LICENSE RENEWAL INTERIM STAFF GUIDANCE 

LR-ISG-2015-01 

CHANGES TO BURIED AND UNDERGROUND PIPING AND TANK RECOMMENDATIONS 

INTRODUCTION

This license renewal interim staff guidance (LR-ISG) LR-ISG-2015-01, “Changes to Buried and 

Underground Piping and Tank Recommendations,” provides changes to NUREG-1801, 

“Generic Aging Lessons Learned (GALL) Report,” Revision 2 (December 2010), and 

NUREG-1800, “Standard Review Plan for Review of License Renewal Applications for Nuclear 

Power Plants,” (SRP-LR), Revision 2 (December 2010), as described below. LR-ISG-2015-01 

replaces aging management program (AMP) XI.M41, “Buried and Underground Piping and 

Tanks,” and the associated Updated Final Safety Analysis Report Summary Description in 

LR-ISG-2011-03, “Changes to the Generic Aging Lessons Learned (GALL) Report, Revision 2 

Aging Management Program (AMP) XI.M41, ‘Buried and Underground Piping and Tanks’.” In 

addition, recommendations contained within AMP XI.M41 related to reductions in the extent of 

inspections to manage selective leaching in buried components were relocated to AMP XI.M33, 

“Selective Leaching.” These changes provide one acceptable approach for managing the 

associated aging effects for components within the scope of the License Renewal Rule (Title 10 

of the Code of Federal Regulations (10 CFR) Part 54, “Requirements for Renewal of Operating 

Licenses for Nuclear Power Plants”). A licensee may cite LR-ISG-2015-01 in its license renewal 

application (LRA) until the guidance in this LR-ISG is incorporated into the license renewal 

guidance documents (i.e., GALL Report, SRP-LR). 

DISCUSSION 

Based on industry operating experience and the staff’s review of LRAs and plant-specific buried 

and underground piping and tanks inspection reports since issuance of AMP XI.M41, the staff 

has determined that the GALL Report and SRP-LR should be revised to reflect new 

recommendations associated with AMP XI.M41. LR-ISG-2015-01 includes technical and 

editorial changes to AMP XI.M41. Based on changes to the extent of inspections of buried 

piping, the “detection of aging effects” inspection tables have been consolidated, resulting in 

elimination of duplicate recommendations. In addition, some details have been deleted 

because they have been deemed not necessary for an understanding of the recommendations 

for managing aging effects associated with buried and underground piping and tanks. 

Given the extensive reorganization of AMP XI.M41, a marked up version has not been provided. 

Description of Major Changes 

• Program Description Changes: the paragraph referencing the programs used to 

manage internal surfaces of buried and underground piping was deleted. The first 

paragraph of the Program Description states that AMP XI.M41 manages aging effects 

associated with the external surfaces of buried and underground components. The staff 

concluded that there was no need to direct the user to other AMPs that are used to 

manage the internal surfaces of the components. The wording “of the external surfaces 

of,” was added to the “scope of program” program element for clarity. 
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• Changes in Aging Effects: the “scope of program” and “parameters monitored or 

inspected” elements were revised to clarify that the changes in material properties aging 

effect is only applicable to cementitious (cement-based substance) materials. GALL 

Report, Revision 2 stated that a change in material properties was associated with 

polymeric materials. The “parameters monitored or inspected” program element was 

revised to state that loss of material due to wear can occur in polymeric materials. Loss 

of material due to wear can occur in polymeric components buried in soil containing 

deleterious materials (e.g., rocks, debris) that move over time due to seasonal change 

effects on the soil. The staff has concluded that for the polymeric materials addressed in 

the GALL Report (i.e., fiberglass, high-density polyethylene (HDPE), polyvinyl chloride 

(PVC)), there is reasonable assurance that changes in material properties will not occur 

as a result of contact with typical soil environments. However, the soil environment, as a 

result of deleterious materials (e.g., sharp rocks, foreign material) can cause loss of 

material and potential groundwater exposure can result in change in material properties 

of cementitious materials. 

• Upper Limits on Cathodic Protection Criterion: the maximum negative 1200 millivolt 

(mV) cathodic protection criterion was relocated from the “acceptance criteria” program 

element to the “preventive actions” program element. NACE International [formerly the 

National Association of Corrosion Engineers] SP [Standard Practice] 0169-2007, 

“Control of External Corrosion on Underground or Submerged Metallic Piping Systems,” 

states that the use of excessive polarized potentials should be avoided; however, it does 

not establish a specific upper limit as an acceptance criterion for the performance of 

cathodic protection systems. The standard specifically states: (a) Section 6.2.2.3.3, 

“[t]he use of excessive polarized potentials on externally coated pipelines should be 

avoided to minimize cathodic disbondment of the coating;” and (b) Section 6.2.2.3.4, 

“[p]olarized potentials that result in excessive generation of hydrogen should be avoided 

on all metals, particularly higher strength steel, certain grades of stainless steel, titanium 

alloy, aluminum alloys, and prestressed concrete cylinder pipe.” Based on these 

statements, the staff relocated the negative 1200 mV cathodic protection criterion to a 

recommendation within the “preventive actions” program element. Likewise, the 

recommended upper polarization potentials of no more negative than negative 

1,000 mV relative to a copper/copper sulfate reference electrode (CSE) for cementitious 

containing high-strength prestressing wire was relocated. It is the staff’s intent that if an 

applicant chooses to use an alternative limit, the applicant would state an exception and 

a basis for the alternative value. This approach is the same for any of the other 

recommendations in the “preventive action” program element. However, if a survey data 

point is more negative than the upper negative limit during periodic cathodic protection 

surveys, the data point would no longer be considered as failing cathodic protection 

acceptance criteria (i.e., those recommended in the “acceptance criteria” program 

element). The exceedance of the upper limit would be addressed in the licensee’s 

corrective action or preventive maintenance program. This change allows licensees 

flexibility in balancing the performance of its cathodic protection systems. 

The staff also added a recommendation related to the potential for stress corrosion 

cracking of steel and stainless steel components. Because this cracking is dependent 

on plant-specific characteristics (e.g., the cathodic protection polarization level, 

temperature, pH), the staff did not incorporate specific recommendations. If these 
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conditions are applicable, the applicant describes the conditions and alternative cathodic 

protection levels in the LRA. 

• Coatings on Underground Components: the recommended preventive actions for 

underground steel and copper alloy piping and tanks were changed to recommend that 

coatings be used. Prior to this change, the recommended preventive actions for 

coatings on steel and copper alloy piping stated, “when provided, coatings are in 

accordance with ...” As a result of this change, if an applicant’s underground steel or 

copper alloy piping is not coated, the applicant would state an exception and the 

technical basis for the acceptability of the exception (e.g., demonstrate that the condition 

should not require additional inspections or other actions). The staff incorporated this 

change because, based on the review of plant-specific documents during audits, it noted 

that the typical air conditions in underground vaults have higher moisture content than 

uncontrolled indoor air conditions in plant spaces within buildings. During walkdowns 

and its review of corrective action documents, the staff noted that loss of material has 

occurred in the vaults. 

• Parameters Monitored or Inspected: based on public comment, the staff added

descriptive detail to this program element. 

• Manual Manipulation of Polymeric Materials: the recommendation to augment 

polymeric material inspections with manual examinations was eliminated. The staff has 

concluded that flexible polymeric materials are not typically used in buried or 

underground piping or tank pressure boundary applications, and therefore, manual 

examinations do not add value. 

• Fire Water System Leak Rate Tests: an annual system leak rate test was added to the 

list of alternatives to preventive actions and to conducting visual examinations of the 

external surfaces of fire mains installed in accordance with NFPA® [National Fire 

Protection Association] 24. The staff has concluded that annual system leak rate tests 

are as effective as annual flow tests (already allowed in AMP XI.M41) to detect 

degradation of buried fire main piping. 

• Availability of Cathodic Protection: the term “availability” in relation to cathodic 

protection was changed to “operated.” The staff concluded that the term “available” may 

result in licensees concluding that as long as cathodic protection equipment was 

installed, it is available. However, the intent of the staff was that the cathodic protection 

system should be providing protection. 

• Timing of Additional Inspections: a provision was added to the “detection of aging 

effects” program element to address the timing of additional inspections when 

plant-specific conditions result in transitioning to a higher inspection category during a 

current 10-year inspection interval. The staff recognizes that the complexity of 

conducting visual examinations of buried piping requires extensive planning and 

scheduling. The staff concluded that deferring additional examinations to no later than 

the end of two refueling cycles in the next interval would not present an unacceptable 

level of uncertainty regarding the condition of buried piping components. 

• Adverse Indications and Conditions: the terms, “adverse indications” and “adverse 

conditions” referring to unacceptable inspection findings were replaced with “coatings, 

backfill or the condition of exposed piping that does not meet acceptance criteria.” This 
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change ensures that follow-on actions as a result of unacceptable inspection findings are 

appropriate for the magnitude of the degradation. In addition, this change makes the 

AMP more consistent with other GALL Report AMPs, which refer to acceptance criteria 

rather than terms such as “adverse indications” and “adverse conditions.” 

• Sample Size Increase: the sample size increase previously stated in the “acceptance 

criteria” program element was revised and moved to the “corrective actions” program 

element. Two changes were incorporated. 

The first change was to set a maximum limit of five additional inspections. The 

recommendation in LR-ISG-2011-03 was to double the number of inspections from a 

specific category. The staff recognizes that for some material types, depending on the 

effectiveness of the preventive actions, the previous sample size increase would result in 

significantly more inspections. The maximum of five additional inspections is based on 

the guidance provided in Generic Letter 90-05, “Guidance for Performing Temporary 

Non-Code Repair of ASME Code Class 1, 2, and 3 Piping.” The staff has concluded that 

doubling the number of inspections or conducting five additional inspections, whichever 

is less, will provide adequate insights to the licensee in regard to the condition of buried 

components. 

Based on its review of an extensive number of buried pipe inspection results, the staff 

also recognizes that there are instances where minor coating or base material damage 

is noted. However, the depth or extent of the damage to the base material would not 

warrant an increase in the sample size. The intended function of typical buried piping 

and tanks is to ensure that sufficient flow at adequate pressure can be delivered to 

downstream in-scope components. This function could be met even though leakage is 

occurring. The staff revised the sample size increase recommendation to those 

instances where degradation in base material (extrapolated to the end of the period of 

extended operation), regardless of cause, results in a potential challenge to the pressure 

boundary. 

• Extent of Inspections: Table XI.M41-2 (previously Table 4a), “Inspections of Buried 

Pipe,” was significantly revised. During the development of GALL Report, Revision 2, 

the staff became aware of a number of industry operating experience examples where 

leakage had occurred. As a result the staff developed AMP XI.M41, Table XI.M41-2, 

which resulted in recommendations for buried pipe inspections based on the material 

type, effectiveness of preventive actions (i.e., coatings, backfill, cathodic protection), soil 

sampling, and plant-specific operating experience. The number of inspections in each 

10-year period for plants with effective preventive actions (i.e., one inspection per 

10-year period starting 10 years prior to the period of extended operation) was not 

significantly changed from that of GALL Report, Revision 1. The staff established a new 

tier of inspections (i.e., Inspection Category D) for plants that could demonstrate that 

cathodic protection was not required based on plant-specific data (i.e., two inspections 

per 10-year period starting 10 years prior to the period of extended operation). 

However, for plants where: (a) the preventive actions, particularly cathodic protection, 

were not effective, (b) cathodic protection was not used; (c) plant-specific operating 

experience revealed significant buried piping or coating degradation; or (d) soil sampling 

revealed that the soil is corrosive, new Inspection Categories E and F were developed in 

GALL Report, Revision 2. Therefore, the number of inspections for these two new 
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categories was substantially increased in each 10-year interval in GALL Report, 

Revision 2. 

Based on the staff’s continuing review of industry operating experience and 

plant-specific buried piping inspection results, the staff has noted that: (a) there have 

been no failures of the intended function of buried piping components (i.e., sufficient flow 

at adequate pressure is delivered); (b) coating degradation, when found, is generally 

limited in extent; (c) metal loss outside of the immediate vicinity of degraded coatings is 

minimal; and (d) as a result of the industry’s buried pipe initiative, awareness of the 

importance of cathodic protection and the condition of coatings has greatly improved. 

As a result, the staff has reduced the number of inspections recommended for buried 

piping components for Inspection Categories E and F. The new extent of inspections is 

loosely based on NEI [Nuclear Energy Institute] 09-14, “Guideline for the Management of 

Underground Piping and Tank Integrity,” Revision 3. Appendix C, “Guidance for 

Inspection and Condition Assessment of Buried and Underground Piping and Tanks,” of 

this document established a range of one to three inspections per buried pipe grouping. 

This document credited indirect inspections. The staff has not credited indirect (e.g., 

guided wave examinations) inspections as an alternative to direct visual inspections of 

the external surfaces of buried piping. The staff concluded that three inspections (or 5 

percent of the piping length) per 10-year interval commencing 10 years prior to the 

period of extended operation will provide reasonable assurance that the pressure 

boundary function of buried steel, copper alloy, or aluminum alloy piping components will 

be met during the period of extended operation for Inspection Category E. To conduct 

inspections for Category E, it is permissible that cathodic protection does not meet 

performance goals; however, the conditions necessary to meet Category E are: 

coatings have been provided, backfill meets the recommendations in the “preventive 

actions” program element, plant-specific operating experience meets expectations, and 

soil sampling demonstrates that the soil is not corrosive. The number of inspections for 

Category F, if Category E had not been met, is six inspections (or 10 percent of the 

piping length) per 10-year interval commencing 10 years prior to the period of extended 

operation. It should be noted that an expansion of sample size is conducted if coatings, 

backfill, or the exposed piping condition does not meet acceptance criteria. 

• Alternative Cathodic Protection Acceptance Criteria: the following alternative 

cathodic protection acceptance criteria were added: (a) negative 750 mV relative to a 

CSE instant off where soil resistivity is greater than 10,000 ohm-centimeters (ohm-cm) to 

less than 100,000 ohm-cm; (b) negative 650 mV relative to a CSE, instant off where soil 

resistivity is greater than 100,000 ohm-cm, and (c) verifying less than 1 mil per year 

(mpy) loss of material. 

The staff added the alternative acceptance criteria for higher resistivity soils based on: 

(a) its inclusion in international standards; (b) the staff’s review of industry papers on the 

alternative acceptance criteria; and (c) the recommendation to verify the acceptability 

(e.g., 1 mpy) of the alternative criteria as described in the above discussion associated 

with adding the 1 mpy loss of material criterion. ISO [International Organization for 

Standardization] 15589:2003, “Petroleum and Natural Gas Industries -- Cathodic 

Protection of Pipeline Transportation Systems -- Part 1: On-land Pipelines,” and British 

Standard, EN 12954:2001, “Cathodic Protection of Buried or Immersed Metallic 

Structures - General Principles and Application for Pipelines,” allow use of the alternative 
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cathodic protection criteria in higher resistivity soils. NACE Corrosion Expo 2006, Paper 

No. 06163, “Cathodic Protection of Pipelines in High Resistivity Soils and the Effects of 

Seasonal Changes,” and NACE Corrosion Expo 2012, Paper No. C2012-001165, 

“Evaluation of Global Cathodic Protection Criteria – Part 3: Effectiveness of the -100 mV 

Polarization Criterion and Various Off-Potentials with Higher Resistivity Soils, Elevated 

Temperatures, and Soils with Bacteria,” support the use of alternative cathodic 

protection acceptance criteria in higher resistivity soils. 

The staff added the loss of material rate based on NACE International 

Publication 05107, “Report on Corrosion Probes in Soil or Concrete,” which states that 

an average corrosion rate of less than 1 mpy over a 12-month monitoring period is 

generally accepted as an indication that cathodic protection is effective. Based on public 

comments, the staff expanded the 1 mpy criterion to allow higher loss of material rates in 

instances where the higher rate would not result in a loss of intended function prior to the 

end of the period of extended operation. The staff concluded that loss of material rates 

that exceed 1 mpy are acceptable when plant-specific configurations (e.g., thicker wall 

pipe) enable a demonstration that adequate wall thickness will be maintained throughout 

the period of extended operation. 

• Use of Electrical Resistance Corrosion Rate Probes and Associated Acceptance 

Criterion: When alternative cathodic protection criteria are used, the AMP incorporates 

verification of the effectiveness of the protection of the most anodic metal. An 

acceptable method for this verification is to measure that external loss of material rate 

using electrical resistance corrosion rate probes to measure that external loss of material 

rate. When using electrical resistance probes, the applicant states (a) the qualifications 

of the individuals who will determine the installation locations of the probes and the 

methods of use (e.g., NACE CP4, “Cathodic Protection Specialist”); and (b) how the 

impact of significant site features (e.g., large cathodic protection current collectors, 

shielding due to large objects located in the vicinity of the protected piping) and local soil 

conditions will be factored into placement of the probes and use of probe data. Based 

on these new recommendations, there is reasonable assurance that: (a) the cathodic 

protection system will be protecting the buried steel piping consistent with the 

plant-specific corrosion rate bases and (b) the design and use of the buried piping 

coupons will be sufficient to detect actual corrosion rates. The AMP confirms the 

external loss of material rate on a specified periodicity. 

• Selective Leaching Inspections: the recommendations in AMP XI.M41 related to 

reductions in the extent of inspections for AMP XI.M33, “Selective Leaching,” have been 

moved to AMP XI.M33 with no technical changes. See Appendix C. 

• Operating Experience: industry operating experience examples were updated. 
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ACTIONS 

Applicants should use Appendices A through C in preparing their LRAs to be consistent with the 

GALL Report and this LR-ISG. 

NEWLY IDENTIFIED SYSTEMS, STRUCTURES, AND COMPONENTS UNDER 

10 CFR 54.37(b) 

The NRC is not proposing to treat the revised recommendations for managing aging effects 

associated with buried and underground piping and tanks as “newly identified” systems, 

structures, components (SSCs) under 10 CFR 54.37(b). Therefore, any additional action for 

such SSCs, which the NRC may impose upon current holders of renewed operating licenses 

under 10 CFR Part 54, would not fall within the scope of 10 CFR 54.37(b). The NRC would 

address compliance with the requirements of 10 CFR 50.109, “Backfitting,” before imposing any 

new aging management requirements on current holders of renewed operating licenses (see 

discussion below). 

BACKFITTING AND ISSUE FINALITY 

This LR-ISG contains guidance on one acceptable approach for managing the associated aging 

effects occurring during the period of extended operation for buried and underground piping and 

tanks. The staff intends to use the guidance in this LR-ISG when reviewing current and future 

license renewal applications. The staff also intends to use the LR-ISG in evaluating voluntary, 

licensee-initiated changes to previously-approved AMPs. Existing holders of renewed operating 

licenses may follow the guidance in this LR-ISG, but would not be required to do so. 

Backfitting 

Issuance of this LR-ISG does not constitute backfitting as defined in the Backfit Rule for nuclear 

power plants, 10 CFR 50.109(a)(1), and the NRC staff did not prepare a backfit analysis for 

issuing this LR-ISG. There are several rationales for this conclusion, depending on the status of 

the nuclear power plant licensee under 10 CFR Parts 50 and 54. 

Licensees currently in the license renewal process - The backfitting provisions in 

10 CFR 50.109 are not applicable to an applicant for a renewed license. Therefore, issuance of 

this LR-ISG would not constitute backfitting as defined in 10 CFR 50.109(a)(1). 

Licensees that already hold a renewed license - This guidance would be nonbinding and the 

LR-ISG would not require current holders of renewed licenses to take any action (i.e., 

programmatic or plant hardware changes for managing the associated aging effects for 

components within the scope of this LR-ISG). Current holders of renewed licenses could treat 

the information presented in this LR-ISG as “operating experience” information and consider this 

information to ensure that relevant AMPs are, and will remain, effective. If, in the future, the 

NRC decides to take additional action and impose requirements for managing the associated 

aging effects for components within the scope of this LR-ISG, then the NRC would follow the 

requirements of the Backfit Rule. 

Current 10 CFR Part 50 operating license holders that have not yet applied for renewed 

licenses - The backfitting provisions in 10 CFR 50.109 do not apply to any future applicant for 

license renewal. Therefore, issuance of this LR-ISG would not constitute backfitting as defined 

in 10 CFR 50.109(a)(1). 
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Issue Finality under 10 CFR Part 52 

Issuance of this LR-ISG is not inconsistent with the issue finality provision applicable to 

standard design certifications, 10 CFR 52.63, or the specific issue finality provisions in each of 

the approved design certification rules within the appendices of 10 CFR Part 52. The design 

certification information for the rules in 10 CFR Part 72 does not address compliance with the 

license renewal requirements in 10 CFR Part 54. Therefore, the issue finality provisions 

applicable to these design certifications do not extend to the nuclear safety issues of license 

renewal and the NRC need not address these issue finality provisions when issuing this LRISG. 

Issuance of this LR-ISG would not be inconsistent with the issue finality provision, 

10 CFR 52.98, which is applicable to current combined licenses issued under 10 CFR Part 52. 

The NRC’s issuance of those combined licenses was not based upon any consideration of 

compliance with the license renewal requirements in 10 CFR Part 54. Furthermore, the issue 

finality provisions of 10 CFR Part 52 do not extend to the aging management matters covered 

by 10 CFR Part 54, as evidenced by the requirement in 10 CFR 52.107, “Application for 

Renewal,” stating that applications for renewal of a combined license must be in accordance 

with 10 CFR Part 54. Therefore, the issue finality provisions applicable to the current holders of 

combined licenses do not extend to the subject of license renewal and the NRC need not 

address § 52.98 when issuing this LR-ISG. 

Currently no holders of combined licenses are seeking license renewal under 10 CFR Part 54, 

and the issue finality provisions in 10 CFR Part 52 are not applicable to future applicants 

seeking a renewed license. Therefore, the changes and new positions presented in the LR-ISG 

may be made without consideration of the issue finality provisions in 10 CFR Part 52. 

CONGRESSIONAL REVIEW ACT 

This LR-ISG is a rule as defined in the Congressional Review Act (5 U.S.C. §§ 801-808). 

However, the Office of Management and Budget has not found it to be a major rule as defined in 

the Congressional Review Act. 

APPENDICES 

Appendix A, SRP-LR, Table 3.0-1, FSAR Supplement for AMP XI.M41 

Appendix B, Revised AMP XI.M41, Buried and Underground Piping and Tanks

Appendix C, Changes to GALL Report AMP XI.M33, Selective Leaching, to the Detection of 

Aging Effects Program Element 

REFERENCES

5 U.S.C. § 801, Congressional Review of Agency Rulemaking, Office of the Law Revision 

Counsel of the House of Representatives, 2012. 

10 CFR Part 50, Domestic Licensing of Production and Utilization Facilities, Office of the 

Federal Register, National Archives and Records Administration, 2015. 

10 CFR Part 54, Requirements for Renewal of Operating Licenses for Nuclear Power Plants, 

Office of the Federal Register, National Archives and Records Administration, 2015. 
- 9 - 

British Standard EN 12954:2001, Cathodic Protection of Buried or Immersed Metallic 

Structures - General Principles and Application for Pipelines. 

International Organization for Standardization, ISO 15589:2003, Petroleum and Natural Gas 

Industries -- Cathodic Protection of Pipeline Transportation Systems -- Part 1: On-land 

Pipelines. 

NACE, NACE International Publication 05107, Report on Corrosion Probes in Soil or Concrete. 

NACE, NACE Corrosion Expo 2006, Paper No. 06163, Cathodic Protection of Pipelines in High 

Resistivity Soils and the Effects of Seasonal Changes. 

NACE, NACE Corrosion Expo 2012, Paper No. C2012-001165, Evaluation of Global Cathodic 

Protection Criteria – Part 3: Effectiveness of the -100 mV Polarization Criterion and Various 

Off-Potentials with Higher Resistivity Soils, Elevated Temperatures, and Soils with Bacteria. 

Nuclear Energy Institute, NEI 09-14, Guideline for the Management of Underground Piping and 

Tank Integrity, Revision 3. 

U.S. Nuclear Regulatory Commission, Regulatory Guide 1.54, Revision 2, Service Level I, II, 

and III Protective Coatings Applied to Nuclear Power Plants. 

U.S. Nuclear Regulatory Commission, Generic Letter 90-05, Guidance for Performing 

Temporary Non-Code Repair of ASME Code Class 1, 2, and 3 Piping. 

U.S. Nuclear Regulatory Commission, NUREG-1801, Revision 2, Generic Aging Lessons 

Learned (GALL) Report, December 2010. 

U.S. Nuclear Regulatory Commission, NUREG-1800, Revision 2, Standard Review Plan for 

Review of License Renewal Applications for Nuclear Power Plants, December 2010.
APPENDIX A 

SRP-LR TABLE 3.0-1, FSAR SUPPLEMENT for AMP XI.M41 

A-1 

Table 3.0-1 FSAR Supplement for Aging Management of Applicable Systems 

GALL 

Chapter 

GALL 

Program Description of Program Implementation Schedule* 

XI.M41 

Buried and Underground Piping and Tanks 

This program is a 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, cracking and changes in material properties (for cementitious piping). It addresses 

piping and tanks composed of any material, including metallic, 

polymeric, and cementitious materials. The program also manages aging through preventive and mitigative actions (i.e., coatings, backfill quality, and cathodic protection). The number of inspections is based on the effectiveness of the preventive and mitigative actions. Annual cathodic protection surveys are conducted. For steel components, where the acceptance criteria for the effectiveness of the cathodic protection is other than -850 mV instant off, loss of material rates are measured. Inspections are conducted by qualified individuals. Where the coatings, backfill or the condition of exposed piping does not meet 

acceptance criteria such that the depth or extent of degradation of the base metal could have resulted in a loss of pressure boundary function when the loss of material rate is extrapolated to the end of the period of extended operation, an increase in the sample size is conducted. If a reduction in the number of inspections recommended in GALL Report, AMP XI.M41, Table XI.M41-2 is claimed based on a lack of soil corrosivity as determined by soil testing, then soil testing is conducted once in each 10-year period starting 10 years prior to the period of extended operation. 

Program should be implemented before the period of extended operation 
APPENDIX B 

REVISED AMP XI.M41, BURIED AND UNDERGROUND PIPING AND TANKS 

B-1 

Program Description 

The program manages the aging of the external surfaces of buried and underground piping and 

tanks. It addresses piping and tanks composed of any material, including metallic, polymeric, 

and cementitious materials. This program manages aging through preventive, mitigative, 

inspection, and in some cases, performance monitoring activities. It manages applicable aging 

effects such as loss of material, cracking, and changes in material properties (for cementitious 

piping only). 

Depending on the material, preventive and mitigative techniques may include external coatings, 

cathodic protection, and the quality of backfill. Also, depending on the material, inspection 

activities may include electrochemical verification of the effectiveness of cathodic protection, 

nondestructive evaluation of pipe or tank wall thicknesses, pressure testing of the pipe, 

performance monitoring of fire mains, and visual inspections of the pipe or tank from the 

exterior. 

This program does not provide aging management of selective leaching. The Selective 

Leaching of Materials program (AMP XI.M33) is applied in addition to this program for 

applicable materials and environments. 

Evaluation and Technical Basis 

1. Scope of Program: This program manages the effects of aging of the external surfaces of 

buried and underground piping and tanks constructed of any material including metallic, 

polymeric, and cementitious materials. The term “polymeric” material refers to plastics or 

other polymers that comprise the pressure boundary of the component. The program 

addresses aging effects such as loss of material, cracking, and changes in material 

properties (for cementitious piping only). The program also manages loss of material due to 

corrosion of piping system bolting within the scope of this program. The Bolting Integrity 

Program (AMP XI.M18) manages other aging effects associated with piping system bolting. 

This program does not provide aging management of selective leaching. The Selective 

Leaching of Materials (AMP XI.M33) is applied in addition to this program for applicable 

materials and environments. 

2. Preventive Actions: Preventive actions utilized by this program vary with the material of the 

tank or pipe and the environment (e.g., air, soil, concrete) to which it is exposed. There are 

no recommended preventive actions for titanium alloy, super austenitic stainless steels, and 

nickel alloy materials. Preventive actions for buried and underground piping and tanks are 

conducted in accordance with Table XI.M41-1 and the following:

Table XI.M41-1. Preventive Actions for Buried and Underground Piping and Tanks 

C: Coatings; CP: Cathodic Protection; B: Backfill 

Material Buried Underground 

Stainless Steel C, B None 

Steel C, CP, B C 

Copper alloy C, CP, B C 

Aluminum alloy C, CP, B None 
APPENDIX B 

REVISED AMP XI.M41, BURIED AND UNDERGROUND PIPING AND TANKS 

B-2 

Table XI.M41-1. Preventive Actions for Buried and Underground Piping and Tanks 

C: Coatings; CP: Cathodic Protection; B: Backfill 

Material Buried Underground 

Cementitious C, CP, B None 

Polymer B None 

a. For buried stainless steel or cementitious piping or tanks, coatings are provided based 

on the environmental conditions (e.g., stainless steel in chloride containing 

environments). Applicants provide justification when coatings are not provided. Coatings 

are in accordance with Table 1 of NACE SP0169-2007 or Section 3.4 of 

NACE RP0285-2002 as well as the following coating types: asphalt/coal tar enamel, 

concrete, elastomeric polychloroprene, mastic (asphaltic), epoxy polyethylene, 

polypropylene, polyurethane, and zinc. 

b. For buried steel, copper alloy, and aluminum alloy piping and tanks and underground 

steel and copper alloy piping and tanks, coatings are in accordance with Table 1 of 

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

c. Cathodic protection is in accordance with NACE SP0169-2007 or NACE RP0285-2002. 

The system is operated so that the cathodic protection criteria and other considerations 

described in the standards are met at every location in the system for which cathodic 

protection is credited. The system monitoring interval discussed in Section 10.3 of 

NACE SP0169-2007 may not be extended beyond one year. The equipment used to 

implement cathodic protection need not be qualified in accordance with 10 CFR Part 50, 

Appendix B. 

d. Cathodic protection is supplied for reinforced concrete pipe and prestressed concrete 

cylinder pipe. Applicants provide justification when cathodic protection is not provided. 

e. Critical potentials for cathodic protection: 

i. To prevent damage to the coating or base metal (e.g., aluminum), the limiting critical 

potential should not be more negative than -1200 mV. 

ii. Where an impressed current cathodic protection system is utilized with prestressed 

concrete cylinder pipe, steps are taken to avoid an excessive level of potential that 

could damage the prestressing wire. Therefore, polarized potentials more negative 

than -1,000 mV relative to a CSE are avoided to prevent hydrogen generation and 

possible hydrogen embrittlement of the high-strength prestressing wire. 

iii. Depending on the environment, steel and stainless steel components can experience 

stress corrosion cracking dependent on the cathodic protection polarization level, 

temperature, pH, etc. If these conditions are applicable, the applicant describes the 

conditions and alternative cathodic protection levels in the LRA. 

iv. Any further over-protection limits are defined by the applicant and managed during 

surveillance activities. The use of excessive polarized potentials on externally coated 

pipelines should be avoided. 
APPENDIX B 

REVISED AMP XI.M41, BURIED AND UNDERGROUND PIPING AND TANKS 

B-3 

f. Backfill is consistent with SP0169-2007 Section 5.2.3 or NACE RP0285-2002, Section 

3.6. The staff considers 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) to meet 

the objectives of NACE SP0169-2007 and NACE RP0285-2002. For stainless steel and 

cementitious materials, backfill limits apply only if the component is coated. For 

materials other than aluminum alloy, the staff also considers the use of controlled low 

strength materials (flowable backfill) acceptable to meet the objectives of SP0169-2007. 

g. Alternatives to the preventive actions in Table XI.M41-1 are as follows:

i. A broader range of coatings may be used if justification is provided in the LRA. 

ii. Backfill quality may be demonstrated by plant records or by examining the backfill 

while conducting the inspections described in the “detection of aging effects” 

program element of this AMP. 

iii. For fire mains installed in accordance with National Fire Protection Association 

(NFPA) NFPA® 24, preventive actions beyond those in NFPA® 24 need not be 

provided if: (a) the system undergoes either a periodic flow test in accordance with 

NFPA® 25; (b) the activity of the jockey pump (e.g., number of pump starts, run time) 

is monitored as described in “detection of aging effects” program element of this 

AMP; or (c) an annual system leakage rate test is conducted. 

iv. Failure to provide cathodic protection in accordance with Table XI.M41-1 may be 

acceptable if justified in the LRA. 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 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 operating experience search are included in the LRA. 

3. Parameters Monitored or Inspected:

a. Visual inspections of: (a) the external surface condition of buried or underground piping 

or tanks; (b) the external surface condition of associated coatings; or (c) external 

surfaces of controlled low strength material backfill are performed. Monitoring of the 

surface condition of the component is conducted to ensure that the aging effects under 

3.b are not present or have not progressed to such a degree where a loss of intended 

function could occur. Monitoring of the surface condition of coatings is conducted to 

ensure that the coatings are intact, well-adhered, and otherwise sound; such that aging 

effects would not be expected for the base material of the component. Monitoring of the 

external surfaces of controlled low strength material backfill is conducted to ensure that 

there are no cracks present that could admit groundwater to the surface of the 

component. 

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

i. loss of material due to general, pitting, crevice, and microbiologically-influenced 

corrosion (MIC) for aluminum alloy (MIC is not applicable for aluminum alloys), 

copper alloy, steel, stainless steel, super austenitic, and titanium alloy components; 
APPENDIX B 

REVISED AMP XI.M41, BURIED AND UNDERGROUND PIPING AND TANKS 

B-4 

ii. loss of material due to wear for polymeric materials; 

iii. cracking, spalling, and corrosion or exposure of rebar for cementitious pipe; 

iv. cracking, blistering, change in color due to water absorption for high-density 

polyethylene (HDPE) and fiberglass components; 

v. cracking due to aggressive chemical attack and leaching for cementitious piping; and 

vi. changes in material properties due to aggressive chemical attack for cementitious 

piping as evidenced by visual indications such as cracking, exfoliation, spalling, 

scaling, or residue or deposits from leaching of the concrete. 

c. Volumetric nondestructive examination techniques as well as pit depth gages or calipers 

may be used for measuring wall thickness as long as: (a) they have been demonstrated 

to be effective for the material, environment, and conditions (e.g., remote methods) 

during the examination; and (b) they are capable of quantifying general wall thickness 

and the depth of pits. Wall thickness measurements are conducted to ensure that 

minimum wall thickness requirements are met. 

d. Inspections for cracking due to stress corrosion cracking for steel, stainless steel and 

susceptible aluminum alloy materials utilize a method that has been demonstrated to be 

capable of detecting cracking. Coatings that: (a) are intact, well-adhered, and otherwise 

sound for the remaining inspection interval; and (b) exhibit small blisters that are few in 

number and completely surrounded by sound coating bonded to the substrate do not 

have to be removed. Inspections for cracking are conducted to assess the impact of 

cracks on the pressure boundary function of the component. 

e. Pipe-to-soil potential and the cathodic protection current are monitored for steel, copper 

alloy, and aluminum alloy piping and tanks in contact with soil to determine the 

effectiveness of cathodic protection systems. 

f. When using alternatives to excavated direct visual examination of fire mains, appropriate 

inspection parameters are used in order to detect indications of fire main leakage. For 

example: 

i. During periodic flow test, a reduction in available flow rate. 

ii. For jockey pump monitoring, an increase in the number of pump starts or run time of 

the pump. 

iii. During annual system leakage rate testing an increase in unaccounted flow leak 

rates (i.e., the leakage path could be through a valve disc and seat, which is not 

pertinent to this AMP). 

4. Detection of Aging Effects: Methods and frequencies used for the detection of aging 

effects vary with the material and environment of the buried and underground piping and 

tanks. Inspections of buried and underground piping and tanks are conducted in 

accordance with Table XI.M41-2 and the following. There are no inspection 

recommendations for titanium alloy, super austenitic, or nickel alloy materials. 

Table XI.M41-2 inspection quantities are for a single unit plant. For two-unit sites, the 

inspection quantities (i.e., not the percentage of pipe length) are increased by 50 percent. 

For a three-unit site, the inspection quantities are doubled. For multi-unit sites, the 

inspections are distributed evenly among the units. Additional inspections, beyond those in 

Table XI.M41-2 may be appropriate if exceptions are taken to program element 2, 

“preventive actions,” or in response to plant-specific operating experience. 
APPENDIX B 

REVISED AMP XI.M41, BURIED AND UNDERGROUND PIPING AND TANKS 

B-5 

Inspections of buried and underground piping and tanks are conducted during each 10-year 

period, commencing 10 years prior to the period of extended operation. Piping inspections 

are typically conducted by visual examination of the external surfaces of pipe or coatings. 

Tank inspections are conducted externally by visual examination of the surfaces of the tank 

or coating or internally by volumetric methods. Opportunistic inspections are conducted for 

in-scope piping whenever they become accessible. Visual inspections are supplemented 

with surface and/or volumetric nondestructive testing if evidence of wall loss beyond minor 

surface scale is observed. 

Table XI.M41-2. Inspection of Buried and Underground Piping and Tanks 

Inspections of Buried Piping 

Material Preventive Action 

Categories 

Inspection 

See section 4.c. for extent 

of inspections 

Stainless Steel 1 inspection 

Polymeric 

Backfill is in accordance with 

preventive actions program 

element 

1 inspection 

Backfill is not in accordance 

with preventive actions 

program element 

The smaller of 1% of the 

length of pipe or 2 

inspections 

Cementitious 1 inspection 

Steel 

C The smaller of 0.5% of the 

piping length or 1 inspection 

D The smaller of 1% of the 

piping length or 2 

inspections 

E The smaller of 5% of the 

piping length or 3 

inspections 

F The smaller of 10% of the 

piping length or 6 

inspections 

 
APPENDIX B 

REVISED AMP XI.M41, BURIED AND UNDERGROUND PIPING AND TANKS 

B-6 

Table XI.M41-2. Inspection of Buried and Underground Piping and Tanks 

Copper alloy 

C The smaller of 0.5% of the 

piping length or 1 inspection 

D The smaller of 1% of the 

piping length or 2 

inspections 

E The smaller of 5% of the 

piping length or 3 

inspections 

F The smaller of 10% of the 

piping length or 6 

inspections 

Aluminum alloy 

C The smaller of 0.5% of the 

piping length or 1 inspection 

D The smaller of 1% of the 

piping length or 2 

inspections 

E The smaller of 5% of the 

piping length or 3 

inspections 

F The smaller of 10% of the 

piping length or 6 

inspections 

Inspections of Buried Tanks and Underground Piping and Tanks 

Material Buried Tanks Underground 

Piping 

Underground 

Tanks 

Stainless Steel All tanks 1 inspection All tanks 

Polymeric All tanks 1 inspection None 

Cementitious All tanks 1 inspection None 

Steel All tanks 

The smaller of 2% of 

the piping length or 2 

inspections 

All tanks 
APPENDIX B 

REVISED AMP XI.M41, BURIED AND UNDERGROUND PIPING AND TANKS 

B-7 

Table XI.M41-2. Inspection of Buried and Underground Piping and Tanks 

Copper alloy or 

Aluminum alloy All tanks 

The smaller of 1% of 

the length of piping 

or 1 inspection 

All tanks 

The Preventive Action Categories are used as follows: 

A: Category A no longer used 

B: Category B no longer used 

C: Category C applies when: 

a. Cathodic protection was installed or refurbished 5 years prior to the end of the 

inspection period of interest; and 

b. Cathodic protection has operated at least 85 percent of the time since either 10 

years prior to the period of extended operation or since installation/refurbishment, 

whichever is shorter. Time periods in which the cathodic protection system is 

off-line for testing do not have to be included in the total nonoperating hours; and 

c. Cathodic protection has provided effective protection for buried piping as evidenced 

by meeting the acceptance criteria of Table XI.M41-3 of this AMP at least 80 

percent of the time since either 10 years prior to the period of extended operation or 

since installation/refurbishment, whichever is shorter. As found results of annual 

surveys are to be used to demonstrate locations within the plant’s population of 

buried pipe where cathodic protection acceptance criteria have, or have not, been 

met. 

D: Inspection criteria provided for Category D piping may be used for those portions of 

in-scope buried piping where it has been demonstrated, in accordance with the 

“preventive actions” program element of this AMP, that external corrosion control is not 

required. 

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

population of buried piping where: 

a. An analysis, conducted in accordance with the “preventive actions” program 

element of this AMP, has demonstrated that installation or operation of a cathodic 

protection system is impractical; or 

b. A cathodic protection system has been installed but all or portions of the piping 

covered by that system fail to meet any of the criteria of Category C piping above, 

provided: 

i. Coatings and backfill are provided in accordance with the “preventive actions” 

program element of this AMP; and 

ii. Plant-specific operating experience is acceptable (i.e., no leaks in buried piping 

due to external corrosion, no significant coating degradation or metal loss in 

more than 10 percent of inspections conducted); and 

iii. Soil has been demonstrated to not be corrosive for the material type (e.g., 

AWWA C105, “Polyethylene Encasement for Ductile-Iron Pipe Systems,” 
APPENDIX B 

REVISED AMP XI.M41, BURIED AND UNDERGROUND PIPING AND TANKS 

B-8 

Table XI.M41-2. Inspection of Buried and Underground Piping and Tanks 

Table A.1, “Soil-Test Evaluation”). In order to demonstrate that the soil is not 

corrosive, the applicant: 

1) Obtains a minimum of three sets of soil samples in each soil environment 

(e.g., moisture content, soil composition) in the vicinity in which in-scope 

components are buried. 

2) Tests the soil for soil resistivity, corrosion accelerating bacteria, pH, 

moisture, chlorides, sulfates, and redox potential. 

3) Determines the potential soil corrosivity for each material type of buried 

in-scope piping. In addition to evaluating each individual parameter, the 

overall soil corrosivity is determined. 

4) Conducts soil testing once in each 10-year period starting 10 years prior to 

the period of extended operation. 

F: Inspection criteria provided for Category F piping is used for those portions of in-scope 

buried piping which cannot be classified as Category C, D, or E. 

a. Transitioning to a Higher Number of Inspections: Plant-specific conditions can result 

in transitioning to a higher number of inspections than originally planned at the beginning 

of a 10-year interval. For example, degraded performance of the cathodic protection 

system could result in transitioning from Preventive Action Category C to Preventive 

Action Category E. Coating, backfill, or the condition of exposed piping that do not meet 

acceptance criteria could result in transitioning from Preventive Action Category E to 

Preventive Action Category F. If this transition occurs in the latter half of the current 

10-year interval, 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, but in all cases, the examinations are completed within 4 years after the end of 

the particular 10-year interval. These additional inspections conducted during the four 

years following the end of an inspection interval cannot also be credited towards the 

number of inspections stated in Table XI.M41-2 for the following 10-year interval. 

b. Exceptions to Table XI.M41-2 inspection quantities: 

i. Where piping constructed of steel, copper alloy, or aluminum alloy has been coated 

with the same coating system and the backfill has the same requirements, the total 

inspections for this piping may be combined to satisfy the recommended inspection 

quantity. For example, for Preventive Action Category F, 10 percent of the total of 

the associated steel, copper alloy, or aluminum alloy is inspected; or 6 10-foot 

segments of steel, copper alloy, or aluminum alloy piping is inspected. 

ii. For buried piping, inspections may be reduced to one-half the number of inspections 

indicated in Table XI.M41-2 when performance of the indicated inspections 

necessitates excavation of piping that has been fully backfilled using controlled low 

strength material. The inspection quantity is rounded up (e.g., where three 

inspections are recommended in Table XI.M41-2, two inspections are conducted). In 

conducting these inspections, the backfill may be excavated and the pipe examined, 

or the soil around the backfill may be excavated and the controlled low strength 
APPENDIX B 

REVISED AMP XI.M41, BURIED AND UNDERGROUND PIPING AND TANKS 

B-9 

material backfill examined. The backfill inspection includes excavation of the top 

surfaces and at least 50 percent of the side surface to visually inspect for cracks in 

the backfill that could admit groundwater to the external surfaces of the component. 

When conducting inspection of backfill based on the number of inspections 

designated for that material type, 10 linear feet of the backfill is exposed for each 

inspection. 

iii. No inspections are necessary if all the piping constructed from a specific material 

type is fully backfilled using controlled low strength material for: (a) polymeric and 

cementitious materials; (b) steel and copper alloy materials when Preventive Action 

Category C is met; and (c) stainless steel materials. 

iv. If all of the in-scope polymeric material is nonsafety-related, no more than one 

inspection need be conducted. 

v. Buried polymeric tanks are only inspected if backfill is not in accordance with the 

preventive actions. 

vi. Stainless steel tanks are inspected when they are not coated and the underground 

environment is potentially exposed to in-leakage of groundwater or rain water. 

vii. Steel, copper alloy, and aluminum alloy buried tanks are not inspected if the cathodic 

protection provided for the tank met the criteria for Preventive Action Category C. 

c. Guidance related to the extent of inspections for piping is as follows: 

i. When the inspections are based on the number of inspections in lieu of percentage 

of piping length, 10 feet of piping is exposed for each inspection. 

ii. When the percentage of inspections for a given material type results in an inspection 

quantity of less than 10 feet, then 10 feet of piping is inspected. If the entire run of 

piping of that material type is less than 10 feet in total length, then the entire run of 

piping is inspected. 

d. Piping inspection location selection: Piping inspection locations are selected based 

on risk (i.e., susceptibility to degradation and consequences of failure). Characteristics 

such as coating type, coating condition, cathodic protection efficacy, backfill 

characteristics, soil resistivity, pipe contents, and pipe function are considered. 

Opportunistic examinations of nonleaking pipes may be credited toward examinations if 

the location selection criteria are met. The use of guided wave ultrasonic examinations 

may not be substituted for the inspections listed in the table. 

e. Alternatives to visual examination of piping are as follows: 

i. Aging effects associated with fire mains may be managed by either: (a) a flow test 

as described in Section 7.3 of NFPA® 25 at a frequency of at least one test in each 

one-year period; (b) monitoring the activity of the jockey pump (e.g., pump starts, run 

time) on an interval not to exceed one month; or (c) an annual system leak rate test. 

If the aging effects are not managed by one of these alternatives, and the extent of 

inspections is not based on the percentage of piping for that material type, then two 

additional inspections are added to the inspection quantity for that material type. 

ii. At least 25 percent of the in-scope piping constructed from the material under 

consideration is pressure tested on an interval not to exceed five years. The piping 

is pressurized to 110 percent of the design pressure of any component within the 
APPENDIX B 

REVISED AMP XI.M41, BURIED AND UNDERGROUND PIPING AND TANKS 

B-10 

boundary (not to exceed the maximum allowable test pressure of any nonisolated 

components) with test pressure being held for a continuous eight hour interval. 

iii. At least 25 percent of the in-scope piping constructed from the material under 

consideration is internally inspected by a method capable of precisely determining 

pipe wall thickness. The inspection method has been demonstrated to be capable of 

detecting both general and pitting corrosion on the external surface of the piping and 

is qualified by the applicant to identify loss of material that does not meet acceptance 

criteria. Ultrasonic (UT) examinations, in general, satisfy this criterion. As of the 

effective date of this document, guided wave ultrasonic examinations do not meet 

the intent of this paragraph. If internal inspections are to be conducted in lieu of 

direct visual examination, they are conducted at an interval not to exceed 10 years. 

f. Guidance related to the extent of inspections for tanks is as follows. Examinations 

are conducted from the external surface of the tank using visual techniques or from the 

internal surface of the tank using volumetric techniques. A minimum of 25 percent 

coverage is obtained. This area includes at least some of both the top and bottom of the 

tank. If the tank is inspected internally by volumetric methods, the method is: capable of 

determining tank wall thickness, demonstrated to be capable of detecting both general 

and pitting corrosion, and qualified by the applicant to identify loss of material that does 

not meet acceptance criteria. Double wall tanks may be examined by monitoring the 

annular space for leakage. 

5. Monitoring and Trending: For piping and tanks protected by cathodic protection systems, 

potential difference and current measurements are trended to identify changes in the 

effectiveness of the systems and/or coatings. If aging of fire mains is managed through 

monitoring jockey pump activity (or a similar parameter), the jockey pump activity (or similar 

parameter) is trended to identify changes in pump activity that may be the result of 

increased leakage from buried fire main piping. Likewise, if leak rate testing is conducted, 

leak rates are trended. Where wall thickness measurements are conducted, the results are 

trended when follow up examinations are conducted. 

6. Acceptance Criteria: The acceptance criteria associated with this AMP are: 

a. For coated piping or tanks, there is either no evidence of coating degradation, or the 

type and extent of coating degradation is evaluated as insignificant by an individual: (a) 

possessing a NACE Coating Inspector Program Level 2 or 3 inspector qualification; (b) 

who has completed the Electric Power Research Institute (EPRI) Comprehensive 

Coatings Course and completed the EPRI Buried Pipe Condition Assessment and 

Repair Training Computer Based Training Course; or (c) a coatings specialist qualified in 

accordance with an ASTM standard endorsed in Regulatory Guide 1.54, Rev. 2, 

“Service Level I, II, and III Protective Coatings Applied to Nuclear Power Plants.” 

b. Cracking is absent in rigid polymeric components. Blistering, gouges, or wear of 

nonmetallic piping is evaluated. 

c. The measured wall thickness projected to the end of the period of extended operation 

meets minimum wall thickness requirements. 

d. Indications of cracking in metallic pipe are managed in accordance with the “corrective 

actions” program element. 

e. Cementitious piping may exhibit minor cracking and spalling provided there is no 

evidence of leakage, exposed or rust staining from rebar or reinforcing “hoop” bands. 
APPENDIX B 

REVISED AMP XI.M41, BURIED AND UNDERGROUND PIPING AND TANKS 

B-11 

f. Backfill is acceptable if the inspections do not reveal evidence that the backfill caused 

damage to the component’s coatings or the surface of the component (if not coated). 

g. Flow test results for fire mains are in accordance with NFPA® 25, Section 7.3. 

h. For pressure tests, the test acceptance criteria are that there are no visible indications of 

leakage, and no drop in pressure within the isolated portion of the piping that is not 

accounted for by a temperature change in the test media or by quantified leakage across 

test boundary valves. 

i. Changes in jockey pump activity (or similar parameter) that cannot be attributed to 

causes other than leakage from buried piping are not occurring. 

j. When fire water system leak rate testing is conducted, leak rates are within acceptance 

limits of plant-specific documents. 

k. Cracks in controlled low strength material backfill that could admit groundwater to the 

surface of the component are not acceptable. 

l. Criteria for pipe-to-soil potential when using a saturated CSE reference electrode is as 

stated in Table XI.M41-3, or acceptable alternatives as stated below. 

Table XI.M41-3. Cathodic Protection Acceptance Criteria 

Material Criteria1,2

Steel -850 mV relative to a CSE, 

instant off 

Copper alloy 100 mV minimum polarization 

Aluminum alloy 100 mV minimum polarization 

1 Plants with sacrificial anode systems state the test method and acceptance 

criteria and the basis for the method and criteria in the application. 

2 For steel piping, when: (a) active MIC has been identified or is probable; (b) 

temperatures greater than 60°C (140°F); or (c) in weak acid environments, a 

polarized potential of -950 mV or more negative is recommended. 

m. Alternatives to the -850 mV criterion for steel piping in Table XI.M41-3 are as 

follows. 

i. 100 mV minimum polarization 

ii. -750 mV relative to a CSE, instant off where soil resistivity is greater than 

10,000 ohm-cm to less than 100,000 ohm-cm 

iii. -650 mV relative to a CSE, instant off where soil resistivity is greater than 

100,000 ohm-cm 

iv. Verify less than 1 mpy loss of material. Loss of material rates in excess of 1 mpy 

may be acceptable if an engineering evaluation demonstrates that the corrosion 

rate would not result in a loss of intended function prior to the end of the period of 
APPENDIX B 

REVISED AMP XI.M41, BURIED AND UNDERGROUND PIPING AND TANKS 

B-12 

extended operation. The engineering evaluation is cited and summarized in the 

LRA. 

When using the 100 mV, -750 mV, or -650 mV polarization criteria as an alternative to 

the -850 mV criterion for steel piping, means to verify the effectiveness of the protection 

of the most anodic metal is incorporated into the program. One acceptable means to 

verify the effectiveness of the cathodic protection system, or to demonstrate that the loss 

of material rate is acceptable, is to use installed electrical resistance corrosion rate 

probes. The external loss of material rate is verified: 

• Every year when verifying the effectiveness of the cathodic protection system by 

measuring the loss of material rate. 

• Every 2 years when using the 100 mV minimum polarization. 

• Every 5 years when using the -750 or -650 criteria associated with higher resistivity 

soils. The soil resistivity is verified every 5 years. 

As an alternative to verifying the effectiveness of the cathodic protection system 

every 5 years, soil resistivity testing is conducted annually during a period of time 

when the soil resistivity would be expected to be at its lowest value (e.g., maximum 

rainfall periods). Upon completion of 10 annual consecutive soil samples, soil 

resistivity testing can be extended to every 5 years if the results of the soil sample 

tests consistently verified that the resistivity did not fall outside of the range being 

credited (e.g., for the -750 mV relative to a CSE, instant off criterion, all soil resistivity 

values were greater than 10,000 ohm-cm). 

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

• The qualifications of the individuals that will determine the installation locations of the 

probes and the methods of use (e.g., NACE CP4, “Cathodic Protection Specialist”). 

• How the impact of significant site features (e.g., large cathodic protection current 

collectors, shielding due to large objects located in the vicinity of the protected 

piping) and local soil conditions will be factored into placement of the probes and use 

of probe data. 

7. Corrective Actions: Results that do not meet the acceptance criteria are addressed as 

conditions adverse to quality or significant conditions adverse to quality under those specific 

portions of the quality assurance (QA) program that are used to meet Criterion XVI, 

“Corrective Action,” of 10 CFR Part 50, Appendix B. Appendix A of the GALL-SLR Report 

describes how an applicant may apply its 10 CFR Part 50, Appendix B, QA program to fulfill 

the corrective actions element of this AMP for both safety-related and nonsafety-related 

structures and components within the scope of this program. 

a. Where damage to the coating has been evaluated as 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. 

b. If coated or uncoated metallic piping or tanks show evidence of corrosion, the remaining 

wall thickness in the affected area is determined to ensure that the minimum wall 

thickness is maintained. This may include different values for large area minimum wall 

thickness and local area wall thickness. If the wall thickness extrapolated to the end of 

the period of extended operation meets minimum wall thickness requirements, 

recommendations for expansion of sample size, below do not apply. 
APPENDIX B 

REVISED AMP XI.M41, BURIED AND UNDERGROUND PIPING AND TANKS 

B-13 

c. Where the coatings, backfill, or the condition of exposed piping does not meet 

acceptance criteria, the degraded condition is repaired or the affected component is 

replaced. In addition, where 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 period of extended operation, an expansion of sample size 

is conducted. The number of inspections within the affected piping categories are 

doubled or increased by 5, 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 in which the original inspection was conducted or, if identified in 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 four years following the end of an inspection 

interval cannot also be credited towards the number of inspections in Table XI.M41-2 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 in which the inspections were 

conducted or, if identified in the latter half of the current 10-year interval, within 4 years 

after the end of the 10-year interval. 

d. Unacceptable cathodic protection survey results are entered into the plant corrective 

action program. 

e. Sources of leakage detected during pressure tests are identified and corrected. 

f. When using the option of monitoring the activity of a jockey pump instead of inspecting 

buried fire water system piping, a flow test or system leak rate test is conducted by the 

end of the next refueling outage or as directed by the current licensing basis, whichever 

is shorter, when unexplained changes in jockey pump activity (or equivalent equipment 

or parameter) are observed. 

g. Indications of cracking are evaluated in accordance with applicable codes and 

plant-specific design criteria. 

8. Confirmation Process: The confirmation process is addressed through those specific 

portions of the QA program that are used to meet Criterion XVI, “Corrective Action,” of 

10 CFR Part 50, Appendix B. Appendix A of the GALL-SLR Report describes how an 

applicant may apply its 10 CFR Part 50, Appendix B, QA program to fulfill the confirmation 

process element of this AMP for both safety-related and nonsafety-related structures and 

components within the scope of this program. 

9. Administrative Controls: Administrative controls are addressed through the QA program 

that is used to meet the requirements of 10 CFR Part 50, Appendix B, associated with 

managing the effects of aging. Appendix A of the GALL-SLR Report describes how an 

applicant may apply its 10 CFR Part 50, Appendix B, QA program to fulfill the administrative 

controls element of this AMP for both safety-related and nonsafety-related structures and 

components within the scope of this program. 
APPENDIX B 

REVISED AMP XI.M41, BURIED AND UNDERGROUND PIPING AND TANKS 

B-14 

10. Operating Experience: Operating experience 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. Given the differences in piping and tank configurations between 

transmission pipelines and those in nuclear facilities, it is necessary for an applicant to 

evaluate both plant-specific and nuclear industry operating experience and to modify its 

AMP, accordingly. The following examples of industry experience may be of significance to 

an applicant’s program: 

• In August 2009, a leak was discovered in a portion of buried aluminum alloy 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 alloy pipe 

and the steel supports. (ADAMS Accession No. ML093160004). 

• 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. (ADAMS Accession 

No. ML093160004). 

• In April 2010, while performing inspections as part of its buried pipe program, a licensee 

discovered that major portions of its auxiliary feedwater piping were substantially 

degraded. The licensee's 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. (ADAMS Accession 

No. 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 ten locations along the exposed 

piping. The leaking and unacceptable portions of the degraded pipe were clamped and 

recoated until a permanent replacement could be installed. (ADAMS Accession 

No. ML13329A422). 

The program is informed and enhanced when necessary through the systematic and 

ongoing review of both plant-specific and industry operating experience, as discussed in 

Appendix B of the GALL Report. 

References 

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2009. 

ASTM Standard D 448-08, Standard Classification for Sizes of Aggregate for Road and Bridge 

Construction, 2008. 

AWWA C105, “Polyethylene Encasement for Ductile-Iron Pipe Systems,” American Water 

Works Association, 2010. 

EPRI 1021175, Recommendations for an Effective Program to Control the Degradation of 

Buried and Underground Piping and Tanks, (1016456 Revision 1), December 23, 2010. 
APPENDIX B 

REVISED AMP XI.M41, BURIED AND UNDERGROUND PIPING AND TANKS 

B-15 

ISO 15589-1, Petroleum and natural gas industries – Cathodic protection of pipeline 

transportation systems – Part 1: On land pipelines, November 15, 2003. 

NACE Recommended Practice RP0285-2002, Standard Recommended Practice Corrosion 

Control of Underground Storage Tank Systems by Cathodic Protection, revised April 2002. 

NACE Standard Practice SP0169-2007, Control of External Corrosion on Underground or 

Submerged Metallic Piping Systems, 2007. 

NFPA® 24, Standard for the Installation of Private Fire Service Mains and Their Appurtenances, 

2010 edition. 

NFPA® 25, Standard for the Inspection, Testing, and Maintenance of Water-Based Fire 

Protection Systems, 2008 edition. 

NACE Standard RP0100-2004, Standard Recommended Practice, Cathodic Protection of 

Prestressed Concrete Cylinder Pipelines, 2004 

Regulatory Guide 1.54, Revision 2, Service Level I, II, and III Protective Coatings Applied to 

Nuclear Power Plants, U.S. Nuclear Regulatory Commission, October 2010.
APPENDIX C 

CHANGES to GALL REPORT AMP XI.M33, “SELECTIVE LEACHING,” CHANGES to the 

DETECTION OF AGING EFFECTS PROGRAM ELEMENT 

C-1 

The following recommendations are added to the “detection of aging effects” program element 

of AMP XI.M33. 

For buried components susceptible to selective leaching, dependent on plant-specific operating 

experience and implementation of preventive actions of AMP XI.M41, the number of one-time 

selective leaching inspections for the external surfaces of buried components which are 

susceptible to selective leaching may be adjusted as follows: 

• No selective leaching inspections are required of the external surface of gray cast iron 

buried components which meet the following conditions: (a) the components have been 

cathodically protected since installation, (b) the cathodic protection system has had 80 

percent availability for the 10 year period prior to the period of extended operation, and 

(c) the as-found measured pipe-to-soil potential readings during periodic cathodic 

protection surveys meets the “acceptance criteria” program element of AMP XI.M41. 

Where only portions of the population of components have met this criterion, those 

portions may be deducted from the population size for purposes of determining the 

number of inspections; however, the maximum sample size of AMP XI.M33 is still 

applicable. The same adjustments may be utilized for copper alloy based components; 

however, technical justification must be provided that demonstrates the effectiveness of 

cathodic protection in the prevention of selective leaching for those alloys. Absent such a 

justification, the AMP XI.M33 sample size recommendations cannot be adjusted. 

• No selective leaching inspections are required of the external surface of buried 

components which are coated in accordance with Table XI.M41-1 of AMP XI.M41, and 

where visual examinations of in-scope buried piping has not revealed any coating 

damage. The inspection sample size may be reduced to 5 percent of the population with 

a maximum sample of six components when minor through-wall coating damage has 

been identified in plant-specific operating experience such that: (a) there were no more 

than two instances of damage identified in the 10-year period prior to the period of 

extended operation, and (b) if the pipe surface area affected by the coating damage is 

assumed to have been a through-wall hole, the pipe could be shown to meet 

unreinforced opening criteria of the applicable piping code.
APPENDIX D 

RESOLUTION OF PUBLIC COMMENTS 

D-1 

The staff received comments from: 

• NEI, dated August 6, 2015, [ADAMS Accession No. ML15225A076]; Comment 

Nos. 1 - 67 

• Hank Kleinfelder, dated August 6, 2015, [ADAMS Accession No. ML15225A077]; 

Comment Nos. 68 and 69 

• Anonymous, dated August 7, 2015, [ADAMS Accession No. ML15225A078]; Comment 

No. 70 

• Kevin Anstee for Entergy – River Bend Station, dated August 10, 2015, [ADAMS 

Accession No. ML15244A392]; Comment No. 71 

• Steven Daily, dated August 10, 2015, [ADAMS Accession No. ML15244A391]; Comment 

Nos. 72 through 76 

Comments were copied from the letters with minimal minor edits. NEI utilized underlining and 

cross outs to indicate industry recommended wording revisions or additions. 

 
APPENDIX D 

RESOLUTION OF PUBLIC COMMENTS 

D-2 

# Comment Staff Resolution 

1 P1 / Discussion 

Editorial – Incorrect comma usage in initial 

sentence. 

Based on industry operating experience and the 

staff’s review of LRAs and plant-specific buried 

and underground piping and tanks inspection 

reports since issuance of AMP XI.M41, the staff 

has determined that the GALL Report and SRPLR should be revised to reflect new 

recommendations associated with AMP XI.M41. 

Editorial change incorporated. 

2 Introduction, page 1 and Discussion “Description 

of Changes”, page 5 

Neither the introduction nor the discussion 

mentions that AMP XI.M33 is also modified by 

the ISG, yet changes are included as Appendix 

C. The discussion of selective leaching 

inspections on page 5 says that the 

recommendations in AMP XI.M41 have been 

moved to AMP XI.M33 with no technical 

changes. However, this is in the context of the 

changes to AMP XI.M41 and the description 

does not make it clear that the changes to AMP 

XI.M33 are provided in this ISG. 

The introduction should be revised to indicate 

that changes to AMP XI.M33 are also included in 

the ISG. The discussion of selective leaching on 

page 5 could also be revised to refer to Appendix 

C for the changes to AMP XI.M33. 

Editorial changes incorporated. 

3 Discussion “Description of Changes”, page 2 

Appendix B “Preventive Actions”, page B-2 

Page 2 states that the maximum negative 1200 

mv CP criterion was relocated from the 

"acceptance criteria" program element to a 

recommendation within the "preventive actions" 

program element, to allow licensees flexibility in 

balancing the performance of their CP systems. 

Page 2 describes this upper limit as a 

“recommendation.” The new description in the 

“preventive actions” program element says that 

“the limiting critical potential should not be more 

negative than -1200 mV.” The use of “should 

not” implies that negative 1200 mv is a 

recommendation not a requirement, but the 

wording is not completely clear. 

In addition to moving from one program element 

to another, it may be beneficial to refer to the 

1200 mV criterion as a recommendation, such as 

it is recommended that the limiting critical 

potential should not be more negative than -1200 

mV. 

The staff does not agree with this comment. All of the 

AMP program elements are recommendations. 

Although the term “recommendation” is used in many 

GALL Report AMPs, it is predominantly associated 

with citing documents published by EPRI, ASME and 

other staff issued documents (e.g., NUREG, generic 

letter) and not individual provisions of AMPs. It is still 

the staff’s intent that if an applicant chooses to use an 

alternative limit, it would state an exception and a 

basis for the alternative value. This approach is the 

same for any of the other recommendations in the 

“preventive action” program element. However, if a 

reading is more negative than the upper negative limit 

during periodic cathodic protection surveys the reading 

would no longer be considered as failing cathodic 

protection acceptance criteria (i.e., those 

recommended in the “acceptance criteria” program 

element) 
APPENDIX D 

RESOLUTION OF PUBLIC COMMENTS 

D-3 

4 Description of Changes pdf Page 2, 2nd Bullet 

“Coating on Underground Components” 3rd 

Sentence 

The 3rd sentence reads, “As a result of this 

change, if an applicant’s underground steel or 

copper alloy piping is not coated, the applicant 

would state an exception and the basis of an 

exception.” It seems like most stations would be 

taking an exception, except a very few. 

As a result of this change, if an applicant’s 

underground steel or copper alloy piping is not 

coated and there are no indications of corrosion 

that could challenge the structural integrity or 

pressure boundary, the applicant would state an 

exception and the basis of an exception. 

The staff does not agree with this comment. As stated 

in the discussion associated with the change, the staff 

has observed loss of material during walkdowns of 

vaults or reviewed plant-specific operating experience 

demonstrating the same during several audits. The 

staff has concluded that given the environmental 

conditions in the vaults, it is appropriate that steel and 

copper piping be coated. As stated in the comment, 

this is a recommendation and an exception can be 

proposed and justified if appropriate. 

5 Discussion “Description of Changes”, page 4 

Appendix B “Acceptance Criteria”, page B-11 

When discussing electrical resistance probes 

(ERPs), both page 4 and page B-11 state that 

the application will specify the qualifications of 

the individuals who will determine the installation 

locations of the probes and the methods of use. 

It then gives an example of NACE CP-4, 

“Cathodic Protection Specialist”. It is not clear 

whether this is just an example of the type of 

qualification or the level of qualification. For 

example, elsewhere in the ISG (page B-9) 

discusses that evaluations are performed by 

NACE Level 2 or 3. So would that level of 

qualification (i.e. Level 2 or 3) be adequate for 

determining the installation locations of the 

ERPs? 

If CP-4 is required, then “e.g.” should not be 

used. If CP-4 is just an example of a type of 

qualification, then the discussion should indicate 

that other levels are also acceptable. 

The staff has made no changes based on the 

comment. The staff cited CP4, Cathodic Protection 

Specialist, as an example of the recommended 

qualification level for personnel associated with the 

design and installation of electrical resistance probes 

due to the complexity of specifying the correct type, 

location, number, etc. of probes to install. Based on a 

review of the NACE website, a CP4 qualified individual 

should be capable of designing complete cathodic 

protection systems and applying new technologies to 

an existing cathodic protection program. In contrast, a 

CP3, Cathodic Protection Technologist, would be 

capable of designing and installing simplistic forms of 

galvanic and impressed current cathodic protection 

systems. In that regard, the staff has concluded that 

when using NACE to qualify individuals, the CP4 level 

of qualification, not lower levels, is appropriate for the 

design and installation of electrical resistance probes. 

Therefore, the example was not provided to imply that 

a CP3 would be adequate. The example was 

provided because there could be other means to 

qualify an individual to a similar knowledge level as 

that obtained for CP4. 

In regard to the “NACE Level 2 or 3” cited on page 

B-9, these certification levels are associated with 

coating inspector qualifications. Therefore they are 

not applicable to cathodic protection qualifications. 

 6 P6 / Backfitting 

Revision of typo in 2nd sentence under 

Licensees that already hold a renewed license. 

...and consider to this information to ensure that 

relevant AMPs are, and will remain, effective. 

Editorial change incorporated. 

7 P7 / 1st paragraph 

Editorial – Incorrect comma usage. 

...do not extend to the nuclear safety issues of 

license renewal and the NRC need not 

address... 

Editorial change incorporated. 
APPENDIX D 

RESOLUTION OF PUBLIC COMMENTS 

D-4 

8 P7 / 2nd paragraph 

Editorial – Incorrect comma usage. 

...do not extend to the nuclear safety issues of 

license renewal and the NRC need not 

address... 

Editorial change incorporated. 

9 A-1 / 1st paragraph 

...actions (i.e., coatings, backfill quality, and 

cathodic protection). 

Editorial – Incorrect comma usage. 

Editorial change incorporated. 

10 Page A-1 Description of program, 6th sentence. 

Actions required when cathodic protection does 

not meet acceptance criteria are inconsistent 

with the XI.M41 element 6. Alternate acceptance 

criteria are allowed under NACE SP0169. 

Recommend revising the 6th sentence as 

follows: Where the acceptance criteria for the 

effectiveness of the cathodic protection is other 

than -850 mV instant off or 100 mV shift, actual 

loss of material rates are measured from in-situ 

coupons or installed electrical resistance 

corrosion rate probes. 

The staff agrees with this comment in part. The staff 

does not agree that a 100 mV shift can be used as an 

acceptance criterion in the absence of a means to 

verify the effectiveness of the cathodic protection 

system. The only acceptance criterion for an 

impressed cathodic protection system is -850 mV 

relative to a CSE, instant off. Alternative acceptance 

criteria are provided; however, in each case, the loss 

of material rate is measured to confirm the 

effectiveness of the cathodic protection system. The 

term “actual” was deleted because the staff recognizes 

that whenever coupons or probes are used, they might 

not measure the exact loss of material rate of the 

protected piping. In addition, the term, “from in-situ 

coupons” was deleted because AMP XI.M41 currently 

only contains recommendations for measuring loss of 

material rates by electrical resistance corrosion rate 

probes. 

11 Appendix B, Program Description, end of 1st 

paragraph 

The revised AMP uses the term “cementitious” in 

places and the term “reinforced cement and 

asbestos concrete pipe”. 

Recommend “cementitious” be defined; further, it 

should be consistently used with concrete 

materials. 

The staff agrees with this comment. Terms such as 

“cement,” “reinforced concrete,” and “asbestos 

cement” were replaced with “cementitious.” The only 

use of the term “concrete” is: (a) when it refers to the 

environment in which the buried piping or tank is 

embedded (to remain consistent with the GALL Report 

AMR line items); (b) when it is included in a title; and 

(c) when it is included in a quote. The term 

“cementitious” was clarified by adding a parenthetical 

phrase after its first use, “cement-based substance.” 

12 Element 1 / Page B-1 

Editorial – Incorrect comma usage. 

... refers to plastics or other polymers... 

Editorial change incorporated. 

13 Scope of Program / App B 

Added sentence "The term “polymeric” material 

refers to plastics, or other polymers that 

comprise the structural element of the 

component" has the potential to imply something 

other than intended. Since the function of 

mechanical components managed by this 

program is either pressure boundary or leakage 

boundary, consider replacing the words 

"structural element" with “pressure” or “leakage 

boundary.” 

The staff agrees with this comment. The term 

“structural element” was revised to “pressure 

boundary.” This is consistent with the SRP-LR, 

Table 2.1-4(b), “Typical ‘Passive’ Component-Intended 

Functions,” use of term, “[p]rovide pressure-retaining 

boundary so that sufficient flow at adequate pressure 

is delivered.” 
APPENDIX D 

RESOLUTION OF PUBLIC COMMENTS 

D-5 

14 Element 2, Table 2 / Page B-1 

Reinforcement in cementitious materials is 

protected by CP for Reinforced Concrete Pipe & 

PCCP. Coatings are a less common mitigation 

for RCP. 

Reinforcement in cementitious materials is 

protected by CP for Reinforced Concrete Pipe & 

PCCP. Coatings are a less common mitigation 

for RCP. 

The staff agrees with this comment in part. 

Table XI.M41-1 (previously Table 2) was revised to 

include a recommendation for cathodic protection for 

reinforced concrete pipe and prestressed concrete 

cylinder pipe. The staff has concluded that protective 

coatings should be recommended for cementitious 

materials to minimize the potential for aging effects 

such as cracking or changes in material properties due 

to aggressive chemical attack, or leaching. 

15 Page B-1 Element 1 & program description 

The program description was revised to remove 

the discussion of the applicability with the 

Selective Leaching Program. Recommend that 

the discussion of the applicability of the Selective 

Leaching program be added to Element 1 similar 

to the discussion of the Bolting Integrity Program 

in Element 1. Page 5 of the ISG notes that the 

recommendations related to reductions in the 

extent of inspections for AMP XI.M33 have been 

moved to AMP XI.M33 with no technical 

changes. When will these AMP XI.M33 changes 

be issued for industry use and reference? 

Recommend the following be added to element 

1: 

This program does not provide aging 

management of selective leaching. The Selective 

Leaching of Materials (AMP XI.M33) is applied in 

addition to this program for applicable materials 

and environments. 

The staff agrees with this comment. The 

recommended sentence was added to the “scope of 

program” program element of AMP XI.M41. 

The changes to AMP XI.M33 were provided in 

Appendix C of the draft and final version of this 

LR-ISG. 
APPENDIX D 

RESOLUTION OF PUBLIC COMMENTS 

D-6 

16 Preventive Actions / App B 

Omission of the "When provided..." wording for 

underground coating recommendation will likely 

result in the need for exception by most 

applicants. The justification for this action in 

discussion on page 2 indicated that "typical air 

conditions in underground vaults have higher 

moisture content than uncontrolled indoor air 

conditions in plant spaces within buildings." 

There is no discussion of what documentation 

exists to support this statement, but the definition 

of air-indoor, uncontrolled in NUREG-1801 only 

assumes that system temperatures are expected 

to be above the dewpoint. Where system 

temperatures are expected to be below 

dewpoint, they are normally insulated to mitigate 

condensation. For other piping, there is no OE 

cited that indicates that normal film coatings (i.e., 

paint) is ineffective at controlling surface 

corrosion. 

The presence of coatings in pipe trenches is 

likely to be an unusual condition, as trenches are 

(were) generally considered to be a sheltered 

environment for which coatings are (were) 

unnecessary. Installation of coatings on 

underground piping if they don't already exist 

would likely be impractical... as such, this 

"preventive" action is more of a design or 

installation consideration than it is a preventive 

action. A recommendation made today to use 

coatings in these locations will likely not result in 

installation of coatings. Rather, it will result in 

exceptions to the program recommendations. If 

the existing industry population of piping/tanks in 

underground (not buried) locations is 

predominantly not coated, it would be more 

beneficial to provide guidance that does not 

require applicants to take an exception. 

Recommend providing an allowance that 

underground (not buried) piping / tanks may be 

uncoated, or may have standard protective film 

coatings (paint). Specify that an increase in 

number or frequency of inspections is warranted 

if wetted conditions or evidence of more than 

minor surface corrosion is noted during initial 

inspections. 

The staff does not agree with this comment. 

The basis for the staff’s statement that, "typical air 

conditions in underground vaults have higher moisture 

content than uncontrolled indoor air conditions in plant 

spaces within buildings,” is its review of plant-specific 

operating experience and walkdowns of underground 

vaults during AMP audits. The staff’s review included 

instances of extensive general corrosion and 

submergence of piping components in underground 

vaults. Examples include: (a) Safety Evaluation 

Report With Open Items Related to the License 

Renewal of Limerick Generating Station, Units 1 and 2 

(ADAMS Accession No. ML12213A721), Section 

3.0.3.2.12, Enhancement No. 2; and (b) Safety 

Evaluation Report Related to the License Renewal of 

Byron Station, Units 1 and 2, and Braidwood Station, 

Units 1 and 2 (ADAMS Accession No. ML15182A051), 

Section 3.0.3.2.15, Operating Experience. 

The staff has concluded that “normal film coatings” 

may not be effective in preventing loss of material in 

high humidity or immersion environments. 

The staff does not agree with the implication of the 

statement, “installation of coatings on underground 

piping if they don't already exist would likely be 

impractical... as such, this ‘preventive’ action is more 

of a design or installation consideration than it is a 

preventive action.” Coatings share a similar 

characteristic as backfill in that their use as preventive 

actions is better accomplished during the design 

phase rather than a backfit. The staff recognizes that 

backfitting coatings on underground piping could be 

costly and it does not expect that applicants would 

coat underground piping simply based on AMP XI.M41 

recommending coatings as a preventive action. 

However, the basis for the inspections of underground 

piping cited in Table XI.M41-2 is that the piping is 

coated. Should an applicant state an exception to 

having coated underground piping, it would be 

expected that there would be an increase in the 

number or frequency of inspections of the piping or of 

the vault conditions (e.g., due to in-leakage) to justify 

the exception. 
APPENDIX D 

RESOLUTION OF PUBLIC COMMENTS 

D-7 

17 Element 2, Sub-paragraph a / Page B-2 

Editorial – Incorrect comma usage. 

... copper alloy, and aluminum alloy piping and 

tanks and underground steel and copper alloy 

piping and tanks, coatings are 

Editorial change incorporated. 

18 Page B-2 Element 2.c last sentence 

As noted by prior industry comments and NACE 

International SP0169-2007, use of excessive 

polarized potentials should be avoided on all 

metals particularly those metals that could result 

in excessive generation of hydrogen (e.g. 

aluminum, titanium, or selected grades of 

stainless steel). In addition NACE International 

SP0169 does not provide a limiting critical 

potential to prevent damage of coatings. 

Consistent with SP0169, the use of excessive 

polarized potentials on externally coated 

pipelines should be avoided to minimize cathodic 

disbondment of the coating. 

Recommend the last sentence be revised to 

read: 

To prevent damage to the coating metallic 

components, the limiting critical potential should 

not be more negative than -1200 mV. A further 

over-protection limit shall be defined by the 

applicant and managed during surveillance 

activities. The use of excessive polarized 

potentials on externally coated pipelines should 

be avoided. 

The staff agrees with the concept of this comment in 

principal; however, the changes to the AMP are 

different than those proposed in the comment. A new 

section was included in reference to Table XI.M41-1 in 

AMP XI.M41, “Critical potentials for cathodic 

protection.” It includes the following. 

IAEA NE Series No. NP-T-3.20, “Buried and 

Underground Piping and Tank Ageing Management 

for Nuclear Power Plants,” Section 4.3.14.5, 

“Blistering,” states that excessive amounts of cathodic 

protection current (i.e., greater than -1200 mV) can 

cause coating disbondment and blistering. Therefore, 

the staff revised the first sentence to cite coatings and 

base metal. 

The upper limit for prestressed concrete cylinder pipe 

in Table XI.M41-3, footnote 2, was moved to the 

“preventive actions” program element for the same 

reason that the upper limit of -1200 mV was moved 

from Table XI.M41-3. These upper limits are 

important as preventive actions; however, the intent of 

the acceptance criteria in Table XI.M41-3 was to 

establish criteria that are used to transition to different 

preventive action categories in Table XI.M41-2 (i.e., 

increased or decreased number of inspections). 

When the upper limits are not met, the variance should 

be considered as a condition adverse to quality that is 

addressed by the corrective action program. 

Increased inspections, if conducted, would be as a 

result of the licensee’s evaluation of the condition 

adverse to quality in lieu of recommended increased 

inspections stated in Table XI.M41-2. 

In addition, the staff included a new bullet under this 

note describing the potential for SCC of steel and 

stainless steel buried components depending on the 

environment. 

The staff included, with slight edits, the second 

proposed sentence as an additional caution under this 

note. 
APPENDIX D 

RESOLUTION OF PUBLIC COMMENTS 

D-8 

19 Element 2, Sub-paragraphs a – d / Page B-2 

References to NACE SP0169-2007 should be 

replaced or supplemented by reference to latest 

edition, SP0169-2013, particularly with respect to 

Table 1a/1b for coatings. 

Recommended change: NACE SP0169-

20072013 

 

The staff agrees with this comment in part. The staff 

has concluded that it will not adopt the 2013 edition of 

SP0169 in its entirety. The staff does not agree with 

Section 6, “Criteria and Other Considerations for 

Cathodic Protection,” for several reasons. Some 

examples include: 

• The staff disagrees with the use of the 100 mV 

cathodic polarization acceptance criterion (in the 

mixed metal environment) without confirmatory 

testing to verify that all metals are adequately 

protected. The staff’s position is supported by 

ISO 15589-1, Section 5.3.2.2 which states, 

“[f]urthermore, the criteria shall not be used in 

case of pipelines connected to or consisting of 

mixed metal components.” 

• The staff disagrees with the language in Section 

6.2.1.1, which allows criteria that have been 

documented through empirical evidence to 

indicate corrosion control effectiveness on specific 

piping systems. Given that the staff has not 

reviewed this “empirical evidence,” it can not 

endorse this option. 

• The staff does not agree with the use of a 

potential of –850 mV instant-on without 

measurement or calculation of voltage drops. 

However, the staff reviewed SP0169-2013, Section 5, 

“External Coatings,” and has concluded that the 

expanded list of coating materials in the cited tables 

are acceptable for use and provide for a more efficient 

review of LRAs. Table XI.M41-1 was revised to cite 

the specific materials that were added in SP0169-

2013, Section 5, Table 1a, “Generic External Coating 

Systems for Carbon Steel Pipe with Material 

Requirements and Recommended Practices for 

Application) for Underground and Submerged Pipe 

(Field- and Shop-Applied)” and Table 1b, “Generic 

External Coating Systems for Ductile Iron Pipe with 

Material Requirements and Recommended Practices 

for Application.” 

The staff has concluded that the coating types cited in 

the 2013 Edition can be capable of restricting moisture 

penetration and/or electrically isolating the base metal 

of the buried component and are therefore acceptable 

as coatings for buried and underground components. 

References: (a) Corrosion, LL Shreir, 3rd Edition, 

Chapter 14.8, “Protective Coatings for Underground 

Use;” and (b) “CP Shielding and Pipeline Coatings,” 

Greg Ruschau, CC Technologies. 
APPENDIX D 

RESOLUTION OF PUBLIC COMMENTS 

D-9 

20 Element 3.a.i / Page B-3 

Corrosion nomenclature change. 

Recommended change: microbiologicallyinfluenced corrosion. 

Editorial change incorporated. The staff also revised 

this section to reflect that aluminum alloy components 

are not susceptible to MIC. Aluminum components 

are susceptible to pitting and crevice corrosion; 

however, they are not susceptible to microbiologicallyinfluenced corrosion in buried environments. The staff 

reached the conclusion that aluminum is not 

susceptible to microbiologically-influenced corrosion 

based on a review of the following: 

• Corrosion of Aluminum, Christian Vargel, Elsevier, 

2004, Chapter 2.11, “Microbiological Corrosion,” 

which states, “[t]here is no specific microbiological 

corrosion of aluminum in aqueous media, especially 

in seawater, which contains a wide range of 

bacteria.” 

• A Practical Manual on Microbiologically Influenced 

Corrosion, Volume 2 (2nd Edition), John G Stoecker, 

NACE International, 2001, Chapter 7, “MIC in the 

Power Industry,” and Chapter 8, “MIC in the Waste 

Treatment Industries,” which state, “[m]icrobial 

influences can cause localized corrosion, often at 

rates one or more orders of magnitude greater than 

the expected general corrosion rates, for copperbased alloys, carbon steels, and stainless steels.” 

There was no mention of aluminum alloys. 

• ASM Handbook, Volume 13A, “Corrosion: 

Fundamentals, Testing, and Protection,” Stephen D 

Cramer, 2003, Section 58, “Microbiologically 

Influenced Corrosion,” Stephen C Dexter, University 

of Delaware, page 407 MIC of aluminum alloys is 

only cited for aircraft fuel tanks. 

21 Element 3.a.iii. / Page B-3 

Recommend deletion of loss of material due to 

wear for polymeric materials, or cite relevant OE 

showing this to be an applicable AE of concern. 

Is the OE definitive in concluding that the wear 

was a result of objects slowly migrating over time 

due to seasonal changes, versus damage 

incurred during original backfilling? 

Recommended change provided in comment. 

The staff does not agree with this comment. The staff 

has not seen any specific OE associated with ground 

movement of deleterious material in backfill damaging 

polymeric components. However, it is well known that 

objects such as concrete block and rebar can move 

based on seasonal changes in backfill. This 

movement could damage polymeric materials. 

22 Element 3.a.iv / Page B-3 

Editorial – Incorrect comma usage. 

... asbestos cement pipe and concrete pipe; 

Editorial change incorporated. 
APPENDIX D 

RESOLUTION OF PUBLIC COMMENTS 

D-10 

23 Element 3.a.vi / Page B-3 

Editorial – Semicolon between aging effects 

implies another bullet based upon the preceding 

structure in this section. Recommend a comma. 

Recommended change: 

vi. cracking due to aggressive chemical attack 

and leaching;, changes in material properties 

due to aggressive chemical attack, for reinforced 

concrete and asbestos cement piping. 

The staff editorially realigned the bullets to address 

this comment. 

24 Element 3.b / Page B-3 

Suggest addition of other NDE technologies and 

potentially cross-referencing EPRI Buried Pipe 

NDE Guide. 

Ultrasonic testing (UT), Magnetic Flux Leakage 

(MFL), Pulsed Eddy Current (PEC), Saturated 

Low Frequency Eddy Current (SLOFEC), and 

other non-destructive means may be used to 

measure wall thickness... Applicants must 

ensure that evaluation technologies are fit for 

purpose and comply with governing codes, 

where applicable. 

The staff agrees with this comment, but rather than 

listing specific NDE techniques, it provided two 

conditions for the use of wall thickness measurement 

techniques: (a) the method has been demonstrated to 

be effective for the material, environment, and 

conditions (e.g., remote methods) during the 

examination; and (b) the method is capable of 

quantifying general wall thickness and the depth of 

pits. 

25 Element 3.c / Page B-3 

Coatings may be intact, but could be disbonded. 

Replace the following sentence: 

Intact coatings do not have to be removed to 

inspect for potential cracking.” 

Recommended wording: 

Coatings that are intact, well-adhered, and 

otherwise sound for the remaining inspection 

interval do not have to be removed. 

The staff concluded that the proposed sentence 

accurately describes the staff’s intent. The change 

was incorporated. The staff also addressed coatings 

exhibiting blisters that are small in size and few in 

number. 

26 Element 4, 1st paragraph, bottom of page / Page 

B-3 

Editorial – Incorrect comma usage. 

For multi-unit sites, the inspections are... 

Editorial change incorporated. 
APPENDIX D 

RESOLUTION OF PUBLIC COMMENTS 

D-11 

27 Appendix B / page B-3 

The section for parameters monitored or 

inspected fails to identify the appropriate 

parameters to monitor. Item d. is the only item 

that identifies any parameters to monitor, that is, 

“pipe-to-soil potential and cathodic protection 

current.” Parameters monitored or inspected 

must be things that you can monitor and inspect 

even when there are no signs of aging effects. 

They must match the detection methods. For 

visual inspections and surface examinations, the 

only parameter that can be monitored is surface 

condition. Wall thickness should be the 

parameter monitored for the UT examinations. 

The AMP does not provide parameters to 

monitor for flow testing, jockey pump activity 

monitoring, or annual system leak test. Listing 

the applicable aging effects under parameters 

monitored and inspected is not consistent with 

the SRP description of the ten program 

elements. 

Recommend adding appropriate parameters to 

monitor. 

The staff revised the “parameters monitored or 

inspected” program element as follows. For 

conditioning monitoring aspects, a link was provided 

between the aging effect and the parameter or 

parameters that will be monitored. For performance 

monitoring aspects (e.g., jockey pump monitoring) 

specific examples were provided for each test method 

or trended parameter. 

28 Appendix B, Element #4, Page B-4, top 

paragraph 2nd sentence 

The sentence reads, “Piping inspections are 

typically conducted by visual examination of the 

external surfaces of pipe or coatings.” It does not 

address the scenario where much of the buried 

piping is encased in concrete, which industry 

sees as controlled low strength material backfill). 

Recommended change: 

Piping inspections are typically conducted by 

visual examination of the external surfaces of 

pipe, encasement if encased in controlled low 

strength material backfill or coatings. 

The staff revised the “parameters monitored or 

inspected” program element to address inspection of 

the external surfaces of controlled low strength 

material backfill. In conjunction with resolving this 

comment, the staff recognized that there was not an 

acceptance criterion for controlled low strength 

material backfill. A new acceptance criterion was 

added stating that cracks in controlled low strength 

material backfill that could admit groundwater to the 

surface of the component are not acceptable. 
APPENDIX D 

RESOLUTION OF PUBLIC COMMENTS 

D-12 

29 Element 4, Table 4, Preventive Action 

Categories D & E / Page B-6 

Eliminate the need to perform soil testing and 

confirm non-corrosive soil as part of Category E, 

and reverse the number of inspections between 

Categories D & E. 

Preventive Action Category D prerequisites are 

that soil has been proven non-corrosive per 

Element 2 Section e.iv (i.e., soil tests performed; 

locations, results, methodology submitted in the 

LRA). No cathodic protection is required. 

Preventive Action Category E prerequisites are 

that coatings and backfill meet preventive 

measure criteria, as-found coatings have been 

found in satisfactory condition, and soil has been 

demonstrated non-corrosion by performing soil 

test results prior to LRA submittal, and every 10-

year period during PEO. Cathodic protection is 

provided, but not performing at desired level. 

A station should perform fewer inspections when 

it has demonstrated it has coatings and backfill 

meeting preventive measures, a history of 

satisfactory as-found coating conditions, 

demonstrated non-corrosive soil, and some level 

of cathodic protection, than a station which has 

also demonstrated non-corrosive soil but has no 

cathodic protection at all. 

Alternatively, the existing numbers would be 

sufficient for stations which do not need to 

provide evidence of non-corrosive soil as many 

northern plants (where roadways are salted) 

would meet the definition of “mildly” or 

“moderately” corrosive soil per existing 

guidelines such as AWWA Standard C105 and 

Table 20.1 of C.P. Dillon Corrosion Control in the 

Chemical Process Industries. Effectively, this 

would prevent many/most northern plants from 

meeting definition of “non-corrosive” and ever 

meeting Preventive Action Category E. 

Recommended changes: 

Switch the number of inspections between 

categories D&E. 

Remove requirement to perform soil testing and 

demonstrate non-corrosive soil for category E. 

The staff does not agree with this comment. Preventive 

Action Category D is for those portions of in-scope buried 

piping where it has been demonstrated that external 

corrosion control is not necessary. The staff has concluded 

that the number of inspections for Preventive Action Category 

D is appropriate. If the applicant has presented sufficient 

evidence to demonstrate that external corrosion control is not 

required (i.e., soil analyses, pipe to soil potential 

measurements, other relevant parameters) periodic 

confirmation inspections should be conducted. However, the 

quantity of inspections does not need to be as high as for 

Preventive Action Category E. 

Preventive Action Categories C and E are used when it was 

not possible (or evidence was not presented in the LRA) to 

demonstrate that cathodic protection is not needed. Where 

cathodic protection is needed to protect the buried 

components, Preventive Action Category C represents the 

ideal condition. A cathodic protection system has been 

installed and the system is meeting operating and 

effectiveness goals. In contrast, for Preventive Action 

Category E, cathodic protection system is not meeting 

operating and effectiveness criteria, or it is impractical to 

install cathodic protection even though it is necessary to 

provide adequate protection for buried components. 

The AMP recommends that coatings and backfill are 

provided in accordance with the “preventive actions” program 

element for Preventive Action Category E. In order to meet 

this provision, it is presumed that there are plant-specific 

specifications or records that would demonstrate that the 

coatings and backfill are consistent with the “preventive 

actions” program element. Alternatively for backfill, if there 

are no plant-specific records, the AMP allows the backfill to 

be confirmed with each excavation. However, these 

plant-specific specifications, records, or excavations do not 

demonstrate that all of the coatings and backfill are 

acceptable. It is possible that local areas may have 

deleterious materials in the backfill or coating holidays might 

exist in some locations. In fact, based on the staff’s review of 

plant-specific OE, it is likely that most stations have some 

locations where the backfill and coatings are not completely 

effective. As a result, Preventive Action Category E 

recommends soil sampling to determine the corrosivity of the 

soil as a defense in depth for the coatings and backfill for 

those locations where cathodic protection is not meeting 

operating and effectiveness criteria, or it is impractical to 

install cathodic protection. The recommendation to conduct 

periodic soil testing for Preventive Action Category E will not 

be removed; however, an applicant can elect to not perform 

soil sampling by conducting inspections to Preventive Action 

Category F. 

In regard to the portion of the comment associated with 

northern plants, the staff has concluded that it is appropriate 

to use the term “demonstrated to be not corrosive.” The staff 

recognizes that when measuring only soil resistivity, terms 

such as “mildly” or “moderately” corrosive are used. 

However, as recommended in Table XI.M41-2, soil tests 

include multiple parameters including, soil resistivity, 

corrosion accelerating bacteria, pH, moisture, chlorides, 

sulfates, and redox potential. Given the values for each of 

these, an overall soil corrosivity characteristic can be 

determined. For example, AWWA C105, “Polyethylene 

Encasement for Ductile-Iron Pipe Systems,” Table A.1, 

“Soil-Test Evaluation,” states that a ten point or higher rating 

indicates that the soil is corrosive to ductile iron pipe. 
APPENDIX D 

RESOLUTION OF PUBLIC COMMENTS 

D-13 

30 Element 4, Table 4, Preventive Action Category 

E / Page B-6 

If the previous comment is not incorporated, 

Table 4, Category E, part b.iii.5 should be 

deleted. 

Item 5 precludes any station from meeting 

preventive action category E if soil samples are 

not performed prior to LRA submittal. If a 

definition or standard of what constitutes 

acceptable soil conditions was defined in the 

table, this would allow stations flexibility to 

perform soil sampling, testing, and evaluation at 

any time following issuance of a renewed license 

and meet the same intent as submitting the 

results with the LRA. As a result, stations could 

then adhere to Preventive Action category E 

should their cathodic protection underperform 

during any 10-year period and fail to meet 

category C criteria, and not have to default to 

category F instead. 

Recommended changes: 

Delete Table 4, Category E, part b.iii.5: 

5) Provides a summary of the results and 

conclusions of the soil testing in the LRA. 

The staff agrees with this comment. This wording was 

deleted from the AMP. The decision to conduct 

inspections to Preventive Action Categories C, E or F 

(although not D) is appropriately made when 

inspections are being conducted and not upon 

submittal of the LRA. Table XI.M41-2 was revised to 

provide AWWA C105, Table A.1 as one acceptable 

method to demonstrate that the soil is not corrosive. 

31 Element 4, Table 4, subpart E.a / Page B-6 

Suggest clarifying whether sites with excessive 

cementitious backfill are included. 

Recommended change: 

An analysis, conducted in accordance with the 

“preventive actions” program element of this 

AMP, has demonstrated that installation or 

operation of a cathodic protection system is 

impractical, apart from areas affected by 

cementitious backfill; or...” 

The staff does not agree with this comment. If it is 

impractical to install cathodic protection due to the 

amount of cementitious backfill that was used, 

Preventive Action Category E is still appropriate. For 

those portions of piping that are encased in controlled 

low strength material backfill, the inspections can 

consist of inspecting the external surfaces of the 

backfill for cracking. 
APPENDIX D 

RESOLUTION OF PUBLIC COMMENTS 

D-14 

32 Page B-6 and B-7, Table 4 Category E.b.iii 

As written, these criteria could be extremely 

difficult to meet. 1). Criterion E.b.iii should be 

revised to indicate that mildly corrosive soil 

environment may be acceptable. As written the 

soil environment must be demonstrated to be not 

corrosive. All soil environments have some 

corrosive tendencies. The analysis should 

demonstrate that an aggressive environment 

does not exist that would result in loss of 

intended function prior to the end of the PEO. 

Plants in northern environments typically have 

mildly aggressive soil environments next to 

roads that are heavily salted in winter. 

2.) Criterion E.b.iii.4) should be revised to delete 

or reword the reference to submitting the 

application. This would allow plants with 

renewed license to use Category E rather than 

Category F. 

3.) Criterion E.B.iii.5 prevents the use of 

Category E if soil samples are performed prior to 

LRA submittal. 

Recommend revising the following portions of 

Category E.B.iii as follows: 

E.b.iii Soil environment has been demonstrated 

to be not corrosive non-aggressive for the 

material type and would not result in a loss of 

intended function prior to the end of the PEO. In 

order to demonstrate that the soil is not corrosive 

aggressive, the applicant: 

E.b.iii.4) Conducts soil testing prior to submitting 

the application and once in each 10-year period 

starting 10 years prior to the period of extended 

operation. 

E.b.iii.5) Provides a summary of the results and 

conclusions of the soil testing in the LRA to the 

NRC. 

The staff agrees in part with this comment. The staff’s 

response to this comment and associated changers 

are discussed in Comment No. 29, last paragraph, and 

Comment No. 30. 

33 Element 4.a, 2nd sentence / Page B-7 

Typo. 

...For example, degraded performance of the 

cathodic protections system... 

Editorial change incorporated. 

34 Element 4.a, last sentence / Page B-7 

Last sentence of section should be clarified, with 

regards to the inability to credit inspections 

performed as part of the transition allowance as 

also counting as those required during the 

following interval. 

These additional inspections conducted during 

the four years following the end of an inspection 

interval cannot also be credited towards the 

number of inspections stated in Table 4 for the 

following 10-year interval. 

Editorial change incorporated. 
APPENDIX D 

RESOLUTION OF PUBLIC COMMENTS 

D-15 

35 Detection of Aging Effects / App B 

Page B-8 

It's not clear how the section c.iii extent of 

inspections for fire protection piping must be 

integrated with other inspections. If the piping is 

of the same material category as that in other 

systems, it's not clear that the inspections must 

include any fire protection piping at all, even if 

the extent of inspections is expanded as 

directed. The inspections are still based only on 

the material (and preventive conditions), not on 

the system. 

If the intent is that at least two inspections be 

performed on Fire Protection piping, then 

clarification should be provided in this section, or 

in Table 4. The remainder of the program is 

written such that no Fire Protection piping need 

be inspected if the system is monitored via 

approved alternatives. 

The staff agrees that as written, the sentence does not 

adequately convey the staff’s intent. The sentence 

was revised to clarify the staff’s intent. The intent is 

that if aging effects associated with fire protection 

piping are not managed by activities such as periodic 

flow tests, jockey pump monitoring, or annual leak 

test, then the number of excavated direct visual 

examinations in its material type is increased. The 

increase in inspections accounts for the fact that there 

is generally a considerable amount of buried fire 

protection piping. If this piping is not being monitored 

or tested for potential leakage by one of the 

alternatives, then increased inspections should be 

conducted for this material. This does not mean that 

fire protection piping must be excavated for direct 

visual inspection. 

For example, assume that the buried fire protection 

piping is constructed of ductile iron piping and steel 

piping is being inspected based on Preventive Action 

Category E. The number of inspections of buried steel 

piping would be 5 percent of the total of all buried steel 

piping including the fire protection piping or 5 

inspections of buried steel piping would be conducted. 

If the fire protection piping was being monitored or 

inspected by one of the above alternatives, 5 percent 

of the total of steel buried piping without including the 

fire protection piping or 3 inspections would be 

conducted. 

36 Element 4.d / Page B-8 

Suggest advising safe accessibility as well as 

risk. 

... selected based on risk (i.e., susceptibility to 

degradation and consequences of failure) and 

consider safe accessibility. 

The staff has not made any changes to AMP XI.M41 

based on this comment. Buried components 

inspections should be performed on those 

components with the highest susceptibility to 

degradation and the highest consequences of failure 

to plant safety. Industrial safety considerations are 

managed by the licensee. 

37 Page B-8 element 4.b.iii 

Element 4.b.iii (Exceptions to Table 4 Inspection 

Quantities) notes that when Preventative Action 

Category A or C is met for all materials except 

aluminum alloys, no inspections are necessary if 

all piping constructed from a specific material 

type is fully backfilled using controlled low 

strength material. There is no Preventative 

Action Category A defined for Table 4. 

Revise 4.b.iii as follows: 

For polymeric piping or when Preventative Action 

Category A or C is met for all materials except 

aluminum alloys, no inspections are necessary if 

all piping constructed from a specific material 

type is fully backfilled using controlled low 

strength material. 

The staff agrees with the need to correct this 

sentence. The reference to Category A was removed 

while retaining the alternative for polymeric piping as 

well as other materials. 
APPENDIX D 

RESOLUTION OF PUBLIC COMMENTS 

D-16 

38 Detection of Aging Effects App. B, b.iii, Page 

B-8. 

Item b.iii has "Category A shown" which no 

longer exists. 

Delete Category A. 

The staff agrees with this comment. See the response 

to Comment No. 37 

39 Detection of Aging Effects 

App. B, b.iv, Page B-8. 

Item b.iv has "Category B shown" which no 

longer exists. 

Delete existing text, “Category B shown.” 

The staff agrees with the need to correct this 

sentence. The sentence was revised to remove 

reference to Category B but retain the intent of the 

exception. 

40 Appendix B, Element #4, Page B-8, b.iii 

What is “Preventive Action Category A?” 

Please define. 

The staff does not agree with this comment; however, 

an editorial change was incorporated, see the 

response to related Comment No. 37. There is no 

need to define Category A because Table XI.M41-2 

states that Preventive Action Categories A and B are 

“no longer used.” Based on the staff’s attendance of 

several industry meetings related to buried piping, it 

recognized that Preventive Action Categories C 

through F were cited in industry presentations related 

to inspections of buried piping. As a result, the staff 

retained Preventive Action Categories C through F 

rather than re-lettering them as Preventive Action 

Categories A through D. 

41 Appendix B, Element #4, Page B-8, b.iv 

The sentence states “If all of the in-scope 

polymeric material is nonsafety-related, the 

inspection quantities for Preventive Action 

Category B may be reduced by half.” However, 

there are no inspection quantities in preventive 

action category B for polymeric materials. 

Recommend rewording as follows: 

If all of the in-scope polymeric material is 

nonsafety-related, the inspection quantities forin 

Preventive Actions Category B may be reduced 

by half. 

The staff agrees with this comment. See the response 

to Comment No. 39. 

42 Appendix B, Page B-8, section point d. 

“Piping inspection locations are selected based 

on risk (i.e., susceptibility to degradation and 

consequences of failure).” 

Recommend additional sentence=> In general, 

inspection locations as well as re-inspection 

intervals should be based on new risk results by 

re-integrating the monitoring and inspection 

results into plant’s buried piping risk database in 

order to update determine future re-inspection 

locations and intervals. 

The staff agrees that past inspection results should be 

used as input in determining the susceptibility to 

degradation for the selection of future inspection 

locations. However, inspection results should not be 

used to increase the interval of inspections beyond 10 

years. The proposed wording is ambiguous in regard 

to inspection intervals. As such, the staff has 

concluded that no changes will be incorporated into 

AMP XI.M41 as a result of this comment. 
APPENDIX D 

RESOLUTION OF PUBLIC COMMENTS 

D-17 

43 Element 4.e.ii / Page B-9 

Design pressure testing is only required for 

ASME structural credit and is not advised as a 

corrosion evaluation methodology. At a 5-year 

interval, operating pressure should be sufficient 

to identify / address vulnerabilities for nonsafetyrelated segments. Adding continuity and 

bounding components will compensate for this 

lesser pressure. This is consistent with NEI 09-

14 guidance. 

Recommended rewording: 

The piping is pressurized to 110 percent of the 

design pressure of any bounding component 

within the boundary with test pressure being held 

for a continuous eight hours interval. 

The staff agrees with this comment in part. Given that 

the term “bounding” is not defined, the staff adopted 

wording from ANSI/ASME B31.1, “Power Piping,” 

1983 Edition which states, “but shall not exceed the 

maximum allowable test pressure of any nonisolated 

components, such as vessels, pumps, or valves. 

44 Element 4.e.iii / Page B-9 

Inspections must be qualified to address threats. 

The inspection method has been demonstrated 

to be capable of detecting both general and 

pitting corrosion and is qualified by the applicant 

to identify/evaluate potentially unacceptable 

flaws. 

The staff agrees with this comment; however, 

alternative wording was used to link the aging effect to 

the acceptance criterion. 

45 Element 4.f. / Page B-9 

Inspections must be qualified to address threats. 

...demonstrated to be capable of detecting both 

general and pitting corrosion and is qualified by 

the applicant to identify / evaluate potentially 

unacceptable flaws. 

The staff agrees with this comment; however, 

alternative wording was used to link the aging affect to 

the acceptance criteria. 
APPENDIX D 

RESOLUTION OF PUBLIC COMMENTS 

D-18 

46 Page B-9 Element 6.a. 

Add a third coating qualification option that 

requires inspection and evaluation of buried 

external coating by a coating specialist qualified 

in accordance with an ASTM standard endorsed 

in Reg Guide 1.54 including staff limitations 

associated with a particular standard. Reg Gide 

1.54 Rev 2 endorses ASTM D4537-04a and 

ASTM D7108-05 which establish guidelines to 

qualify coating inspectors and Nuclear Coating 

Specialists. 

Recommend Element 6.a. be revised as follows: 

For coated piping or tanks, there is either no 

evidence of coating degradation, or the type and 

extent of coating degradation is evaluated as 

insignificant by an individual possessing NACE 

Coating Inspector Level 2 or 3 inspection 

qualification, qualifications in accordance with an 

ASTM standard endorsed in Regulatory Guide 

1.54 including staff limitations associated with a 

particular standard, or an individual who has 

attended the EPRI Comprehensive Coating 

Course and complete the EPRI Buried Pipe 

Condition Assessment and Repair Training 

Computer Based Training Course. 

The staff reviewed the qualification requirements for a 

coatings specialist during its development of AMP 

XI.M42, “Internal Coatings/Linings for In-Scope Piping, 

Piping Components, Heat Exchangers, and Tanks.” 

The staff has concluded that a coatings specialist 

qualified in accordance with Regulatory Guide 1.54 

(RG 1.54) has undergone sufficiently rigorous 

qualification program consistent with the other 

proposed qualification methods cited in AMP XI.M41. 

The change was incorporated and RG 1.54 was 

incorporated as a reference into the ISG and AMP 

XI.M41. 

47 Element 6.c / Page B-9 

Add rust staining as an indicator of migration 

without leakage due to insufficient cover. 

...leakage or exposed or rust staining from rebar 

or reinforcing “hoop” bands. 

The staff agrees with this comment. The change was 

incorporated as requested. 

48 Element 6.f / Page B-9 

Hydro testing is overly specific for some piping 

systems, functions, and conditions. 

For hydrostatic pressure tests, the test 

acceptance criteria are that there are no visible 

indications of leakage, and no drop in pressure 

within the isolated portion of the piping, that is 

not accounted for by a temperature change in 

the test media or by quantified leakage across 

test boundary valves. 

The staff agrees with this change. Given that the 

specific pressurization value is provided in the AMP 

(I.e. 110 percent), the term “pressure test” is 

adequately descriptive. The change was incorporated 

as requested. The change was also incorporated in 

two other places where the testing is cited in the AMP. 

49 Element 6.f / Page B-9 

Editorial –Incorrect comma usage. 

...isolated portion of the piping that is not 

accounted for... 

Editorial change incorporated. 

50 Appendix B /page B-9 

Acceptance criterion of no pressure drop seems 

abnormally stringent for a hydrostatic test. Isn’t it 

normal to have such tests deemed acceptable 

based only on visual inspections not identifying 

leakage? 

N/A 

The staff does not agree with this comment. When a 

pressure test is utilized in lieu of an excavated direct 

visual examination of buried piping, 25 percent of the 

particular material type is pressure tested. It is not 

expected that all of this piping would be excavated and 

available for visual observation of leakage. Pressure 

drop is the only viable means to detect leakage in the 

unexcavated piping. 
APPENDIX D 

RESOLUTION OF PUBLIC COMMENTS 

D-19 

51 Element 6.g / Page B-10 

Editorial –Incorrect comma usage. 

...leakage from buried piping are, not occurring. 

Editorial change incorporated. 

52 Element 6, Table 6 / Page B-10 

Add -1200mV acceptance criterion for aluminum 

piping per NACE SP0169-2013. 

-Similar to relocation of discussion on 

precautions of overprotection of coated piping, 

recommend discussion on precautions of 

overprotection of PCCP pipe be moved to 

Element 2 as a preventive measure as well. 

-Add -1200mV acceptance criterion for 

aluminum. 

Relocate PCCP overprotection discussion to 

Element 2. 

The staff agrees with this comment. AMP XI.M41 was 

revised to state that the upper -1200 mV polarization 

criterion applies to prevent damage to either the 

coatings or base metal, for example aluminum. The 

limit for PCCP (prestressed concrete cylinder piping) 

was moved to the “preventive actions” program 

element in response to Comment No. 18. 

53 Appendix B, Table 6, foot note 2 

This table uses -1,000 mV. In other areas -1,200 

mVs are used? Need to be consistent in all 

locations where 1200mV is used such as 2.b that 

implies 1200 is the criteria for all when it isn’t for 

prestressed concrete piping as discussed in 

Table 6. 

Recommend adding to 2.b, For prestressed 

concrete cylinder piping the potential should be 

no more than -1000 mV to prevent hydrogen 

generation or embrittlement of the prestressed 

wiring. 

The staff agrees with this comment. See resolution of 

Comment Nos. 18 and 52. 
APPENDIX D 

RESOLUTION OF PUBLIC COMMENTS 

D-20 

54 Appendix B “Acceptance Criteria” Table 6, page 

B-10 

Page B-10, Table 6 provides CP acceptance 

criteria (-850 mV relative to a CSE instant off for 

Steel). If acceptance criteria are not met, that 

test point is not considered "effective" and would 

result in transitioning into a higher inspection 

category. However, Note 2 within this table 

states that "Where an impressed current 

cathodic protection system is utilized with prestressed concrete pipe, steps are taken to avoid 

an excessive level of potential that could 

damage the prestressing wire. Therefore, 

polarized potentials more negative than -1000 

mV relative to a CSE are avoided...". It is not 

clear whether the -1000 mV for pre-stressed 

concrete pipe is a criterion that would determine 

whether the protection is "effective" that would 

result in transitioning into a higher inspection 

category if exceeded, or just a level to be 

avoided. 

If it is meant to be an acceptance criterion, then 

include the -1000 mV in the body of the table 

rather than a footnote. If it is not an acceptance 

criterion, that should be clarified in the footnote. 

The staff agrees with this comment. See response to 

Comment No. 18. 

55 Element 6.k.iv / page B-10 & B-11 

The -650mV and -750mV criteria should not 

need to be confirmed via the 1mpy criterion. If 

<1mpy corrosion is occurring, as indicated by an 

ER probe, this is confirmation itself of lack of 

corrosion, such that a secondary evaluation 

need not be performed of whether test points are 

also meeting -650mV and -750mV at locations of 

high resistivity soils. These alternative values for 

high resistivity soils are presented in ISO 15589-

1 as valid stand-alone acceptance criteria, not 

requiring confirmation via other means. 

This is particularly relevant to piping which is 

backfilled in cementitious material. Cementitious 

materials often have very high resistivity values, 

but an ER probe would be unable to provide 

representative corrosion rates of pipes 

embedded in concrete backfill. Without breaking 

apart the cementitious fill and directly examining 

the embedded pipe, there are few practical 

means to otherwise confirm absence of on-going 

corrosion. This requirement to confirm corrosion 

rates should especially not be applicable to 

piping embedded in cementitious materials. 

Recommend only requiring the soil resistivities 

be verified every 5 years for application of 

the -650mV and -750mV criteria. 

The staff does not agree with this comment. However, 

based on a further review of NACE Corrosion Expo 

2006, Paper No. 06163, the staff has concluded that 

an alternative to verifying the effectiveness of the 

cathodic protection system every 5 years will provide 

equivalent assurance. The paper states, “[l]arge 

variations in soil resistivity (by an order of magnitude) 

were observed...” 

The alternative consists of soil resistivity testing being 

conducted annually during periods where soil 

resistivity would be expected to be at its lowest value. 

In addition, if 10 years of data demonstrate that 

resistivity is within the expected range (e.g., for the -

750 mV relative to a CSE, instant off criterion, all soil 

resistivity values were greater than 10,000 ohm-cm), 

the staff has concluded that further soil resistivity 

testing could be conducted every 5 years. 

The staff concludes that this alternative provides 

equivalent assurance of adequate cathodic protection 

because there is ample evidence (see the basis for the 

change discussion in the front material of the ISG) to 

demonstrate that in higher resistivity soils, lower levels 

of cathodic protection provide adequate protection for 

the piping. 
APPENDIX D 

RESOLUTION OF PUBLIC COMMENTS 

D-21 

56 Element 6.k.iv / page B-11 

The 100mV criterion should not be required to be 

proven effective by periodic assessment of a 

1mpy criterion. The 100mV criterion can be 

proved effective in a mixed metal environment 

for a material that is not the most anodic, through 

a variety of means. 

The 100mV shift can be proven effective with 3 

basic components; reference cell, noncathodically protected metal object that is 

electrically isolated from a mixed-metal 

environment, and a cathodically protected 

protect metal object of the same material that is 

interconnected with the mixed metalenvironment. So long as the instant-off 

polarization potential difference between the 

non-cathodically protected object and 

cathodically protected object is >100mV, this is 

demonstration of 100mV of polarization. While 

certain sophisticated ER probe assemblies (i.e., 

“smart-stacks”) prove this with ER probes, which 

also are able to provide information on corrosion 

rates, ER probes are not exclusively required to 

perform this assessment. As such, validation of 

<1mpy corrosion rates in all applications is not 

possible, nor should it be required. 

Demonstration of this 100mV shift is in 

accordance with NACE SP0169-2013, and 

numerous international standards, which have 

long established this as evidence of effective 

cathodic protection and not requiring validation 

of material loss rates through other means. 

Inclusion of the requirement to verify 

effectiveness of the 100mV shift, as evidence by 

also monitoring corrosion rate over time, is 

beyond the scope and requirements of NACE 

SP0169-2013 and all international CP standards, 

and thus, should not be included in LR-ISG2015-01. 

Recommend removing requirement to validate 

corrosion rate (<1mpy) when demonstrating the 

100mV polarization criteria. Acceptability of 

100mV shift as an acceptance criterion could be 

documented in an engineering evaluation, if 

necessary. 

The staff does not agree with this comment. The 

100mV polarization criterion may not be effective in a 

mixed metal environment. This is reinforced by ISO 

15589-1, which states, “[f]urthermore, the criteria [100 

mV polarization] shall not be used in case of pipelines 

connected to or consisting of mixed metal 

components.” The typical nuclear site contains buried 

mixed metals. 

AMP XI.M41states that if the 100mV polarization 

criterion is used, the applicant verifies the 

effectiveness of the cathodic protection system. The 

AMP provides one recommended method to 

demonstrate that the cathodic protection system is 

effective. If an applicant selects this method, it can 

declare its program consistent in regard to using the 

100 mV polarization criterion. An applicant can state 

an exception to the AMP, propose an alternative way 

to demonstrate the effectiveness of the cathodic 

protection system, and provide the basis to explain 

why the method will be effective. 
APPENDIX D 

RESOLUTION OF PUBLIC COMMENTS 

D-22 

57 Page B-10 and B-11 

Element 6.k. 

ISO 15589-1, an international standard on 

cathodic protection, cites additional cathodic 

protection guidance on cathodic protection 

acceptance criteria that should be incorporated 

into XI.M41. The acceptance criteria for cathodic 

protection polarization of steel piping, specifically 

the -850mV criterion, should be modified to 

incorporate guidance provided in ISO 15589-1. 

This ISO standard lists other CP potential values 

based upon soil resistivity. 

<100ohm-m -850mV 

100-1000 ohm-m -750mV 

>1000ohm-m -650mV 

The -650 mV and -750 mV criteria based on soil 

resistivity should not need to be confirmed by the 

1mpy criterion. 

Recommend revising Table 6 to allow the 

application of -650 mV and -750 mV acceptance 

criteria based on soil resistivity and deleting 

confirmation by the 1mpy criterion and require 

only soil resistivity be verified every 5 years. 

The staff does not agree with this comment; however, 

a related change was incorporated. See the response 

to Comment No. 55. 

58 Page B-10 and B-11 Element 6.k 

The 1 mpy acceptance criterion should be 

revised to note that corrosion rates in excess of 

1 mpy may also be acceptable if the corrosion 

rate would not result in a loss of intended 

function prior to the end of the PEO. 

Recommend adding the following to the first 

paragraph on page B-11 just prior to the last 

sentence: Corrosions rates in excess of 1mpy 

may be acceptable if an engineering evaluation 

demonstrates that the corrosion rate would not 

result in a loss of intended function prior to the 

end of the PEO. 

The 1 mpy criterion is an industry-accepted standard. 

For example, it is cited in NACE SP-0169-2013, 

Section 6.1, “Criteria and Other Considerations for 

Cathodic Protection, Introduction.” However, the staff 

agrees with this comment. The staff recognizes that 

some buried pipe systems, depending on the pipe 

design pressure and wall thickness, may have 

adequate margin to allow a higher annual corrosion 

rate. AMP XI.M41 was revised to include a 

recommendation that the engineering evaluation be 

cited and summarized in the LRA. The purpose of the 

summary in the LRA is for the staff to effectively 

determine the adequacy of the evaluation or to 

formulate followup questions. 

59 Element 7.a / Page B-11 

Nonconforming fill requires guidance on 

corrective actions to focus results. 

...observed damage will not lead to further 

degradation (e.g., indirect assessments of 

coatings / CP integrity or CP performance within 

specifications to address risks to damaged 

areas). 

The staff does not agree with this comment. The 

recommendations in the comment are not related to 

mitigating the potential impact of damage to the 

coatings. The AMP recommendation is to assess the 

extent of the nonconforming backfill. The staff revised 

the wording to more clearly align with the extent of the 

degraded backfill. The wording, “in the vicinity of the 

observed damage” is intended to communicate that 

the extent of condition is not meant to encompass the 

entire site, but rather the degraded backfill in the 

vicinity where the deleterious materials were detected. 

However, if repeated instances of detecting 

deleterious material in the backfill that caused damage 

to coatings occur, it would be expected that a licensee 

would appropriately respond via its corrective action 

program. 
APPENDIX D 

RESOLUTION OF PUBLIC COMMENTS 

D-23 

60 Element 7.b / Page B-11 

Editorial – Incorrect comma usage. 

...large area minimum wall thickness and local 

area wall thickness... 

Editorial change incorporated. 

61 Element 7.c / Page B-11 

Where the coatings, backfill, or the condition of 

exposed piping reveals piping integrity results 

that do not meet acceptance criteria, the 

degraded component is repaired or replaced. In 

addition, an expansion of sample size is 

conducted to evaluate the at-risk condition 

identified (e.g., damaged coatings due to 

nonconforming fill and poor CP). The number of 

inspections within the affected piping categories 

are doubled or increased by 5, whichever is 

smaller. If nonconforming piping integrity 

conditions are identified in any of the expanded 

samples, an analysis is conducted to determine 

the extent of condition and extent of cause. The 

number of the follow-on inspections is 

determined based on the extent of condition and 

extent of cause. 

Recommend restricting corrective actions to 

integrity-driving risks and not merely 

nonconforming controls. 

The staff agrees with this comment. Based on its 

review of an extensive number of buried pipe 

inspection results, there are instances where minor 

coating or base material damage is noted. However, 

the depth or extent of the damage to the base material 

would not warrant an extent of condition inspection 

plan. The intended function of typical buried piping 

and tanks is to ensure that sufficient flow at adequate 

pressure can be delivered to downstream in-scope 

components. This function could be met even though 

leakage is occurring. The staff revised the 

recommendation to conduct extent of condition 

inspections to those instances where degradation in 

base material, regardless of cause, could result in a 

potential challenge to the pressure boundary. 

62 Element 7.f. / page B-12 

This recommended corrective action does not 

seem necessary. Alternatives to the -850mV 

criterion are intended to demonstrate, through 

other means, whether the CP system is effective. 

If, through these other means, CP is still found to 

be ineffective, the consequence should be no 

different than if the -850mV criterion was used 

and not met...specifically, it would count against 

the Effectiveness criteria contained in Table 4 

and result in changes in preventive action 

categories (e.g., drop from Category C to E or 

F). 

If corrosion rates consistently came back >1mpy, 

indicative of on-going corrosion, the piping 

segment would thereby meet category E or F, 

and require inspection. If corrosion rates came 

back >1mpy once or twice over 10 years, this 

would not be indicative of significant corrosion 

and cause for concern. 

Recommended change: 

f. When using the alternatives to the -850 mV 

relative to a CSE instant off acceptance criterion 

for the cathodic protection system, the 

application states what actions will be taken if 

the measured external loss of material 

acceptance criterion, or internal loss of material 

rates (if opportunistic inspections are conducted 

by other AMPs) is exceeded. 

The staff agrees with the logic of this comment. The 

purpose of establishing acceptance criteria for the 

cathodic protection system is to establish reasonable 

assurance that loss of material will not challenge the 

intended function of a buried component. The outcome 

of assessing the effectiveness of the cathodic 

protection system should be the same regardless of 

the criteria or means to assess the effectiveness. The 

staff deleted the sentence as recommended. 
APPENDIX D 

RESOLUTION OF PUBLIC COMMENTS 

D-24 

63 Appendix B “Corrective Actions”, page B-12 

Corrective Actions element part “g” discusses 

the option of monitoring the activity of a jockey 

pump instead of inspecting buried fire water 

system piping. It contains a cross reference to 

“4.d.i”. The cross reference seems incorrect as 

Section 4 “Detection of Aging Effects” part “d” 

does not contain an item “i”. 

It seems that the correct cross reference should 

be 4.e.i. 

An editorial change was incorporated to remove 

reference to the earlier section of the AMP. 

64 Element 10 / Page B-12 

SP0169-2013 has relevant guidance for design / 

application of CP. 

Such as those prescribed in NACE SP0169-

2007, NACE SP0169-2013, and NACE RP0285-

2002 

The staff does not agree with adopting the 2013 

edition of NACE SP0169-2013. See the response to 

Comment No. 19. 

65 Element 10 / Page B-12 

Editorial – Incorrect comma usage. 

...plant-specific and nuclear industry operating 

experience and to modify its AMP, accordingly. 

Editorial change incorporated. 

66 References / Page B-13 

Suggest adding EPRI guidance, if permissible. 

Recommendations for Buried Piping / Tanks and 

the Buried Piping NDE Reference Guide. 

The staff added EPRI 1021175, “Recommendations 

for an Effective Program to Control the Degradation of 

Buried and Underground Piping and Tanks,” to the 

reference list. The document contains valuable 

information about buried piping and tanks (e.g., 

potential causes of failure, risk ranking considerations) 

and is publically available at no charge. 

67 General 

We agree with many of the revisions 

incorporated by this ISG. The revisions are 

based on industry operating experience and 

lessons learned consistent with the NEI 09-14 

industry initiative for management of 

underground piping and tank integrity. The 

revisions provide flexibility for aging 

management of underground piping and tanks, 

incorporation of applicable program 

improvements, and consideration of applicable 

industry operating experience. 

Comment – no revision required. 

No response required 

68 Appendix B, d. 

ECDA tools have had limited success in nuclear 

power plants (ASME PVP2012 Session 2.1P). 

SP0502 tools can be useful with a skilled 

operator with an understanding of the limitations. 

Add after has been effective: “under certain 

conditions with a nuclear power plant 

experienced technician” 

The staff reviewed the AMP recommendations for 

selecting piping inspection locations and determined 

that sufficient guidance was provided by the first 

sentence to not require an example. The sentence 

associated with ECDA was deleted. 
APPENDIX D 

RESOLUTION OF PUBLIC COMMENTS 

D-25 

69 Appendix B, i. 

Soil-to-pipe is incorrect, replace with pipe-to-soil. 

Editorial change incorporated. 

70 Good No response required 

71 In Appendix B under Section 6 on Page B-9 of 

draft LR-ISG-2015-01 it states that the 

qualifications of the individual that is evaluating 

the coatings for coated piping or tanks. It invokes 

the NACE Coating Inspector Program Level 2 or 

3 inspector qualification. It also allows for an 

individual who has attended the EPRI 

Comprehensive Coatings Course and completed 

the EPRI Buried Pipe Condition Assessment and 

Repair Training Computer Based Training 

Course. Invoking the EPRI Comprehensive 

Coatings Course is overly restrictive and not 

consistent to what is done within the industry. 

ASTM D-33 developed ASTM D7108 (Standard 

Guide for Establishing Qualifications for a 

Nuclear Coatings Specialist) and this standard is 

invoked by Regulatory Guide 1.54, Rev. 2. 

Suggest the sentence be revised to state, or an 

individual who is a Nuclear Coatings Specialist 

qualified in accordance with ASTM D7108 and 

completed the EPRI Buried Pipe Condition 

Assessment and Repair Training Computer 

Based Training Course. 

The staff agrees with this comment. See the response 

to Comment No. 46. 
APPENDIX D 

RESOLUTION OF PUBLIC COMMENTS 

D-26 

72 My questions and comments relate to the 

"Alternative Cathodic Protection Acceptance 

Criteria" that are described in LR-ISG-2015-01. 

The following alternative cathodic protection 

(CP) acceptance criteria were added for buried 

piping and tanks going through license renewal: 

(a) -750 mV (CSE) instant-off structure-to-soil 

potential where the soil resistivity is greater than: 

(a) 10,000 ohm-cm to less than 100,000 ohmcm, and (b) -650 mV (CSE) instant-off structureto-soil potential where the soil resistivity is 

greater than 100,000 ohm-cm. 

We understand that the staff added these criteria 

for soils with higher resistivity based on its 

inclusion in international standards, the staff's 

review of industry papers on alternative 

acceptance criteria, and a recommendation to 

verify the alternative acceptance criteria through 

the use of electrical resistance (ER) probes to 

verify that the corrosion rate is less than 1 mpy. 

It would appear that these two alternative criteria 

are far less restrictive than the minimum -850 

mV (CSE) polarized instant-off criteria as 

referenced in NACE SP0169-2013 or Table 6a 

"Cathodic Protection Acceptance Criteria" that is 

referenced in the previous Staff Guidance LRISG-2011-03 (i.e., -850 mV instant-off potential 

or the 100 mV minimum polarization that is 

limited to electrically isolated sections of pipe). 

The following are my questions / comments. 

Based on these questions and comments I 

believe additional guidance from the NRC should 

be provided: 

No response is required for this portion of the 

comment. The subparts of the comment are 

addressed in Comment Nos. 73 – 76. 

73 We have a client that has installed coupon test 

stations for buried piping at their site; however 

they do not have ER probes installed. We have 

conducted limited testing on the soil backfill in 

the lab for various chemical species, pH, % 

moisture content, soil resistivity (soil box 

method) and have performed linear polarization 

resistance (LPR) testing of the soil samples in 

the lab using a carbon steel coupon. LPR 

corrosion rate testing could also be performed in 

the field at the coupon test stations using the 

Native and CP Coupons. I assume that LPR, 

corrosion rate test results would also be 

applicable to qualify use of the Alternative CP 

Acceptance Criteria? 

Based on its review of NACE RP-0502-2002, 

“Standard Recommended Practice Pipeline External 

Corrosion Direct Assessment Methodology,” the staff 

will not revise AMP XI.M41 to incorporate LPR testing 

in lieu of electrical resistance corrosion probes. The 

basis for this is that LPR probes measure an 

instantaneous rate of corrosion. The testing results 

could under predict the cumulative rate of loss of 

material over time. In addition, NACE International 

Publication 05107, “Report on Corrosion Probes in 

Soil or Concrete,” states that the inputs used for LPRs 

are not valid under applied CP potentials and some 

instruments only provide a qualitative indication of 

corrosion by pitting. In addition, Figure 6, “Range of 

Operation of LPR Probes in Soil and Concrete,” of this 

document reveals limited applicability for one type of 

LPR probe (without solution resistance compensation) 

in the soil resistivity and loss of material rates of 

interest. 

As with all recommendations in an AMP, an applicant 

can state an exception and provide a basis for using 

alternative method. 
APPENDIX D 

RESOLUTION OF PUBLIC COMMENTS 

D-27 

74 Since some of the pipe is backfilled with 

engineered fill, the Wenner 4-pin method for 

determining soil resistivity (ASTM G57) would 

not be applicable, as these measurements are 

taken in remote areas (typically outside of the 

plant area) where the readings would not be 

influenced by buried structures beneath the pins. 

The Wenner 4-pin readings would therefore be 

more applicable for measuring the soil resistivity 

of the native soil at the site, rather than the soil 

backfill. For measuring the soil backfill resistivity, 

the soil box method (ASTM G187) using "asfound" and "saturated" soil samples from around 

the pipe should be performed. Is this a correct 

assumption? 

No changes to the AMP are proposed or necessary. 

AMP XI.M41 does not provide specific guidance on 

methods to determine soil resistivity, beyond 

recommending the periodicity of testing, number and 

location where the measurement is taken (i.e., in the 

vicinity in which in-scope components are buried). 

75 How often do you collect soil samples for 

resistivity testing along a piping system and how 

do you apply these readings to the alternative 

criteria? Is there a maximum distance from the 

pipe that the soil samples should be collected 

and tested? For example are 2 or 3 soil box 

resistivity readings measured at a plant typically 

sufficient to prove that the soils have higher 

resistivity (i.e., >10,000 ohm-cm), or should the 

use of the alternative criteria be based on 

assessment of documentation that indicates 

similar soil backfill conditions exist on any given 

section of pipe and using the soil box resistivity 

data from pipe excavations for that system. 

No changes to the AMP are proposed or necessary. 

AMP XI.M41 recommends the: (a) periodicity of 

measuring soil resistivity; (b) location of samples, in 

that readings are taken in the vicinity of the buried 

component of interest; and (c) the minimum number of 

soil samples, that being, three sets of soil samples in 

each soil environment (e.g., moisture content, soil 

composition) in the vicinity in which in-scope 

components are buried. The maximum distance that 

samples are taken from a component of interest is at 

the discretion of site or contractor personnel used by 

the applicant taking into consideration plant-specific 

configurations 

76 How many ER probes (or LPR corrosion rate 

measurements) are considered necessary to 

verify that the corrosion rate is less than 1 mpy? 

ER probes rely on changes in the cross sectional 

area of a buried electrical resistance conductor 

that is exposed to the soil environment next to 

the pipe and typically the probe is furnished with 

a check element to verify equipment accuracy. 

For ER probes typically you would measure the 

corrosion rate with the same instrument on a 

quarterly basis and then trend the data to 

determine corrosion rate over several years so 

the corrosion rate can be determined as a 

function of environmental conditions such as rain 

fall and periods of drought. They can be 

electrically connected to the structure with an 

external grounding cable so the probe can 

provide a continuous record of the CP system 

effectiveness. Are LPR measurements using a 

carbon steel coupon exposed to the soil sample 

or LPR measurements from coupon test stations 

considered acceptable alternatives for 

determining corrosion rate? 

The staff’s position regarding the use of LPR probes is 

addressed in the response to Comment No. 73. 

The staff has concluded that the number and location 

of ER probes necessary to verify a corrosion rate of 

less than 1 mpy is a plant-specific determination. 

These parameters are derived by individuals meeting 

the qualification recommendations in AMP XI.M41 

(e.g., NACE CP4).