosion, foreign materials, paint, and physical damage and Prior to the period of extended

74. Fire Water System installed in the proper orientation (e.g., upright, pendant, or A.2.1.16 operation.

sidewall). Any sprinkler that is painted, corroded, damaged, loaded, or in the improper orientation, and any glass bulb sprinkler where the bulb has emptied, will be evaluated for replacement.

Enhance the program to a) conduct an inspection of piping and branch line conditions every 5 years by opening a flushing connection at the end of one main and by removing a sprinkler toward the end of one branch line for the purpose of inspecting for the presence of foreign organic and inorganic material per the guidance provided in NFPA 25 (2011 Edition) and b) If the presence of sufficient foreign Prior to the period of extended

75. Fire Water System organic or inorganic material to obstruct pipe or sprinklers is A.2.1.16 operation.

detected during pipe inspections, the material will be removed and its source is determined and corrected.

In buildings having multiple wet pipe systems, every other system shall have an internal inspection of piping every 5 years as described in NFP A 25 (2011 Edition), Section 14.2.2.

U.S. Nuclear Regulatory Commission SBK-L-16186/Enclosure 2/Page 14 Enhance the Program to conduct the following activities annually per the guidance provided in NFP A 25 (2011 Edition). Prior to the period of extended

76. Fire Water System A.2.1.16

main drain tests operation.

deluge valve trip tests

fire water storage tank exterior surface inspections The Fire Water System Program will be enhanced to include the following requirements related to the main drain testing per the guidance provided in NFPA 25 (2011 Edition).

The requirement that ifthere is a 10 percent reduction in Prior to the period of extended

77. Fire Water System full flow pressure when compared to the original A.2.1.16 operation.

acceptance tests or previously performed tests, the cause of the reduction shall be identified and corrected if necessary.

Recording the time taken for the supply water pressure to return to the original static (nonflowing) pressure.

Enhance the program to include periodic inspections of in-scope insulated components for possible corrosion under insulation. A sample of outdoor component surfaces that are insulated and a sample of indoor insulated components Prior to the period of extended

78. External Surfaces Monitoring A.2.1.24 exposed to condensation (due to the in-scope component operation.

being operated below the dew point), will be periodically inspected every 10 years during the period of extended operation.

Enhance the program to include visual inspection of internal Open-Cycle Cooling Water coatings/linings for loss of coating integrity. Within 10 years prior to the

79. A.2.1.11 System period of extended operation.

Enhance the program to include visual inspection of internal coatings/linings for loss of coating integrity. Within 10 years prior to the

80. Fire Water System A.2.1.16 period of extended operation.

U.S. Nuclear Regulatory Commission SBK-L-16186/Enclosure 2/Page 15 Enhance the program to include visual inspection of internal coatings/linings for loss of coating integrity. Within 10 years prior to the

81. Fuel Oil Chemistry A.2.1.18 period of extended operation.

Inspection of Internal Surfaces Enhance the program to include visual inspection of internal coatings/linings for loss of coating integrity. Within 10 years prior to the

82. in Miscellaneous Piping and A.2.1.25 period of extended operation.

Ducting Components Enhance the ASR AMP to install extensometers in all Tier 3 areas of two dimensional reinforced structures to monitor expansion due to alkali-silica reaction in the out-of-plane Alkali-Silica Reaction direction.

83. A.2.l.31A December 31,2016.

Monitoring Monitoring expansion in the out-of-plane direction will commence upon installation of the extensometers and continue on a six month frequency through the period of extended operation.

Evaluate the acceptability of inaccessible areas for structures ASME Section XI, Subsection Prior to the period of extended

84. within the scope of ASME Section XI, Subsection IWL A.2.1.28 IWL operation.

Program.

Enhance the program to perform additional tests and inspections on the Fire Water Storage Tanks as specified in

85. Section 9.2.7 ofNFPA 25 (2011 Edition) in the event that it Prior to the period of extended Fire Water System A.2.1.16 is required by Section 9.2.6.4, which states "Steel tanks operation.

exhibiting signs of interior pitting, corrosion, or failure of coating shall be tested in accordance with 9.2.7."

86. Enhance the program to include disassembly, inspection, and Prior to the period of extended Fire Water System A.2.1.16 cleaning of the mainline strainers every 5 years. operation.

Increase the frequency of the Open Head Spray Nozzle Air

87. Prior to the period of extended Fire Water System Flow Test from every 3 years to every refueling outage to be A.2.1.16 operation.

consistent with LR-ISG-2012-02, AMP XI.M27, Table 4a.

>

U.S. Nuclear Regulatory Commission SBK-L-16186/Enclosure 2/Page 16 Enhance the program to include verification that a) the drain holes associated with the transformer deluge system are draining to ensure complete drainage of the system after each

88. test, b) the deluge system drains and associated piping are Within five years prior to the Fire Water System A.2.1.16 configured to completely drain the piping, and c) normally- period of extended operation.

dry piping that could have been wetted by inadvertent system actuations or those that occur after a fire are restored to a dry state as part of the suppression system restoration.

Incorporate Coating Service Level III requirements into the RCP Motor Refurbishment Specification for the internal Inspection oflnternal Surfaces painting of the motor upper bearing coolers and motor air Prior to the period of extended

89. in Miscellaneous Piping and A.2.1.25 coolers. All four RCP motors will be refurbished and operation.

Ducting Components replaced using the Coating Service Level III requirements prior to entering the period of extended operation.

Implement the PWR Vessel Internals Program. The program will be implemented in accordance with MRP-227-A Prior to the period of extended PWR Vessel Internals (Pressurized Water Reactor Internals Inspection and A.2.1.7

90. operation Evaluation Guidelines) and NEI 03-08 (Guideline for the Management of Materials Issues).

U.S. Nuclear Regulatory Commission SBK-L-16186/Enclosure 2/Page 17 Implement the Building Deformation Monitoring Program Enhance Structures Monitoring Program to require structural evaluations be performed on buildings and components affected by deformation as necessary to ensure that the structural function is maintained. Evaluations of structures will validate structural performance against the design basis, and may use results from the large-scale test programs, as appropriate. Evaluations for structural deformation will also consider the impact to functionality of affected systems and Building Deformation components (e.g., conduit expansion joints). NextEra will 91 A.2.l.31B March 15, 2020 Monitoring evaluate the specific circumstances against the design basis of the affected system or component.

Enhance the Building Deformation AMP to include additional parameters to be monitored based on the results of the CEB Root Cause, Structural Evaluation and walk downs.

Additional parameters monitored will include: alignment of ducting, conduit, and piping; seal integrity; laser target measurements; key seismic gap measurements; and additional instrumentation.

v t e Letter Sequence Response to RAI
CAC:ME4028, (Approved, Closed)
Initiation Request, Request, Request Acceptance... Supplement Administration Withholding Request Acceptance Meeting Questions 14 November 2016 30 November 2016 7 March 2017 1 March 2017 16 March 2017 29 March 2017 24 May 2017 24 May 2017 Answers 23 November 2016 25 May 2017 20 June 2017 20 June 2017 Results Approval, Approval, Approval, Approval, Approval Other: ML16230A182, ML16277A549, ML16333A247, ML17262A374, ML19205A390
MONTHYEAR2017-03-01 [Table View]

SBK-L-16186, Supplement 50, Response to Request for Additional Information for the Review of License Renewal Application Providing Changes to Buried and Underground Piping and Tank Recommendations

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SBK-L-16186, Supplement 50, Response to Request for Additional Information for the Review of License Renewal Application Providing Changes to Buried and Underground Piping and Tank Recommendations

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