NL-25-0421, Subsequent License Renewal Application Response to Request for Additional Information and Request for Confirmation of Information, Set 1

Subsequent License Renewal Application Response to Request for Additional Information and Request for Confirmation of Information, Set 1

ML25356A534
Person / Time
Site:	Hatch
Issue date:	12/22/2025
From:	Southern Nuclear Operating Co
To:	Office of Nuclear Reactor Regulation
Shared Package
ML25356A532	List: ML25356A533 NL-25-0421, Subsequent License Renewal Application Response to Request for Additional Information and Request for Confirmation of Information, Set 1
References
NL-25-0421, RAI B.2.3.27-1
Download: ML25356A534 (0)

Text

Edwin I. Hatch Nuclear Plant Unit 1 and 2 Subsequent License Renewal Application Response to Request for Additional Information and Request for Confirmation of Information, Set 1 to NL-25-0421 Response to RAI B.2.3.27-1 to NL-25-0421 Response to RAI B.2.3.27-1 E1-1 RAI B.2.3.27-1 Regulatory Basis:

10 CFR 54.21(a)(3) requires an 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.

One of the findings that the staff must make to issue a renewed license (10 CFR 54.29(a)) is that actions have been identified and have been or will be taken with respect to managing the effects of aging during the period of extended operation on the functionality of structures and components that have been identified to require review under 10 CFR 54.21, such that there is reasonable assurance that the activities authorized by the renewed license will continue to be conducted in accordance with the current licensing basis. In order to complete its review and enable making a finding under 10 CFR 54.29(a), the staff requires additional information in regard to the matters described below.

Background:

GALL-SLR Report AMP XI.M41, Buried and Underground Piping and Tanks, Table XI.M41-1, Preventive Actions for Buried and Underground Piping and Tanks, recommends that cathodic protection is provided for buried carbon steel piping; however, it does not recommend that cathodic protection is provided for buried stainless steel piping. In addition, GALL-SLR Report AMP XI.M41 states the following:

[f]ailure to provide cathodic protection in accordance with Table XI.M41-1 may be acceptable if justified in the SLRA. The justification addresses soil sample locations, soil sample results, the methodology and results of how the overall soil corrosivity was determined, pipe to soil potential measurements and other relevant parameters. If cathodic protection is not provided for any reason, the applicant reviews the most recent 10 years of plant-specific operating experience (OE) to determine if degraded conditions that would not have met the acceptance criteria of this AMP have occurred. This search includes components that are not in-scope for license renewal if, when compared to in-scope piping, they are similar materials and coating systems and are buried in a similar soil environment. The results of this expanded plant-specific OE search are included in the SLRA.

[a]dditional inspections, beyond those in Table XI.M41-2 [Inspection of Buried and Underground Piping and Tanks] may be appropriate if exceptions are taken to program element 2, preventive actions, or in response to plant-specific OE.

SLRA Section B.2.3.27, Buried and Underground Piping and Tanks, states the following:

Exception 1[:][c]athodic protection is not installed at HNP [Hatch Nuclear Plant] as recommended in NUREG-2191, Table XI.M41-1.

HNP is proactively replacing portions of buried carbon steel piping with stainless steel as part of corrective actions driven by the existing program.

[the Buried and Underground Piping and Tanks program is] continuing to evaluate installation of cathodic protection in targeted locations and installation of targeted cathodic protection in additional locations if determined it would significantly improve plant safety.

[HNP will] install cathodic protection on the diesel fuel oil storage tanks prior to the SPEO

[subsequent period of extended operation].

to NL-25-0421 Response to RAI B.2.3.27-1 E1-2 The plant specific OE discussion in SLRA Section B.2.3.27 notes external corrosion and leaks in buried piping due to coatings failure. In addition, in relation to previous inspections and OE for buried carbon steel plant service water piping, SLRA Section B.2.3.27 notes several unsatisfactory results due to both internal and external degradation.

During its audit, the staff reviewed a report which noted that (a) site testing suggests that implementing targeted cathodic protection at HNP may be feasible but presents challenges and more testing is needed to fully evaluate the practicality of cathodic protection; (b) installing semi-deep anode groundbeds is potentially feasible at the site; and (c) buried piping systems at HNP are experiencing varying degrees of corrosion, with particular concern for those systems composed of carbon steel.

Issue:

1. The staff seeks additional information with respect to (a) how much in-scope buried carbon steel piping has been replaced with stainless steel piping to date; (b) why the SLRA does not include commitments to replace in-scope buried carbon steel piping with stainless steel piping since the site is proactively doing piping replacements; and (c) the amount of in-scope carbon steel piping that would be remaining during the SPEO once these replacements have occurred. This information is relevant to the staffs review of Exception No. 1 since cathodic protection is a recommended preventive action for carbon steel but not for stainless steel.

2. The staff seeks additional information with respect to why installation of cathodic protection is limited to the diesel fuel oil storage tanks and does not include any in-scope buried carbon steel piping. Based on the staffs observations noted in the Background section above, it appears that providing cathodic protection for in-scope carbon steel piping is potentially feasible.

3. Based on plant-specific OE and other observations noted in the Background section above (related to the condition of external coatings and ongoing external corrosion), the staff seeks additional information with respect to why cathodic protection will not be provided for in-scope carbon steel piping during the SPEO. It appears that external coatings cannot be relied upon as the sole barrier to prevent external corrosion moving into the SPEO.

Request:

1. Provide additional information with respect to (a) how much in-scope buried carbon steel piping has been replaced with stainless steel piping to date; (b) why the SLRA does not include commitments to replace in-scope buried carbon steel piping with stainless steel piping since the site is proactively doing piping replacements; and (c) the amount of in-scope carbon steel piping that would be remaining during the SPEO once these replacements have occurred.

2. Provide additional information with respect to why installation of cathodic protection is limited to the diesel fuel oil storage tanks and does not include any in-scope buried carbon steel piping.

3. Provide additional information with respect to why external coatings can be relied upon as the sole preventive action for in-scope buried carbon steel piping during the SPEO.

Response to B.2.3.27-1 Request 1:

NRC staff has requested information regarding the amount of in-scope buried carbon steel piping that has been replaced with stainless steel to date, why a commitment was not made in the SLRA to perform future replacements of in-scope carbon steel piping, and the amount of in-scope carbon steel piping that would remain during the SPEO. The proactive replacement of buried piping is not part of the aging management strategy for HNP. The proposed Buried and Underground Piping and Tanks AMP provides reasonable assurance of continued safe operation during the SPEO. Approximately 1000 linear feet of in-scope carbon steel buried piping has been replaced with stainless steel.

to NL-25-0421 Response to RAI B.2.3.27-1 E1-3 The proactive replacement of in-scope buried carbon steel piping is not driven by the existing Buried Piping and Tanks Program and it wasnt the intent of the SLRA to incorporate these actions as part of the program enhancements for the SPEO. However, future replacements would consider the use of stainless steel and would impact future aging management consideration for the Buried and Underground Piping and Tanks AMP. The future replacement of in-scope carbon steel piping was not intended to be part of the Buried and Underground Piping and Tanks Program.

In response to this request, the HNP SLRA will be supplemented to remove any ambiguity around the proactive replacement of carbon steel in-scope buried piping with stainless steel as part of this AMP.

Response to B.2.3.27-1 Request 2:

The NRC staff requested information with respect to why installation of cathodic protection is limited to the diesel fuel oil storage tanks and does not include any in-scope buried carbon steel piping.

The proposed Buried and Underground Piping and Tanks AMP manages in-scope buried piping to provide reasonable assurance of safe operation throughout the SPEO. The installation of cathodic protection (CP) for the HNP site is discussed below. The discussion below includes the major considerations for practicality of a CP system and directly addresses site-specific considerations.

Based on the information below, HNP determined that the installation and operation of a CP system for the buried piping at HNP would be impractical. However, for the relatively small and isolated area of the diesel fuel oil storage tanks (DFOSTs), a CP system could be installed and operated, providing a benefit given that the area is segregated from the congested linear piping runs which would limit the impact to buried discontinuous steel and other materials such as stainless steel piping.

HNP has determined that installation of CP at locations other than the DFOSTs is impractical because the adverse effects of installation and operation of CP outweigh the potential benefits that may be provided. These effects exist for installation of CP on the DFOSTs, however, mitigation of these effects is more practical due to the relatively small footprint and segregated area of the targeted components. In addition, HNP has determined that based on the operating experience and past soil testing history, the future soil testing activities and inspection plan will be sufficient to provide reasonable assurance that the in-scope buried piping systems can perform their intended functions throughout the SPEO.

To determine the impacts of installation of a CP system at HNP, continuity and stray current; shielding and congested piping; and bare steel current draw were evaluated. These evaluations are summarized below followed by an evaluation of the different types of CP systems that were considered.

Potential Cathodic Protection Issues A. Continuity and Stray Current When considering a new CP system for HNP which was not designed with CP to be practical, it is critical to understand the piping configuration and the extent to which the piping is electrically bonded or continuous. HNP performed testing to determine if buried piping is electrically continuous, however the results were inconclusive. Additional testing, or possibly excavation and inspection, is required to determine if buried piping is electrically continuous. This effort would be necessary to understand the extent of modification required to prevent accelerated corrosion due to stray current.

Stray current corrosion potentially impacts CP system installations, particularly for plants which were to NL-25-0421 Response to RAI B.2.3.27-1 E1-4 not originally designed for CP systems. A review of the potential for stray current at HNP follows. For grounded systems, current that is picked up by other buried metallic structures is merely current that is wasted and not available to protect the intended buried piping. For isolated metallic structures, such as foreign pipelines, ductile iron piping systems, and nearby facilities or structures, stray current is a significant concern. Stray current problems occur when current is picked up on an isolated structure and later discharges off that structure and back to a grounded structure. At the location where stray currents discharge, rapid corrosion may be inadvertently induced on the isolated structure.

The following table contains piping systems that would be potentially susceptible to stray current at HNP:

HNP Piping Systems Potentially Susceptible to Stray Current System Material Notes Fire Protection Gray Cast Iron or Ductile Iron Mechanical connections are not bonded, making piping segments electrically discontinuous and therefore susceptible to stray current corrosion. Fire protection piping loops around the entire site.

Storm Drain Corrugated Metal Pipe (CMP)

CMP drains are typically made of uncoated galvanized steel and typically not bonded to process piping. The storm drain piping is routed throughout the site making piping both potentially susceptible to stray current and a current draw for CP current.

Hydrogen Steel May be grounded but not to the same ground as in-scope piping making it susceptible to stray current corrosion.

Oxygen Steel May be grounded but not to the same ground as in-scope piping making it susceptible to stray current corrosion.

Sanitary Water Steel Unknown grounding Service Air /

Instrument Air Stainless Steel Socket Welded More extensive continuity testing would determine if other buried piping systems that are out of scope are electrically continuous. However, fire protection piping is not electrically continuous and other buried piping systems, whether in-scope or out of scope, are more likely than not electrically discontinuous. Therefore, the piping systems listed in the table above, like fire protection piping, would be exposed to the effects of stray currents.

B. Shielding and Congested Piping Another factor of concern for providing CP is shielding, or preventing current distribution from reaching the target buried structures due to underground structures that include buildings, congested piping configuration, pilings, duct banks and cement conduits. In the below sketch the in-scope buried piping and the congestion of this piping is shown, but the below sketch does not show all buried assets throughout the site (e.g. ground cables, subsurface utilities, etc.)

to NL-25-0421 Response to RAI B.2.3.27-1 E1-5 HNP In-Scope Buried Piping to NL-25-0421 Response to RAI B.2.3.27-1 E1-6 Shielding may be addressed by increasing the number of anodes and placement of anodes in close proximity to the piping, which could lead to the over protection of piping closest to the anodes. It would be impractical to install a large number (potentially up to 1000 for long runs of piping) of low output anodes (i.e., sacrificial anodes) that would be needed to overcome all the effects of shielding. As shown on the above sketch, the complexity of station piping and structures makes it virtually impossible to determine the exact current distribution. The above sketch provides an example of the issues for the sites buried piping. It shows the congested nature of the in-scope Unit 1 and Unit 2 service water pipe runs, which makes engineering a solution difficult. At times, the electrically discontinuous fire protection piping runs parallel and perpendicular. Not shown are abandoned pipe runs and other buried piping systems, such as sanitary water, instrument and service air.

One known complication involved with installing cathodic protection at HNP is the abandoned buried carbon steel piping. When HNP replaces buried steel piping, it abandons the old piping in place and routes new piping, in parallel, where design allows, with existing pipe. The abandoned piping could prevent the CP current from reaching its intended target piping by shielding or bare steel current draw.

C. Bare steel current draw A related concern to the shielding effect for HNP, which was not designed for CP systems, is the current draw of buried bare steel or copper piping and structures. This affects the ability for anodes to supply required CP at the recommended effectiveness levels (-850mV) to the targeted piping.

These structures include the copper ground grid and other local grounds like security fences, reinforced concrete, and uncoated piping such as storm drains, uncoated stainless steel pipe replacement, and other bare steel.

Cathodic Protection System Types Based on the considerations above, the following CP systems were evaluated:

A. Deep bed (site wide)

A deep bed system would either use a single large anode or a few anodes surrounding the site installed deep into the ground relatively far away from the buried pipe systems. This type of system would have a minimal footprint but would be impacted by shielding and stray current that would be a concern at the HNP site, as described in the previous sections.

B. Remote bed A remote bed system contains various buried anodes relatively far away from the buried pipe systems but installed at a more shallow depth than the deep bed system.

The specific issue with HNP implementing a deep bed anode design or a remote shallow bed is the arrangement of the plant piping. In the area of interest between the plant and the river, the congested piping in this area includes residual heat removal service water (RHRSW), plant service water (PSW),

DFOST piping, and other buried commodities. Some of this piping has been replaced with stainless steel. To the east of the turbine building, there is high pressure coolant injection, reactor core isolation cooling, and standby gas treatment. Fire protection is also routed all around the site and is routed sometimes parallel and sometimes perpendicular to the other piping systems. Lines are nested in some locations, with many lines in close proximity and some routed perpendicular to each other.

There are other barriers such as buildings, duct banks, and paved areas making it very difficult to locate the distributed anode. Given the shielding effect of these structures and configured piping, to NL-25-0421 Response to RAI B.2.3.27-1 E1-7 cathodic currents would be prevented from reaching sections of targeted piping. Stray current would also impact systems and structures which are not connected to the CP system.

C. Distributed bed A distributed bed system contains various buried anodes as close as fifteen feet to the buried pipe systems. For distributed beds, anodes are installed by a drilling process. This increases the risk of accidental damage to piping, wire, conduits, or other plant SSCs, and it would be incredibly difficult to repair. Distributed bed CP designs require a large number of anodes, which results in numerous drilled locations, and trenching to connect all of the anodes.

Protecting the entire site with a distributed anode bed system would be impractical due to the large number of anodes and related trenching and excavations required. Stray current would need to be evaluated for its effect on existing plant structures. As noted above, piping systems at HNP are in very close proximity to each other, which would make separating out a small scope of targeted piping problematic and impractical. The challenges with this design at HNP include properly locating anodes, shielding, and stray current corrosion. Stray current corrosion would adversely affect metals in the ground which are not bonded to the proposed CP system, including piping and structures. Stray current corrosion is a phenomenon in which non-bonded metal within the influence of the anodes becomes anodic itself and corrodes at a faster rate than it otherwise would. Fire protection piping, as well as any piping or metallic structures not bonded to the proposed CP system, would be negatively affected by stray current corrosion. The fire protection piping cannot be bonded to the CP system because it is not electrically continuous.

D. Linear anode A shallow bed system is installed linearly along each buried pipe. The voltage associated with this system is such that shielding and stray current effects are mostly eliminated. However, each pipe must be fully excavated so that the system can be installed. Installation of a linear anode requires excavating the entire length of the target piping and laying the anode bed next to the pipe. This is impractical for the entire site and for individual runs due to the large scale and congested nature of the buried in-scope piping.

Summary Ensuring safe plant operation while also protecting members of the public throughout the SPEO is the ultimate goal of HNP. Ensuring integrity of the emergency DFOSTs is paramount to meeting that goal because of the importance of the emergency diesel generator system. HNP currently performs ultrasonic thickness measurements of these tanks and current projections are that the tanks will continue to perform their intended functions throughout the SPEO.

HNP has determined that installation of CP at locations other than the DFOSTs is impractical because the adverse effects of installation and operation of CP outweigh the potential benefits that may be provided. These effects exist for installation of CP on the DFOSTs, however, mitigation of these effects is more practical due to the relatively small footprint and segregated area of the targeted components. In addition, HNP has determined that based on the operating experience and past soil testing history, the future soil testing activities, as described in Section B.2.3.27 of the HNP SLRA, and inspection plan will be sufficient to provide reasonable assurance that the in-scope buried piping systems can perform their intended functions throughout the SPEO. In addition, the HNP SLRA states that the site will continue to evaluate the installation of CP in targeted areas and may install CP if determined it would significantly improve plant safety. Future evaluations could include, but are not to NL-25-0421 Response to RAI B.2.3.27-1 E1-8 limited to, continuity testing, pipe-to-soil potential testing and soil testing.

For in-scope buried piping systems, HNP has determined that along with continued soil sampling, using excavation activities to perform inspections to gather information on the condition of buried piping provides reasonable assurance that the buried piping systems can perform their intended functions throughout the SPEO. These soil tests contribute to inspection location selection through on going corrosivity trending.

In conclusion, it is impractical to install CP at HNP for in-scope buried piping. However, HNP will install CP on the buried DFOSTs. The tanks are uncoated. In addition, considerations during design of the system will include preventing impact to nearby piping systems. An anode design could reduce impact of stray current on nearby piping systems. HNP has not selected and is not committing to a specific CP system design.

Response to B.2.3.27-1 Request 3:

The NRC staff requested information with respect to why cathodic protection will not be provided for in-scope carbon steel piping during the SPEO.

External coatings and backfill can be relied upon as a preventive action for in-scope buried carbon steel piping during the SPEO due to HNPs robust coating system and use of backfill in accordance with the standards described in NUREG-2191. The HNP corrective action program and the extensive inspection activities described in the HNP SLRA are also relied upon to trend and take appropriate action when necessary for early detection and correction of aging effects.

With respect to backfill, in-scope carbon steel piping located inside the protected area (PA) has class 1 backfill. Class 1 fill includes only clean, non-organic soils taken from approved borrow areas.

Materials containing brush, roots, sod, or other perishable materials are not suitable. All fill material shall be placed at a moisture content within +/- 3% of the optimum moisture content. The required compaction density shall be 95% Modified Proctor Maximum Dry Density (ASTM D 1557). Field (in-place) test of Class 1 compacted earth backfill shall be conducted utilizing either ASTM D 2937 or ASTM D 1556. Additionally, testing is performed for roller compacted and hand compacted fill, at 1 test/1 ft. depth per 50 ft. of pipe and 1 test/1 ft. depth per 25 ft. of pipe, respectively.

Class 1 backfill satisfies the following criteria:

i. The maximum density of the soil as determined by the designated Proctor test shall not be less than 100 pounds per cubic foot (dry density).

ii. The Plasticity Index of the soil shall not be higher than 25.

iii. The maximum particle size in place shall not be greater than 2 inches.

The in-scope carbon steel piping external coatings are in accordance with AWWA-C203-66, coal tar enamel coating, which has been shown to be a robust coating system at HNP with minimal OE on external degradation. As presented in the SLRA, all minor defects to the coating system were isolated to the immediate area and were attributed to improper backfill or excavation activity. This led to one (1) instance of a through wall leak of the RHRSW line that did not prevent the system from performing its intended function. To minimize the possibility for recurrence, after inspection and prior to placing backfill, holiday testing is performed by Quality Control (QC) to ensure the integrity of the AWWA-C203-66, 50-mil coal tar wrap.

The buried in-scope ductile and gray cast iron piping has asphaltic coated exterior in accordance with to NL-25-0421 Response to RAI B.2.3.27-1 E1-9 ANSI/AWWA C151/A21.51 and cement mortar lined interior in accordance with ANSI/AWWA C104/A21.4. The asphaltic coating is applied per the specifications prior to purchase and installation of the ductile and gray cast iron piping. Per manufacturer specifications, this asphaltic coating is at a minimum of 1 mil in thickness.

A conservative number of inspections prescribed compared to NUREG-2191 recommendations will provide reasonable assurance that the buried piping at HNP will maintain its intended function. As mentioned previously, it is impractical to install CP on the piping systems at HNP due to piping systems not being electrically continuous and effects from stray current corrosion, shielding from congested piping runs and other SSCs, and bare steel current draw. An analysis was conducted in accordance with the preventive actions program element of the Buried Piping and Tanks AMP, including soil analysis and an expanded OE review. Based on these, HNP meets the criteria for Category E based on impracticality. However, due to OE history, additional inspections would be prudent and warranted. As such, the number of inspections for Category E, three inspections, was doubled to six inspections before multiplying by 1.5 for a two-unit site. Then two inspections were added in accordance with XI.M41 Element 4 e.i, for a total of 11 inspections.

HNP has re-reviewed the operating experience associated with the buried piping systems and has determined that in no cases was there a loss of system intended function due to aging of the external surface of in-scope buried pipe. In all cases, the degradation was within the systems ability to perform its intended function and the degradation was repaired or was evaluated and determined to be acceptable with continued monitoring. This review provides confidence that the existing coatings and backfill along with the inspection strategy are sufficient to provide reasonable assurance that the buried piping systems will continue to be able to perform their intended functions throughout the SPEO.

Soil Testing and Operating Experience HNP SLRA B.2.3.27, Justification for Exception 1 contains details on recent soil analysis results, including steps being taken to periodically monitor soil corrosivity and perform soil analysis on a 5-year frequency to trend soil in the vicinity of in-scope piping which will inform future inspection priority.

Historical and recent soil analysis results have shown that the soil at HNP is generally mild to moderately corrosive, which correlates to <10 points using the soil corrosivity index guidance in Electric Power Research Institute Report 3002005294, Soil Sampling and Testing Methods to Evaluate the Corrosivity of the Environment for Buried Piping and Tanks at Nuclear Power Plants, Table 9-4, Soil Corrosivity Index from BPWORKS as referenced in NUREG-2191 which has been considered an acceptable method for determining if soil is not corrosive. Specifically, 51 samples were taken during the 2010, 2012, and 2023 soil tests. The following paragraph contains the detailed results for carbon steel, mild steel, and ductile iron.

Carbon steel, mild steel, and ductile iron - 46 samples were < 10 pts, or mildly corrosive, 5 samples were > 10, but < 15pts, or moderately corrosive. In the plant stack area, 2 of these 5 samples were in the same location at different depths (2ft and 5ft) and in the same general area as a third sample. In the area near the fuel oil storage tanks, 1 sample was near the area with the buried Diesel Fuel Oil Storage Tanks and the other sample was between the above ground Fire Diesel Fuel Oil Storage Tanks.

In 2024, 13 samples were taken for SLR in-scope buried piping targeted samples at depths > 5 Carbon steel, mild steel, ductile iron - all 13 samples were < 10 pts, or mildly corrosive.

to NL-25-0421 Response to RAI B.2.3.27-1 E1-10 The soil at HNP will continue to be sampled during each inspection activity leading up to and through the SPEO. Additionally, evaluation will be performed at least every five years during the SPEO. The soil results will help inform selection of future inspection locations. During any inspection activity where damage to the coating has been evaluated as being significant by, (1) an individual who has a NACE Coating Inspector Program Level 2 or 3 inspector qualification; (2) an individual who has completed the EPRI Comprehensive Coatings Course and completed the EPRI Buried Pipe Condition Assessment and Repair Training Computer Based Training Course; or (3) a coatings specialist qualified in accordance with an ASTM standard endorsed in RG 1.54, Revision 2, Service Level I, II, and III Protective Coatings Applied to Nuclear Power Plants., and the damage was caused by nonconforming backfill, an extent of condition evaluation is conducted to determine the extent of degraded backfill in the vicinity of the observed damage.

When coatings, backfill, or condition of exposed piping does not meet the acceptance criteria, the degraded condition is repaired or affected component is replaced. In addition, when 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 is extrapolated to the end of the SPEO, an expansion of sample size is conducted. The number of inspections within the affected piping categories is doubled or increased by five, whichever is smaller. If acceptance criteria are not met in any of the expanded samples, an analysis is conducted to determine the extent of condition and extent of cause.

HNP has reviewed over 10 years of plant-specific operating experience and found no evidence of significant external corrosion or leaks in buried carbon steel piping or tanks that have led to a loss of system intended function. Within that 10-year search, Unit 1 division 1 RHRSW buried pipe developed a through wall leak due to external corrosion. Through examination and the extent of condition review performed, the cause was determined to be improper backfill in the immediate vicinity of the piping.

Other inspection results have shown some coatings degradation or pipe wall thinning, but none that indicate long term aging is occurring that would lead to a system not being able to perform its intended function throughout the SPEO.

For the Plant Specific Operating Experience section of the SLRA (Pages B.2.137 and B.2.138) the following information is provided to further explain the OE:

In 2014, the external pitting that was identified on the 30-inch radwaste discharge pipe was documented as due to coatings failure. This defect was limited to the top side of the pipe which indicates that the coatings damage was likely due to construction and not due to aging. Weld build-up was added to the pipe at the location of the pits. A second excavation was performed where additional pitting was identified, however, the measured pipe wall was within minimum wall thickness acceptance. The identified pitting was repaired. This system is not in-scope of SLR. The area that was excavated was outside the Protected Area and has a Class 2 backfill specification that is different than the Class 2 backfill for piping that is inside the Protected Area. The Class 2 compaction requirement of 95% Standard Proctor Maximum Dry Density (ASTM D 698) applies for locations outside the Protected Area. Field (in-place) test of Class 2 compacted earth backfill was conducted at the following frequencies utilizing either ASTM D 2937 or ASTM D 1556 for roller compacted and hand compacted fill, at 1 test/1 ft. depth per 100 ft. of pipe and 1 test/1 ft. depth per 50 ft. of pipe, respectively.

Excavation requirements are different when comparing activities performed inside and those performed outside the PA which are less rigorous. Excavation activities performed within the PA are guided under a different process than those performed outside the PA. For example, hand digging, or hydro excavation, is the only approved method for excavation inside the PA with less restrictive requirements for digging outside the PA. Of the 7 identified coating defects to NL-25-0421 Response to RAI B.2.3.27-1 E1-11 from this OE, 5 of those were attributed to excavation activities, and the 2 other coating defects were attributed to improper backfill. Consequently, there is a potential that the less restrictive excavation process requirements contributed to the coating defects outside the PA.

As stated previously, a second excavation was performed as part of an extent of condition, and the external pitting initially identified was determined to be isolated to the immediate area of discovery. This is an example of the effectiveness of the Hatch corrective action program, which ensures that any indication of improper backfill is documented and inspection scope expanded to bound the condition and correct the issue. In addition, the extensive number of inspection activities planned prior to and throughout SPEO will provide reasonable assurance that any adverse condition is identified and corrected.

In 2019, a condition report was written to identify the area concerned with fire protection system piping leaks. These leaks were due to pressure perturbations which led to an overpressure event. These leaks were not age related and did not identify external corrosion as a cause. Prior to 2022, there were no fire protection system leaks linked to age related degradation. As discussed in SLRA Section B.2.3.21, the first instance of graphitic corrosion to the outside diameter of the fire protection piping was identified in 2022. Fire protection is in-scope for SLR, however, it is gray cast iron and ductile iron material with an asphaltic coated exterior in accordance with ANSI/AWWA C151/A21.51 and cement mortar lined interior in accordance with ANSI/AWWA C104/A21.4. This is different from the coating system on the in-scope carbon steel piping.

In 2019, a corrective action report was generated to address leaks in the carbon steel piping in the vicinity of the Unit 1 and Unit 2 Condensate Storage Tanks (CSTs). The leaks between 2007 and 2019 were attributed to external degradation of the carbon steel to concrete interface. The pipe that is surrounded by concrete is coated in accordance with a different specification than that for pipe exposed to soil. This conclusion was based on a review of site OE from 2007 to 2019.

According to a plant drawing for service water & condensate piping outside the buildings, the note for coating requirements of AWWA-C203-66, coal tar enamel, is only for buried piping.

An apparent cause determination report from 2013 states that inspections of coatings and seals at the pipe-to-concrete interface are not included in the Buried Pipe program scope because these areas are not considered buried. This is consistent with other corrective action program products (e.g. Technical Evaluations and Condition Reports) from this review.

Inspections for all carbon steel pipe-to-concrete interfaces in the Unit 1 and Unit 2 CST/Condensate pump enclosures were completed in July 2013. Consistent with site drawings, there was no evidence of coating applied to piping that was not in contact with soil, with the exception of one location that had a liquid coating applied. Inconsistent with site drawings, no penetration seal was in place at the pipe-to-concrete interface. Corrective action was taken to place a penetration seal per site drawings at the locations with pipe-to-concrete interface.

Most of the CST system piping is not in-scope of SLR, with the exception of high pressure coolant injection and reactor core isolation cooling buried stainless steel piping. As of 2025, the piping associated with Unit 1 CST has all been replaced with coated 304 stainless steel, and Unit 2 piping is planned to be replaced with coated 304 stainless steel by 2027.

As part of a 2022 report, a review was performed of approximately 115 inspections from 2008 to NL-25-0421 Response to RAI B.2.3.27-1 E1-12 to 2021 on systems within the scope of the applicable guidance at the time, NEI 09-14. Of the systems within the scope of SLR, RHRSW and PSW were the only systems with adverse inspection results. Due to these results, RHRSW and PSW will be prioritized for inspection.

Other conclusions of this review were that localized corrosion (pitting) was affecting buried piping to an unknown extent. This was in part due to the following: initial inspection locations that were reviewed under this report were not required to be recorded, therefore, the degradation rate could not be determined on specific piping segments. Based on this feedback, the site has adjusted inspection timelines and practices and applied techniques to better determine degradation rates which will help more accurately predict life expectancy of the piping. Future SLR inspections are prioritized based on risk ranking of each location (high risk items scheduled earlier), locations for which longer time periods have elapsed since previous inspection and locations which have an unknown or uncertain degradation rate. For example, in 2022 inspections were conducted on Unit 1 CST carbon steel piping and Unit 1 &

2 PSW and RHRSW carbon steel piping. Approximately 6-10 axial feet of was exposed per inspection, and coating was removed for approximately 3-6 axial feet of piping for the inspections. The 6 lines ran east/west, and all other lines ran north/south directions. All lines, except for the stainless steel reactor core isolation cooling suction line, had varying levels of wall loss identified on the exposed piping inside the excavated area. For in-scope piping PSW and RHRSW, UT results showed an average reading of 0.310 and 0.450 and minimum of 0.262 and 0.358, for a nominal thickness of 0.365 and 0.500 respectively. Most of the wall loss is attributed to internal corrosion.

2022 Buried Asset Program Review A 2022 report mentioned above was a comprehensive review of the SNC program across the fleet against the guidance under NEI 09-14. A summary for HNP was provided of what the vendor knew from information that was able to be found at the time of the issuance of the report. Many recommended actions were to locate missing inspection information from known inspection work order history.

The 2022 report described gaps in historical documentation on inspections and data from Guided Wave Testing (GWT) methodology which should not be relied upon in lieu of direct inspections. SNC performed a 10-year OE search which covered the same OE date range that was reviewed in this report. Work orders were completed to comply with the guidance at the time, which in this case was NEI 09-14. Defects were always reported as part of the Corrective Action Process, but acceptable conditions were not always documented, particularly for the condition of piping and coatings. The applicable condition reports were reviewed and provided as part of the SLR audit process.

Captured below are additional operating experience summaries that are relevant based on shared material, coating, and soil characteristics. These summaries are provided to demonstrate how the AMP performs inspections and evaluates results.

In 2014, QC observed partial tape coat defects on an 18 buried carbon steel off-gas pipe unearthed for ultrasonic testing (UT) inspection near the steam seal piping at the stack. The defects (two sections, each about 1 wide by 12 long) appeared to be caused by equipment during the unearthing process for inspection. After consulting with the buried pipe engineer, it was decided to proceed with backfilling. The justification was that the tape coat damage was minor and historical UT measurements of other underground piping in the area were in very good condition. The area was backfilled after engineering review, and the condition report was closed following proper notification and evaluation procedures.

to NL-25-0421 Response to RAI B.2.3.27-1 E1-13 In 2015, a work order was created as part of the Asset Management Plan to inspect and assess the condition of buried condensate transfer piping near the Unit 2 CST. The inspection was prompted by a 2011 tritium leak and the focus was to verify the anomaly indicated by previous GWT performed in 2013 in an adjacent excavation which detected significant wall loss (25-60%) in some pipe segments.

The 2015 scope included direct inspections and additional GWT/UT to verify pipe integrity and coating condition. Two excavations were performed to access the condensate transfer to residual heat removal and condensate transfer to fuel pool cooling piping. The results yielded minor pitting with the lowest measured wall thickness of 0.183 and 0.167, respectively. Fitness-For-Service calculations were performed to find remaining life and next scheduled inspection.

QC performed as-found coating inspections per plant process. The majority of the tape coating was in good condition, with no major damage or disbonding. All piping surfaces except the bottom-dead center (which had crusted mud) were found acceptable. The QC-measured pit depths on both residual heat removal and fuel pool cooling pipes were above required minimum wall values. No other conditions were noted on other piping segments. The condensate transfer piping is not in-scope of SLR.

In 2022, during UT inspections of Unit 2 RHRSW Division 1 piping, a single localized point was found to be below the previously calculated minimum pipe wall thickness. The affected pipe is an 18-inch diameter, seamless SA106 Grade B carbon steel pipe, with a nominal wall thickness of 0.500 inches.

The thinnest measured location of 0.249 inches was found during a full circumference grid inspection where the remainder of the piping inspection points were above the allowable minimum wall thickness.

An engineering evaluation was conducted and determined that, despite the localized thinning, the pipe maintained its structural integrity and continued to perform its intended design function. However, the remaining margin between actual and allowable wall thickness was considered insufficient for long-term operation, necessitating a repair. Prior to the performance of the UT, the coatings engineer performed a coating condition assessment per plant process, noting loose areas and nicks through tape coating. No additional condition report was required.

The chosen corrective action was to apply a weld overlay at the area of localized thinning, following ASME BPV Code Case N-661-3, which is accepted by Regulatory Guide 1.147 for in-service inspection. The weld overlay is a temporary repair, intended to restore wall thickness and maintain code compliance until a permanent repair can be made. Permanent repair was completed in 2025.

Summary The conclusion taken from the OE review is that the coating systems provide adequate protection against the soil environment. The majority of inspections performed had satisfactory results, with no need for corrective actions. When degradation was identified, the piping was either evaluated as being sufficient with minor repairs or is tracked in the corrective action program so that follow on inspections would be performed.

References:

None Associated SLRA Revisions:

The SLRA revisions include changes associated with this RAI response and changes resulting from feedback received during the in-office audit. These audit questions include 14-3, 14-6, 14-8, 14-9, 14-11, and 14-13. Rather than submitting a separate supplement, the SLRA revisions included in the to NL-25-0421 Response to RAI B.2.3.27-1 E1-14 following pages represent all intended changes to the SLRA associated with the TRP-14 Buried and Underground Piping and Tanks AMP.

SLRA Table 3.3.2-8 is revised to include the stainless steel buried pipe in the fire protection system exposed to soil.

SLRA Section A.2.2.27 on page A.2-16 is revised to include that annual cathodic protection surveys are conducted for the emergency diesel fuel oil storage tanks and the associated acceptance criteria.

This section is also clarified that the residual heat removal system piping in scope of the AMP is associated with the residual heat removal service water system.

SLRA Table A-3 on pages A.4-23 through A.4-27 is revised to include the following changes:

Revise enhancement e to remove copper alloy.

Revise enhancement i to include that potential difference and current measurements are trended to identify changes in effectiveness of any installed cathodic protection system and/or coatings.

Revise enhancement k, items 4 and 5 to change 10-year period to 10-year interval. Also changed in implementation schedule.

Revise enhancement k to include item number 7 to state that unacceptable cathodic protection survey results will be entered into the CAP.

Include enhancement m to state that in-scope copper alloy tubing used in the fire protection diesel fuel oil system between the A fire protection diesel fuel oil storage tank and the diesel fire pump will be replaced with 304 stainless steel tubing encased within a 4" stainless steel chase pipe.

SLRA Section B.2.3.27 on pages B.2-130 through B.2-139 is revised to include the following changes:

Clarify that the residual heat removal system piping in scope of the AMP is associated with the residual heat removal service water system.

Revise the Program Description to clarify that only in-scope copper alloy piping will be replaced with stainless steel piping.

Revise the site-specific inspection quantities and enhancements section to remove copper alloy buried piping. Also changed 10-year period to 10-year interval in several locations.

Remove the discussion related to reduced inspection quantities.

Revise Table B.2.3.27-1 to remove the copper alloy fire protection inspection priority line and include stainless steel fire protection inspection priority line.

Revise Table B.2.3.27-1 Note 1 to clarify the inspection priority rankings.

Residual heat removal was updated to residual heat removal service water in several locations, consistent with the revisions in Section A.2.2.27.

Revise exception 1 to apply to only carbon steel piping and clarity the justification for exception to state that cathodic protection is impractical.

Revise the justification for exception 1 to clarify how the site-specific inspection quantities for steel piping compare to NUREG-2191 recommendations.

Revise the justification for exception 2 to include the grade and length of the uncoated stainless steel plant service water piping.

to NL-25-0421 Response to RAI B.2.3.27-1 E1-15 Revise the enhancements section to include the preventive action to replace the in-scope copper alloy tubing used in the fire protection diesel fuel oil system between the A fire protection diesel fuel oil storage tank and the diesel fire pump with 304 stainless steel tubing within a 4" stainless steel chase pipe.

Revise the enhancements section to include the enhancements that were inadvertently omitted from the SLRA. Additionally, include the implementation action changes made in Table A-3 described above to their corresponding enhancements.

Add additional detail to several operating experience items, add clarification about when future replacements will be made, and add a new item to give more details about how the corrective action program is used at HNP.

Section 3 - Aging Management Review Results Hatch Nuclear Plant Page 3.3-167 Subsequent License Renewal Application Revision 0 Table 3.3.2-8: Fire Protection System - Summary of Aging Management Evaluation Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Program NUREG-2191 Item Table 1 Item Notes Piping and piping components Pressure boundary Stainless steel Soil (external)

Loss of material Buried and Underground Piping and Tanks (B.2.3.27)

VII.I.AP-137 3.3-1, 107 B

to NL-25-0421 Response to RAI B.2.3.27-1 E1-16

Appendix A - Final Safety Analysis Report Supplement Hatch Nuclear Plant Subsequent License Renewal Application Page A.2-16 Revision 0 A.2.2.27 Buried and Underground Piping and Tanks The Buried and Underground Piping and Tanks AMP, previously known as the Underground Pipe and Tanks Monitoring Program, is an existing condition monitoring program that manages the aging effects associated with the external surfaces of buried and underground piping and tanks such as loss of material and cracking. This AMP addresses piping and tanks composed of any metallic material that are within the scope of SLR in the emergency diesel generator (EDG), FP, high pressure coolant injection (HPCI), plant service water (PSW), reactor core isolation cooling (RCIC), residual heat removal service water (RHRSW), and standby gas treatment (SBGT) systems.

This AMP also manages aging through preventive and mitigative actions (i.e., inspections, coatings, backfill quality, and cathodic protection for the emergency diesel fuel oil storage tanks). The number of inspections for each 10-year inspection period, commencing 10 years prior to the SPEO, is based on the effectiveness of the preventive and mitigative actions above. Annual cathodic protection surveys are conducted for the emergency diesel fuel oil storage tanks. For these 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.

Visual inspections of external surfaces of buried components are performed to check for evidence of coating/wrapping damage, loss of material, and cracking. Internal inspections may be performed using a method capable of precisely determining pipe wall thickness. The method must be capable of detecting both general and pitting corrosion on the external surface of the piping and must be qualified to identify loss of material that does not meet the acceptance criteria. Ultrasonic examinations, in general, satisfy this criterion. The selection of locations of the inspections of buried components is based on plant OE, risk, soil conditions, and past inspection results; these inspections will occur once prior to the SPEO and at least every 10 years during the SPEO. Opportunistic examinations of nonleaking pipes may be credited toward examinations if the location selection criteria are met.

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 SPEO, an increase in the sample size is conducted. to NL-25-0421 Response to RAI B.2.3.27-1 E1-17

Appendix A - Final Safety Analysis Report Supplement Hatch Nuclear Plant Subsequent License Renewal Application Page A.4-23 Revision 0 Table A-3 List of SLR Implementation Actions and Implementation Schedule No.

Aging Management Program or Activity (Section)

NUREG-2191 Section Action Description Implementation Schedule 30 Buried and Underground Piping and Tanks (A.2.2.27)

XI.M41 Continue the existing Buried and Underground Piping and Tanks AMP, including enhancements to:

a) Update the Excavation & Earthwork Quality Control procedure to state that new and replacement backfill shall meet the requirements of NACE SP-0169-2007 Section 5.2.3 or NACE RP-0285-2002 Section 3.6. Backfill that is located within 6 inches of the component that meets ASTM D 448-08 size number 67 (size number 10 for polymeric materials) is considered to meet the objectives of NACE SP0169-1 2007 and NACE RP0285-2002. For stainless steel, backfill limits apply only if the component is coated.

The use of controlled low-strength materials (flowable backfill) is also acceptable to meet the objectives of NACE SP0169-2007.

b) Update the BUPT implementing procedure to perform soil testing during excavations for inspections. Additionally, include a requirement to perform an evaluation at least every five years during the SPEO to ensure the soil samples taken during that period are representative of the vicinity in which in-scope components are buried.

c) Install cathodic protection on the diesel fuel oil storage tanks prior to the SPEO. The cathodic protection system installed on the diesel fuel oil storage tanks will be in accordance with NACE SP0169-2007 or NACE RP0285-2002.

d) Update procedures and/or specifications to require that newly installed, buried stainless steel piping is coated in accordance with Table 1 of National Association of Corrosion Engineers (NACE)

SP0169-2007 or Section 3.4 of NACE RP0285-2002.

e) Update the BUPT implementing procedure to monitor for crevice corrosion and MIC for copper alloy, steel (including ductile and gray cast iron), and stainless steel components.

No later than the last refueling outage prior to the SPEO, or no later than 6 months prior to the SPEO. i.e.:

Unit 1: 02/06/2034 Unit 2: 12/13/2037 Implement the AMP and start the 10-year intervalperiod inspections no earlier than 10 years prior to the SPEO. to NL-25-0421 Response to RAI B.2.3.27-1 E1-18

Appendix A - Final Safety Analysis Report Supplement Hatch Nuclear Plant Subsequent License Renewal Application Page A.4-24 Revision 0 Table A-3 List of SLR Implementation Actions and Implementation Schedule No.

Aging Management Program or Activity (Section)

NUREG-2191 Section Action Description Implementation Schedule f)

Update the BUPT implementing procedure to clarify that inspections for cracking due to SCC for stainless steel and steel (in a carbonate-bicarbonate environment) utilize a method that has been determined to be capable of detecting cracking.

Coatings that: (a) are intact, well-adhered, and otherwise sound for the remaining inspection period; 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.

g) Update fuel oil storage tank inspection and cleaning tasks to align with a 10-year frequency.

h) Update the BUPT implementing procedure to specify that visual inspections are supplemented with surface and/or volumetric nondestructive testing if evidence of wall loss beyond minor surface scale is observed.

i)

Update the BUPT implementing procedure to include the following: Where practical, identified degradation (e.g., coating condition) is projected until the next scheduled inspection occurs.

Results are evaluated against acceptance criteria to confirm that the sampling bases (e.g., selection, size, frequency) will maintain the components intended functions throughout the SPEO based on the projected rate and extent of degradation. For any installed cathodic protection system, potential difference and current measurements are trended to identify changes in the effectiveness of the system and/or coatings.

j)

Update the BUPT implementing procedure to include the following acceptance criteria:

1. For coated piping or tanks, there is either no evidence of coating degradation, or the type and extent of coating degradation is evaluated as being insignificant by (1) an individual who has a NACE Coating Inspector Program to NL-25-0421 Response to RAI B.2.3.27-1 E1-19

Appendix A - Final Safety Analysis Report Supplement Hatch Nuclear Plant Subsequent License Renewal Application Page A.4-25 Revision 0 Table A-3 List of SLR Implementation Actions and Implementation Schedule No.

Aging Management Program or Activity (Section)

NUREG-2191 Section Action Description Implementation Schedule Level 2 or 3 inspector qualification; (2) an individual who has completed the EPRI Comprehensive Coatings Course and completed the EPRI Buried Pipe Condition Assessment and Repair Training Computer Based Training Course; or (3) a coatings specialist qualified in accordance with an ASTM standard endorsed in RG 1.54, Revision 2, Service Level I, II, and III Protective Coatings Applied to Nuclear Power Plants.

2. The measured wall thickness projected to the end of the SPEO meets minimum wall thickness requirements.

3. Indications of cracking in metallic pipe are managed in accordance with the corrective actions program element.

4. Backfill is acceptable if the inspections do not reveal evidence that the backfill caused damage to the components coatings or the surface of the component (if not coated).

5. Cracks in cementitious backfill that could admit groundwater to the surface of the component are not acceptable.

k) Update the BUPT implementing procedure to include the following corrective actions:

1. Where damage to the coating has been evaluated as being significant and the damage was caused by nonconforming backfill, an extent of condition evaluation is conducted to determine the extent of degraded backfill in the vicinity of the observed damage.

2. 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 to NL-25-0421 Response to RAI B.2.3.27-1 E1-20

Appendix A - Final Safety Analysis Report Supplement Hatch Nuclear Plant Subsequent License Renewal Application Page A.4-26 Revision 0 Table A-3 List of SLR Implementation Actions and Implementation Schedule No.

Aging Management Program or Activity (Section)

NUREG-2191 Section Action Description Implementation Schedule values for large area minimum wall thickness and local area wall thickness. If the wall thickness extrapolated to the end of the SPEO meets the minimum wall thickness requirements, the recommendations for expansion of sample size below do not apply.

3. When the coatings, backfill, or condition of exposed piping does not meet the acceptance criteria, the degraded condition is repaired or the affected component is replaced.

In addition, when 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 is extrapolated to the end of the SPEO, an expansion of sample size is conducted. The number of inspections within the affected piping categories is doubled or increased by five, whichever is smaller. If the acceptance criteria are not met in any of the expanded samples, an analysis is conducted to determine the extent of condition and extent of cause.

The number of follow-on inspections is determined based on the extent of condition and extent of cause.

4. The timing of the additional examinations is based on the severity of the degradation identified and is commensurate with the consequences of a leak or loss of function.

However, in all cases, the expanded sample inspection is completed within the 10-year intervalperiodduring which the original inspection was conducted or, if identified during the latter half of the current 10-year intervalperiod, within 4 years after the end of the 10-year intervalperiod. These additional inspections conducted during the 4 years following the end of an inspection intervalperiod cannot also be credited toward the number of inspections for the following 10-year intervalperiod. The number of inspections may be limited by the extent of piping or tanks subject to the observed degradation mechanism. to NL-25-0421 Response to RAI B.2.3.27-1 E1-21

Appendix A - Final Safety Analysis Report Supplement Hatch Nuclear Plant Subsequent License Renewal Application Page A.4-27 Revision 0 Table A-3 List of SLR Implementation Actions and Implementation Schedule No.

Aging Management Program or Activity (Section)

NUREG-2191 Section Action Description Implementation Schedule

5. The expansion of sample inspections may be halted in a piping system or portion of system that will be replaced within the 10-year intervalperiod during which the inspections were conducted or, if identified during the latter half of the current 10-year intervalperiod, within 4 years after the end of the 10-year period interval.

6. Indications of cracking are evaluated in accordance with applicable codes and plant-specific design criteria.

7. Unacceptable cathodic protection survey results are entered into the CAP.

l)

Update the Underground Piping and Tanks Asset Management Plan to include:

1.

The required inspections for SLR.

2.

A requirement that newly installed, buried stainless steel piping is coated in accordance with Table 1 of National Association of Corrosion Engineers (NACE) SP0169-2007 or Section 3.4 of NACE RP0285-2002.

m) Replace the in-scope copper alloy tubing used in the diesel fuel oil system between the A diesel fuel oil storage tank and the diesel fire pump with 304 stainless steel tubing encased within a 4" stainless steel chase pipe.

to NL-25-0421 Response to RAI B.2.3.27-1 E1-22

Appendix B - Aging Management Programs Hatch Nuclear Plant Subsequent License Renewal Application Page B.2-130 Revision 0 B.2.3.27 Buried and Underground Piping and Tanks Program Description The Buried and Underground Piping and Tanks AMP, previously known as the Underground Pipe and Tanks Monitoring Program, is an existing condition monitoring program that manages the aging effects associated with the external surfaces of buried and underground piping and tanks such as loss of material and cracking. This AMP addresses piping and tanks composed of any metallic material that are within the scope of SLR in the emergency diesel generator, fire protection, high pressure coolant injection, PSW, reactor core isolation cooling, residual heat removal service water, and standby gas treatment systems. There are no buried polymeric components, buried cementitious components, or underground components within the scope of License Renewal that require aging management by the Buried and Underground Piping and Tanks AMP.

This AMP manages aging through preventive, mitigative, inspection, and performance monitoring activities. The Buried and Underground Piping and Tanks AMP includes the following: (a) preventive actions to mitigate degradation (e.g., external coatings or wrappings and quality of backfill), (b) condition monitoring (inspections) (e.g., nondestructive evaluation of pipe or tank wall thicknesses, visual inspections of the external surfaces and coatings/wraps of pipe, and internal tank inspections capable of detecting loss of material on the external surface), (c) performance monitoring activities (e.g., pressure testing of piping, performance monitoring of fire mains) to provide early warning of system leakage, (d) proactive replacement of portions of buried carbon steel in-scope copper alloy piping with stainless steel as part of corrective actions, and (e) continuing to evaluate installation of cathodic protection in targeted locations and installation of targeted cathodic protection in additional locations if determined it would significantly improve plant safety.

Internal inspections may be performed using a method capable of precisely determining piping or tank wall thickness. The method must be capable of detecting both general and pitting corrosion on the external surface of the piping or tank and must be qualified to identify loss of material that does not meet the acceptance criteria. Ultrasonic examinations, in general, satisfy this criterion.

A 2024 soil analysis found that the soil surrounding HNPs in-scope piping was generally mild to moderately corrosive, with certain areas and materials posing a higher risk. HNP will use this information in determining next steps for appropriate preventive actions to effectively manage the aging of its buried and underground piping and tanks. In order to continually monitor potential soil corrosivity, HNP will sample and test the soil excavated for inspections. An evaluation will be performed at least every five years during the SPEO to ensure the soil samples taken during that period are representative of the vicinity in which in-scope components are buried. The results of this soil testing will be used to inform future inspection locations. Additionally, opportunistic inspections of the external surfaces of in-scope buried piping and tanks are performed when the piping or tanks are excavated for any reason.

Site-Specific Inspection Quantities:

Site-Specific Inspection Quantities for buried piping and tanks are required because cathodic protection is not currently installed. In addition, the five buried diesel generator fuel oil storage tanks and the buried plant service water stainless steel piping are not coated. HNP will perform the following number of inspections for each 10-year intervalperiod, starting in the 10-year intervalperiod prior to the SPEO: to NL-25-0421 Response to RAI B.2.3.27-1 E1-23

Appendix B - Aging Management Programs Hatch Nuclear Plant Subsequent License Renewal Application Page B.2-131 Revision 0 Stainless Steel Buried Piping Two inspections of 10-foot segments Uncoated Stainless Steel Buried Piping Two one-time inspections of 10-foot segments in soil with the highest corrosivity rating will be performed in addition to the first stainless steel inspections prior to the SPEO.

Steel Buried Piping The smaller of 10% of the piping length or eleven inspections of 10-foot segments Copper Alloy Buried Piping The smaller of 10% of the piping length or nine inspections of 10-foot segments Steel Buried Tanks One inspection for each of the buried fuel oil storage tanks Inspection quantities may be reevaluated if HNP determines that appropriate preventive actions can be credited for reduced inspection quantities per NUREG-2191,Section XI.M41.

Site Inspection Locations and Priorities:

Table B.2.3.27-1 identifies material of construction, soil conditions, and plant operating experience for each in-scope system to establish inspection priorities. Characteristics such as coating type (i.e., material type), coating condition, backfill characteristics, soil corrosivity, pipe contents, and pipe function are considered. If an opportunity for inspection on non-leaking piping occurs prior to the scheduled inspection, the opportunistic inspection can be credited for satisfying the scheduled inspection if the selection criteria are met.

Table B.2.3.27-1: Site Inspection Locations and Priorities System Material Soil Conditions Previous Inspections/Operating Experience Inspection Priority1 Emergency diesel generator (EDG)

Carbon steel Moderately corrosive Piping: Five inspections performed in 2013. All inspections satisfactory.

Tanks: All five tanks inspected from 2013 to 2016. All inspections satisfactory.

Piping: CS 4 Tanks: One inspection for each of the buried fuel oil storage tanks Fire protection Carbon steel Moderately to appreciably corrosive No adverse OE identified.

CS 6 Fire protection Copper alloy Unknown No adverse OE identified.

CA 1 Fire protection Ductile iron Moderately to appreciably corrosive No adverse OE identified.

CS 72 to NL-25-0421 Response to RAI B.2.3.27-1 E1-24

Appendix B - Aging Management Programs Hatch Nuclear Plant Subsequent License Renewal Application Page B.2-132 Revision 0 System Material Soil Conditions Previous Inspections/Operating Experience Inspection Priority1 Fire protection Gray cast iron Mildly to moderately corrosive System pressure perturbations have led to mechanical failures. These failures are not believed to be related to external corrosion.

CS 52 Fire protection Stainless steel Unknown No adverse OE identified SS 1 High pressure coolant injection (HPCI)

Stainless steel Moderately to severely corrosive One inspection performed in 2010. No adverse OE identified.

SS 1 Plant service water (PSW)

Carbon steel Moderately to appreciably corrosive 39 inspections from 2010 to 2020.

Several unsatisfactory results due to both internal and external degradation.

CS 2 Plant service water (PSW)

Stainless steel (uncoated)

Moderately to severely corrosive No previous inspections or OE identified. Uncoated stainless steel PSW piping was installed in 2014.

USS 13 Reactor core isolation cooling (RCIC)

Stainless steel Moderately to severely corrosive Four inspections from 2010 to 2013.

No adverse OE identified.

SS 2 Residual heat removal service water (RHRSW)

Carbon steel Moderately to appreciably corrosive 17 inspections from 2010 to 2021.

Several unsatisfactory results, mostly related to internal corrosion.

Through wall leak in 2020.

CS 1 Standby gas treatment (SBGT)

Carbon steel Moderately to appreciably corrosive Three inspections from 2010 to 2013.

All inspections satisfactory.

CS 3 Table Notes:

1. Inspection priorities are grouped by material type (e.g., CS for carbon steel) and ranked from by priority, with the highest priority set at (1) to lowest priority (4). The inspection priorities consider previous inspection results, the number of previous inspections, operating experience, system risk ranking, and the use of preventive actions, if applicable. The total number of inspections for each material type shall be consistent with the quantities listed previously.

2. Ductile and gray cast iron are grouped with the steel population.

3. Two one-time inspections of 10-foot segments in soil with the highest corrosivity rating will be performed in addition to the first stainless steel inspections prior to the SPEO. The inspection results will be trended to ensure the components intended functions are maintained throughout the subsequent period of extended operation based on the projected rate and extent of degradation. Unacceptable results are entered into the site's corrective action program. to NL-25-0421 Response to RAI B.2.3.27-1 E1-25

Appendix B - Aging Management Programs Hatch Nuclear Plant Subsequent License Renewal Application Page B.2-133 Revision 0 This AMP does not provide aging management of selective leaching. The Selective Leaching AMP (B.2.3.21) is applied in addition to this program for applicable materials and environments.

NUREG-2191 Consistency The Buried and Underground Piping and Tanks AMP, with enhancements, is consistent with two exceptions to the 10 elements of NUREG-2191,Section XI.M41, Buried and Underground Piping and Tanks."

Exceptions to NUREG-2191 The Buried and Underground Piping and Tanks AMP includes the following exceptions to the NUREG-2191 guidance:

Exception 1. Element 2, Preventive Actions Cathodic protection is not installed at HNP for carbon steel piping systems as recommended in NUREG-2191, Table XI.M41-1.

Exception 2. Element 2, Preventive Actions The diesel fuel oil storage tanks and a portion of stainless steel PSW piping are not coated as recommended in NUREG-2191, Table XI.M41-1.

Justification for Exception Justification for Exception 1 The BUPT AMP is an existing program that has performed excavations and inspections in the past. Historical inspection results have led to additional inspections or replacement as documented in the Underground Piping and Tanks (UPT) Asset Management Plan. HNP is proactively replacing portions of buried carbon steel piping with stainless steel as part of corrective actions driven by the existing program. In addition, HNP is employing an industry recognized software to estimate corrosion rates based on soil samples. A 2024 soil analysis found that the soil surrounding HNPs in-scope piping was generally mild to moderately corrosive, with certain areas and materials posing a higher risk. HNP will use this information in determining next steps for appropriate preventive actions to effectively manage the aging of its buried and underground piping and tanks. In order to continually monitor potential soil corrosivity, HNP will sample and test the soil excavated for inspections. An evaluation will be performed at least every five years during the SPEO to ensure the soil samples taken during that period are representative of the vicinity in which in-scope components are buried. The results of this soil testing will be used to inform future inspection locations.

HNP has determined that installation of cathodic protection is impractical because the adverse effects of installation of cathodic protection outweigh the potential benefits that may be provided. These adverse effects are due to piping systems not being electrically continuous and effects from stray current corrosion, shielding from congested piping runs and other SSCs, and bare steel current draw. Site wide deep bed, remote bed, distributed bed, and linear anode cathodic protection systems were evaluated and all were determined to be impractical to install. HNP will continue to evaluate installation of cathodic protection in targeted locations and may install targeted cathodic protection in additional locations if determined it would significantly improve plant safety. In addition, any buried carbon steel piping that is not replaced with stainless steel or to NL-25-0421 Response to RAI B.2.3.27-1 E1-26

Appendix B - Aging Management Programs Hatch Nuclear Plant Subsequent License Renewal Application Page B.2-134 Revision 0 cathodically protected will be managed by inspecting the smaller of 10% of the piping length or 11 inspections of 10-foot segments. By reducing the population of piping most susceptible to corrosion, establishing expected corrosion rates based on soil conditions, and inspecting the most susceptible piping, HNP will provide reasonable assurance that its buried piping will continue to perform its intended function through the SPEO.

A conservative number of inspections will provide reasonable assurance that the buried piping at HNP will maintain its intended function. An analysis was conducted in accordance with the preventive actions program element of the Buried Piping and Tanks AMP, including soil analysis and an expanded OE review. Based on these, HNP meets the criteria for Category E based on impracticality. However, due to OE history, additional inspections would be prudent and warranted. As such, the number of inspections for Category E, three inspections, was doubled to six inspections before multiplying by 1.5 for a two-unit site. Then two inspections were added in accordance with XI.M41 Element 4 e.i, for a total of 11 inspections.

Justification for Exception 2 The diesel fuel oil storage tanks are internally inspected using volumetric methods on a 10-year frequency. Past inspection results of the tanks have been satisfactory with no indication of wall loss greater than 12.5% of the nominal wall thickness. These satisfactory inspection results in addition to continued periodic inspections and installation of cathodic protection provide reasonable assurance that the tanks will continue to perform their intended function through the SPEO.

Soil sampling indicates that the soil conditions at HNP are moderately to severely corrosive for stainless steels. However, the estimated corrosivity for stainless steels is heavily affected by the modeling assumptions used by the vendor. Consequently, the actual soil condition for stainless steel may be less corrosive than indicated by the model. The uncoated grade 316L stainless steel PSW piping is approximately 1,000 feet and is conservatively considered the highest inspection priority even though its service life is shorter relative to other buried stainless steel in similar soil environments.

Enhancements The Buried and Underground Piping and Tanks AMP will be enhanced as follows, for alignment with NUREG-2191.

Element Enhancement 2 - Preventive Actions Update the Excavation & Earthwork Quality Control procedure to state that new and replacement backfill shall meet the requirements of NACE SP-0169-2007 Section 5.2.3 or NACE RP-0285-2002 Section 3.6. Backfill that is located within 6 inches of the component that meets ASTM D 448-08 size number 67 (size number 10 for polymeric materials) is considered to meet the objectives of NACE SP0169-1 2007 and NACE RP0285-2002. For stainless steel, backfill limits apply only if the component is coated. The use of controlled low-strength materials (flowable backfill) is also acceptable to meet the objectives of NACE SP0169-2007.

2 - Preventive Actions Update the BUPT implementing procedure to perform soil testing during excavations for inspections. Soil corrosivity will be evaluated using either American Water Works Association C105, to NL-25-0421 Response to RAI B.2.3.27-1 E1-27

Appendix B - Aging Management Programs Hatch Nuclear Plant Subsequent License Renewal Application Page B.2-135 Revision 0 Polyethylene Encasement for Ductile-Iron Pipe Systems, Table A.1, Soil Test Evaluation, or Electric Power Research Institute Report 3002005294, Soil Sampling and Testing Methods to Evaluate the Corrosivity of the Environment for Buried Piping and Tanks at Nuclear Power Plants, Table 9-4, Soil Corrosivity Index from BPWORKS. Additionally, include a requirement to perform an evaluation at least every five years during the SPEO to ensure the soil samples taken during that period are representative of the vicinity in which in-scope components are buried.

2 - Preventive Actions Install cathodic protection on the diesel fuel oil storage tanks prior to the SPEO. The cathodic protection system installed on the diesel fuel oil storage tanks will be in accordance with NACE SP0169-2007 or NACE RP0285-2002.

2 - Preventive Actions Update the Asset Management Plan, procedures, and specifications to require that newly installed, buried stainless steel piping is coated in accordance with Table 1 of National Association of Corrosion Engineers (NACE) SP0169-2007 or Section 3.4 of NACE RP0285-2002.

2 - Preventive Actions Replace the in-scope copper alloy tubing used in the fuel oil system between the A diesel fuel oil storage tank and the diesel fire pump with 304 stainless steel tubing within a 4" stainless steel chase pipe.

3 - Parameters Monitored/Inspected Update the BUPT implementing procedure to monitor for crevice corrosion and MIC for copper alloy, steel (including ductile and gray cast iron), and stainless steel components.

3 - Parameters Monitored/Inspected Update the BUPT implementing procedure to clarify that inspections for cracking due to SCC for stainless steel and steel (in a carbonate-bicarbonate environment) utilize a method that has been determined to be capable of detecting cracking. Coatings that: (a) are intact, well-adhered, and otherwise sound for the remaining inspection periodinterval; 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.

4 - Detection of Aging Effects Update fuel oil storage tank inspection and cleaning tasks to align with the 10-year frequency recommended in NUREG-2191.

4 - Detection of Aging Effects Update the BUPT implementing procedure to specify that visual inspections are supplemented with surface and/or volumetric nondestructive testing if evidence of wall loss beyond minor surface scale is observed.

4 - Detection of Aging Effects Update the Underground Piping and Tanks Asset Management Plan to include the plant specific inspection quantities for SLR.

5 - Monitoring &

Update the BUPT implementing procedure to include the to NL-25-0421 Response to RAI B.2.3.27-1 E1-28

Appendix B - Aging Management Programs Hatch Nuclear Plant Subsequent License Renewal Application Page B.2-136 Revision 0 Trending following: Where practical, identified degradation (e.g., coating condition) is projected until the next scheduled inspection occurs. Results are evaluated against acceptance criteria to confirm that the sampling bases (e.g., selection, size, frequency) will maintain the components intended functions throughout the subsequent period of extended operation based on the projected rate and extent of degradation. For any installed cathodic protection system, potential difference and current measurements are trended to identify changes in the effectiveness of the systems and/or coatings.

6 - Acceptance Criteria Update the BUPT implementing procedure to include the following acceptance criteria:

• For coated piping or tanks, there is either no evidence of coating degradation, or the type and extent of coating degradation is evaluated as being insignificant by (1) an individual who has a NACE Coating Inspector Program Level 2 or 3 inspector qualification; (2) an individual who has completed the EPRI Comprehensive Coatings Course and completed the EPRI Buried Pipe Condition Assessment and Repair Training Computer Based Training Course; or (3) a coatings specialist qualified in accordance with an ASTM standard endorsed in Regulatory Guide 1.54, Revision 2, Service Level I, II, and III Protective Coatings Applied to Nuclear Power Plants.

• The measured wall thickness projected to the end of the SPEO meets minimum wall thickness requirements.

• Indications of cracking in metallic pipe are managed in accordance with the corrective actions program element.

• Backfill is acceptable if the inspections do not reveal evidence that the backfill caused damage to the components coatings or the surface of the component (if not coated).

• Cracks in cementitious backfill that could admit groundwater to the surface of the component are not acceptable.

• Acceptance criteria for cathodic protection will be in accordance with NUREG-2191, XI-M41, Element 6.

7 - Corrective Actions Update the BUPT implementing procedure to include the following corrective actions:

• Where damage to the coating has been evaluated as being significant and the damage was caused by nonconforming backfill, an extent of condition evaluation is conducted to determine the extent of degraded backfill in the vicinity of the observed damage.

• If coated or uncoated metallic piping or tanks show evidence of corrosion, the remaining wall thickness in the to NL-25-0421 Response to RAI B.2.3.27-1 E1-29

Appendix B - Aging Management Programs Hatch Nuclear Plant Subsequent License Renewal Application Page B.2-137 Revision 0 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. If the wall thickness extrapolated to the end of the subsequent period of extended operation meets the minimum wall thickness requirements, the recommendations for expansion of sample size below do not apply.

• When the coatings, backfill, or condition of exposed piping does not meet the acceptance criteria, the degraded condition is repaired or the affected component is replaced.

In addition, when 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 is extrapolated to the end of the subsequent period of extended operation, an expansion of sample size is conducted. The number of inspections within the affected piping categories is doubled or increased by five, whichever is smaller. If the acceptance criteria are not met in any of the expanded samples, an analysis is conducted to determine the extent of condition and extent of cause. The number of follow-on inspections is determined based on the extent of condition and extent of cause.

• The timing of the additional examinations is based on the severity of the degradation identified and is commensurate with the consequences of a leak or loss of function.

However, in all cases, the expanded sample inspection is completed within the 10-year interval during which the original inspection was conducted or, if identified during the latter half of the current 10-year interval, within 4 years after the end of the 10-year interval. These additional inspections conducted during the 4 years following the end of an inspection interval cannot also be credited toward the number of inspections for the following 10-year interval.

The number of inspections may be limited by the extent of piping or tanks subject to the observed degradation mechanism.

• The expansion of sample inspections may be halted in a piping system or portion of system that will be replaced within the 10-year interval during which the inspections were conducted or, if identified during the latter half of the current 10-year interval, within 4 years after the end of the 10-year interval.

• Indications of cracking are evaluated in accordance with applicable codes and plant-specific design criteria.

• Unacceptable cathodic protection survey results are entered into the CAP.

Operating Experience to NL-25-0421 Response to RAI B.2.3.27-1 E1-30

Appendix B - Aging Management Programs Hatch Nuclear Plant Subsequent License Renewal Application Page B.2-138 Revision 0 Industry Operating Experience HNP evaluates industry OE items for applicability per the Operating Experience Program and takes appropriate corrective actions. Industry OE shows that buried and underground piping and tanks are subject to corrosion. Corrosion of buried oil, gas, and hazardous materials pipelines have been adequately managed through a combination of inspections and mitigative techniques, such as those prescribed in NACE SP0169-2007 and NACE RP0285-2002. The following industry OE is identified in NUREG-2191:

In June 2009, an active leak was discovered in buried piping associated with the condensate storage tank. The leak was discovered because elevated levels of tritium were detected. The cause of the through-wall leaks was determined to be the degradation of the protective moisture barrier wrap that allowed moisture to come in contact with the piping resulting in external corrosion (ML093160004).

In August 2009, a leak was discovered in a portion of buried aluminum pipe where it passed through a concrete wall. The piping is in the condensate transfer system. The failure was caused by vibration of the pipe within its steel support system. This vibration led to coating failure and eventual galvanic corrosion between the aluminum pipe and the steel supports (ML093160004).

In April 2010, while performing inspections as part of its buried pipe program, a licensee discovered that major portions of the auxiliary feedwater piping were substantially degraded. The licensees cause determination attributes the cause of the corrosion to the failure to properly coat the piping as specified during original construction. The affected piping was replaced during the next refueling outage (ML103000405).

In November 2013, minor weepage was noted in a 10-inch service water supply line to the emergency diesel generators while performing a modification to a main transformer moat. Coating degradation was noted at approximately 10 locations along the exposed piping. The leaking and unacceptable portions of the degraded pipe were clamped and recoated until a permanent replacement could be implemented (ML13329A422).

The BUPT AMP, with enhancements, is informed by the industry OE items above.

Plant Specific Operating Experience A recent HNP OE search was performed for SLR which covers the last 10 years of operation.

Per NUREG-2191, since cathodic protection is not provided at HNP, this search includes components that are not in-scope for LR if, when compared to in-scope piping, they are of similar materials and coating systems and are buried in a similar soil environment. Relevant OE items are as follows:

In August 2014, during an inspection for the underground pipe and tanks monitoring program, external pitting corrosion was identified on a 30-inch radwaste discharge pipe resulting in the measured pipe wall being below the acceptable minimum wall calculation. The pitting appeared to be caused by corrosion due to coatings failure and was limited to the top side of the pipe which indicates that the coatings damage was likely due to construction and not due to aging. Weld build-up was added to the pipe at the location of the pits. Pitting corrosion was also identified on a separate leg of the 30-inch radwaste discharge piping in a second excavation. The pitting identified in the second excavation did not result in the measured pipe wall being below the acceptable minimum wall calculation. The identified pitting was repaired. This piping to NL-25-0421 Response to RAI B.2.3.27-1 E1-31

Appendix B - Aging Management Programs Hatch Nuclear Plant Subsequent License Renewal Application Page B.2-139 Revision 0 is not within the scope of SLR and the area that was excavated was outside the Protected Area and has a different backfill specification and less restrictive excavation requirements than piping that is inside the Protected Area and in-scope of SLR.

In 2015, the 2Y52A001C diesel fuel oil storage tank was cleaned and inspected using the guidance in API Standard 1631. Seventy-one spot UT readings were obtained using a 3ft x 3ft grid and another 24 random readings were taken within the vessel for a total of 95 readings. All measurements were within 12.5 percent of the nominal wall thickness (0.500 inches) with the lowest at 0.468 inches.

In 2016, the 1R43A002B and 1R43A002C diesel fuel oil storage tanks were cleaned and inspected using the guidance in API Standard 1631. Eighty-five spot UT readings were obtained using a 3ft x 3ft grid and another 25 random readings were taken within each vessel for a total of 110 readings per tank. All measurements were within 12.5 percent of the nominal wall thickness (0.500 inches) with the lowest at 0.462 inches for tank 1R43A002B and 0.458 inches for tank 1R43A002C.

In 2016, the 2Y52A001A diesel fuel oil storage tank was cleaned and inspected using the guidance in API Standard 1631. Eighty-five spot UT readings were obtained using a 3ft x 3ft grid and another 25 random readings were taken within the vessel for a total of 110 readings. All measurements were within 12.5 percent of the nominal wall thickness (0.500 inches) with the lowest at 0.468 inches.

In February 2019, a condition report was generated that identified an area of concern related to the number of buried fire protection system piping leaks at HNP. The plant response to this condition report states that system pressure perturbations led to an overpressure event that caused the recent failure. Because of the brittle nature of cast iron piping, system pressure perturbations caused by improper pump starts can lead to piping failures. The evaluation of this OE does not identify external corrosion as a cause of the fire protection piping failures. Corrective actions included replacement of the fire pump engine controllers to prevent simultaneous pump start. Prior to 2022, which was the first instance of graphitic corrosion to the outside diameter of the fire protection piping, no other system leaks were linked to age related degradation.

Fire protection piping has a different coating system in accordance with ANSI/AWWA C151/A21.51 and cement mortar lined interior in accordance with ANSI/AWWA C104/A21.4. This is different from the coating system on the in-scope carbon steel piping.

In 2019, a corrective action report was generated to document the actions taken to address leaks in buried carbon steel piping in the vicinity of the Unit 1 and 2 condensate storage tank (CST) enclosures. Four events were identified related to CST piping leaks between 2007 and 2019 that were attributed to external corrosion or degradation at the carbon steel to concrete interface. The piping that is surrounded by concrete is not coated consistently with the coatings applied to pipe exposed to soil. Long-term asset management items are tracking the replacement of buried carbon steel piping in the vicinity of the CST with stainless steel piping. A 2024 design change replaced all in-scope buried carbon steel piping that connects to the Unit 1 CST. The replacement piping is wrapped/coated type 304 stainless steel. The equivalent Unit 2 piping is planned to be replaced with coated type 304 stainless steel by 2027in 2025.

In September 2020, the Unit 1, Division 1 RHRSW buried pipe developed a through wall leak due to external pitting. This external pitting corrosion was caused by the to NL-25-0421 Response to RAI B.2.3.27-1 E1-32

Appendix B - Aging Management Programs Hatch Nuclear Plant Subsequent License Renewal Application Page B.2-140 Revision 0 degradation of the pipe tape coating from foreign material present in the sand backfill during construction. Progressively over time, the pipe vibration from the process flow and the foreign material in the sand backfill caused the degradation to the pipe coating. A visual inspection of exposed piping in the excavated area identified localized coating damage on U1 PSW, U2 PSW, U2 RHRSW, U2 radwaste dilution line (abandoned in place), and U2 blowdown piping. Based on a review of CR history performed at the time of this event, the extent of condition was determined to be bounded to the immediate excavated area. The failed U1, Division 1 RHRSW piping was replaced. Inspection and coatings repair of the other exposed piping was also completed.

In 2022 during UT inspections of the Unit 2 RHRSW Division 1 piping, a single localized point was found to be below the previously calculated minimum pipe wall thickness. The affected pipe is an 18-inch diameter, seamless SA106 Grade B carbon steel pipe, with a nominal wall thickness of 0.500 inches. The thinnest measured location of 0.249 inches was found during a full circumference grid inspection where the remainder of the piping inspection points were above the allowable minimum wall thickness. An engineering evaluation was conducted and determined that, despite the localized thinning, the pipe maintained its structural integrity and continued to perform its intended design function. However, the remaining margin between actual and allowable wall thickness was considered insufficient for long-term operation, necessitating a repair. Prior to the performance of the UT, the coatings engineer performed a coating condition assessment per plant process, noting loose areas and nicks through tape coating.

No additional condition report was required.

The chosen corrective action was to apply a weld overlay at the area of localized thinning, following ASME BPV Code Case N-661-3, which is accepted by Regulatory Guide 1.147 for in-service inspection. The weld overlay is a temporary repair, intended to restore wall thickness and maintain code compliance until a permanent repair can be made. Permanent repairs are scheduled under a work order, with controls in place to ensure the overlay does not exceed the permitted life (maximum two fuel cycles, or four years, unless further inspections justify extension).

In 2022, a vendor performed a review of the buried asset program. The report includes information on 115 inspections performed from 2008 to 2021 on systems within the scope of the NEI 09-14 program. Of the systems within the scope of SLR, RHRSW and PSW were the only systems with adverse inspection results. Due to these results, RHRSW and PSW will be prioritized for inspection. Other conclusions of this review were that localized corrosion (pitting) was affecting buried piping to an unknown extent. This was in part due to the following: initial inspection locations that were reviewed under this report were not required to be recorded, therefore, the degradation rate could not be determined on specific piping segments. Based on this feedback, the site has adjusted inspection timelines and practices and applied techniques to better determine degradation rates which will help more accurately predict life expectancy of the piping. Future SLR inspections are prioritized based on risk ranking of each location (high risk items scheduled earlier), locations for which longer time periods have elapsed since previous inspection and locations which have an unknown or uncertain degradation rate.

For example, in 2022 inspections were conducted on Unit 1 CST carbon steel piping and Unit 1 & 2 PSW and RHRSW carbon steel piping. Approximately 6-10 axial feet of each piping run were exposed, and coating was removed over to NL-25-0421 Response to RAI B.2.3.27-1 E1-33

Appendix B - Aging Management Programs Hatch Nuclear Plant Subsequent License Renewal Application Page B.2-141 Revision 0 approximately 3-6 axial feet for the inspections. The 6 lines ran east/west, and all other lines ran north/south directions. All lines, except for the stainless steel RCIC suction line, had varying levels of wall loss identified on the exposed piping inside the excavated area. For in-scope piping PSW and RHRSW, UT results showed an average reading of 0.310 and 0.450 and minimum of 0.262 and 0.358, for a nominal thickness of 0.365 and 0.500 respectively. Most of the wall loss is attributed to internal corrosion.

In 2024, a vendor performed soil analysis for buried piping asset management. The analysis included soil sample data from 2010, 2012, 2023, and 2024. The analysis found that the soil surrounding HNPs in-scope piping was generally mild to moderately corrosive, with certain areas and materials posing a higher risk. The results of this analysis are included in and used to inform Table B.2.3.27-1: Site Inspection Locations and Priorities.

AMP effectiveness will be assessed at least every five years per NEI 14-12.

The Buried and Underground Piping and Tanks AMP is informed and enhanced when necessary through the systematic and ongoing review of both plant specific and industry OE, including research and development, such that the effectiveness of the AMP is periodically evaluated.

Conclusion The Buried and Underground Piping and Tanks AMP, with enhancements, provides reasonable assurance that the effects of aging will be managed so that the intended function(s) of components within the scope of the AMP will be maintained consistent with the CLB during the SPEO. to NL-25-0421 Response to RAI B.2.3.27-1 E1-34

Edwin I. Hatch Nuclear Plant Unit 1 and 2 Subsequent License Renewal Application Response to Request for Additional Information and Request for Confirmation of Information, Set 1 to NL-25-0421 Response to RAI 4.3.7-1 to NL-25-0421 Response to RAI 4.3.7-1 E2-1 RAI 4.3.7-1 Regulatory Basis:

Pursuant to 10 CFR 54.21(c), the SLRA must include an evaluation of time-limited aging analyses (TLAAs). The applicant must demonstrate that (i) the analyses remain valid for the subsequent period of extended operation, (ii) the analyses have been projected to the end of the subsequent period of extended operation, or (iii) the effects of aging on the intended function(s) will be adequately managed for the subsequent period of extended operation.

Background:

SLRA Section 4.3.7 indicates that after the screening evaluation for environmentally assisted fatigue (EAF) to determine the limiting locations, the applicant performed a detailed evaluation to reduce excessive conservatisms associated with the screening environmentally adjusted cumulative usage factor (CUFen) values.

In addition, NUREG/CR-6909, Revision 1, Section 4.1.4 indicates that the average temperature approach for the calculation of the environmental fatigue correction factor (Fen) can be used for a simple, linear transient in consideration of the threshold temperature for Fen (i.e., the average temperature calculation uses the threshold temperature in place of the minimum transient temperature when the minimum transient temperature is less than the threshold temperature). A more conservative approach than the average temperature approach is the Fen calculation with the maximum temperature of each transient.

Issue:

SLRA Section 4.3.7 does not clearly describe how the detailed evaluation reduces the excessive conservatism associated with the screening CUFen values that are based on conservative temperature, strain rate, and sulfur content in steels.

In addition, SLRA Section 4.3.7 does not clearly discuss the following: (1) whether the average temperature approach is used for the Fen calculation in the detailed evaluation after the screening evaluation; (2) if so, whether the average temperature approach is used only for a simple, linear transient and whether the Fen threshold temperature for each material type is used per NUREG/CR-6909, Revision 1; and (3) if the average temperature approach is used for a complex transient, why the conservatism of the applicants approach is comparable to or greater than that of the modified rate approach described in NUREG/CR-6909, Revision 1, Section 4.4 (i.e., plant-specific demonstration of the adequacy of the applicants approach).

Request:

1. Explain how the detailed evaluation reduced the excessive conservatism associated with the screening CUFen values that are based on conservative temperature, strain rate, and sulfur content in steels. As part of the response, clarify how the detailed evaluation determines the temperature, strain rate, and sulfur content in steels in the calculation Fen calculation.

2. Clarify the following: (1) whether the average temperature approach is used for the Fen calculation in the detailed EAF evaluation; and (2) if so, whether the average temperature approach is used only for a simple, linear transient and whether the Fen threshold temperature for each material type is used per NUREG/CR-6909, Revision 1 (e.g., 150 ºC for carbon and low alloy steels).

to NL-25-0421 Response to RAI 4.3.7-1 E2-2

3. If the average temperature approach is used for complex transients in the detailed EAF evaluation, describe the following: (1) the complex transients; (2) the components for which the complex transients are evaluated; and (3) why the conservatism of the applicant's average temperature approach is comparable to or greater than that of the modified rate approach described in NUREG/CR-6909, Revision 1, Section 4.4 (i.e.,

plant-specific demonstration of the adequacy of the applicant's approach by comparing the Fen and CUFen values between the average temperature approach and the modified rate approach).

Response to 4.3.7-1 Request 1:

Various conservatism reductions, as detailed below, are used depending on the location and need for reductions. While further reductions could be possible, attempts at conservatism reduction are usually stopped once acceptability is achieved.

Temperatures used are either the maximum or average for a load pair depending on the location and transient. See response to question 2 for additional details.

A conservatively calculated strain rate (slower than is actually expected) was used for load combinations that include a step change transient. Step changes that strain rate was calculated for are:

During shutdown for the recirculation and attached residual heat removal system.

During shutdown and scram for the steam condensate drain system.

A stress peak associated with a step change typically occurs within the first 5 to 10 seconds of the stress response. Thirty seconds was used for strain rate calculation to conservatively account for some lag in the stress peak caused by a step change. All other load combinations and transients used the most conservative (produces the largest Fen and therefore largest CUFen) value of strain rate possible in NUREG/CR-6909, Revision 1, based EAF calculation or used the modified rate approach.

As specified in NUREG/CR-6909, Revision 1, the most conservative value (produces the largest Fen and therefore largest CUFen) possible for S* is 3.47. It is the factor used for material sulfur content in EAF calculations for carbon and low alloy steels.

A detailed evaluation for a location varies from a screening evaluation in that total fatigue for locations is based on fatigue for individual load pairs which are then summed up to calculate a total usage. Fen values for individual load pairs are based on temperatures (Maximum or average) for those load pairs whereas a screening evaluation uses one bounding, maximum, temperature.

Code Case N-902, which has been unconditionally accepted by the NRC, was used for one piping location to reduce conservatism.

Sm (allowable stress) averaging is used as permitted by Note 4 (Note 1 in the 1971 ASME Code) of Figure NB-3222-1 of Section III of the 2007 Edition with Addenda through 2009 ASME Code, When the secondary stress is due to a temperature transient at the point at which the stresses are being analyzed or to restraint of free end deflection, the value of Sm shall be taken as the average of the tabulated Sm for to NL-25-0421 Response to RAI 4.3.7-1 E2-3 the highest and the lowest temperatures of the metal during the transient. When part or all of the secondary stress is due to mechanical load, the value of Sm shall not exceed the value for the highest temperature during the transient..

Response to 4.3.7-1 Request 2:

SLRA Section 4.3.7, as supplemented by the response to RAI 4.3.7-1, discusses the average temperature approach for detailed EAF analysis. The average temperature is calculated using the transient maximum temperature and the higher of the transient minimum temperature and the threshold temperature for environmental fatigue correction factor (Fen) for each material type below which the effect of EAF is insignificant.

The average temperature approach is used for 11 of 30 NB-3600 piping evaluations and 3 of 15 evaluations of vessel locations. The piping locations include core spray, recirculation, residual heat removal, standby liquid control, feedwater, and drains. Vessel locations include the control rod drive hydraulic system return nozzle which has been capped, core DP nozzle, and a feedwater nozzle location. Startup, shutdown, and loss of feedwater are examples of transients for which an average temperature approach was used.

The Fen threshold temperature is used in all cases. In NB-3600 piping analyses, transients that have multiple up and down thermal portions are split up so each split only has a downward or upward temperature ramp. This makes NB-3600 evaluations inherently simple for EAF evaluation. Two vessel locations used an average temperature combined with minimum strain rate (conservative) approach where more complex transients are split up into simple ones for fatigue analysis and therefore allowing the use of average temperature. For one vessel location, the original method of very conservatively lumping all cycles together was retained. The most severe cooldown and heatup were used to calculate stress which was then used for all cycles to calculate fatigue. Evaluating all transients based on the most severe cooldown and heatup turns the evaluation into an evaluation of simple transients and introduces conservatism by grouping all transients into one bounding category. Use of average temperature combined with minimum strain rate (conservative) for this location is therefore justified and produces an overall conservative value of CUFen.

Response to 4.3.7-1 Request 3:

Some design basis transients are defined to go from one state to another like startup (cold to hot) and shutdown (hot to cold) linearly and therefore result in a constant strain rate and linear temperature response. A scram transient is a good example of a design transient that includes at least one cooldown and heat up cycle and is considered complex. A scram involving a loss of feedwater by design basis definition has multiple cooldown and heat up cycles, multiple stress peaks and valleys, and would therefore be considered complex. This type of transient is split up for fatigue analysis so that all the peaks and valleys are considered. The resulting transients split up from a complex transient used the most conservative (produces the largest Fen) value of strain rate possible.

Most components have complex transients as design basis input. Stress and fatigue evaluations split those up into simpler transients for fatigue analysis.

to NL-25-0421 Response to RAI 4.3.7-1 E2-4 Complex transients were split up into simpler transients for most locations that used an average temperature to calculate a Fen value. For one location, the Unit 2 Core DP Nozzle, the original method of very conservatively lumping all cycles together was retained. The most severe heat up and most severe cooldown transients for the location were used to calculate stress and fatigue for all transients. The basis for stress and fatigue evaluation is therefore two simple, bounding transients that are used for all transients. The simple, bounding nature of the transients allows for the use of an average temperature while using the most conservative value of strain rate, 0.0004%/s, specified in NUREG/CR-6909, Revision 1, which states The lower bound or saturation strain rate of 0.0004%/s can be used to perform the most conservative evaluation. This is a very conservative approach overall which will result in a conservative CUFen value as compared to the modified rate approach used when very detailed stress output is available for all transients. NUREG/CR-6909 Revision 1, Section 4.1.4 does allow the use of average temperatures for transients that are not simple linear transients if information is available that justifies the use of this approach. Industry information is available that justifies the use of the average temperature approach for transients that are not simple in a paper entitled Use of Average Temperature in Fen Calculations, Proceedings of the ASME 2020 Pressure Vessel & Piping Conference, PVP2020-21009. This paper compares Fen values based on the modified rate approach with those using the average temperature approach. The paper documents case studies where the modified rate approach and average temperature approach are used on various BWR and PWR reactor pressure vessel components of varying materials. The paper concluded that in every case study, the total CUFen value was greater (more conservative) with a Fen value based on the average temperature approach rather than a Fen value based on the modified rate approach.

• is provided a site specific example Use of Average Temperature When Calculating Fen. This plant specific demonstration provides additional confirmation that the average temperature approach is conservative when calculating the Fen value and environmentally adjusted cumulative usage factor (CUFen) for complex thermal transients at Hatch.

References:

None Associated SLRA Revisions:

None to NL-25-0421 Response to RAI 4.3.7-1 E2-5 Use of Average Temperature When Calculating Fen Environmentally assisted fatigue (EAF) evaluations performed for Hatch used average temperature when calculating Fen values as allowed by NUREG/CR-6909, Revision 1.

NUREG/CR-6909 requires that Fen values resulting from use of average temperature are consistent with those that would be obtained using the modified rate approach (MRA).

PVP2020-21009 provides a methodology for conservatively calculating Fen using average temperature as compared to the modified rate approach.

Hatch uses SI:FatiguePro 4 (FP4) to monitor fatigue including stress-based fatigue (SBF) for feedwater nozzle locations. The FP4 SBF module uses the modified rate approach (MRA) in the calculation of Fen. To compare an average temperature approach to the modified rate approach on a plant-specific basis for Hatch, Fen values based on the modified rate approach included in the FP4 output for Hatch are compared to values calculated using average temperature. As required by NUREG/CR-6909, Revision 1, average temperature is the average of the maximum temperature for the transient and the higher of the threshold temperature for the material under consideration and the minimum temperature for the transient. The methodology for calculating Fen for carbon steel is:

For carbon (CS) and low alloy steel (LAS):

Fen = exp((0.003 - 0.031
*)S* T* O*)

where: S* = 2.0 + 98 S for sulfur content, S, 0.015 wt. %

= 3.47 for S > 0.015 wt. %

T* = 0.395 for service temperature, T < 150°C

= (T - 75)/190 for 150 T 325°C O* = 1.49 for dissolved oxygen, DO < 0.04 parts per million (ppm)

= ln(DO/0.009) for 0.04 ppm DO 0.5 ppm

= 4.02 for DO > 0.5 ppm

* = 0 for strain rate,
> 2.2%/sec

= ln(
/2.2) for 0.0004
2.2%/sec

= ln(0.0004/2.2) for
< 0.0004%/sec Regarding the use of average temperature, NUREG/CR-6909, Revision 1, states:

For simple, linear transients, an average temperature that considers the threshold temperature of 150°C may be used to calculate Fen for a specific stress cycle or load set pair. Complex thermal transients that have multiple increasing and decreasing temperature excursions should be evaluated using the maximum temperature for the specific stress cycle or load set pair unless information is available to justify the use of an average temperature.

In May of 2023, Hatch Unit 1 entered a scheduled maintenance outage. This complex transient for the feedwater nozzles is used as a plant-specific comparison of Fen determined by the modified rate approach and Fen determined by a simplified approach using an average temperature. As was done for this location in Hatch EAF calculations to NL-25-0421 Response to RAI 4.3.7-1 E2-6 for subsequent license renewal, the following conservative choice is made for the average temperature approach to calculating Fen:

The minimum strain rate,
< 0.0004%/sec, is used, which is conservative because it results in larger Fen values.

The comparison of the average temperature Fen versus the MRA Fen for this complex transient is shown in Table 1. The average temperature Fen of 4.51 is conservative as compared to the MRA Fen.of 2.45.

Table 1: Results Summary Average Tmax Tmin*

Tave Temp MRA From To

(°F)

(°F)

(°F)

Fen**

Fen**

5/18/2023 5/26/2023 493 302 203 4.51 2.45

• Since Tmin is below 302°F, 302°F (the threshold temperature for carbon steel) is used instead.

• • DO is 0.1 for this location resulting in an O* value of 2.41.

The following figure and table show the data associated with the scheduled maintenance outage on the date ranges in Table 1. Temperature data at the feedwater nozzle safe end (blue) and reactor (brown) is presented. Fen results are shown for the carbon steel feedwater nozzle safe end.

Figure 1: 5/18/2023 to 5/26/2023 Temperature Data to NL-25-0421 Response to RAI 4.3.7-1 E2-7 Table 2: 5/18/2023 to 5/26/2023 FP4 MRA Fen Result This plant specific demonstration provides additional confirmation that the average temperature approach is conservative when calculating the Fen value and environmentally adjusted cumulative usage factor (CUFen) for complex thermal transients at Hatch.

Edwin I. Hatch Nuclear Plant Unit 1 and 2 Subsequent License Renewal Application Response to Request for Additional Information and Request for Confirmation of Information, Set 1 to NL-25-0421 Response to RCIs B.2.3.27-1, B.2.3.33-1, and 3.5.2.2.2 to NL-25-0421 Response to RCIs B.2.3.27-1, B.2.3.33-1, and 3.5.2.2.2 E3-1 RCI B.2.3.27-1:

Based on discussions between the applicant and staff during the audit, it is the staffs understanding that in-scope buried diesel fuel oil storage tanks are from initial construction and have not been replaced. Confirm that the in-scope buried diesel fuel oil storage tanks are from initial construction and have not been replaced.

Response to RCI B.2.3.27-1:

SNC confirms that the in-scope buried diesel fuel oil storage tanks are from initial construction and have not been replaced.

RCI B.2.3.33-1:

The enhancements to the Parameters Monitored or Inspected program element of the Structures Monitoring AMP and Inspection of Water-Control Structures Associated with Nuclear Power Plants AMP state that Include surface staining in the list of alkali-silica reaction (ASR) indications.

Confirm that the complete list of ASR indications included in the enhanced Structures Monitoring AMP and the enhanced Inspection of Water-Control Structures Associated with Nuclear Power Plants AMP aligns with, or is equivalent to, the visual indications of aggregate reactions, such as map or patterned cracking, alkali silica gel exudations, surface staining, expansion causing structural deformation, relative movement or displacement, or misalignment/distortion of attached components, as described in SRP-SLR Sections 3.5.3.2.2.1, Item 2, and 3.5.3.2.2.3, Item 2.

Response to RCI B.2.3.33-1:

SNC confirms that the complete list of ASR indications included in the enhanced Structures Monitoring AMP and the enhanced Inspection of Water-Control Structures Associated with Nuclear Power Plants AMP, which is supplemented in letter NL-25-0342 to include the enhancement, is equivalent to the visual indications of aggregate reactions, such as map or patterned cracking, alkali silica gel exudations, surface staining, expansion causing structural deformation, relative movement or displacement, or misalignment/distortion of attached components, as described in SRP-SLR Sections 3.5.3.2.2.1, Item 2, and 3.5.3.2.2.3, Item 2.

RCI 3.5.2.2.2 SLRA Section 3.5.2.2.2.1, Item 1 and SLRA Section 3.5.2.2.2.3, Item 1 state The concrete met all the standard code requirements. Air entrainment content conformed to the design requirements of ACI 211.1 as determined by ASTM C231. The staff reviewed Hatch general concrete specification PDCR-PSOC-84-001 in the Portal, which indicates that the total air content of the concrete shall not be less than three percent nor more than five percent of the concrete by volume.

In addition, SLRA Section 3.5.2.2.2.1, Item 1 and SLRA Section 3.5.2.2.2.3, Item 1 state that OE has not identified any significant loss of material (spalling, scaling) and cracking due to freeze-thaw of reinforced concrete structures within the scope of license renewal.

Confirm that the air content of the existing concrete used in the in-scope structures was to NL-25-0421 Response to RCIs B.2.3.27-1, B.2.3.33-1, and 3.5.2.2.2 E3-2 between three percent and five percent.

Confirm that evaluation was performed and determined that the observed loss of material or cracking in accessible areas of the in-scope concrete structures discussed in SLRA Sections 3.5.2.2.2.1, Item 1, and 3.5.2.2.2.3, Item 1 had no impact on the intended function of the concrete structures.

Response to RCI 3.5.2.2.2:

SNC confirms that the total air content of the HNP concrete is not less than three percent nor more than five percent of the concrete by volume.

OE was evaluated for loss of material and cracking. SNC confirms that observed loss of material or cracking in accessible areas of the in-scope concrete structures discussed in SLRA Sections 3.5.2.2.2.1, Item 1, and 3.5.2.2.2.3, Item 1 had no impact on the intended function of the concrete structures.