NACE International carefully removed from the pipe; see

NACE International

After hardening of the resin, the bituminous coating around the cap was peeled off, and the whole cap was carefully removed from the pipe; see Figure A6.

Figure A6: The cap is removed. The leak is located in the center of the black spot.

It was found that the bituminous coating had delaminated in all areas of the pipe and had become brittle. However, in the area surrounding the leak (i.e., under the cap), it was soft and sticky, adhering well to the steel. The area above and around the leak was covered by bituminous material with regions of shiny appearance (Figure A7).

Figure A7: Shiny appearance of the bitumen above the leak.

After removal of this material and cleaning, localized attack with deep cavities in a generally passive suilace and a pinhole-size penetration were found; see Figures A8 and A9.

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Figure A8: Pipe surface after removal of the coating.

Figure A9: The corroded area after cleaning. The arrow indicates the leak location.

The cap was cut perpendicular to the pipe's axis, in the plane of the leak position. Figure A10 presents a view of the cross section. Above the corroded area, the original layer of the coating is no longer visible. Instead, the bitumen has spread out and formed a bubble-like structure (black material, denoted as "K in Figure A10). Embedded are regions of soil material (gray material, "B") and a white substance (material "C"), well separated by thin layers of material A.

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Figure A10: View of the cross section of the soil cap, in direction of the pipe's axis. The letters indicate different types of material.

Chemical Analyses

Multiple samples of materials A, B, and C were characterized by wet chemical analysis and by energy dispersive X-ray analysis (EDX) in the scanning electron microscope (SEM), operated at 20 kV. The results are summarized as follows:

Material A

All black material was based on bitumen with varying amounts of iron oxide (mainly magnetite) and a sodium compound, presumably carbonate. The inorganic components are finely dispersed in the bituminous matrix.

The bituminous material was removed by extracting with an organic solvent, and the solid residual was separated into magnetic and nonmagnetic portions. Figures A11(a) and A11(b) present the corresponding EDX spectra. The element sulfur is believed to originate from the bitumen, as it was also identified in a sample of the bitumen visible in Figure A7; see the EDX analysis in Figure Al2.

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1.1. 2.SS 3.11 8_811 5_88 6-15 7_11 R_SO 9_1111

Figure A11(a): EDX spectrum of the non magnetic fraction of material A.

1_80 2.811 3.811 4.88 5-11 6-11 7.88 8-11 9.SO

Figure A11(b): EDX spectrum of the magnetic fraction of material A.

1.611 2-08 3_66 8-Se SAM 6_86 7_88 S_SO 9_11

Figure Al2: EDX spectrum of the shiny bitumen visible in Figure A7.

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Material B

This grey material is based on the soil material, i.e., it is a silicate incorporating minor amounts of alkali (Na, K) and earth alkali (Ca, Mg) ions; see the EDX analysis in Figure A13. Based on the analysis of an aqueous eluate of the soil (ratio 1 g solid/10 mL distilled water) sampled far from the corrosion site, the Na ions are soluble (110 mg Na/kg soil), and a pH of 8.2 was found. The content of soluble Na increases with decreasing distance from the corrosion site and was found as high as 12,500 mg/kg in material from inside the cap. The EDX spectrum in Figure A14 was obtained from material sampled inside the cap.

2.81 3AS CAS 5.68 6.11 7.68 8.SO 9.14

Figure A13: EDX spectrum of the soil far from the corrosion site.

11.96 1.80 2_711 3.611 4.56 5.411 6.36 7.2S $AS 9.14

Figure A14: EDX spectrum of material B.

Material C

This white substance was identified as a mixture of sodium bicarbonate (NaHCO3) and sodium carbonate (Na2CO3) in a molar ratio of 1:1, without any significant impurities; its EDX analysis is presented in Figure A15. A solution of 1 g in 10 mL water resulted in pH of 9.6.

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Na

o

ci

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1.55 2.1111 3.14 4.511 5.821 6.1116 7.116 SAS 9.1111

Figure A15: EDX Spectrum of material C.

Summary and Discussion

This case of pipeline corrosion is characterized by localized attack similar to pitting. Surprisingly, the bituminous coating was found to be deformed like a bubble. Its appearance gives the impression of being remelted. Such thermal influence could also explain the good adherence of the coating in the vicinity of the corrosion site, while it was found generally delaminated in all other areas, which should be considered normal, given its age. Magnetite was found to be the major corrosion product; however, it could not form a protective layer and was dispersed in the bituminous material. High cathodic activity is indicated by large volumes of pure sodium carbonate embedded in the bubble.

The findings from the failure analysis indicate that processes that can hardly be explained by normal corrosion and appear compatible with AC-influenced corrosion have taken place. These specific features are (1) strongly localized, pitting-like attack, (2) finely dispersed magnetite as the predominant corrosion product, (3) accumulation of large amounts of sodium carbonate, (4) indications of local temperature excursions to values softening bitumen, and (5) influence of mechanical forces mixing soil, bitumen, and sodium carbonate as could be achieved by slowly evolving gas bubbles.

The following case histories are based on the expanded version of the presentation given at the NACE Eastern Area Conference, Oct 8-10, 2007.68

Case Study 3 (Adapted from Reference 68)

A 10 in (254 mm) diameter, 0.188 in (4.78 mm) wall, API 5LX, grade 60 steel underground liquid product pipeline was installed in 1994. It was coated with 14 to 16 mil (0.36 to 0.41 mm) thick FBE. The pipeline was located in a common corridor with three HVAC transmission lines for approximately 18 miles (29 km). The corridor included a 345 kV double circuit, vertically mounted line on steel towers, a 115 kV horizontally configured line on wood towers, and a 230 kV horizontal wood tower line. See Figure A16.

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Figure A16: Schematic of HVAC lines and the affected pipeline.

The pipeline parallels (at a typical spacing of 50 ft [15 rn]) with several crossings under these HVAC lines. These transmission lines leave the pipeline at 90 degree angles at both ends of the collocation. In 2001, a fourth HVAC transmission line was added to the corridor. This 230 kV double-circuit vertically mounted steel towered line runs parallel for approximately 4 miles (6.4 km). It enters the main corridor 2.5 miles (4.0 km) from where the pipeline pulls away, and it turns with the pipeline at 90 degrees, then runs with it for 1.5 miles (2.4 km) before crossing and leaving it at 90 degrees. In 2006, an ILI run identified several external corrosion anomalies in a 200 ft (61 m) long section of the pipeline in the area where it is near the newer 230 kV line.

Excavation of these anomalies revealed corrosion pits 0.163 in (4.14 mm) deep (87% of wall), 0.145 in (3.68 mm) deep (77% of wall), and 0.115 in (2.92 mm) deep (61% of wall), all of which had similar morphology characteristic of AC corrosion damage. See Figures A17, A18, and A19.

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Figure A17: Dig 1. Anomaly 0.163 in (4.14 mm) deep (87% of wall loss).

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Figure A18: Dig 2. Anomaly 0.145 in (3.68 mm) deep (77% wall loss).

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Figure A19: Dig 2. Anomaly 0.115 in (2.92 mm) deep (61% wall loss).

During the investigation, AC pipe-to-soil potentials at the pipe surface in the area were found to be from 5.5 to 7.8 VAC. The resistance of the soil directly adjacent to the pitting site was from 785 to 2,298 acm, and the soil pH was 8. The DC pipe-to-soil potentials and the high pH under the corrosion product at the pipe surface (11 to 13) indicated adequate CP. The soil resistivity along the remainder of the collocation varied from 5,000 to 30,000 acm; induced AC potentials as high as 22 VAC were measured at other locations in the corridor. However, the ILI run did not show external corrosion anomalies outside the isolated pocket of low-resistivity soil.

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A 14 in (356 mm), 0.375 in (9.53 mm) wall, high-pressure steel underground gas pipeline was installed in 1999. It was coated with 14 to 16 mil (0.36 to 0.41 mm) FBE and crossed and paralleled three 345kV HVAC transmission lines for approximately 4 miles (6.4 km). Two of the 345 kV transmission lines are single-circuit lines carried horizontally on steel towers. The pipeline runs parallel between these lines at a typical spacing of 200 ft (61 m) from one line and 400 ft (122 m) from the second. The pipeline leaves the transmission corridor at 90 degrees and joins a third 345 kV transmission line (double-circuit vertical steel tower configuration) with a spacing of approximately 45 ft (14 m) for approximately 0.5 miles (0.8 km), crossing and leaving it at 90 degrees. In 2004, an ILI run identified several external corrosion anomalies in the short section of the pipeline in the area close to where it crosses the double-circuit transmission line. See Figure A20.

Figure A20: Schematic of HVAC lines and the affected pipeline.

Excavation of these anomalies revealed coating damage over a 20 ft (6.1 m) long section. Several corrosion pits were observed at large coating holidays. The deepest was 0.150 in (3.81 mm) deep (40% of wall loss) and had a morphology consistent with that considered to be characteristic of AC corrosion damage. No AC potentials were taken during the dig investigation; however, a survey at a later date indicated an induced potential of 2.3 V. See Figure A21.

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IIIIIII I 11111 11111111 1 11111111110111i11111y1111•I 1 i1111illitll 1 '3 4 5

I ? CZ 61. 21. Ll 0

11111i.11111iidwilitiih: 111 1 11111:11011 ,1111111imillaujijuillimlity,Itilitinhinhohni , ,;1

Figure A21: Coating damage and corrosion sites.

Predictive modeling indicated that induced AC potentials of up to 8 V may have been present at the excavation site under certain transmission line loading. The bulk soil resistance (determined by the Wenner 4 pin method at 5 ft [1.5 m] spacing) at the excavation site was 540 Ocm. Over the remaining length of the collocation, the soil resistance varied from 3,900 to 19,000 O'cm with measured induced AC potentials up to 4.9 VAC.

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The soil in the excavation contained many large rocks, and a sample (soil only) taken directly adjacent to the pitting was 175 D'cm with a pH of 7.0. The surface DC pipe-to-soil potential records indicated adequate CP for most of the pipeline operating history. However, a combination of possible shielding from the rocks and coating degradation before installation likely contributed to the observed corrosion damage at pitting sites that did not appear to have AC corrosion morphology.

Case History 4 (Adapted from Reference 69)

Figures A22 through A24 include brief descriptions of underground pipe corrosion considered to be caused by AC.

Coating: polyethylene Type of soil: clay Resistivity: 200-3,000 D'cm Soil resistivity (near corrosion): 200 D'cm pH of the soil (near the corrosion): 12 Collocation (2.5 km) with electric line: 380 kV-50 Hz Time of exposure: 1 year Position: along the pipeline Voff potential: —950 mV Average alternating value measured: 13 V RMS Corrosion survey: coating defect survey Note: Presence of 31 defects in 1.5 km; in 20

of these defects, corrosion has been found with areas ranging from 4 to 300 mr11

2

Figure A22: Underground pipe corrosion considered to be caused by AC.

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Coating: two-layer polyethylene Type of soil: sand/slime Resistivity: 3,500 acm Soil resistivity (near the corrosion): 200 acm pH of the soil (near the corrosion): 13-14 Collocation (4 km) with electric line: 80 kV-16 % Hz Time of exposure: 25 years Position: narrow spacing Voff potential: —950 mV Average alternating value measured: 30 V RMS Corrosion survey: potential measurements Corrosion products: included magnetite


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Coating: bitumen Type of soil: sand/slime Resistivity: 3,500 acm Soil resistivity (near corrosion): 200 acm pH of the soil (near the corrosion): 13-14 Collocation (4 km) with electric line: 380 kV-50 Hz Time of exposure: 20 years Position: narrow spacing Voff potential: —950 mV Average alternating value measured: 30 V rms Corrosion survey: pigging Note: formation of protrusion at the corrosion

site


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INTERNATIONAL

THE CORKOSION SOCIETY

Standard Practice

Control of External Corrosion on Underground or Submerged Metallic Piping Systems

This NACE International standard represents a consensus of those individual members who have reviewed this document, its scope, and provisions. Its acceptance does not in any respect preclude anyone, whether he or she has adopted the standard or not, from manufacturing, marketing, purchasing, or using products, processes, or procedures not in conformance with this standard. Nothing contained in this NACE International standard is to be construed as granting any right, by implication or otherwise, to manufacture, sell, or use in connection with any method, apparatus, or product covered by Letters Patent, or as indemnifying or protecting anyone against liability for infringement of Letters Patent. This standard represents minimum requirements and should in no way be interpreted as a restriction on the use of better procedures or materials. Neither is this standard intended to apply in all cases relating to the subject. Unpredictable circumstances may negate the usefulness of this standard in specific instances. NACE International assumes no responsibility for the interpretation or use of this standard by other parties and accepts responsibility for only those official NACE International interpretations issued by NACE International in accordance with its governing procedures and policies which preclude the issuance of interpretations by individual volunteers.

Users of this NACE International standard are responsible for reviewing appropriate health, safety, environmental, and regulatory documents and for determining their applicability in relation to this standard prior to its use. This NACE International standard may not necessarily address all potential health and safety problems or environmental hazards associated with the use of materials, equipment, and/or operations detailed or referred to within this standard. Users of this NACE International standard are also responsible for establishing appropriate health, safety, and environmental protection practices, in consultation with appropriate regulatory authorities if necessary, to achieve compliance with any existing applicable regulatory requirements prior to the use of this standard.

CAUTIONARY NOTICE: NACE International standards are subject to periodic review, and may be revised or withdrawn at any time in accordance with NACE technical committee procedures. NACE International requires that action be taken to reaffirm, revise, or withdraw this standard no later than five years from the date of initial publication. The user is cautioned to obtain the latest edition. Purchasers of NACE International standards may receive current information on all standards and other NACE International publications by contacting the NACE International FirstService Department, 1440 South Creek Drive, Houston, Texas 77084-4906 (telephone +1 281-228-6200).

Revised 2013-10-04 Reaffirmed 2007-03-15 Reaffirmed 2002-04-11 Reaffirmed 1996-09-13

Revised April 1992 Revised January 1983

Revised September 1976 Revised January 1972 Approved April 1969 NACE International

1440 South Creek Drive Houston, Texas 77084-4906

+1 281-228-6200 ISBN 1-57590-035-1

© 2013, NACE International

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SP0169-2013

Foreword

This standard presents methods and practices for achieving effective control of external corrosion on underground or submerged metallic piping systems. These methods and practices are also applicable to many other underground or submerged metallic structures. It is intended for use by corrosion control personnel concerned with the corrosion of underground or submerged piping systems, such as those used for the transport of oil, gas, water, and other fluids. This standard describes the use of electrically insulating coatings, electrical isolation, and cathodic protection (CP) as they relate to external corrosion control. This standard does not include corrosion control methods based on injection of chemicals into the environment, on the use of electrically conductive coatings, or on the use of nonadhered polyethylene encasement (refer to NACE Publication 10A292).1 The standard contains specific provisions for the application of CP to existing uncoated, existing coated, and new piping systems. Also included are methods for control of stray currents on pipelines.

This standard should be used in conjunction with the practices described in the following NACE standards and publications, when appropriate (use latest revisions):

SP05722

SKI 773

SP02854

SP02865

SP01886

TPC 117

TM04975

For accurate and correct application, this standard must be used in its entirety. Using or citing only specific paragraphs or sections can lead to misinterpretation and misapplication of the practices contained in this standard.

This standard does not designate practices for every specific situation because of the complexity of conditions to which underground or submerged piping systems are exposed. This standard is not intended to apply to offshore pipelines and structures. For these facilities, the recommended NACE standards are NACE SP0607/ISO 15589-2 for offshore pipelines, and SP01761° for offshore structures. Definitions of onshore and offshore vary, and it is the responsibility of the user to determine which of the above standards apply to pipelines across coastal boundaries.

This standard was originally published in 1969, and was revised by NACE Task Group T-10-1 in 1972, 1976, 1983, and 1992. It was reaffirrned in 1996 by NACE Unit Committee T-10A, "Cathodic Protection," and in 2002 and 2007 by Specific Technology Group (STG) 35, "Pipelines, Tanks, and Well Casings." It was revised in 2013 by Task Group (TG) 360, "Piping Systems: Review of SP0169-2007 (formerly RP0169), 'Control of External Corrosion on Underground or Submerged Metallic Piping.'" This standard is issued by NACE International under the auspices of STG 35, which is composed of corrosion control personnel from oil and gas transmission companies, gas distribution companies, power companies, corrosion consultants, and others concerned with external corrosion control of underground or submerged metallic piping systems.

In NACE standards, the terms shall, must, should, and may are used in accordance with the definitions of these terms in the NACE Publications Style Manual. The terms shall and must are used to state a requirement, and are considered mandatory. The term should is used to state something good and is recommended, but is not considered mandatory. The term may is used to state something considered optional.

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Standard Practice

Control of External Corrosion on Underground or Submerged Metallic Piping Systems

Contents

1. General 1 2. Definitions, Abbreviations, and Acronyms 1 3. Determination of Need for External Corrosion Control 7 4. Piping System Design 9 5. External Coatings 12 6. Criteria and Other Considerations for Cathodic Protection 17 7. Design of Cathodic Protection Systems 22 8. Installation of CP Systems 25 9. Control of Stray Currents 28 10. Operation and Maintenance of CP Systems 30 11. External Corrosion Control Records 32 References 34 Bibliography 40 Appendix A: External Coatings Tables 44 Appendix B: Review of International Standards 48 FIGURES Figure 1: Residual Corrosion Rate of Carbon Steel Specimens as a Function of AC and

CP Current Density. Laboratory Tests Performed in Simulated Soil Conditions 19 Figure 2: SCC Range of Pipe Steel in Carbonate/Bicarbonate Environments 20 TABLES Table la: 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) 13

Table 1 b: Generic External Coating Systems for Ductile Iron Pipe with Material Requirements and Recommended Practices for Application 14

Table 2: Common Reference Electrodes and Their Potentials and Temperature Coefficients 22

Table A1: References for General Use in the Installation and Inspection of External Coating Systems for Underground or Submerged Piping 45

Table A2: External Coating System Characteristics Relative to Environmental Conditions 45

Table A3(a): External Coating System Characteristics Related to Design and Construction 46

Table A3(b): External Coating System Characteristics Related to Design and Construction: Design and Construction Factor Recommended Test Methods 47

Table A4: Methods for Evaluating Field Performance of External Coatings 48 Appendix B: Review of International Standards 48

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Section 1: General

1.1 This standard presents accepted methods and practices for the control of external corrosion on buried or submerged steel, stainless steel, cast iron, ductile iron, copper, and aluminum piping systems.

1.2 This standard is intended to serve as a guide for establishing requirements for control of extemal corrosion on the following systems:

1.2.1 New piping systems: A proven method of corrosion control (e.g., coating supplemented with CP) should be provided in the initial design and maintained during the service life of the piping system, unless investigations indicate that corrosion control is not required. Consideration should be given to the construction of piping in a manner that facilitates the use of in-line inspection (ILI) tools.

1.2.2 Existing coated piping systems: CP should be provided and maintained (which includes the maintenance of coating as necessary), unless investigations indicate that CP is not required.

1.2.3 Existing uncoated piping systems: Studies can be made to determine the extent and rate of corrosion on existing uncoated piping systems. When these studies indicate that corrosion affects the safe or economic operation of the system, adequate corrosion control measures shall be taken.

1.3 The provisions of this standard are intended to be applied under the direction of competent persons who, by reason of knowledge of the physical sciences and the principles of engineering and mathematics, acquired by education and related practical experience, are qualified to engage in the practice of corrosion control on underground or submerged metallic piping systems.

Note: Such persons might be, but are not limited to, registered professional engineers or persons recognized as Corrosion Specialists or CP Specialists by NACE, if their professional activities include suitable experience in external corrosion control of underground or submerged metallic piping systems.

1.4 Special conditions in which CP is ineffective or only partially effective sometimes exist (see Paragraph 6.2.1.4 for examples). Deviation from this standard might be warranted in specific situations provided that corrosion control personnel in responsible charge are able to demonstrate that the objectives expressed in this standard have been achieved.

1.5 This standard is not intended for use in the control of intemal corrosion.

Section 2: Definitions,(1) Abbreviations, and Acronyms

Definitions:

Amphoteric Metal: A metal that is susceptible to corrosion in both acid and alkaline environments.

Anode: The electrode of an electrochemical cell at which oxidation occurs. (Electrons flow away from the anode in the external circuit. It is usually the electrode where corrosion occurs and metal ions enter solution.)

Anode Bed: One or more anodes installed—underground or submerged—for the purpose of supplying cathodic protection. It is often called a groundbed.

Backfill: Material placed in a hole to fill the space around the anodes, vent pipe, and buried components of a cathodic protection system. For the purposes of this standard, "backfill" is also defined as the material (native or imported) used to fill a pipeline trench.

Beta Curve: A plot of dynamic (fluctuating) stray current or related proportional voltage (ordinate) versus the corresponding structure-to-electrolyte potentials at a selected location on the affected structure (abscissa). For the purposes of this standard,

(1) Definitions in this section reflect common usage among practicing corrosion control personnel and apply specifically to how the terms are used in this standard. In many cases, in the interests of brevity and practical usefulness, the scientific definitions are abbreviated or paraphrased.

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"Beta Curve" is defined as a correlation between the pipe-to-soil potential of the affected pipeline and the open-circuit potential between the affected pipeline and the stray current source.

Cable: One conductor or multiple conductors insulated from one another.

Casing: A metallic pipe (norrnally steel) installed to contain a pipe or piping.

Cathode: The electrode of an electrochemical cell at which reduction is the principal reaction. (Electrons flow toward the cathode in the external circuit.)

Cathodic Disbondment: The destruction of adhesion between a coating and the coated surface caused by products of a cathodic reaction.

Cathodic Polarization: (1) The change of electrode potential caused by a cathodic current across the electrode/electrolyte interface; (2) a forced active (negative) shift in electrode potential. See Polarization.

Cathodic Protection: A technique to reduce the corrosion of a metal surface by making that surface the cathode of an electrochemical cell.

Cathodic Protection Criterion: Standard for assessment of the effectiveness of a cathodic protection system.

Coating: (1) A liquid, liquefiable, or mastic composition that, after application to a surface, is converted into a solid protective, decorative, or functional adherent film; (2) (in a more general sense) a thin layer of solid material on a surface that provides improved protective, decorative, or functional properties. Coatings used in conjunction with cathodic protection are electrically isolating materials applied to the surface of the metallic structure that provides an adherent film that isolates the metallic structure from the surrounding electrolyte. The thickness and structure of the coating type vary according to the environment and application parameters.

Coating Disbondment: The loss of adhesion between a coating and the pipe surface.

Coating System: The complete number of coats and type applied to a substrate in a predetermined order. (When used in a broader sense, surface preparation, pretreatments, dry film thickness, and manner of application are included.)

Conductor: A material suitable for carrying an electric current. It can be bare or insulated.

Continuity Bond: A connection, usually metallic, that provides electrical continuity between structures that can conduct electricity.

Correlation: (1) A causal, complementary, parallel, or reciprocal relationship, as by having corresponding characteristics. (2) (As used in Section 9) Simultaneous measurement of two dynamic (time-varying) parameters, e.g., voltage and current, presented in an X-Y plot to determine the relative relationship between the two parameters and whether the fluctuations over time are caused by one or more sources of stray current.

Corrosion: The deterioration of a material, usually a metal, that results from a chemical or electrochemical reaction with its environment.

Corrosion Potential (E.): The potential of a corroding surface in an electrolyte measured under open-circuit conditions relative to a reference electrode (also known as electrochemical corrosion potential, free corrosion potential, open-circuit potential).

Corrosion Rate: The time rate of progress of corrosion. (It is typically expressed as mass loss per unit area per unit time, penetration per unit time, etc.)

Current Applied Potential: The half-cell potential of an electrode measured while protective current flows through the electrolyte environment, typically measured with respect to a reference electrode placed at the soil surface.

Current Density: The electric current to or from a unit area of an electrode surface.

Diode: A bipolar semiconducting device having a low resistance in one direction and a high resistance in the other.

Disbondment: The loss of adhesion between a coating and the substrate.

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Distributed-Anode Impressed Current System: An impressed current anode configuration in which the anodes are "distributed" along the structure at relatively close intervals such that the structure is within each anode's voltage gradient. This anode configuration causes the electrolyte around the structure to become positive with respect to remote earth.

Electrical Isolation: The condition of being electrically separated from other metallic structures or the environment.

Electrical Shielding: Preventing or diverting the cathodic protection current from its intended path.

Electrical Survey: Any technique that involves coordinated electrical measurements taken to provide a basis for deduction conceming a particular electrochemical condition relating to corrosion or corrosion control.

Electrode: A material that conducts electrons, is used to establish contact with an electrolyte, and through which current is transferred to or from an electrolyte.

Electrolytically Contacted Pipeline Casing: A casing that contains soil or water electrolyte in contact with both the casing and the carrier pipe.

Electroosmotic Effect: Passage of a charged particle through a membrane under the influence of a voltage. Soil or coatings can act as the membrane.

Electrolyte: A chemical substance containing ions that migrate in an electric field. For the purposes of this standard, "Electrolyte" refers to the soil or liquid adjacent to and in contact with an underground or submerged metallic piping system, including the moisture and other chemicals contained therein.

Empirical: Originating in or based on observation or experience.

Free Corrosion Potential: See Corrosion Potential.

Foreign Structure: Any metallic structure that is not intended as a part of a system under cathodic protection.

Galvanic Anode: A metal that provides sacrificial protection to another metal that is more noble when electrically coupled in an electrolyte. This type of anode is the electron source in one type of cathodic protection.

Galvanic Series: A list of metals and alloys arranged according to their corrosion potentials in a given environment.

Holiday: A discontinuity in a protective coating that exposes unprotected surface to the environment.

Impressed Current: An electric current supplied by a device employing a power source that is extemal to the electrode system. (An example is direct current for cathodic protection.)

In-Line Inspection: The inspection of a pipeline using an electronic instrument or tool that travels along the interior of the pipeline.

Instant-Off Potential: The polarized half-cell potential of an electrode taken immediately after the cathodic protection current is stopped, which closely approximates the potential without IR drop (i.e., the polarized potential) when the current was on.

Interference: Any electrical disturbance on a metallic structure as a result of stray current.

Interference Bond: An intentional metallic connection, between metallic systems in contact with a common electrolyte, designed to control electrical current interchange between the systems.

IR Drop: See Voltage Drop.

Isolation: See Electrical Isolation.

Line Current: The direct current flowing in a pipeline.

Linear Anode Impressed Current System: An impressed current anode configuration in which a continuous anode is installed parallel to the structure such that the structure is within the anode voltage gradient.


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Long-Line Current: Current through the earth between an anodic and a cathodic area that returns along an underground metallic structure. (Usually used only where the areas are separated by considerable distance and where the current results from concentration-cell action.)

Mechanical Damage Protection: Any material or equipment used to eliminate or minimize damage to the piping system (as might be caused from soil stresses and damage caused from rocks, debris, or other outside forces) without inhibiting or interfering with CP.

Mechanical Damage Protection System: Consists of multiple processes and products to achieve protection for the piping and coating system.

Mechanical Shielding: Protective cover against mechanical damage. See Mechanical Damage Protection and Mechanical Damage Protection System.

Microbiologically Influenced Corrosion (MIC): Corrosion affected by the presence or activity, or both, of microorganisms.

Mixed Potential: A potential resulting from two or more electrochemical reactions occurring simultaneously on one metal surface.

Nonadhered: Not bonded to the surface by chemical reaction or mechanical means.

Nonshielding Coating System: A coating system with a failure mode (loss of adhesion, etc.) that does not prevent distribution of cathodic protection current to the metal substrate.

Oxidation: (1) Loss of electrons by a constituent of a chemical reaction; (2) Corrosion of a material that is exposed to an oxidizing gas at elevated temperatures.

Pipe-to-Electrolyte Potential: See Structure-to-Electrolyte Potential.

Pipeline Casing: See Casing.

Polarization: The change from the open-circuit potential as a result of current across the electrode/electrolyte interface.

Polarized Potential: (1) (general use) The potential across the electrode/electrolyte interface that is the sum of the corrosion potential and the applied polarization; (2) (cathodic protection use) the potential across the structure/electrolyte interface that is the sum of the corrosion potential and the cathodic polarization.

Reduction: Gain of electrons by a constituent of a chemical reaction.

Reference Electrode: An electrode having a stable and reproducible potential, which is used in the measurement of other electrode potentials.

Reverse-Current Switch: A device that prevents the reversal of direct current through a metallic conductor.

Shielding: (1) Protecting; protective cover against mechanical damage; (2) preventing or diverting cathodic protection current from its natural path. For the purposes of this standard, see Electrical Shielding and Mechanical Shielding.

Shorted Pipeline Casing: A casing that is in direct metallic contact with the carrier pipe.

Sound Engineering Practices: Reasoning exhibited or based on thorough knowledge and experience, logically valid, and has technically correct premises that demonstrate good judgment or sense in the application of science.

Stray Current: Current through paths other than the intended circuit.

Stray-Current Corrosion: Corrosion resulting from stray current.

Structure-to-Electrolyte Potential: The potential difference between the surface of a buried or submerged metallic structure and electrolyte that is measured with reference to an electrode in contact with the electrolyte.


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Telluric Current: Current in the earth as a result of geomagnetic fluctuations.

Unbonded: To have lost the ability to adhere to a surface to which applied and become disbonded or to have never been adhered (nonadhered) to a surface to which it has been applied.

Voltage: An electromotive force or a difference in electrode potentials expressed in volts.

Voltage Drop: The voltage across a resistance when the current is applied in accordance with Ohm's Law. This term is also referred to as IR drop.

Weak Acids: Acids that only partially dissociate to form hydrogen (H+) ions at moderate concentrations.11

Wire: A slender rod or filament of drawn metal. In practice, the term is also used for smaller-gauge conductors.

Abbreviations and Acronyms:

AC: Alternating current

AGA:12) American Gas Association

ANSI:131 American National Standards Institute

API:141 American Petroleum Institute

ARO: Abrasion-resistant overcoating

ASTM:151 ASTM International (formerly American Society for Testing and Materials)

AWG: American Wire Gauge

AWWA:161 American Water Works Association

BSI:m British Standards Institute

CIS: Close interval (potential) survey

CP: Cathodic protection

CGA:(8) Canadian Gas Association

CSA:19) Canadian Standards Association International

CSE: Saturated copper-copper sulfate reference electrode

DC: Direct current

DCVG: Direct current voltage gradient

DIN:(10) Deutsches Institut fur Normung

DNV:(1.11 Det Norske Veritas

mAmerican Gas Association (AGA), 400 North Capitol St. NW, Suite 400, Washington, DC 20001. (3)American National Standards Institute (ANSI), 1819 L St. NW, Washington, DC 20036. (4)American Petroleum Institute (API), 1220 L St. NW, Washington, DC 20005-4070. (5)ASTM International, 100 Barr Harbor Dr., West Conshohocken, PA 19428-2959. (6) American Water Works Association (AWWA), 6666 West Quincy Ave., Denver, CO 80235. (7) Bntish Standards Institution (BSI), British Standards House, 389 Chiswick High Road, London W4 4AL, United Kingdom. (8) Canadian Gas Association (CGA), 350 Sparks Street, Suite 809, Ottawa, Ontario K1R 7S8, Canada. (6) CSA International, 178 Rexdale Blvd., Toronto, Ontario, Canada M9W 1R3. (10) Deutsches Institut fur Normung (DIN), Burggrafenstrasse 6, D-10787 Berlin, Germany.


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ECDA: Extemal corrosion direct assessment

EN: (12) European Standard

FBE: Fusion-bonded epoxy

HDD: Horizontal directional drilling

HIC: Hydrogen-induced cracking

HPIS:(131 High Pressure Institute of Japan

HVAC: High-voltage altemating current

HVDC: High-voltage direct current

ILI: In-line inspection

ISO:(141 International Organization for Standardization

JWWA:1151 Japan Water Works Association

MIC: Microbiologically influenced corrosion

MIG: Metal inert-gas shielded arc (welding process)

mV: Millivolt(s)

NAPCA:1161 National Association of Pipe Coating Applicators

NEC: National Electrical Code (U.S.)

NEMA:1171 National Electrical Manufacturers Association (U.S.)

NIST:118) National Institute of Standards and Technology (U.S.)

NFPA:1191 National Fire Protection Association (U.S.)

NRC:1201 National Research Council (Canada)

NSF:(21) NSF International

PE: Polyethylene

ROW: Right-of-way

SA:1221 Standards Australia

(11) Det Norske Veritas (DNV), Ventasveien 1, 1322, Hovik, Oslo, Norway. (12) European Standard, European Committee for Standardisation, Rue de Stassart, 36, B-1050 Brussels. Belgium. (13) High Pressure Institute of Japan (HPIS), 5th Floor. Sanpo Sakuma Bldg.,1-11, Kanda-Sakuma-cho, Chiyoda-ku 101-0025, Tokyo, Japan. (14) International Organization for Standardization (ISO), 1 we de Varembe, Case Postale 56, CH-1121, Geneve 20, Switzerland. (16) Japan Water Works Association (JWWA), 4-8-9 Kudan Minami, Chiyoda-ku 102-0074, Tokyo, Japan. (16) National Association of Pipe Coating Applicators (NAPCA), 1000 Louisiana St., Suite 3400, Houston, TX 77002. (17) National Electncal Manufacturers Association (NEMA), 1300 North 17th St., Suite 1752, Rosslyn, Virginia 22209. (18) National Institute of Standards and Technology (NIST) (formerly National Bureau of Standards), 100 Bureau Dr., Gaithersburg, MD 20899. (19) National Fire Protection Association (NFPA), Batterymarch Park, Quincy, MA 02269. (20) National Research Council Canada (NRC), 1200 Montreal Road, Ottawa, Ontario K1A 0R6, Canada. 121 ) NSF International, 789 Dixboro Rd., Ann Arbor, MI 48113. (22) Standards Australia (SA), P.O. Box 1055, Strathfield, NSW 2135, Australia.


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SCC: Stress corrosion cracking

SHE: Standard hydrogen electrode

SP: Standard practice

SSPC: Society for Protective Coatings(23)

STG: Specific Technology Group (NACE)

TG: Task Group (NACE)

TIG: Tungsten inert-gas shielded arc (welding process)

TPC: Technical Practices Committee (NACE) (now TCC)

TM: Test method (NACE)

Section 3: Determination of Need for External Corrosion Control

3.1 Introduction

3.1.1 Metallic structures, underground or submerged, are subject to corrosion. Adequate corrosion control procedures can reduce or eliminate metal loss for safe and economical operation.

3.1.2 This section provides practices for determining when an underground or submerged metallic piping system requires external corrosion control.

3.2 The need for extemal corrosion control should be based on data obtained from one or more of the following: corrosion surveys, operating records, visual observations, test results from similar systems in similar environments, in-line inspections, engineering and design specifications, risk assessment, environmental exposure, physical operating conditions, safety, and economic considerations. The absence of leaks alone is insufficient evidence that corrosion control is not required; however, such data can be useful to evaluate the effectiveness of existing corrosion control measures.

3.2.1 Environmental and physical factors include the following:

3.2.1.1 Corrosion rate of the particular metallic piping system in a specific environment (see Paragraph 3.2.2.1), pipe wall thickness, pipe material, and method of manufacturing;

3.2.1.2 Nature of the product being transported, the working temperature, temperature differentials within the pipeline causing thermal expansion and contraction, tendency of backfill to produce soil stress, and working pressure of the piping system as related to design specification;

3.2.1.3 Location of the piping system as related to population density and frequency of visits by personnel;

3.2.1.4 Location of the piping system as related to other facilities; and

3.2.1.5 Stray-current sources.

3.2.2 Economic considerations include the following:

3.2.2.1 Costs of maintaining the piping system in service for its expected life. Maintenance of a piping system may include repairing corrosion leaks and reconditioning or replacing all or portions of the system. To make estimates of the costs involved, the user should determine the probability of corrosion or the rate at which corrosion is proceeding. The usual methods of predicting the probability or rate of corrosion are as follows:

(23) Society for Protective Coatings (SSPC), 40 24th St., Pittsburgh, PA 15222.


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F13 (a) Study of corrosion history on the piping system in question or on other systems of the same material in the same general area or in similar environments. Cumulative leak-frequency curves are valuable in this respect.

CD (b) Study of the environment (electrolyte) surrounding a piping system: resistivity, pH, and chemical and microbial

composition of the soil. Redox potential tests may also be used to a limited extent. Once the nature of the CT environment has been determined, the probable corrosiveness is estimated by reference to actual corrosion experience on similar metallic structures, when environmental conditions are similar. Consideration of possible

environmental changes such as those that might result from irrigation, spillage of corrosive substances, pollution, 0 and seasonal changes in water table and soil moisture content should be included in such a study.

(1:1

(c) Investigation for corrosion on a piping system by visual inspection of the pipe or by instruments that mechanically or electrically inspect the condition of the pipe. Condition of the piping system should be carefully determined and recorded each time a portion of the line is excavated for any reason.

(d) Maintenance records detailing leak locations, pipe inspection reports, soil studies, structure-to-electrolyte 0 potential surveys, surface potential surveys, line current studies, and wall thickness surveys used as a guide for locating areas of maximum corrosion.

(e) Statistical treatment of available data. -0

(f) Results of pressure testing. Under certain conditions, this can help to determine the existence of corrosion. 0_

(g) Coating, if present, should be evaluated for consideration of its effectiveness in corrosion control. 0

3.2.2.2 Contingent costs of corrosion (risk assessment, etc.). in addition to the direct costs that result from corrosion, contingent costs include:

o_ CD

(a) Public liability claims; 0_ 0

(b) Property damage claims;

co (c) Damage to natural facilities, such as municipal or irrigation water supplies, forests, parks, and scenic areas;

(d) Cleanup of product lost to surroundings;

(e) Plant shutdown and startup costs;

(f) Cost of lost product;

(g) Loss of revenue through interruption of service;

5 (h) Loss of contract or goodwill through interruption of service; and cr)

CT (i) Loss of reclaim or salvage value of piping system.

CD 3.2.2.3 Costs of corrosion control. The usual costs for protecting buried or submerged metallic structures are for

coating and CP, which may each be applied to part or all of the structure as needed to provide adequate corrosion 'FT control. Other corrosion control costs include: CD

cn CD (a) Relocation of piping to avoid known corrosive conditions (this may include installing lines above ground); 0

(b) Relocation because of public road or transit construction that results in adverse conditions; c-)

(c) Reconditioning and extemally coating the piping system, especially a coating upgrade; 0 'a

(d) Use of corrosion-resistant materials; 5 to

(e) Use of selected or inhibited backfill; CD

(f) Electrical isolation to limit possible galvanic action; and 0

(g) Correction of conditions in or on the pipe that might accelerate corrosion. p CCD

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3.2.2.4 Replacement cost of the asset under protection.

Section 4: Piping System Design

4.1 Introduction

This section provides accepted corrosion control practices in the design of an underground or submerged piping system. A person qualified to engage in the practice of corrosion control should be consulted during all phases of pipeline design and construction (see Paragraph 1.3). These practices should not be construed as taking precedence over recognized safety practices.

4.2 External Corrosion Control

4.2.1 External corrosion control must be a primary consideration during the design of a piping system. Materials selection and coatings are primary methods of external corrosion control. Because perfect coatings are not feasible, CP should be used in conjunction with coatings for extended corrosion protection. For additional information, see Sections 5 and 6.

4.2.2 External coatings are commonly utilized in conjunction with CP. When specified, they should be properly selected, specified, and applied. Desirable characteristics of external coatings are given in Paragraph 5.1.2.1.

4.2.3 Piping systems should be constructed in such a manner to avoid electrical shielding of CP.

4.3 Electrical Isolation

4.3.1 Isolation devices such as flange assemblies, prefabricated joints, unions, couplings, or, where permissible, sections of nonconductive piping should be installed within piping systems in which electrical isolation of portions of the system is required to facilitate the application of extemal corrosion control. These devices must be properly selected for temperature, pressure, chemical resistance, dielectric resistance, and mechanical strength. Safety measures must be considered if isolating devices are installed in areas in which combustible atmospheres are likely to be present. Locations at which electrical isolating devices may be considered include, but are not limited to, the following:

4.3.1.1 Points at which facilities change ownership, such as meter stations, delivery facilities, and well heads;

4.3.1.2 Connections to mainline piping systems, such as gathering or distribution system laterals;

4.3.1.3 Inlet and outlet piping of in-line measuring and pressure-regulating stations;

4.3.1.4 Compressor or pumping stations, either in the suction and discharge piping or in the main line immediately upstream and downstream from the station;

4.3.1.5 Stray-current areas;

4.3.1.6 The junction of dissimilar metals;

4.3.1.7 The termination of service line connections and entrance piping;

4.3.1.8 The junction of a coated pipe and an uncoated pipe;

4.3.1.9 Locations at which electrical grounding is used, such as motorized valves and instrumentation; and

4.3.1.10 Water pipelines, connections to water hydrants, existing pipelines, or pipelines of different materials, such as steel and ductile or cast iron.

4.3.2 Casings should be avoided. However, when metallic casings are required as part of the underground piping system, the pipeline should be electrically isolated from such casings. Casing isolators must be properly sized and spaced and be tightened securely on the pipeline to withstand insertion stresses without sliding on the pipe. Inspection should be made to verify that the leading isolator has remained in position. Concrete coatings on the carrier pipe could preclude the use of casing isolators. Consideration shall be given to the use of support under the pipeline at each end of the casing to minimize


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settlement. The type of support selected should not cause damage to the pipe coating. Casing seals may be installed to resist the entry of foreign matter into the casing (refer to NACE SP0200).12

4.3.3 Piping systems should be electrically isolated from supporting pipe stanchions, bridge structures, tunnel enclosures, pilings, grounded structures, reinforcing steel in concrete, and metal tiedowns used for restraining purposes when electrical contact would adversely affect CP.

4.3.4 When an isolating joint is required, a device manufactured to perform this function should be used, or, if permissible, a section of nonconductive pipe, such as plastic pipe, may be installed. In either case, these should be properly rated and installed in accordance with the manufacturers instructions. In addition, consideration must be given to possible detrimental effects of stray current around the joint, both inside (if containing an electrically conductive material ) and outside the pipe.

4.3.5 River weights, pipeline anchors, and metallic reinforcement in weight coatings should be electrically isolated from the carrier pipe. Weighting and anchors should be designed and installed so that coating damage does not occur and the carrier pipe is not electrically shielded.

4.3.6 Metallic curb boxes and valve enclosures should be designed, fabricated, and installed in such a manner that electrical isolation from the piping system is maintained.

4.3.7 Isolating spacing materials should be used when the intent is to maintain electrical isolation between a metallic wall sleeve and the pipe.

4.3.8 Underground piping systems should be installed so that they are physically separated from all foreign underground metallic structures at crossings and parallel installations and in such a way that electrical isolation could be maintained if desired.

4.3.9 Based on load rating of altemating current (AC) transmission lines, adequate separation should be maintained between pipelines and electric transmission tower footings, ground cables, and counterpoise. Consideration must always be given to induced AC voltages, lightning, fault current protection of pipeline(s), and to personnel safety (see NACE SP0177). The need for lightning and fault current protection at isolating devices must be considered. Cable connections from isolating devices to arresters should be short, direct, and of a size suitable for short-term high current loading.

4.4 Electrical Continuity ,

Electrical continuity of piping systems that are constructed with nonwelded pipe joints is not reliable. Electrical continuity can be ensured by bonding across bell- and spigot-type joints and to the metallic components of the mechanical joints in an effective manner (see Paragraph 4.5.3).

4.5 Corrosion Control Test Stations

4.5.1 Test stations for potential, current, or resistance measurements shall be provided at sufficient locations to facilitate CP testing. Such locations may include, but are not limited to, the following:

4.5.1.1 Pipe casing installations;

4.5.1.2 Metallic stnicture crossings;

4.5.1.3 Isolating joints;

4.5.1.4 Waterway crossings;

4.5.1.5 Bridge crossings;

4.5.1.6 Valve stations;

4.5.1.7 Galvanic anode installations;

4.5.1.8 Road crossings;

4.5.1.9 Stray-current areas; and

4.5.1.10 Impressed current installations.


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4.5.2 A span of pipe used for current flow measurement test stations should exclude:

4.5.2.1 Foreign metallic structure crossings;

4.5.2.2 Lateral connections;

4.5.2.3 Mechanical couplings such as screwed joints, transition pieces, valves, flanges, or electrical connections, such 0 as anode or rectifier attachments, or metallic bonds; and

4.5.2.4 Changes in pipe wall thickness and diameter, unless span resistance is measured.

4.5.3 Attachment of Copper Test Lead and Bonding Wires to Steel and Other Ferrous Pipes

4.5.3.1 Test lead wires may be used both for periodic testing and for current-carrying purposes. As such, the wire/pipe attachment should be mechanically strong and electrically conductive.

4.5.3.2 Methods of attaching wires to the pipe include (a) exothermic welding, (b) soldering, (c) brazing, (d) rnechanical means, and (e) high-strength permanent magnetic connections. TJ

4.5.3.3 Particular attention must be given to the attachment method to avoid (a) damaging or penetrating the pipe, (b) sensitizing or altering of pipe properties, (c) weakening the test lead wire, (d) damaging intemal or external pipe 0_ coatings, and (e) creating hazardous conditions in explosive or combustible environments. Refer to ASME B31.8,13 0 Section 862.115 or ASME B31.4,14 Section 461.1.5 for additional recommendations when attaching a test lead wire on gas or liquid pipeline systems. CT)

0_ 4.5.3.4 Mechanical connections that remain secure and electrically conductive may be used. Attachment by cp mechanical means is the least desirable method. Such a connection can loosen, become highly resistant, or lose 0_ electrical continuity. 0

4.5.3.5 The connection must be tested for mechanical strength and electrical continuity. All exposed portions of the pipe and connection should be thoroughly cleaned of all welding slag, dirt, oils, etc.; primed, if needed; and coated with R3 materials compatible with the cable insulation, pipe coating, and environment.

4.5.4 Attachment of Aluminum Test Lead Wire to Aluminum Pipes • •

4.5.4.1 Aluminum test lead wire, or aluminum tabs attached to aluminum wire, may be welded to aluminum pipe using 0 the tungsten inert-gas shielded arc (TIG) or metal inert-gas shielded arc (MIG) process. Welded attachments should be made to flanges or at butt weld joints. Attachment at other sites can adversely affect the mechanical properties of the pipe because of the heat of welding.

(J) 5

4.5.4.2 Test lead wire may be attached to aluminum pipe by soldering. If low-melting-point soft solders are used, a flux is required. Flux residues can cause corrosion unless removed. Particular attention must be given to the attachment method to avoid (a) damaging or penetrating the pipe, (b) sensitizing or altering of pipe properties, (c) weakening the

cn test lead wire, and (d) creating hazardous conditions in explosive or combustible environments. CD

Note: The use of copper test lead wire can cause preferential galvanic attack on the aluminum pipe. When copper wire 3 or flux is used, care must be taken to seal the attachment areas against moisture. In the presence of moisture, the connection can disbond and be damaged by corrosion. cn

CD 0 4.5.4.3 Aluminum tabs to which test lead wires have been TIG welded can be attached by an explosive bonding

technique called high-energy joining.

0 4.5.4.4 Mechanical connections that remain secure and electrically conductive may be used. Attachment by 0 mechanical means is the least desirable method. Such a connection can loosen, become highly resistant, or lose -0

electrical continuity. 5 c0

4.5.5 Attachment of Copper Test Lead Wire to Copper Pipe CD

4.5.5.1 Copper test lead wire, or copper tabs attached to copper wire, may be attached to copper pipe by one of the 0 following methods. Mechanical connections that remain secure and electrically conductive may be used. Attachment by

77. mechanical means is the least desirable method. Such a connection can loosen, become highly resistant, or lose 5

c.o


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electrical continuity. Particular attention must be given to the attachment method to avoid (a) damaging or penetrating the pipe, (b) sensitizing or altering of pipe properties, (c) weakening the test lead wire, and (d) creating hazardous conditions in explosive or combustible environments. The relative thickness of the wire and the pipe wall dictates, in part, which of the methods can be used:

4.5.5.1.1 Arc welding (TIG, MIG, or shielded metal);

4.5.5.1.2 Electrical resistance (spot) welding;

4.5.5.1.3 Brazing;

4.5.5.1.4 Soldering; or

4.5.5.1.5 Mechanical connection.

4.5.5.2 Attention shall be given to proper joining procedures to avoid possible embrittlement or loss of mechanical properties of the metals from the heat of welding or brazing.

4.5.5.3 A flux might be required, or self-produced, when brazing with some filler metals or soldering with some low-melting-point soft solders. Because flux residues can cause corrosion, they must be removed.

4.5.5.4 The connection must be tested for mechanical strength and electrical continuity. All exposed portions of the pipe and connection should be thoroughly cleaned of all welding slag, flux, dirt, oils, etc.; primed, if needed; and coated with materials compatible with the cable insulation, pipe coating, and environment.

Section 5: External Coatings

5.1 Introduction

5.1.1 This section provides an overview of practices to provide guidance for selecting, testing, evaluating, handling, storing, inspecting, installing, and protecting coating systems for external corrosion control on piping systems.

5.1.2 The functions of external coatings are to control corrosion by isolating the extemal surface of the underground or submerged piping from the environment, to reduce CP current requirements, and to improve current distribution.

5.1.3 Mechanical Damage Protection System

5.1.3.1 Mechanical damage protection systems such as rock shield, abrasion-resistant overcoatings, etc., may be installed if required by owner specifications, and should be designed to eliminate or minimize damage to the pipe and its coating without inhibiting or interfering with CP requirements (see Electrical shielding in Section 2.)

5.1.3.2 Considerations for Determining Whether a Mechanical Damage Protection System Might Be Beneficial or Necessary

5.1.3.2.1 Type of bedding and backfill; and

5.1.3.2.2 Method of installation—horizontal directional drilling, submerging, etc.

5.1.3.3 Considerations for Selecting a Mechanical Damage Protection System

5.1.3.3.1 Must be nontoxic to the environment, does not break down and release toxic chemicals or gases;

5.1.3.3.2 Must not break down during storage, handling, and installation;

5.1.3.3.3 Must be chemically and physically compatible with pipe coating;

5.1.3.3.4 Must be resistant to degradation caused by acidic or caustic electrolyte; and

5.1.3.3.5 Must retain physical characteristics when installed and during anticipated life of the pipe.


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5.1.4 Information in this section is primarily by reference to other documents (see Tables la, lb, and Tables A1 through A4). It is important that the latest revision of the pertinent reference be used, and these tables are not intended to be all inclusive.

5.1.4.1 Tables la and lb are example listings of types of external coating systems, showing the more common references for material specifications and recommended practices for application. This standard does not necessarily recommend the listed coating systems for any particular application. The user must determine the appropriate coating system based on the specific installation. There are currently no known specific coating standards for aluminum, copper, or stainless steel. Note that Tables A1 through A4 are found in Appendix A (nonmandatory).

5.1.4.2 Table A1 lists groupings of references for general use during installation and inspection, regardless of coating type.

5.1.4.3 Table A2 includes lists of extemal coating system characteristics related to environmental conditions containing suggested laboratory test references for various properties.

5.1.4.4 Tables A3(a) and A3(b) are lists of external coating system characteristics related to design and construction, with recommended laboratory tests for evaluating these properties.

5.1.4.5 Table A4 lists the references that are useful in field evaluation of extemal coating systems after the pipeline has been installed.

Table la Generic External Coating Systems for Carbon Steel Pipe with Material Requirements and Recommended Practices for Application(A) for Underground and Submerged Pipe

(Field- and Shop-Applied)

Generic External Coating System Reference

Asphalt/Coal Tar Enamel + Concrete DNV-RP-F10215 NACE Standard RP060216 DNV-RP-F10617 NACE Standard RP039918

Coal Tar Enamel ANSI/AWWA C 20319 NACE Standard RP0602 NAPCA Bulletin 13-79-9420 NACE Standard RP0399

Cold-Applied and Hot-Applied Tape ANSI/AWWA C 2142i ANSI/AWWA C 20922 NAPCA Bulletin 15-83-9423 NACE SP010924

Concrete ISO 21809-526 Elastomeric Materials (Polychloroprene or Equivalent) DNV-RP-F102

DNV-RP-F106 Field-Applied Coatings for Repairs and Rehabilitation DNV-RP-F102

NACE Standard RP0602 NACE SP0109

Field Joint Coatings ISO 21809-3 AWWA C 21626 AWWA C209 DIN 3067227 NACE Standard RP040228 NACE SP0109 NACE Standard RP030329


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Fusion-Bonded Epoxy Coatings 3° ANSI/AWWA C 213

API RP 5L931 CSA Z245.2032 DNV-RP-F106 NACE Standard RP039433 NACE Standard RP0402 NAPCA Bulletin 12-78-0434 NAPCA Bulletin 17-9835 ISO 21809-2

Fusion-Bonded Epoxy + Concrete DNV-RP-F106, used in conjunction with DNV-OS-F10136

Liquid-Epoxy ANSI/AWWA C 210'' NACE Standard RP010538 CSA Z245.20

Mastic Coating SSPC Paint 33Ju Multilayer Epoxy Polyethylene CSA Z245.214u

NF A49-71041

DIN 30670 Multilayer (Including FBE Primer) Polyethylene (PE) and Polypropylene (PP) Anticorrosion

CSA Z245.21 DNV RP-F102 DNV RP-F106 DIN 30670

Polyolefin Coatings NACE 5P018542

DIN 30670 ANSI/AWWA C 21 543 ANSI/AWWA C 216 ANSI/AWWA C 225" DNV-RP-F102 DNV-RP-F106 NAPCA Bulletin 14-83-9445

ISO 21809-4 Polyurethane

ANSI/AWWA C 22246 CSA Z245.20 Work in progress by TG 28147

Prefabricated Films ANSI/AWWA C 214ANSI/AWWA C 216 ANSI/AWWA C 209

Wax NACE Standard RP037545 AWWA C 21749

(A)Note: Many other references are available, and this table is not comprehensive. Listing does not constitute endorsement of any extemal coating system in preference to another. Omission of a system might be a result of unavailability of reference standards or lack of data.

Table 1 b Generic External Coating Systems for Ductile Iron Pipe with Material Requirements

and Recommended Practices for Application(A)

Generic External Coating System Reference Adhesive Tape BS EN 545 u

DIN 30672 Extruded Polyethylene BS EN 545

BS EN 1462851 Reinforced Cement Mortar Coating BS EN 545

DIN 1554252 Field Joint Coating BS EN 545 Mastic Coating SSPC Paint 33 Polyurethane Coating BS EN 545


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Polyethylene Sleeving (as a Supplement to the Zinc Coating with Finishing Layer)

BS EN 545

Wax NACE Standard RP0375 Zinc—All Variations, Including Zinc-Rich Paint and Zinc- Aluminum with Finishing Layer

BS EN 545 DIN 30674-353 ISO 8179-154 ISO 8179-2

(A) Note: Many other references are available, and this table is not comprehensive. Listing does not constitute endorsement of any external coating system in preference to another. Omission of a system might be a result of unavailability of reference standards or lack of data.

5.2 Transport, Storage, Handling, Inspection, and Installation of Coated Pipe

5.2.1 Storage and Handling

5.2.1.1 When coated pipe is stored for later use, the user should evaluate the need to protect the coating from damage and environmental degradation. Consideration should be given to detrimental effects such as mechanical damage, severity of environmental conditions, anticipated length of storage, and ultraviolet (UV) degradation.

5.2.1.2 Damage to coating can be minimized by careful handling and using proper pads and slings placed at appropriate lifting points.

5.2.1.3 For additional guidance on the transport, storage, and handling of coated pipe, refer to API RP 5L155 (rail transport), API 5LW56 (water transport), PRCI PR-218-06450557 (highway transport), and sections in AWWA standards that discuss shipping, handling, and storage of pipe. There might be additional standards that apply to the specific pipe that is being installed.

5.2.2 Inspection

5.2.2.1 All inspection requirements and acceptance criteria should be noted in owner coating specifications and documented in a manner acceptable to the owner.

5.2.2.2 Only personnel trained and qualified in coating inspection should perform inspections. Inspectors shall be familiar with the characteristics of the mill- and field-applied coatings.

5.2.2.3 Surface preparation, primer application (if required), coating thickness, environmental conditions, temperature, bonding, and other specific requirements should be checked periodically, using appropriate or specified test procedures, for conformance to specifications and documented in accordance with owner requirements.

5.2.2.4 For dielectric coatings, holiday detectors are used to detect coating flaws that would not be observed visually. The holiday detector must be operated in accordance with the manufacturers instructions and at a voltage level appropriate to the electrical characteristics of the coating system.6'59

5.2.3 Installation

5.2.3.1 Joints, fittings, and tie-ins must be coated with materials compatible with the existing coatings.

5.2.3.2 Coating defects identified during testing/inspection shall be repaired and the coating repair inspected in accordance with Paragraph 5.2.2.

5.2.3.3 Materials used to repair coatings shall be compatible with the pipe coating to be repaired and have equivalent properties.

5.2.3.4 The ditch bottom should be graded and free of rock or other foreign matter that could damage the external coating or cause electrical shielding. Under difficult conditions, consideration shall be given to importing select bedding material, padding the pipe or ditch bottom, or using a mechanical damage protection system.59

5.2.3.5 Pipe shall be lowered carefully into the ditch to avoid external coating damage. If the pipe is installed by boring (HDD) or other trenchless techniques, external coating damage should be avoided.69'61 When possible, the pipe that passes through the bore should be inspected for coating damage and repaired as necessary.

5.2.3.6 During backfilling:


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5.2.3.6.1 Caution should be exercised to prevent rocks or other debris from striking the pipe and damaging the coating.

5.2.3.6.2 No rock or other foreign material that could damage the external coating or cause electrical shielding should be placed in a trench or closer than 100 mm (4 in, nominal) to the pipe/pipeline.

5.2.3.7 When a pipeline is exposed to atmospheric conditions as a result of operational requirements, it must be coated with a material suitable for the atmosphere to which it is exposed. Coatings shall be applied in accordance with manufacturers specifications. Special attention should be given to air-to-soil interfaces, splash zones, and pipe exposed to UV radiation.

5.2.4 External coatings must be properly selected and applied. The coated pipe must be carefully handled and installed to fulfill these functions. Various types of external coatings can accomplish the desired functions.

5.2.4.1 Desirable characteristics of external coatings include the following:

5.2.4.1.1 Effective electrical isolator;

5.2.4.1.2 Effective moisture barrier;

5.2.4.1.3 Application to pipe by a method that does not adversely affect the properties of the pipe;

5.2.4.1.4 Application to pipe with a minimum of defects;

5.2.4.1.5 Good adhesion to pipe surface;

5.2.4.1.6 Resistance to development of holidays with time;

5.2.4.1.7 Resistance to damage during handling, storage, and installation;

5.2.4.1.8 Ability to maintain substantially constant electrical resistivity with time;

5.2.4.1.9 Resistance to cathodic disbondment and disbonding from other factors such as soil stress and other environmental stresses;

5.2.4.1.10 Resistance to chemical and thermal degradation;

5.2.4.1.11 Ease of repair;

5.2.4.1.12 Retention of physical characteristics;

5.2.4.1.13 Nontoxic to the environment;

5.2.4.1.14 Resistanœ to changes and deterioration during aboveground storage and long-distance transportation;

5.2.4.1.15 Resistance to abrasion and mechanical stress;

5.2.4.1.16 Compatible with cathodic protection; and

5.2.4.1.17 Resistance to microorganisms.

5.2.4.2 Typical factors to consider during selection of an external pipe coating include:

5.2.4.2.1 Type of environment and design life expectations;

5.2.4.2.2 Accessibility of piping system;

5.2.4.2.3 Operating temperature of piping system;

5.2.4.2.4 Ambient temperatures during application, shipping, storage, construction, installation, and pressure testing;


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5.2.4.2.5 Geographical and physical location;

5.2.4.2.6 Type of external coating on existing pipe in the system;

5.2.4.2.7 Handling and storage;

5.2.4.2.8 Pipeline installation methods;

5.2.4.2.9 Pipe surface preparation requirement;

5.2.4.2.10 Possible soil stresses, including thermal cycles; and

5.2.4.2.11 With submerged piping, susceptibility to mechanical damage by impact from debris.

5.2.4.3 Pipeline external coating systems shall be properly selected and applied to ensure that adequate bonding is obtained. Nonadhered (disbonded or unbonded) coatings can create electrical shielding of the pipeline that is detrimental to the effectiveness of the CP system.

5.2.4.4 Coatings may be periodically reformulated, but this might not be declared and the revised coatings can retain the same name. Regular laboratory batch testing can be beneficial to evaluate the quality of coatings and to detect the effects of any reformulation.

Section 6: Criteria and Other Considerations for Cathodic Protection

6.1 Introduction

6.1.1 This section lists criteria for CP that indicate whether adequate CP of a metallic piping system has been achieved (see also Section 1, Paragraphs 1.2 and 1.4). Adequate CP can be achieved at various levels of cathodic polarization depending on the environmental conditions. As such, a single criterion for evaluating the effectiveness of CP might not be satisfactory for all conditions or at all locations along a structure. The use of any approach, including a combination of methods or criteria to achieve adequate corrosion control, is the responsibility of the user, and should be based on the experience of the user and the unique conditions influencing the piping system(s). In determining whether adequate corrosion control has been achieved, the conditions and factors listed in Paragraph 6.2.1.3.1.2, Special Conditions (6.2.1.4), and Relevant Considerations (6.3) should be considered regardless of what methods or criteria are used. A commonly used benchmark for effective extemal corrosion control is (a reduction in the corrosion rate to) 0.025 mm per year (1 mil per year) or less.

6.1.2 In selecting the methods or criteria for a specific pipeline, the following are the responsibilities of the user:

6.1.2.1 To determine the level of corrosion control that is necessary and sufficient to address the specific conditions.

6.1.2.2 To include a means to evaluate the effectiveness of that method or criterion, whether used separately or in combination.

6.1.2.3 To document the effectiveness of CP or other external corrosion control measures (see Section 11). In the absence of such documentation, at least one of the criteria in Paragraph 6.2 shall apply.

6.2 Criteria

6.2.1 Criteria for Steel and Gray or Ductile Cast-Iron Piping

6.2.1.1 Criteria that have been documented through empirical evidence to indicate corrosion control effectiveness on specific piping systems may be used on those piping systems or others with the same characteristics.

6.2.1.2 A minimum of 100 mV of cathodic polarization. Either the formation or the decay of polarization must be measured to satisfy this criterion.8'62

6.2.1.3 A structure-to-electrolyte potential of —850 mV or more negative as measured with respect to a saturated copper/copper sulfate (CSE) reference electrode. This potential may be either a direct measurement of the polarized


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potential or a current-applied potential. Interpretation of a current-applied measurement requires consideration of the significance of voltage drops in the earth and metallic paths.

6.2.1.3.1 Consideration is understood to mean the application of sound engineering practice by either of the following:

6.2.1.3.1.1 Measuring or calculating the voltage drop(s) to establish whether a potential of —850 mV or more negative across the structure-to-electrolyte boundary has been achieved, or

6.2.1.3.1.2 Performing a technical evaluation of the system, including data or information such as the following, used either separately or in combination, which the user deems necessary and sufficient for the situation:

6.2.1.3.1.2.1 Reviewing the historical perforrnance of the CP system, such as type of CP, consistency with time of the potentials at individual test points along the line, consistency of CP current over time, number of years with CP, remedial CP activities, consistency of CIS over time, and external corrosion-related leak history. (Note: Leak history should not be used as the sole means of determining adequate levels of CP). When reviewing the historical performance of the CP system, physical characteristics and results of direct examinations and the environment should also be considered.

6.2.1.3.1.2.2 Determining whether there is physical evidence of corrosion, such as by direct examination to deterrnine evidence of active corrosion and correlation of direct examination data with other data such as CIS, DCVG surveys, and ILI results. When direct examinations are used, the number and extent of the examinations performed as well as a comparison of the environments and their relevance should be considered.

6.2.1.3.1.2.3 Evaluating the physical and electrical characteristics of the pipe and its environment, such as type of electrolyte, electrolyte resistivity, pH, dissolved oxygen content, moisture content, degree of aeration, differences in pipe metallurgy and installation dates, and variations in coating types and condition.

6.2.1.3.1.2.4 Physical characteristics and operational data, such as coated or bare, type of coating and possibility to shield CP, proximity to other lines, especially other lines in the right-of-way, temperature of the pipe, depth of the pipe, proximity to potential stray current sources such as light rail systems, HVAC and HVDC systems, foreign structures with CP, proximity and electrical isolation with structures of varying metals where mixed-metal potentials are a concern, locations where concrete weights and anchors are installed, and changes in operating conditions over time. Construction-related information alone might not provide sufficient information to adequately evaluate the effectiveness of CP, but should be considered during direct examinations and reviewing historical performances.

6.2.1.3.1.2.5 Evaluation of indirect inspection data, such as above-grade electrical surveys, ILI, and direct assessment.

6.2.1.3.1.2.6 Use of coupons to establish levels of current density, free corrosion potential, levels of polarization, corrosion rates, and comparisons between coupon and pipe potentials.

6.2.1.3.1.2.7 Other methods that confirm that sufficient polarization has been achieved to control corrosion.

6.2.1.4 Special Conditions Applicable to Steel and Gray or Ductile Cast-Iron Piping Systems

6.2.1.4.1 When active MIC has been identified or is probable, (e.g., caused by acid-producing or sulfate-reducing bacteria), the criteria listed in Paragraphs 6.2.1.2 and 6.2.1.3 might not be sufficient. Under some conditions, a polarized ,potential of —950 mV CSE or more negative63-65 or as much as 300 mV of cathodic polarization might be requ ired .6°

6.2.1.4.2 At elevated temperatures (> 40 °C [104 °F]), the criteria listed in Paragraphs 6.2.1.2 and 6.2.1.3 may not be sufficient. At temperatures greater than 60 °C (140 °F), the polarized potential of —950 mV CSE or more negative might be required.63.66-68

6.2.1.4.3 On mill-scaled steel, cathodic polarization greater than 100 mV might be required.66


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6.2.1.4.4 In uniformly high-resistivity well-aerated and well-drained soil, polarized potentials less negative than — 850 mV CSE might be sufficient. Note: ISO 15589-1 offers the following for consideration: —750 mV CSE where soil resistivity is between 10,000 Ocm and 100,000 Ocm, and —650 mV CSE where soil resistivity is greater than 100,000 Qcm.

6.2.1.4.5 Under certain circumstances, when well-coated pipelines are installed in close proximity to HVAC power lines, electromagnetically induced AC can cause extemal corrosion. AC densities in excess of 30 A/m2 (2.8 A/ft2) can be sufficient to cause significant external corrosion of ferrous metals, and at AC densities greater than 100 A/m2 (9.3 A/ft2), AC corrosion is to be expected even if a CP criterion is satisfied.69 Furthermore, under some soil conditions, increasing the cathodic polarization can increase AC corrosion as shown in Figure 1.

0 0 0 0 o 0 0 r4 -r

!AC (Ain12)

Figure 1: Residual Corrosion Rate of Carbon Steel Specimens as a Function of AC and CP Current Density. Laboratory Tests Performed in Simulated Soil Conditions."

6.2.1.4.6 In weak acid environments, a polarized potential of —950 mV CSE or more negative might be required.11'71

6.2.1.4.7 When operating pressure and conditions are conducive to high pH stress corrosion cracking, polarized potentials in the cracking range relative to the temperature indicated in Figure 2 should be avoided.71


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Temperature, °C

Figure 2: SCC Range of Pipe Steel in Carbonate/Bicarbonate Environments.72 Note: This figure is not applicable to all grades of steel and in all electrolytes. (For conversion, °F = 9/5 °C + 32).

6.2.2 Criteria for Aluminum Piping


6.2.2.2 A minimum of 100 mV of cathodic polarization between the structure surface and a stable reference electrode containinR two electrolytes. Either the formation or the decay of this polarization must be measured to satisfy this criterion ."2

6.2.2.3 Precautionary Notes

6.2.2.3.1 Excessive Voltages: Notwithstanding the minimum criterion in Paragraph 6.2.2.2, a polarized potential more negative than —1,200 mV with respect to a CSE reference electrode shall not be used unless previous test results indicate that no appreciable corrosion has occurred in the particular environment. Specific attention shall be given to possible corrosion as a result of the buildup of alkali on the metal surface, as outlined in Paragraph 6.2.2.3.2.

6.2.2.3.2 Alkaline Conditions: Aluminum can suffer from corrosion under high-pH conditions, and application of CP tends to increase the pH at the metal surface. Therefore, investigations or testing should be completed prior to the application of CP to determine whether the anticipated level of polarization of the aluminum can create a corrosive condition in the specific electrolyte adjacent to the aluminum alloy under consideration. Aluminum can experience corrosion in alkaline or acidic environments (8.5 < pH < 4) according to the Pourbaix diagrams.73 The specific ranges depend on the specific electrolyte and alloy being tested.

6.2.3 Criteria for Copper Piping


6.2.3.2 A minimum of 100 mV of cathodic polarization. Either the formation or the decay of this polarization must be measured to satisfy this criterion.

6.2.4 Criteria for Stainless Steel Piping


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6.2.4.2 A minimum of 100 mV of cathodic polarization between the structure surface and a stable reference electrode contacting the electrolyte. Either the formation or the decay of this polarization must be used in this criterion.

6.2.4.3 A polarized potential of —450 mV or more negative with respect to a CSE in neutral or alkaline conditions. In acid conditions, the protection potential should be determined by testing.

6.2.4.4 Cautionary note: When operating pressure and conditions are conducive to high pH stress corrosion cracking, polarized potentials in the cracking range relative to the temperature should be avoided. For austenitic stainless steels in acid conditions, the safe negative potential limit shall be determined by testing. For ferritic, martensitic, and duplex stainless steels, the safe potential limit shall be determined by testing.74

6.3 Relevant Considerations

6 3 1 Potential measurements related to criteria are intended to be made with respect to reference electrodes at 25 °C (77 °F). Common practice does not require a temperature correction within 10 °C (18 °F) of this temperature. For temperature correction factors, see Table 2.

6.3.2 When feasible and practicable, ILI of pipelines can be an effective method for determining the presence or absence of corrosion damage. Absence of external corrosion damage or the halting of its growth can indicate adequate extemal corrosion control. The appropriate use of ILI must be carefully considered. The ILI technique, however, might not be capable of detecting all types of extemal corrosion damage, has limitations in its accuracy, and might report as anomalies items that are not external corrosion. For example, longitudinal seam corrosion and general corrosion might not be readily detected by in-line inspection when magnetic tools are used. Also, possible thickness variations, dents, gouges, and external ferrous objects might be detected as corrosion.

6.3.3 The amount of cathodic polarization maintained on a metallic surface can be affected by changes in electrolyte conditions, CP system or structure configuration changes, and changes in influencing sources of AC or DC. These factors should be considered when tests are performed to satisfy the CP criteria.

6.3.4 In mixed-metal piping systems, CP can typically be achieved at a polarized potential that is 100 mV more negative than the open-circuit potential of the most active metal in the system. Amphoteric materials, such as aluminum or lead, which could be damaged by high alkalinity created by CP, might need to be electrically isolated and separately protected.

6.3.5 Cathodic polarization levels that result in excessive generation of atomic hydrogen should be avoided on all metals susceptible to hydrogen embrittlement.

6.3.6 On extemally coated pipelines, as the level of cathodic polarization increases, the pH at the structure-to-electrolyte interface increases, which can increase the risk of blistering or disbondment of the coating.

6.3.7 Reliable measurement of potentials and therefore interpretation of CP criteria can be significantly affected by the presence of electrical shielding. Electrical shielding can be caused by disbonded coatings, thermal insulation, loose wrappers, high-resistivity rock or soils, metal structures or pipelines that are close to the structure being protected, and other man-made materials partially or completely surrounding the pipeline.75

6.4 Alternative Reference Electrodes

6.4.1 Other standard reference electrodes may be substituted for the CSE. Three commonly used reference electrodes are listed below. Refer to Table 2 for their voltage equivalents.

6 4.1.1 Saturated KCI calomel reference electrode.

6.4.1.2 Saturated silver/silver chloride reference electrode.

6.4.1.3 Zinc reference electrode.

In addition to these standard reference electrodes, an altemative metallic element in an electrolyte of fixed concentration may be used in place of the CSE, if the stability of its electrode potential is ensured and if its voltage equivalent referred to a CSE is established.


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Table 2 Common Reference Electrodes and Their Potentials and Temperature Coefficients

Reference Electrode

Electrolyte Solution

Potential C at 25 ° [77 °F]

(V /SHE)

Potential at 25 °C [77 °F]

(V/CSE]

Temperature Coeffici ent

mV/°C (mV/°F)

Typical Usage

Cu/CuSO4 (CSE) Sat. CuSO4 +0.31676 o 0.9 (0.5)76 soils, fresh water

Ag/AgCl(A) (SSC) 0.6 M NaCI (3 1/2%)

+0.25677 -0.06 - 0.33 (0.18)77 seawater, brackish(8)

Ag/AgCl(C) (SSC) Sat. KCI +0.22278 -0.094 - 0.70 (0.39)78 -

Ag/AgCl(C) (SSC) 0.1 N KCI +0.28878 -0.028 - 0.43 (0.24)78 ---

Sat. Calomel (SCE) Sat. KCI +0.24410 -0.072 - 0.70 (0.39)10 water, laboratory

Zn (ZRE) Saline Solution -0.79 ± 0.1" -1.1 ± 0.165 - seawater

Zn (ZRE) Soil -0.80 ± 0.165 -1.1 ± 0.165 - underground Solid junction.

(B)Potential becomes more electropositive with increasing resistivity. See nomograph for correction in waters of varying resistivity in NAGE SP0176,1° or see reference 77. (C)Liquid junction.

0 Examples: -850 mV CSE measured at 100 °F (37.8 °C) would be corrected to -838.5 mV at 25 °C (the actual potential is 11.5 0_ mV less negative than the reading), while -850 mV measured at 40 °F (4.4 °C) would be corrected to -868.5 mV at 25 °C (18.5 cp mV more negative than the reading). (Note: 1 mV/°C = 0.55 mV/°F.)

0

(.4

Section 7: Design of Cathodic Protection Systems f•.) 0

7.1 Introduction Ni • •

7.1.1 This section provides guidelines for designing effective and reliable CP systems.

7.1.2 In the design of a CP system, the following should be considered:

7.1.2.1 Recognition of hazardous conditions prevailing at the proposed installation site(s) and the selection and specification of materials and installation practices that ensure safe installation and operation. 5

co cTo

7.1.2.2 Specification of materials and installation practices to conform to the latest editions of applicable codes and national, intemational, and NACE standards.

CD

7.1.2.3 Selection and specification of materials and installation practices that ensure dependable and economical operation throughout the intended operating life. CD

cn 7.1.2.4 Selection of locations for proposed installations to minimize currents or earth potential gradients that can cause CD detrimental effects on foreign underground or submerged metallic structures. 0

7.1.2.5 Cooperative investigations to determine mutually satisfactory solution(s) for interference problems (see Section 9). 0

7.1.2.6 Consideration must be given to the special conditions listed in Paragraph 6.2.1.4.

7.2 Major objectives of CP system design include the following: cri

7.2.1 To provide sufficient current to the structure to be protected and distribute this current so that the selected criteria for CP are effectively attained;

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F13 7.2.2 To minimize the stray currents on neighboring underground structures (see Section 9);

7.2.3 To provide a design life of the system commensurate with the required life of the protected structure, or to provide for periodic rehabilitation of the system;

ciTo

7.2.4 To provide adequate allowance for anticipated changes in current requirements with time over the design life of the CP system;

0 7.2.5 To locate anodes, cable, test stations, and other equipment where the possibility of disturbance or damage is minimal;

CD and

7.2.6 To provide sufficient monitoring facilities to test and evaluate the effectiveness of the CP system performance.

7.3 Information Useful for Design

7.3.1 Useful piping system specifications and information include the following: ce." (A)

7.3.1.1 Route maps and atlas sheets;

7.3.1.2 Constniction dates;

7.3.1.3 Pipe material, fittings, and other appurtenances; 0

7.3.1.4 Line pipe and field joint extemal coatings; 0

7.3.1.5 Casings; 0_ CD 0_

7.3.1.6 Corrosion control test stations; 0

7.3.1.7 Electrically isolating devices; CA)

7.3.1.8 Electrical bonds; and

7.3.1.9 Aerial, bridge, and underwater crossings.

7.3.2 Useful information on piping system site conditions includes the following: -1)

7.3.2.1 Existing and proposed CP systems;

7.3.2.2 Possible interference sources (see Section 9); Cf) 5

co 7.3.2.3 Special environmental conditions such as operating temperatures, SCC susceptibility, MIC;

CD

7.3.2.4 Neighboring buried metallic structures (including location, ownership, and corrosion control practices); cn CD

7.3.2.5 Structure accessibility; o CD

7.3.2.6 Power availability; CD

7.3.2.7 Feasibility of electrical isolation from foreign structures; and 0

7.3.2.8 Possibility of lightning/voltage surge effects that might require mitigation considerations. o

7.3.3 Useful information from field surveys, corrosion test data, and operating experience includes the following: -00

5 7.3.3.1 Protective current requirements to meet applicable criteria; co "3"..

7.3.3.2 Electrical resistivity of the electrolyte; CD

7.3.3.3 Electrical continuity;z. 0

7.3.3.4 Electrical isolation; CO

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7.3.3.5 Extemal coating integrity;

7.3.3.6 Cumulative leak history or results of inspections;

7.3.3.7 Stray currents;

7.3.3.8 Deviation from construction specifications;

7.3.3.9 Natural pH of the environment; and

7.3.3.10 Other maintenance and operating data.

7.3.4 Field survey work before actual application of CP is not always required if prior experience or test data are available to estimate current requirements, electrical resistivity of the electrolyte, and other design factors.

7.4 Types of CP Systems

7.4.1 Galvanic Anode Systems

Galvanic anodes may be made of materials such as alloys of magnesium, zinc, or aluminum. The anodes are cast, extruded, or continuously cast and hot rolled onto steel cores that support the alloy and, for pipelines, to which cables are normally connected. The anodes are connected to the pipe by these cables, either individually or in groups. Galvanic anodes are limited in current output by the anode-to-pipe driving voltage, the electrolyte resistivity, and the total circuit resistance.

7.4.2 Impressed Current Anode Systems

Impressed current anodes may be of materials such as graphite, high-silicon cast iron, lead-silver alloy, precious metals, mixed-metal oxides, conductive polymers, or steel. They are connected with an insulated cable, either individually or in groups, to the positive terminal of a DC source, such as a rectifier, solar power array, wind generator, closed cycle vapor turbine (CCVT), thermoelectric generator, motor generator, or DC-DC converter. The pipeline (structure) is connected to the negative terminal of the DC source.8°

7.5 Considerations influencing selection of the type of CP system include the following:

7.5.1 Magnitude of protective current required;

7.5.2 Stray currents causing significant potential fluctuations between the pipeline and earth that can preclude the use of galvanic anodes;

7.5.3 Effects of CP stray currents on adjacent structures that can limit the use of impressed current CP systems;

7.5.4 Availability of electrical power;

7.5.5 Physical space available, proximity of foreign structures, easement procurement, surface conditions, presence of streets and buildings, river crossings, and other construction and maintenance concerns;

7.5.6 Future development of the right-of-way area and future extensions to the pipeline system;

7.5.7 Costs of installation, operation, and maintenance;

7.5.8 Electrical resistivity of the environment; and

7.5.9 Location of remote earth.

7.6 Factors Influencing Design of CP Systems

7.6.1 Anode materials have different rates of deterioration or consumption when discharging a given current density from the anode surface in a specific environment. Therefore, for a given current output, the anode life is determined by the environment and anode material, which determine the capacity (often expressed in A h/kg for galvanic anodes or as a consumption rate in kg or pg/A h for impressed current materials), and the anode weight and the number of anodes in the CP


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system. Established anode performance data should be used to calculate the probable deterioration rate. Design of galvanic anode systems must consider both current requirement and design life. The shape of the anode determines its resistance to earth in a given environment, and for galvanic anodes, determines their current output. For impressed current anodes, their shape and resistance determine the relationship between driving voltage and current output.

7.6.2 Data on the dimensions, depth, and configuration of the anodes and the electrolyte resistivity can be used to calculate the resultant resistance to electrolyte of the anode system. Formulas and graphs relating to these factors are available in the bibliography literature and from most anode manufacturers.

7.6.3 Design of galvanic anode systems considers anode-to-pipe potential, electrolyte resisivity, current output, and in special cases, anode lead wire resistance. A separate design for each anode or anode system might not be necessary.

7.6.4 Galvanic anode performance and service life in most soils can be improved by using special backfill material. Mixtures of gypsum, bentonite, and anhydrous sodium sulfate are most commonly used. The backfill is designed to provide a uniform environment, ensure electrolyte contact with the anode, and prevent passivation.

7.6.5 For impressed current systems, the number of anodes required can be reduced and their useful life lengthened by the use of special backfill around the anodes. The most common materials are coal coke, calcined petroleum coke, or natural or manufactured graphite.

7.6.6 In the design of an extensive distributed-anode or linear-anode impressed current system, the voltage and current attenuation along the anode-connecting (header) cable should be considered. In such cases, the design objective is to optimize anode system length, anode spacing and size, and cable size to achieve efficient external corrosion control at the extremities of the protected structure.

7.6.7 When it is anticipated that entrapment of gas generated by anodic reactions could impair the ability of the impressed current anode bed to deliver the required current, suitable provisions shall be made for venting the anodes. For the same current output of the system, an increase in the surface area of the special backfill material or an increase in the number of anodes may reduce gas blockage.

7.6.8 When it is anticipated that electroosmotic effects could impair the ability of the impressed current anode bed to deliver the required current output, suitable provisions shall be made to ensure adequate soil moisture around the anodes. Increasing the number of impressed current anodes or increasing the surface area of the special backfill materials can further reduce the electroosmotic effect.

7.7 Design Drawings and Specifications

7.7.1 Suitable drawings shall be prepared to designate the overall layout of the piping to be protected and the location of significant items of structure hardware, corrosion control test stations, electrical bonds, electrical isolation devices, and neighboring underground or submerged metallic structures.

7.7.2 Layout drawings shall be prepared for each impressed current CP installation, showing the details and location of the components of the CP system with respect to the protected structure(s) and to major physical landmarks. These drawings should include right-of-way information.

7.7.3 The locations of galvanic anode installations should be recorded on drawings or in tabular form, with appropriate notes on anode type, weight, spacing, depth, and backfill.

7.7.4 Specifications should be prepared for all materials and installation practices that are to be incorporated in construction of the CP system.

Section 8: Installation of CP Systems

8.1 Introduction

This section provides procedures for installation of CP systems.

8.2 Construction Specifications


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All construction work on CP systems should be performed in accordance with construction drawings and specifications. The construction specifications should be in accordance with Sections 4 and 7.

8.3 Construction Supervision

8.3.1 All construction work on CP systems should be performed under the surveillance of trained and qualified personnel to verify that the installation is in strict accordance with the drawings and specifications. Exceptions may be made only with the approval of qualified personnel responsible for extemal corrosion control.

8.3.2 All deviations from construction specifications should be documented and when appropriate, documented on as-built drawings.

8.4 Galvanic Anodes

8.4.1 Inspection, Handling, and Storage

8.4.1.1 Packaged anodes should be inspected and steps taken to ensure that backfill material completely surrounds the anode. The individual container for the backfill material and anode should be intact. If individually packaged anodes are supplied in waterproof containers, the containers must be removed before installation. Packaged anodes should be kept dry during storage.

8.4.1.2 Lead wire must be securely connected to the anode. Lead wire should be inspected to ensure that it is not damaged.

8.4.1.3 Other galvanic anodes, such as the unpackaged bracelet or ribbon type, should be inspected to ensure that dimensions conform to design specifications and that any damage during handling does not affect application. If a coating is used on bands and the inner side of bracelet anode segments, it must be inspected and, if damaged, repaired before the anodes are installed.

8.4.2 Installation

8.4.2.1 Anodes should be installed according to construction drawings and specifications. As-built documentation of installation should be maintained for use in follow-up maintenance, repairs, and replacements.

8.4.2.2 Packaged galvanic anodes shall be backfilled with appropriately compacted material. When anodes and special chemical backfill are provided separately, anodes should be centered in special backfill, which should be compacted before backfilling. Care should be exercised during all operations so that lead wires and connections are not damaged. Sufficient slack should exist in lead wires to avoid strain.

8.4.2.3 When anodes in bracelet form are used, external pipe coating beneath the anode should be inspected prior to bracelet installation to ensure that it is free of holidays. Care should be taken to prevent damage to the external coating when bracelet anodes are installed. After application of concrete (if used) to pipe, all concrete should be removed from the anode surface. If reinforced concrete is used, there must be no metallic contact between the anode and the reinforcing mesh or between the reinforcing mesh and the pipe.

8.4.2.4 When a ribbon-type anode is used, it can be trenched or plowed in, with or without special chemical backfill as required, generally parallel to the section of pipeline to be protected.

8.5 Impressed Current Systems

8.5.1 Inspection, Handling, and Storage

8.5.1.1 The rectifier or other DC power source should be inspected by qualified personnel to ensure that internal connections are mechanically secure and that the unit is free of damage and conforms to specifications. Rating of the power source shall comply with the construction specification. Care shall be exercised in handling the power source. The CP power source must be inspected for conformance to specifications.

8.5.1.2 Impressed current anodes are inspected for conformance to specifications concerning anode material, size, length of lead cable, anode lead connection, and integrity of seal. Care shall be exercised to avoid cracking or damaging anodes during handling.


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8.5.1.3 All cables must be carefully inspected to detect defects in insulation. Care shall be taken to avoid damage to cable insulation. Defects in the cable insulation must be repaired using an approved material and technique.

8.5.1.4 Anode backffil material must conform to specifications.

8.5.1.5 When storage is necessary, all materials must be properly stored. The environmental effects of UV damage or weather damage (e.g., freezing, etc.) must be considered.

8.5.2 Installation

8.5.2.1 A rectifier or other DC power source should be located and installed to minimize the possibility of damage and vandalism.

8.5.2.2 Wiring to rectifiers shall comply with applicable codes, standards, and requirements. For safety reasons, an external disconnect switch shall be provided in the AC circuit, and the disconnect switch and rectifier case shall be properly grounded.

8.5.2.3 On thermoelectric generators, a reverse current device shall be installed to prevent galvanic action between the anode bed and the pipe if the flame is extinguished.

8.5.2.4 Impressed current anodes can be installed vertically, horizontally, or in deep holes (see NACE SP0572) as indicated in construction specifications. Backfill material should be installed to ensure that there are no voids around anodes. Care shall be exercised during backfilling to avoid damage to the anode and cable.

8.5.2.5 The cable from the rectifier negative terminal to the pipe is connected to the pipe as described in Paragraph 8.6. Cable connections to the rectifier must be mechanically secure and electrically conductive. Before the power source is energized, it must be verified that the negative cable is connected to the structure to be protected and that the positive cable is connected to the anodes. Measurements shall be made to verify that these connections are correct, such as determining that a negative potential shift has occurred on the structure being protected as a result of energizing the DC power source.

8.5.2.6 Underground splices on the header (positive) cable to the anode bed should be kept to a minimum. Connections between the header and anode cables must be mechanically secure and electrically conductive. If underground or submerged, these connections must be sealed to prevent moisture penetration so that electrical isolation from the environment is ensured.

8.5.2.7 Care must be taken during installation of direct-burial cable to the anodes (positive cable) to avoid damage to insulation. Sufficient slack should be left to avoid strain on all cables. Backfill material around the cable should be free of rocks and foreign matter that might cause damage to the insulation when the cable is installed in a trench. Cable can be installed by plowing if proper precautions are taken.

8.5.2.8 If insulation integrity on the underground or submerged header cable, including splices, is not maintained, this cable can fail because of corrosion.

8.6 Corrosion Control Test Stations, Connections, and Bonds

8.6.1 Pipe and test lead wires shall be clean, dry, and free of foreign materials at points of connection when the connections are made. Connections of cables and test lead wires to the pipe must be installed so they remain mechanically secure and electrically conductive.

8.6.2 All underground or submerged cables and lead wire attachments shall be coated with an electrically isolating material that is compatible with the pipe surface, extemal pipe coating, copper wire, weld material, and wire insulation.

8.6.3 Suitably sized test lead wires shall be color coded or otherwise permanently identified. Wires should be installed with slack. Damage to insulation shall be avoided and repairs made if damage occurs. Test leads should not be exposed to excessive heat and sunlight. Aboveground or flush-to-ground test stations may be used as applicable. If test stations are flush with the ground, adequate slack should be provided within the test station to facilitate test connections.

8.6.4 Cable connections at bonds to other structures or across isolating joints shall be mechanically secure, electrically conductive, and suitably coated. Where possible, bonds between structures or across isolation fittings should be made in above-ground test stations to facilitate monitoring and maintenance.


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8.6.5 Refer to NACE Standard RP010481 for guidelines on installing CP coupon test stations.

8.7 Electrical Isolation

Inspection and electrical measurements are made to ensure that electrical isolation is adequate (see NACE SP02865).

Section 9: Control of Stray Currents

9.1 Introduction

This section provides practices for the detection and control of stray currents. Stray currents can be static or dynamic in nature. Static stray current is characterized by a consistent magnitude and electrolytic path. Dynamic stray current is characterized by varying magnitude and/or electrolytic path. The stray current mechanism and its detrimental effects are described.

9.2 Mechanism of Interference-Current Corrosion (Stray-Current Corrosion)

9.2.1 Interference-current corrosion on underground or submerged metallic structures differs from other causes of corrosion damage in that the current, which causes the corrosion, has a source foreign to the affected structure. Usually the interfering current is collected from the electrolyte by the affected structure from a DC source not metallically bonded to the affected structure. Stray currents can occur as a result of potential differences (gradients) in the earth. The potential difference causes current to flow along parallel paths in the earth. The amount of current flow is determined by the magnitude of the potential difference and the resistance of the parallel paths. A structure that is positive with respect to the surrounding earth discharges current into the earth. A structure that is negative with respect to the surrounding earth picks up current from the earth. In general, the lower the electrolyte resistivity, the more severe the damage from stray-current corrosion can be.

9.2.1.1 Detrimental effects of stray current usually occur at locations where the current is exchanged between the affected structures and the electrolyte.

9.2.1.2 Affected structures made of amphoteric metals such as aluminum and lead can be subject to corrosion damage from a buildup of alkalinity at or near the metal surface collecting stray currents.

9.2.1.3 Coatings can experience cathodic disbondment at areas where voltage gradients in the electrolyte force current onto the affected structure. In addition, as the external coating becomes disbonded, a larger area of metal can be exposed, which would increase the demand for CP current. The coating disbondment can also create electrical shielding problems.

9.2.2 The severity of external corrosion resulting from stray currents depends on several factors:

9.2.2.1 Separation and routing of the interfering and affected structures and location of the interfering current source;

9.2.2.2 Magnitude, duration, and density of the current exchange;

9.2.2.3 Quality of the extemal coating or absence of an external coating on the structures involved; and

9.2.2.4 Presence and location of mechanical joints having high electrical resistance.

9.2.3 Typical sources of stray currents include the following:

9.2.3.1 Direct current: CP rectifiers, thermoelectric generators, DC electrified railway and transit systems, coal mine haulage systems and pumps, welding machines, facilities that utilize grounded DC induction equipment, HVDC power systems, and other DC power systems;

9.2.3.2 Altemating current: AC power systems and AC electrified railway systems (refer to NACE SP0177); and

9.2.3.3 Telluric current.

9.3 Detection of Stray Currents

9.3.1 During external corrosion control surveys, personnel should be alert for electrical or physical observations that could indicate interference from a foreign source such as the following:


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(-D

9.3.1.1 Pipe-to-electrolyte potential changes or fluctuations on the affected structure caused by a foreign source; CD

9.3.1.2 Changes or fluctuations in the line current magnitude or direction caused by a foreign source;

9.3.1.3 Localized pitting in areas near or immediately adjacent to a foreign structure or where a diversion occurs between the structure and an AC power corridor; and 5

0 9.3.1.4 Damage to extemal coatings in a localized area near an anode bed or near any other source of stray current.

CD

9.3.2 For new construction, efforts should be made to identify and plan for the mitigation of anticipated stray currents prior to construction. As soon as practicable after construction of the pipeline is completed, monitoring, testing, and mitigation plans to control the effects of stray currents should be implemented.

9.3.3 In areas where stray currents are suspected, appropriate tests should be conducted. All affected parties should be notified before tests are conducted. Notification should be channeled through local corrosion control coordinating committees, when they exist (see NACE Publication TPC 11). In many cases, especially with dynamic stray current interference, there is more than one source of stray current. Any one or a combination of the following typical test methods can be used to evaluate each possible source of stray current.

9.3.3.1 Measurement or correlations of structure-to-electrolyte potentials with recording or indicating instruments to determine the source(s) and extent of stray current pickup and discharge; 0_

0 9.3.3.2 Measurement or correlations of current flowing on the stnicture with recording or indicating instruments to determine the source(s) and extent of stray current pickup and discharge;

ci) o_

9.3.3.3 Development of beta curves from correlation testing data to locate the area of maximum current discharge from CD the affected structure; and

0 9.3.3.4 Measurement of the variations in current output of the suspected source(s) of stray current and correlations with measurements obtained in Paragraph 9.3.2. co

9.4 Methods for Mitigating Interference Corrosion Problems o

9.4.1 Interference problems are individual in nature, and the solution should be mutually satisfactory to the parties involved. The typical methods of mitigation described below may be used individually or in combination.

-0 9.4.2 CP current can be applied to the affected structure at those locations where the interfering current is being discharged. The source of CP current may be from galvanic anodes or impressed current. The driving voltage of the CP current source must be greater than the driving voltage of the stray current for this method to be effective.

5 9.4.3 A common industry best practice is to install a grounding cell (an interference cell). An alternative is to install a dual cot galvanic anode cell. This consists of two magnesium or zinc anodes within a close proximity to one another (but isolated to aTo ensure no metallic contact) near the interference location. Each anode is electrically connected to one single pipeline

cn through a junction box or foreign test station. The advantage of this arrangement is that it allows the stray current to flow CD safely between the anodes through the soil and thus prevents or minimizes interaction effects without installing a direct bond between the two pipelines. c7).

9.4.4 Relocation of the impressed current anode beds can reduce or eliminate the pickup of stray currents on nearby CD structures. 0

9.4.5 Rerouting of proposed pipelines can avoid sources of stray current. ‘•

9.4.6 Properly located isolating fittings in the affected structure can reduce or resolve interference problems. Caution must 0 -0 be exercised to ensure stray current does not discharge across an isolation device. 5

9.4.7 Application of external coating to current pickup area(s) on the affected structure can reduce or resolve interference ccp problems. Current discharge areas should not be recoated, as this can move the discharge point or concentrate stray currentat coating holidays.

0 9.4.8 Reduction of the stray earth current, e.g., by maximizing the resistance-to-earth and controlling track-to-earth voltage of an ungrounded DC-powered transit system. 5

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9.4.9 Design and installation of electrical bonds of proper resistance between the affected and interfering structures. The purpose of a mitigation bond is to eliminate current flow from the affected structure into the electrolyte by providing a metallic return path for the current. Mitigation bonds should be installed as close as practical to the point of maximum discharge from the affected structure. In general, the feasibility of the mitigation methods described above should be evaluated before an electrical bonding solution is pursued.

9.4.9.1 Unidirectional control devices, such as diodes or reverse current switches, might be required in conjunction with electrical bonds if bidirectional currents are present or could possibly occur. These devices prevent reversal of current flow.

9.4.9.2 A resistor might be necessary in the bond circuit to control the magnitude of electrical current flow from the affected structure to the interfering structure. The resistor(s) must be of the proper wattage rating to safely conduct the bond current.

9.4.9.3 The attachment of electrical bonds can reduce the level of CP on the interfering structure. Supplementary CP might be required on the interfering structure to compensate for this effect.

9.4.9.4 A bond might not effectively mitigate the interference problem in the case of a cathodically protected uncoated or poorly coated pipeline that is causing interference on a coated pipeline. In this situation, consideration should be given to coating/recoating the interfering pipeline in the vicinity of the interference problem.

9.4.9.5 In certain instances, such as rail transit with ungrounded DC traction power distribution systems, bonds can lower the transit system's resistance to earth substantially, often with a notable increase in overall stray earth current levels. In these circumstances, it is important to assess the overall impact of the bond versus its value in mitigating stray current on a particular structure.82

9.5 Indications of Resolved Interference Problems

9.5.1 Restoration of the structure-to-electrolyte potentials on the affected structure to those values that existed before the interference or to mutually accepted values between the parties involved.

9.5.2 Measured line currents on the affected structure that show that the stray current is not being discharged to the electrolyte.

9.5.3 Adjustment of the slope of the beta curve to show that current discharge has been adequately mitigated at the location of maximum exposure. Some approaches to the mitigation of stray current effects can redistribute/relocate current discharges rather than eliminate them. Testing must verify that conditions remain within acceptable limits at locations other than the previous site of maximum exposure.

Section 10: Operation and Maintenance of CP Systems

10.1 Introduction

10.1.1 This section provides procedures and practices for energizing and maintaining continuous, effective, and efficient operation of CP systems.

10.1.1.1 Electrical measurements and inspection are necessary to determine that protection has been established according to applicable criteria (see TM0497 for measurement techniques) and that each part of the CP system is operating properly. Conditions that affect protection are subject to change. Correspondingly, changes might be required in the CP system to maintain protection. Periodic measurements and inspections are necessary to detect changes in the CP system. Conditions may exist in which operating experience indicates that testing and inspections need to be made at different intervals.

10.1.1.2 Care should be exercised in selecting the location, number, and type of electrical measurements used to determine the adequacy of CP.

10.1.1.3 When practicable and determined necessary by sound engineering practice, CIS may be conducted to:


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(a) assess the effectiveness of the CP system;

(b) provide baseline operating data;

(c) locate areas of inadequate protection levels;

(d) locate areas of possible coating deterioration;

(e) identify locations likely to be adversely affected by construction, stray currents, or other environmental conditions; or

(f) select areas to be monitored periodically.

Additional reasons for performing close-interval potential surveys are listed in NACE SP0207.83

10.1.1.4 Adjustments to a CP system shall be accompanied by sufficient testing to assure the criteria remain satisfied and to reassess interference with other structures or isolation points.

10.2 Representative potential measurements shall be obtained after each CP system is initially energized to determine whether the applicable criteria have been satisfied.

10.2.1 Representative potential measurements should be considered after each CP system adjustment.

10.3 The effectiveness of the CP system should be monitored annually. Longer or shorter intervals for monitoring might be appropriate, depending on the variability of CP factors, safety considerations, and economics of monitoring.

10.3.1 A minimum voltage drop considered target on-potential (required minimum [RNA]) can be developed for individual test points for either polarization criterion by adding the measured voltage drop at each location to —850 mV or to the free corrosion potential plus 100 mV. Voltage drop measurement may be collected during CIS or annual CP surveys. Once developed, the target potential may continue to be used until CP polarization conditions change enough to alter the corrosion control requirements or new voltage drop measurements are obtained. Refer to NACE Standard TM0497 for additional information.

10.4 Inspection and tests of CP facilities should be performed and documented to verify their proper operation and maintenance as follows:

10.4.1 All impressed current systems should be checked at intervals of two months. Longer or shorter intervals for monitoring might be appropriate. Evidence of proper functioning can be current output, normal power consumption, a signal indicating normal operation, or satisfactory CP levels on the pipe.

10.4.2 All impressed current systems should be inspected annually as part of a preventive maintenance program to minimize in-service failure. Longer or shorter intervals for monitoring might be appropriate. Inspections may include a check for electrical malfunctions, safety ground connections, meter accuracy, efficiency, and circuit resistance.

10.4.3 Reverse current switches, diodes, interference bonds, and other protective devices whose failures would jeopardize structure protection should be inspected for proper functioning at intervals of two months. Longer or shorter intervals for monitoring might be appropriate.

10.4.4 The effectiveness of isolating fittings, continuity bonds, and casing isolation should be evaluated during the external corrosion control surveys. This can be accomplished by electrical measurements.

10.5 When pipe has been uncovered, it should be examined for evidence of external corrosion and, if externally coated, for condition of the external coating, including, but not limited to, any disbonded coating, noting whether corrosion is under the disbonded coating and pH of environment under the disbonded coating.

10.6 The test equipment used for obtaining each electrical value should be of an appropriate type. Instruments and related equipment should be maintained in good operating condition and checked for accuracy.

10.7 Remedial measures should be taken when periodic tests and inspections indicate that CP is no longer adequate. These measures may include the following:

10.7.1 Repair, replace, or adjust components of CP systems;


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10.7.2 Provide supplementary facilities in which additional CP is necessary;

10.7.3 Thoroughly clean and properly coat bare or poorly coated structures if required to attain CP;

10.7.4 Repair, replace, or adjust continuity and interference bonds;

10.7.5 Remove unintentional metallic contacts; and

10.7.6 Repair defective isolating devices.

10.8 An electrical short circuit between a casing and carrier pipe can result in inadequate CP of the pipeline outside the casing because of reduction of protective current to the pipeline.12

10.8.1 When a short results in inadequate CP of the pipeline outside the casing, steps must be taken to restore CP to a level required to meet the CP criterion. These steps may include eliminating the short between the casing and canier pipe, supplementing CP, or improving the quality of the extemal coating on the pipeline outside the casing. None of these steps will ensure that external corrosion will not occur on the carrier pipe inside the casing; however, a shorted casing does not necessarily result in external corrosion of the carrier pipe inside the casing.12

10.8.2 NACE SP0200 contains useful information on the design, fabrication, installation, and maintenance of steel-cased metallic pipelines.

10.9 When the effects of electrical shielding of CP current are detected, the situation should be evaluated and appropriate action taken.

Section 11: External Corrosion Control Records

11.1 Introduction

11.1.1 This section describes external corrosion control records that will document in a clear, concise, workable manner data that are pertinent to the design, installation, operation, maintenance, and effectiveness of external corrosion control measures.

11.2 Relative to the determination of the need for extemal corrosion control, the following should be recorded (see Paragraph 7.3.3):

11.2.1 Corrosion leaks, breaks, and pipe replacements; and

11.2.2 Pipe and external coating condition observed when a buried structure is exposed.

11.3 Relative to structure design, the following should be recorded:

11.3.1 Line pipe and joint coating material and application specifications; and

11.3.2 Design and location of isolating devices, test leads and other test facilities, and details of other special extemal corrosion control measures taken.

11.4 Relative to the design of external corrosion control facilities, the following should be recorded:

11.4.1 Results of current requirement tests;

11.4.2 Results of soil resistivity surveys;

11.4.3 Location of foreign structures; and

11.4.4 Interference tests and design of interference bonds and reverse current switch installations.


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FD3 11.4.4.1 Scheduling of interference tests, correspondence with corrosion control coordinating committees, and direct communication with the concerned companies.

CD 11.4.4.2 Record of interference tests conducted, including location of tests, name of company involved, and results.

CT)

11.5 Relative to the installation of external corrosion control facilities, the following should be recorded: 5

11.5.1 Installation of CP facilities: c5. CD

11.5.1.1 Impressed current systems:

11.5.1.1.1 Location and date placed in service;

—4 11.5.1.1.2 Number, type, size, depth, backfill, and spacing of anodes;

11.5.1.1.3 Nameplate data of rectifier or other energy source; and (t)

11.5.1.1.4 Cable size and type of insulation.

-0 11.5.1.2 Galvanic anode systems:

tv 11.5.1.2.1 Location and date placed in service; 0.

0 11.5.1.2.2 Number, type, size, backfill, and spacing of anodes; and

cr) 11.5.1.2.3 Wire size and type of insulation.

CD 11.5.2 Installation of interference mitigation facilities: O.

0 11.5.2.1 Details of interference bond installation:

CO 11.5.2.1.1 Location and name of company involved;

11.5.2.1.2 Resistance value or other pertinent information; and r.

11.5.2.1.3 Magnitude and polarity of drainage current. 0 -0 11.5.2.2 Details of reverse current switch:

11.5.2.2.1 Location and name of companies; 5

11.5.2.2.2 Type of switch or equivalent device; and ccD

(i) 11.5.2.2.3 Data showing effective operating adjustment. cn CD

11.5.2.3 Details of other remedial measures.

CD 11.6 Records of surveys, inspections, and tests should be maintained to demonstrate that applicable criteria for interference

cn control and CP have been satisfied. CD 0

11.7 Relative to the maintenance of external corrosion control facilities, the following information should be recorded: ‘.<

11.7.1 Maintenance of CP facilities: 0 0

11.7.1.1 Repair of rectifiers and other DC power sources; and 5 cca

11.7.1.2 Repair or replacement of anodes, connections, wires, and cables. -6 CD

11.7.2 Maintenance of interference bonds and reverse current switches: 0

11.7.2.1 Repair of interference bonds; and 5

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11.7.2.2 Repair of reverse current switches or equivalent devices.

11.7.3 Maintenance, repair, and replacement of external coating, isolating devices, test leads, and other test facilities.

11.8 Records sufficient to demonstrate the effectiveness of external corrosion control measures should be maintained as long as the facility involved remains in service. Other related external corrosion control records should be retained for such a period that satisfies individual company needs.

11.9 Records sufficient to demonstrate adequate criteria used under Paragraph 6.2 must be maintained as long as the criteria are used to determine adequate CP.

References

1. NACE Publication 10A292 (latest revision), "Corrosion and Corrosion Control for Buried Cast- and Ductile-lron Pipe" (Houston, TX: NACE).

2. NACE SP0572 (latest revision), "Design, Installation, Operation, and Maintenance of Impressed Current Deep Anode Beds" (Houston, TX: NACE).

3. NACE SP0177 (latest revision), "Mitigation of Altemating Current and Lightning Effects on Metallic Structures and Corrosion Control Systems" (Houston, TX: NACE).

4. NACE SP0285 (formerly RP0285) (latest revision), "Corrosion Control of Underground Storage Tank Systems by Cathodic Protection" (Houston, TX: NACE).

5. NACE SP0286 (latest revision), "The Electrical Isolation of Cathodically Protected Pipelines" (Houston, TX: NACE).

6. NACE SP0188 (latest revision), "Discontinuity (Holiday) Testing of Protective Coatinge (Houston, TX: NACE).

7. NACE Publication TPC 11 (latest revision), "A Guide to the Organization of Underground Corrosion Control Coordinating Committeee (Houston, TX: NACE).

8. NACE Standard TM0497 (latest revision), "Measurement Techniques Related to Criteria for Cathodic Protection on Underground or Submerged Metallic Piping Systems" (Houston, TX: NACE).

9. NACE SP0607/ISO 15589-2 (MOD) (latest revision), "Petroleum and natural gas industries — Cathodic protection of pipeline transportation systems — Part 2: Offshore pipelines" (Houston, TX: NACE).

10. NACE SP0176 (latest revision), "Corrosion Control of Submerged Areas of Permanently Installed Steel Offshore Structures Associated with Petroleum Production" (Houston, TX: NACE).

11. T. Koybayashi, "Effect of Environmental Factors on the Protective Potential of Steel," Proceedings of the Fifth International Congress on Metallic Corrosion, held 1972 (Houston, TX: NACE), p. 629.

12. NACE SP0200 (latest revision), "Steel-Cased Pipeline Practices" (Houston, TX: NACE).

13. ANSI/ASME B31.8 (latest revision), "Gas Transmission and Distribution Piping Systems" (New York, NY: ASME).

14. ANSI/ASME B31.4 (latest revision), "Pipeline Transportation Systems for Liquid Hydrocarbons and Other Liquids" (New York, NY: ASME).

15. DNV RP-F102 (latest revision), "Pipeline Field Joint Coating and Field Repair of Linepipe Coating" (Oslo, Norway: DNV).

16. NACE Standard RP0602 (latest revision), "Field-Applied Coal Tar Enamel Pipe Coating Systems: Application, Performance, and Quality Control" (Houston, TX: NACE).

17. DNV RP-F106 (latest revision), "Factory Applied External Pipeline Coatings for Corrosion Control" (Oslo, Norway: DNV).


000253

SP0169-2013 a_ CT) 18. NACE Standard RP0399 (latest revision), "Plant-Applied Extemal Coal Tar Enamel Pipe Coating Systems: Application,

Performance, and Quality Control" (Houston, TX: NACE).

19. ANSI/AWWA C 203 (latest revision), "Standard for Coal-Tar Protective Coatings and Linings for Steel Water CT, Pipelines—Enamel and Tape—Hot Applied" (Washington, DC: ANSI and Denver, CO: AWWA).

20. "Extemal Application Procedures for Coal Tar Epoxy Protective Coatings to Steel Pipe," NAPCA Bulletin, 13-79-94, 1994

0 21. ANSI/AWWA C 214 (latest revision), "Tape Coating Systems for the Exterior of Steel Water Pipelinee (Washington, DC: ANSI and Denver, CO: AWWA).

2 22. ANSI/AWWA C 209 (latest revision), "Cold-Applied Tape Coatings for the Exterior of Special Sections, Connections, and Fittings for Steel Water Pipelines'' (Washington, DC: ANSI and Denver: CO: AWWA).

23. "External Application Procedures for Plant Applied Tape Coating to Steel Pipe," NAPCA Bulletin 15-83-94, 1994. cp

24. NACE SP0109 (latest revision), "Field Application of Bonded Tape Coatings for External Repair, Rehabilitation, and Weld 6.)

Joints on Buried Metal Pipelinee (Houston, TX: NACE).

25. ISO 21809 (latest revision), "Petroleum and natural gas industries — External coatings for buried or submerged pipelines -0

used in pipeline transportation systems" (Geneva, Switzerland: ISO).

26. ANSI/AWWA C 216 (latest revision), "Heat-Shrinkable Cross-Linked Polyolefin Coatings for the Exterior of Special Sections, 0 Connections, and Fittings for Steel Water Pipelinee (Washington, DC: ANSI and Denver, CO: AWWA).

27. DIN 30672 (latest revision), "External organic coatings for the corrosion protection of buried and immersed pipelines for continuous operating temperatures up to 50 °C — Tapes and shrinkable materiale (Berlin, Germany: DIN). 0_

(Di a_

28. NACE Standard RP0402 (latest revision), "Field-Applied Fusion-Bonded Epoxy (FBE) Pipe Coating Systems for Girth Weld Joints: Application, Performance, and Quality Control" (Houston, TX: NACE).

C.A.) -t•-e5 29. NACE Standard RP0303 (latest revision), "Field-Applied Heat-Shrinkable Sleeves for Pipelines: Application, Performance, and Quality Control" (Houston, TX: NACE).

30. ANSI/AWWA C 213 (latest revision), "Fusion-Bonded Epoxy Coating for the Interior and Exterior of Steel Water Pipelines" -11•

(Washington, DC: ANSI and Denver: CO: AWWA).

31. API RP 5L9 (latest revision), "External Fusion-Bounded Epoxy Coating of Line Pipe (Washington, DC: API).

32. CSA Z245.20 (latest revision), "External Fusion-Bond Epoxy Coated Steel Pipe (Toronto, ON: CSA). co

33. NACE Standard RP0394 (latest revision), "Application, Performance, and Quality Control of Plant-Applied, Fusion-Bonded 5 co

Epoxy Extemal Pipe Coating" (Houston, TX: NACE).

34. "External Application Procedures for Plant Applied Fusion Bonded Epoxy (FBE) Coatings and Abrasion Resistant Overlay CD (ARO) Coatings to Steel Pipe," NAPCA Bulletin 12-78-04, 2004.

0 35. FBE Anomalies Trouble-Shooting Guide," NAPCA Bulletin 17-98, 1998. (I)

cn 36. DNV OS-F101 (latest revision), "Submarine Pipeline Systeme (Oslo, Norway: DNV).

0 37. ANSI/AWWA C 210 (latest revision), "Liquid-Epoxy Coating Systems for the Interior and Exterior of Steel Water Pipelines" (Washington, DC: ANSI and Denver: CO: AWWA).

0 38. NACE Standard RP0105 (latest revision), "Liquid-Epoxy Coatings for Extemal Repair, Rehabilitation, and Weld Joints on

‘•<. Buried Steel Pipelines" (Houston, TX: NACE). 5

39. SSPC Paint 33, "Coal Tar Mastic, Cold-Applied" (Pittsburgh, PA: SSPC). *3-

40. CSA Z245.21 (latest revision), "Extemal polyethylene coating for pipe (Toronto, ON: CSA). 0

41. NF A49-710 (latest revision), "Steel pipes: External coating with three layer polyethylene based coating: application by extrusion" (La Plaine Saint-Denis Cedex, France: Association frangaise de normalisation). ca

-o NACE International 35

000254 CD a_

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42. NACE SP0185 (latest revision), "Extruded Polyolefin Resin Coating Systems with Soft Adhesives for Underground or Submerged Pipe (Houston, TX: NACE).

43. ANSI/AWWA C 215 (latest revision), "Extruded Polyolefin Coatings for the Exterior of Steel Water Pipe Lines" (Washington, DC: ANSI and Denver, CO: AWWA).

44. ANSI/AWWA C 225 (latest revision), "Fused Polyolefin Coating Systems for the Exterior of Steel Water Pipelines" (Washington, DC: ANSI and Denver, CO: AWWA).

45. "External Application Procedures for Polyolefin Pipe Coating Applied by the Cross Head Extrusion Method or the Side Extrusion Method to Steel Pipe," NAPCA Bulletin 14-83-94, 1994.

46. ANSI/AWWA C 222 (latest revision), "Polyurethane Coatings for the Interior and Exterior of Steel Water Pipe and Fittings" (Washington, DC: ANSI and Denver: CO: AWWA).

47. Work in progress by NACE Task Group 281, "Field-Applied Rigid Polyurethane Coatings for Field Repair, Rehabilitation, and Girth Weld Joints on Pipelines: Application, Performance, and Quality Contror (Houston, TX: NACE).

48. NACE Standard RP0375 (latest revision), "Field-Applied Underground Coating Systems for Underground Pipelines: Application, Performance, and Quality Control" (Houston, TX: NACE).

49. AWWA C 217 (latest revision), "Standard for Petrolatum and Petroleum Wax Tape Coatings for the Exterior of Connections and Fittings for Steel Water Pipelinee (Denver: CO: AWWA).

50. BS EN 545 (latest revision), "Ductile iron pipes, fittings, accessories and their joints for water pipelines. Requirements and test methods" (London, UK: BSI).

51. BS EN 14628 (latest revision), "Ductile iron pipes, fittings and accessories. External polythene coating for pipes. Requirements and test methods" (London, UK: BSI).

52. DIN 15542 (latest revision), "Ductile iron pipes, fittings and accessories. External cement mortar coating for pipes. Requirements and test methode (London, UK: BSI).

53. DIN 30674 (latest revision), "Coating of ductile cast iron pipee (Berlin, Germany: DIN).

54. ISO 8179 (latest revision), "Ductile iron pipes — External zinc-based coating" (Geneva, Switzerland: ISO).

55. API RP 5L1 (latest revision), "Recommended Practice for Railroad Transportation of Line Pipe (Washington, DC: API).

56. API RP 5LW (latest revision), "Recommended Practice for Transportation of Line Pipe on Barges and Marine Vessels" (Washington, DC: API).

57. R.B. Francini, C.E. Kolovich, M.E. Jonell, P.A. Zelenak, M.J. Rosenfeld, "Evaluating the Need for Loading Specifications for Highway Transportation of Line Pipe," PRCI, PR 218-064505, September 2007.

58. NACE SP0490 (latest revision), "Holiday Detection of Fusion-Bonded Epoxy External Pipeline Coatings of 250 to 760 pm (10 to 30 mil) (Houston, TX: NACE).

59. I. Thompson, "Coating and Backfill System Optimisation," PRCI, GRI-8704, May 2004.

60. J.D. Hair, "Coating Requirements for Pipelines Installed By Horizontal Directional Drilling and Slip Boring," PRCI, PR 227-9812, July 2000.

61. NACE Standard TM0102 (latest revision), "Measurement of Protective Coating Electrical Conductance on Underground Pipelinee (Houston, TX: NACE).

62. NACE Publication 35108 (latest revision), "One Hundred Millivolt (mV) Cathodic Polarization Criterion" (Houston, TX: NACE).

63. ISO 15589-1 (latest revision), "Petroleum and Natural Gas Industries — Cathodic Protection of Pipeline Transportation Systems — Part 1: On Land Pipelinee (Geneva, Switzerland: ISO).


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64. K.P. Fischer, "Cathodic Protection in Saline Mud Containing Sulfate Reducing Bacteria," MP 20, 10 (1981): pp. 41-46.

65. W. von Baeckmann, W. Schwenk, W. Prinz, Handbook of Corrosion Protection, 3rd ed. (Burlington, MA: Elsevier, 1997), p. 72.

66. T.J. Barlo, W.E. Berry, "An Assessment of Current Criteria for Cathodic Protection of Buried Pipelines," MP 23, 9 (1984): p. 14.

67. A.D. Zdunrk, T.J. Barlo, "Effect of Temperature on Cathodic Protection Criteria," MP 31, 11 (1992): pp. 22-27.

68. L. Ocando, O. de Rincon, M. de Romero, "Cathodic Protection Efficiency in the Presence of SRB: State of the Art," CORROSION 2009, paper no. 407 (Houston, TX: NACE, 2009).

69. NACE Publication 35110 (latest revision), "AC Corrosion State-of-the-Art: Corrosion Rate, Mechanism, and Mitigation Requirements.' (Houston, TX: NACE).

70. M. Ormellese, L. Lazzari, A. Brenna, A. Trombetta, "Proposal of CP Criterion in the Presence of AC-Interference," CORROSION 2010, paper no. 32 (Houston, TX: NACE, 2010).

71. NACE CP Level 2 Course Material, Houston, TX: NACE, p. 244.

72. T.J. Barlo, "Origin and Validation of the 100 mV Polarization Criterion," CORROSION/2001, paper no. 581 (Houston, TX: NACE, 2001).

73. M. Pourbaix, Atlas of Electrochemical Equilibria in Aqueous Solutions (Houston, TX: NACE, 1974).

74. BS EN 12954 (latest revision), "Cathodic protection of buried or immersed metallic structures. General principles and application for pipelines'. (London, UK: BSI).

75. NACE Publication 10A392 (latest revision), "Effectiveness of Cathodic Protection" (Houston, TX: NACE).

76. M.H. Peterson, R.E. Groover, "Tests Indicate the Ag/AgCI Electrode Is Ideal Reference Cell in Sea Water," Materials Protection 11, 5 (1972): pp. 19-22.

77. D. Ives, G. Janz, Reference Electrodes: Theory & Practice (Burlington, MA: Elsevier, 1961), p. 161 and p. 189.

78. H.H. Uhlig, W. Revie, Corrosion and Corrosion Control, 3rd Ed. (Hoboken, NJ: John Wiley & Sons, 1985), p. 33.

79. H.H. Uhlig, Comosion Handbook (Hoboken, NJ: John Wiley & Sons, 1948), p. 1137.

80. NACE Publication 10A196 (latest revision), "Impressed Current Anodes for Underground Cathodic Protection Systems" (Houston, TX: NACE).

81. ANSI/NACE Standard RP0104 (latest revision), "The Use of Coupons for Cathodic Protection Monitoring Applications" (Houston, TX: NACE).

82. NACE Publication 10B189 (latest revision), "Direct Current (DC) Operated Rail Transit and Mine Railroad Stray Current Mitigation" (Houston, TX: NACE).

83. NAGE SP0207 (latest revision), "Performing Close-Interval Potential Surveys and DC Surface Potential Gradient Surveys on Buried or Submerged Metallic Pipelines" (Houston, TX: NACE).

84. ANSI/AWWA C 203 (latest revision), "Coal-Tar Protective Coatings and Linings for Steel Water Pipelines-Enamel and Tape-Hot Applied" (Washington, DC: ANSI and Denver: CO: AWWA).

85. EN 12068 (latest revision), ''Cathodic Protection - External Organic Coatings for the Corrosion Protection of Buried or Immersed Steel Pipelines Used in Conjunction with Cathodic Protection - Tapes and Shrinkable Materials" (London, UK: BSI).

86. ASTM D4138 (latest revision), "Standard Practices for Measurement of Dry Film Thickness of Protective Coating Systems by Destructive, Cross-Sectioning Means" (West Conshohocken, PA: ASTM).


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87. ASTM G12 (latest revision), "Standard Test Method for Nondestructive Measurement of Film Thickness of Pipeline Coatings on Steel" (West Conshohocken, PA: ASTM).

88. DNV RP-F103 (latest revision), "Cathodic Protection of Submarine Pipelines by Galvanic Anodee (Oslo, Norway: DNV).

89. SSPC PA-2 (latest revision), "Measurement of Dry Coating Thickness with Magnetic Gages" (Pittsburgh, PA: SSPC).

90. NACE SP0274 (formerly RP0274) (latest revision), "High-Voltage Electrical Inspection of Pipeline Coatings Prior to Installation" (Houston, TX. NACE).

91. ASTM G8 (latest revision), "Standard Test Method for Cathodic Disbonding of Pipeline Coatings" (West Conshohocken, PA: ASTM).

92. ASTM G19 (latest revision), "Standard Test Method for Disbonding Characteristics of Pipeline Coatings by Direct Soil Burial" (West Conshohocken, PA. ASTM).

93. ASTM G42 (latest revision), "Standard Test Method for Cathodic Disbonding of Pipeline Coatings Subjected to Elevated Temperatures" (West Conshohocken, PA: ASTM).

94. ASTM G95 (latest revision), "Test Method for Cathodic Disbondment Test of Pipeline Coatings (Attached Cell Method)" (West Conshohocken, PA: ASTM).

95. ASTM G9 (latest revision), "Standard Test Method for Water Penetration into Pipeline Coatinge (West Conshohocken, PA: ASTM).

96. ASTM G17 (latest revision), "Standard Test Method for Penetration Resistance of Pipeline Coatings (Blunt Rod)" (West Conshohocken, PA: ASTM).

97. ASTM D2240 (latest revision), "Standard Test Method for Rubber Property—Durometer Hardnese (West Conshohocken, PA: ASTM).

98. ASTM G14 (latest revision), "Standard Test Method for Impact Resistance of Pipeline Coatings (Falling Weight Test)" (West Conshohocken, PA: ASTM).

99. ASTM D427 (latest revision), "Standard Test Method for Shrinkage Factors of Soils by the Mercury Method" (West Conshohocken, PA: ASTM).

100. ASTM D543 (latest revision), "Standard Practices for Evaluating the Resistance of Plastics to Chemical Reagents" (West Conshohocken, PA: ASTM).

101. ASTM G20 (latest revision), "Standard Test Method for Chemical Resistance of Pipeline Coatinge (West Conshohocken, PA: ASTM).

102. ASTM D2304 (latest revision), "Standard Test Method for Thermal Endurance of Rigid Electrical Insulating Materiale (West Conshohocken, PA: ASTM).

103. ASTM D2454 (latest revision), "Standard Practice for Determining the Effect of Overbaking on Organic Coatings" (West Conshohocken, PA: ASTM).

104. ASTM D2485 (latest revision), "Standard Test Methods for Evaluating Coatings for High-Temperature Service" (West Conshohocken, PA: ASTM).

105. ASTM G18 (latest revision), "Standard Test Method for Joints, Fittings, and Patches in Coated Pipelines" (West Conshohocken, PA: ASTM).

106. ASTM G55 (latest revision), "Standard Test Method for Evaluating Pipeline Coating Patch Materials" (West Conshohocken, PA: ASTM).

107. ASTM G21 (latest revision), "Standard Practice for Determining Resistance of Synthetic Polymetric Materials To Fungi" (West Conshohocken, PA: ASTM).


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SP0169-2013

108. Federal Test Standard No. 406A, Method 6091 (latest revision), "Test Method for Mildew Resistance of Plastics by Mixed Culture Method (Agar Medium) (Washington, DC: GSA).

109. ASTM G6 (latest revision), "Standard Test Method for Abrasion Resistance of Pipeline Coatings" (West Conshohocken, PA: ASTM).

110. ASTM D2197 (latest revision), "Standard Test Method for Adhesion of Organic Coatings by Scrape Adhesion" (West Conshohocken, PA: ASTM).

111. ASTM G10 (latest revision), "Standard Test Method for Specific Bendability of Pipeline Coatings" (West Conshohocken, PA: ASTM).

112. ASTM G11 (latest revision), "Standard Test Method for Effects of Outdoor Weathering on Pipeline Coatinge (West Conshohocken, PA: ASTM).

113. DNV RP F-107 (latest revision), "Risk Assessment of Pipeline Protection" (Oslo, Norway: DNV).

114. DNV OSS-301 (latest revision), "Certification and Verification of Pipelinee (Oslo, Norway: DNV).

115. NACE Standard TM0109 (latest revision), "Aboveground Survey Techniques for the Evaluation of Underground Pipeline Coating Condition" (Houston, TX: NACE).

116. R.A. Gummow, S.A. Segall, "In-Situ Evaluation of Directional Drill/Bore Coating Quality," PRCI, PR 262-9738, October 1998.

117. AS/NZS 2832.1 (latest revision), "Cathodic protection of metals - Pipes and cables" (Strathfield, Australia: Standards Australia).

118. AS/NZS 4352 (latest revision), "Tests for coating resistance to cathodic disbanding" (Strathfield, Australia: Standards Australia).

119. BS EN 7361-1 (latest revision), "Cathodic protection, Part 1. Code of practice for land and marine applicatione (London, UK: BSI).

120. ISO EN 14919 (latest revision), "Thermal spraying - Wires, rods and cords for flame and arc spraying - Classification Technical supply conditions" (Geneva, Switzerland: ISO).

121. CGA OCC-1 (latest revision), "Recommended Practice for the Control of External Corrosion on Buried or Submerged Metallic Piping Systeme (Ottawa, Ontario: CGA).

122. DIN 30 676 (latest revision), "Design and application of cathodic protection of external surfacee (Berlin, Germany: DIN).

123. V. Baeckmann, W. Schwenk, Handbook of Cathodic Protection (Surrey, England: Portcullis Press Ltd., 1975).

124. DIN 50 928 (latest revision), "Corrosion of metals; testing and assessment of the corrosion protection of coated metallic materials in contact with aqueous corrosive agents" (Berlin, Germany: DIN).

125. DIN 50 918 (latest revision), "Corrosion of metals; electrochemical corrosion tests" (Berlin, Germany: DIN).

126. DIN 50 927 (latest revision), "Planning and application of electrochemical corrosion protection of internal surfaces of apparatus, containers and tubes (intemal protection) (Berlin, Germany: DIN).

127. DIN VDE 0150 (latest revision), "Protection against corrosion by stray current from direct current systeme (Berlin, Germany: DIN).

128. Japan Water Works Association, Water Safety Plan 050, 1995.

129. HPIS G 105 (latest revision), "Anti-Corrosion and Corrosion Control Guide of the Oil Tank" (Tokyo, Japan: HPIS).

130. "Detailed Technical Criteria for Hazardous Materials," Japan Fire Bureau Regulations, May 31, 2000.

131. GOST R 51164 (latest revision), "Steel Main Pipelines General Requirements for Protection Against Corrosion" (Moscow, Russia: Standards Publishing House).


000258

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132. U.S. Code of Federal Regulations (CFR) Title 49, "Protection Against Accidental Overpressure," Parts 192 and 195 (Washington, DC: Office of the Federal Register, 1995).

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Howell, R.P. "Potential Measurements in Cathodic Protection Designs." Corrosion 8, 9 (1952): pp. 300-304.

Jacobs, J.A. "A Comparison of Anodes for Impressed Current Systems." NACE Canadian Region Western Conference, Edmonton, Alberta, Canada, February 1980.

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NACE Publication 26156 (withdrawn). "Final Report on Four Annual Anode Inspections." Houston, TX: NACE.

NACE Publication 2M363 (withdrawn). "Recommended Practice for Cathodic Protection of Aluminum Pipe Buried in Soil or Immersed in Water." Houston, TX: NACE.

NACE Publication 35108 (latest revision). "One Hundred Millivolt (mV) Cathodic Polarization Criterion." Houston, TX: NACE.

NACE Publication 35103 (latest revision). "Extemal Stress Corrosion Cracking of Underground Pipelines " Houston, TX: NACE.

NACE SP0102 (latest revision). "In-Line Inspection of Pipelines." Houston, TX: NACE.

NACE SP0204 (latest revision). "Stress Corrosion Cracking (SCC) Direct Assessment Methodology." Houston, TX: NACE.

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Prinz, W. "Close Interval Potential Survey of Buried Pipelines, Methods and Experience." UK Corrosion '86, p. 67.

Riordan, M.A. "The Electrical Survey—What It Won't Do." MP 17, 11 (1978): pp. 38-41.

Riordan, M.A., and R.P. Sterk. 'Well Casing as an Electrochemical Network in Cathodic Protection Design." Materials Protection 2, 7 (1963): pp. 58-68.

Robinson, H.A., and P.F. George. "Effect of Alloying and Impurity Elements in Magnesium Cast Alloy Anodes." Corrosion 10, 6 (1954): p. 182.

Romanoff, M. Underground Corrosion. Houston, TX: NACE, 1989.

Rudenberg, R. "Grounding Principles and Practices." Electrical Engineering 64 (1945): p. 1.

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Schaschl, E., and G.A. Marsh. "Placement of Reference Electrode and Impressed Current Anode Effect on Cathodic Protection of Steel in a Long Cell." MP 13, 6 (1974): pp. 9-11.

Schreiber, C.F., and G.L. Mussinelli. "Characteristics and Performance of the LIDA Impressed-Current System in Natural Waters and Saline Muds." CORROSION/86, paper no. 287. Houston, TX: NACE, 1986.

Schwerdffeger, W.J. "Criteria for Cathodic Protection—Highly Resistant Copper Deteriorates in Severely Corrosive Soil." Materials Protection 57, 9 (1968): p. 43.

Schwerdffeger, W.J. "Effects of Cathodic Current on the Corrosion of an Aluminum Alloy." National Bureau of Standards Joumal of Research 68c (Oct.-Dec. 1964): p. 283.

Schwerdffeger, W.J., and O.N. McDorman. "Potential and Current Requirements for the Cathodic Protection of Steel in Soils." Corrosion 8, 11 (1952): p. 391.

Sunde, E.D.. Earth Conduction Effects in Transmission Systems. New York, NY: Dover Publications, 1968.

Stem, M. "Fundamentals of Electrode Processes in Corrosion." Corrosion 13, 11 (1957): p. 97.

Sudrabin, L.P., and F.W. Ringer. "Some Observations on Cathodic Protection Criteria." Corrosion 13, 5 (1957) p. 351t. Discussion on this paper Corrosion 13, 12 (1957): p. 835t.

Thompson, N.G., and T.J. Barlo. "Fundamental Process of Cathodically Protecting Steel Pipelines." International Gas Research Conference, 1983.

Toncre, A.C. "A Review of Cathodic Protection Criteria." Proceeding of Sixth European Congress on Metallic Corrosion. Held London, England, September 1977, pp. 365-372.

Van Nouhuys, H.C. "Cathodic Protection and High Resistivity Soil." Corrosion 9, 12 (1953): pp. 448-458.

Van Nouhuys, H.C. "Cathodic Protection and High Resistivity Soil—A Sequel." Corrosion 14, 12 (1958): p. 55.

Von Baekmann, W., A. Ballest, and W. Prinz. "New Development in Measuring the Effectiveness of Cathodic Protection." Corrosion Australasia, February, 1983.

Von Baekmann, W., and W. Schwenk. Handbook of Cathodic Protection. Portellis Press, 1975, Chapter 2.

Webster, R.D. "Compensating for the IR Drop Component in Pipe-to-Soil Potential Measurements." MP 26, 10 (1987): pp. 38-41.

Wyatt, B.S., and K.C. Lax. "Close Interval Overline Polarized Potential Surveys of Buried Pipelines." UK Corrosion Conference, 1985.


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Appendix A External Coatings Tables

(Nonmandatory)

This appendix is considered nonmandatory, although it may contain mandatory language. It is intended only to provide supplementary information or guidance. The user of this standard is not required to follow, but may choose to follow, any or all of the provisions herein.

Table A1 References for General Use in the Installation and Inspection of External Coating Systems

for Underground or Submerged Piping

Subject Reference

Application of Organic Pipeline Coatings ANSI/AWWA C 20384 ANSI/AWWA C 209 ANSI/AWWA C 210 ANSI/AWWA C 214 ANSI/AWWA C 215 ANSI/AWWA C 216 ANSI/AWWA C 222 NACE Standard RP0375 ANSI/AWWA C 213 API RP 5L9 CSA Z245.20 AWWA C 225 EN 1206885

Film Thickness of Pipeline Coatings ASTM D41386b ASTM G1287 NACE Standard RP0394 NACE Standard RP0399 DNV RP-F10388

SSPC PA 289 Inspection of Pipeline Coatings

NACE SP027499 ISO 21809-3

Installation DNV-0S-F101 ISO 21809-3


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Table A2 External Coating System Characteristics Relative to Environmental Conditions(A)

Environmental Factor Recommended Test Methode) General Underground Exposure with or Without CP ANSI/AWWA C 203

ANSI/AWWA C 209 ANSI/AWWA C 210 ANSI/AWWA C 214 ANSI/AWWA C 215 ANSI/AWWA C 216 ANSI/AWWA C 222 ANSI/AWWA C 213 API RP 5L9 CSA Z245.20 ASTM G891 ASTM G1992 ASTM G4293 ASTM G9594 API RP 5L9 AWWA C 225 DNV RP-F103

Resistance to Water Penetration and Its Effect on Choice of Coating Thickness

ASTM G995

Resistance to Penetration by Stones in Backfill ASTM G179b ASTM D224092 ASTM G1498

Soil Stress ASTM D42799 Note: ASTM has withdrawn this standard, and it has not yet been replaced.

Resistance to Specific Liquid Not Normally Encountered in Virgin Soil

ASTM D5431uu ASTM G20101

Resistance to Thermal Effects ASTM D23041°2 ASTM D2454103 ASTM D24851°4 ASTM G42

Suitability of Supplementary Materials for Joint Coating and Field Repairs

ASTM G8 ASTM G19 ASTM G42 ASTM G95 ASTM G9 ASTM G18105 ASTM G551°6 NACE Standard RP0394 NACE Standard RP0375 DNV RP-F103 DNV RP-F102

Resistance to Microorganisms ASTM G211ut Federal Test Standard No. 406A, Method 6091108

EN 12068 (A) Not (8) No specific criteria are available. Comparative tests are recommended for use and evaluation as supplementary information only.

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Table A3(a) External Coating System Characteristics Related to Design and Construction

Design and Construction Factor Recommended Test Methods(A)

Backfill Resistance ASTM G14

Driving Ability (Resistance to Sliding Abrasion) ASTM G61°9 ASTM D219711°

Field Bending Ability ASTM G10111 NACE Standard RP0394

Handling Resistance, Abrasion ASTM G6

Handling Resistance, Impact ASTM G14

Resistance to Thermal Effects ASTM G8 ASTM G19 ASTM G42 ASTM G95 ASTM D2304 ASTM D2454 ASTM D2485

Special Requirements for Application of Coating Over the Ditch

ANSI/AWWA C 203 NACE Standard RP0375 ANSI/AWWA C 214 ANSI/AWWA C 209 ANSI/AWWA C 213 API RP 5L9 CSA Z245.20 NACE SP0185

Special Requirements for Mill-Applied Coating ANSI/AWWA C 210 ANSI/AWWA C 216 ANSI/AWWA C 222 ANSI/AWWA C 203 NACE Standard RP0375 ANSI/AWWA C 214 ANSI/AWWA C 209 ANSI/AWWA C 213 API RP 5L9 CSA Z245.20 NACE SP0185 DIN 30670 ANSI/AWWA C 215 DNV RP-F106 NACE Standard RP0394 NACE Standard RP0399 AWWA C 225

Suitability of Joint Coatings and Field Repairs ANSI/AWWA C 213 API RP 5L9 CSA Z245.20 ASTM G8 ASTM G19 ASTM G42 ASTM G95 ASTM G9 ASTM G18 ASTM G55 NACE SP0185 AWWA C 216

Yard Storage, Penetration Under Load ASTM G17 ASTM D2240

Yard Storage, Weathering ASTM G11 2 l')No specific criteria are available. Comparative tests are recommended for use and evaluation as supplementary information only.


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Table A3(b) External Coating System Characteristics Related to Design and Construction

Design and Construction Factor Recommended Test Methods

Design and Construction Factor Recommended Test Methods(A)

Corrosion Control DNV-0S-F101

Current Effects ISO 15589-1

Field Bending Ability DNV RP-F102 NACE Standard RP0394

Handling Resistance, Impact EN 12068 DNV RP-F107113

Resistance to Thermal Effects ASTM G8

Special Requirements for Mill-Applied Coating ANSI/AWWA C 203 NACE Standard RP0375 ANSI/AWWA C 214 ANSI/AWWA C 209 ANSI/AWWA C 213 API RP 5L9 CSA Z245.20 NACE SP0185 DNV-0S-F101 DNV RP-F102 DNV RP-F103 NACE Standard RP0394 NACE Standard RP0399 AWWA C 210 AWWA C 215 AWWA C 216 AWWA C 222 AWWA C 225

Suitability of Joint Coatings and Field Repairs ANSI/AWWA C 213 CSA Z245.20 ASTM G55 NACE SP0185

(A)No specific criteria are available. Comparative tests are recommended for use and evaluation as supplementary information only.


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Table A4 Methods for Evaluating Field Performance of External Coatings

Title or Subject of Method Reference Basis for Rating

(1) Cathodic Disbondment ASTM G8 ASTM G19 ASTM G42 ASTM G95

Purpose is to obtain data relative to specific conditions for comparison with laboratory data

(2) Change in Current Required for CP

ISO 15589-1 Comparison of initial current requirement with subsequent periodic determination of current requirement

(3) Coating Conductance NACE Standard TM0102 Specific coating conductance normalized to 1,000 acm soil

(4) High-Voltage Electrical Inspection of Pipeline Coating

NACE SP0274 DNV-OSS-301114

Detection of holidays using high-voltage electrical inspection

(5) Aboveground Survey Techniques for the Evaluation of Underground Pipeline Coating Condition

NACE Standard TM0109115 Measuring altemating current attenuation or identifying, locating (and for some techniques) determining a relative magnitude of coating defects.

(6) In Situ Evaluation of Directional Drill/Bore Coating Quality

PRCI PR-262-9738116 Combination of current requirements and coating conductance applied to directionally drilled pipe installations.

Appendix B Review of International Standards

(Nonmandatory)

This appendix is considered nonmandatory, although it may contain mandatory language. It is intended only to provide supplementary information or guidance. The user of this standard is not required to follow, but may choose to follow, any or all of the provisions herein.

The following are summaries and direct copies (published with permission) of some international and country standards and regulations on cathodic protection criteria that TG 360 has reviewed which could be of benefit to the corrosion control practitioner. The TG is attempting to receive permission from the various document owners to include criteria excerpts to replace the summaries and as these are received the summaries will be replaced. Permission to publish received after the standard has been approved will be retained for the next SP0169 revision/review. The corrosion control practitioner should be aware of all local applicable standards and regulations for the facilities of concern.

AUSTRALIAN

There is an Australian Standard, AS/NZS 2832.1,117 which is titled "Cathodic Protection of Metals Part 1: Pipes and Cables." The following is a summary of Section 2, Criteria for Cathodic Protection:

• When operators use cathodic protection criteria, they should seek the advice of a cathodic protection specialist to make sure that the criteria are applied correctly.

• For ferrous structures, the criterion for protection is equal to or more negative than —850 mV CSE measured by an instant-off (for clarification: near IR free) method.


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• For copper/copper alloy structures, the criterion for protection is equal to or more negative than —300 mV CSE.

• For lead structures, the criterion for protection is equal to or more negative than —650 mV CSE, if the structure is in aerated soils. When conditions are anaerobic, the criterion for protection is equal to or more negative than —800 mV CSE.

• For mixed-metal structures, the criterion for protection requires that the potential be maintained on all parts of the structure based on the protection requirements for the most anodic metal.

• AS/NZS 2832.1 describes the requirements for structures that are subject to traction or telluric current.

• The 100 mV criterion maintains that an instant off-potential on all parts of the structure must be 100 mV or more negative than the depolarized potential.

• Coupons may be used as an alternate criterion. The instant-off potential must be equal to or greater than —850 mV CSE or 100 mV or more negative than the depolarized potential.

• Resistance probes may be used as an alternate criterion, given that the corrosion rate of the resistance probe is less than 5 pm/y (0.2 mpy), and the instant-off potential must be equal to or greater than —850 mV CSE or 100 mV or more negative than the depolarized potential.

• Other criteria may be used if the user can demonstrate their validity.

• Overprotection can occur if the instant-off potential for ferrous, lead, copper, and copper-alloy structures exceeds —1.2 V.

• AS/NZS 4352118 describes testing to determine the coating resistance to cathodic disbonding.

BRITISH

The 1991 edition of British Standard BS 7361,118 "Cathodic protection, Part 1. Code of practice for land and marine applications," presents CP in Section 2.3.2, Cathodic protection criteria. A summary of this standard is as follows:

Cathodic protection is achieved by bringing metals to certain protection potentials. The protection potentials are listed in Table 1, and corrosion can occur in values more positive than these. These values are, for iron and steel, —850 mV CSE in aerobic conditions and —950 mV CSE in anaerobic conditions.

Potentials can vary considerably over the surface of a metal, so it is important to ensure that the least negative metal soil potential is located when measurements are taken.

• Measurement of the potential difference between the metal surface and electrolyte can be affected by the potential drop that is produced by the protection current (IR drop). The values given in Table 1 might not provide full protection against corrosion, unless measurement methods to eliminate or reduce the effects of IR drop are undertaken. The instant-off potential method has gained acceptance as a method of minimizing IR drop error, although any technique that can be shown to reduce IR drop error may be used.

• Special considerations are discussed in Paragraphs 2.3.2.2 and 2.3.2.6 of BS 7361.

• A more negative potential is recommended for irons and steels that are installed in anaerobic conditions in which sulfate-reducing bacteria (SRB)s might be present.

• Hydrogen blistering and a loss of mechanical strength can occur in stainless steels that are polarized to excessively negative potentials. Stainless steels typically do not need protection in many environments, but in some cases, anodic protection is used.

• Crevice corrosion is common in stainless steel. Cathodic protection significantly reduces the occurrence or severity of crevice corrosion. It is important to note that stainless steel can become more susceptible to crevice corrosion if cathodic protection is administered for some time, and then is disconnected.


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• Concrete-encased steel that is free from chlorides normally does not require cathodic protection, but if the steel is only partially encased, the protection potential depends on the part that is exposed to the soil or water.

• Aluminum is not normally included in cathodic protection systems, because it is susceptible to corrosion if the potential is too negative.

• Lead occasionally corrodes at very negative potentials in alkaline environments.

This standard is was withdrawn as of August 2, 2013, and replaced by BS EN 13635:2004 and BS EN 15112:2006 according to the BSI Web site. It is accepted that the criteria in ISO 15589-1/EN 14919-1120 and EN 12954 are more precise, up to date, and more appropriate than those in BS 7361. The European standards are known as BS EN in Britain and are published as such by BSI.

CANADIAN

The applicable Canadian standard is Recommended Practice for the Control of Extemal Corrosion on Buried or Submerged Metallic Piping Systems, OCC-1,121 published by the Canadian Gas Association. Appendix B addresses the criteria for CP. A summary of this appendix is as follows:

• For steel and cast or ductile iron piping, the negative polarized (instant off) potential shall be at least 850 mV CSE. The on-potential should be at least negative 850 mV CSE, but should account for voltage (IR) drop and a number of factors to consider are listed. The other criterion is a minimum of 100 mV of cathodic polarization between the structure and a reference electrode that contains the electrolyte as it is measured by the formation or decay of polarization.

• For copper and aluminum piping, the 100 mV cathodic polarization criterion applies. However, polarized potentials that are more negative than —1,200 mV can result in corrosion for aluminum piping.

• Dissimilar metal piping requires that the polarized potential be maintained on all surfaces of the structure based on the protection requirements for the most anodic metal.

• The presence of SRBs, elevated temperatures, acidic environments, and dissimilar metals can cause the first criterion (the polarized [instant off] potential shall be at least negative 850 mV CSE) and second criterion (the on-potential should be at least negative 850 mV CSE, but should account for voltage [IR] drop) to be insufficiently electronegative.

• Concrete, dry, or aerated soils are environmental conditions in which it might be acceptable for the values to be more electropositive.

Stray current and stray electrical gradient situations require that different criteria be used than those mentioned in Appendix B of OCC-1.

Operators should account for voltage (IR) drop between the structure and reference electrode, IR drop in the pipe steel and the lead wire (during close-interval potential surveys), presence of dissimilar metals, influence of risers, stray and telluric current, and proximity to anodes when they interpret potential measurements in relation to the criteria mentioned in Appendix B of OCC-1.

• Aluminum and other amphoteric materials can be damaged by high alkalinity created by cathodic protection. They should be electrically isolated and separately protected.

• Saturated copper-copper sulfate reference electrodes can be substituted by other saturated reference electrodes, provided that the voltage equivalent can be established and its stability can be ensured.

EUROPEAN

ISO 15589-1, titled "Petroleum and natural gas industries - Cathodic protection for pipeline transportation systems—Part 1: On-land pipelines," is now also EN 14919-1 (with minor modifications that do not affect the summary of criteria given under the "International" heading). It is applicable to petroleum and natural gas pipelines in all European countries. There is an initiative within CEN and ISO to consolidate EN 14919-1 and EN 12954 into a single common document for all pipelines.

EN 12954: 2001 was prepared by CEN TC 219 WG1 and is applicable to all pipeline categories (including petroleum and natural gas) in all European countries. A summary of this standard is as follows:


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• The criterion for cathodic protection is E Ep, where Ep is the metal-to-electrolyte potential at which the corrosion rate is < 0.01 mm/y (0.04 mpy).

• In the case of metals that are subject to corrosion damage at very negative potentials, the criterion for cathodic protection is El E Ep, in which the potential shall not be more negative than a limiting critical potential (E 1 ).

• Table 1 of EN 12954 lists the protection potentials of the most common metals.

• The protection criteria are identical to those in ISO 15589-1/EN 14919-1 and all potential criteria are defined as IR free.

GERMAN

A translation of the German Standard DIN 30 676122 of October 1985, titled "Design and application of cathodic protection of external surfaces," discusses CP criteria in Sections 3 and 4. A summary of these sections is as follows:

• The criterion for cathodic protection is U Us, where U is the potential of the material, and Us is the protective potential.

• In some cases, corrosion damage occurs in materials at very negative potentials. In these cases, the potential range is limited by a threshold potential, U's, and the criterion for protection is as follows: U's U Us

• The protective potentials for the most commonly used materials are shown in Table 1 of DIN 30 676.

• More criteria related to relative potential changes is available in the Handbuch des kathodischen Korrosionsschutzes (Cathodic Protection Handbook).123

• It is difficult to distinguish between anaerobic and aerobic soils, and because of this, the standard recommends trying to use a protective potential of —0.95 V when laying new pipelines.

• Thin coatings can be affected by blistering. In order to minimize this problem, DIN 50 928124 states that the protective potential range should be limited as the function of the coating.

• DIN 50 918125 describes prerequisites for applying potential criterion. Voltage drop can affect potential measurements. Voltage drop can be caused by cathodic protection currents, cell currents, stray currents (from DC systems), or equalizing currents that flow between different parts of the surface that have different polarities after the current has been switched off.

• Additional protection potentials can be found in DIN 50 927.126

• DIN VDE 0150127 describes the methods of measurement of a structure-to-electrolyte potential.

It is understood that all of these DIN standards have now been withdrawn and replaced with the ENs discussed in the European section.

INTERNATIONAL ORGANIZATION FOR STANDARDIZATION (ISO)

An International Standard, ISO 15589-1, titled "Petroleum and natural gas industries - Cathodic protection for pipeline transportation systems—Part 1: On-land pipelines," was first published in 2003. It has been prepared by ISO/TC 67/SC 2/WG 11, which is the working group devoted to CP for pipelines used in the oil and gas industry. The following is a summary of Sections 5.3.2, Protection criteria, and 5.3.3, Measurements of protection potentials. Although it is only specifically stated in the standard that reference potentials are in respect of the —850 mV CSE protection criterion, it is clear that the intent of the ISO standard is that all referenced potentials are IR free.

In CP systems, all parts of buried pipelines should have polarized potentials more negative than —850 mV CSE. These potentials exist at the metal-to-electrolyte interface, such as the polarized potentials. Polarized potentials are defined in 3.15 and are synonymous with IR-free potential, as well as being structure-to-electrolyte potentials measured without the voltage error caused by IR drop from protection current or any other current.

The critical potential should not be more negative than —1,200 mV CSE to avoid detrimental effects at the metal surface.


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• Stainless steel and other corrosion-resistant alloys typically need to have a potential value that is more positive than — 850 mV CSE, but for most practical applications, —850 mV CSE can be used.

• For pipelines in anaerobic soils in which there are significant quantities of SRBs, the potential should be more negative than —950 mV CSE.

• For pipelines in high-resistivity soils, a protection potential that is more positive than —850 mV CSE may be considered.

• A minimum of 100 mV cathodic polarization between the surface of a pipeline and the reference electrode in contact with the electrolyte may be considered as an alternative to the protection potentials mentioned above. The method of determination is defined.

Use of the 100 mV criterion shall be avoided on pipelines that operate at high temperatures, consist of or are connected to mixed-metal components, are in soils that contain SRBs, or with interference, equalizing, and telluric currents.

• In some cases, pipelines can be afflicted with high pH SCC in the IR free potential range —650 mV to —750 mV. When protective potentials more positive than —850 mV CSE are used, this shall be taken into consideration.

• When the pipeline is electrically continuous and contains components from metals more noble than carbon steel, care should be exercised in the consideration of the protection criteria.

• Pipelines that operate above 40 °C (104 °F) might not be adequately protected by the above values. In these cases, alterative criteria may be used.

• Other reference electrodes may be used for the various criteria, provided that they have reliable properties and can be documented.

• The measurement techniques are defined.

JAPANESE

Three documents from Japan were reviewed, and the information regarding CP criteria was translated:

(1) Japan Water Pipeline Association, WSP 050-95,128 Section 5-1 (1), states that cathodic protection potential shall be at least —850 mV CSE.

(2) High Pressure Institute of Japan, HPIS G105-1989,129 Section 4.5.2, states that cathodic protection potential shall be at least —850 mV CSE. The criterion for using a saturated calomel electrode is —0.77 V, and the potential for using a zinc electrode is —0.25 V.

(3) Japan Fire Bureau Regulations, Detailed Technical Criteria for Hazardous Materials, dated May 31, 2000,139 states that cathodic protection potential shall be at least —850 mV CSE. —0.77 V is the criterion for using a saturated calomel electrode, and the piping may be affected by stray current, so that current drainage points shall be established.

RUSSIAN

The National Standard of the Russian Federation, GOST 51164-98,131 is titled "Main Steel Pipelines, General Requirements for Protection Against Corrosion." CP criteria are addressed in Section 5, Requirements for Electrolytic Protection. A summary of this section is as follows:

• For soils with (a) specific resistance ~ 10 D•m, (b) water soluble salts content 5. 1 g for 1 kg soil, or (c) if the transported product is < 293 K (20 °C [68 '9), the minimal protective potential relative to saturated Cu/CuSO4 reference electrode is —0.85 V (polarization only), or —0.90 V (with ohmic component).

• Tables 4 and 5 in GOST 51164 show the minimal protective potential relative to saturated Cu/CuSO4 reference electrode for pipelines in other conditions.

• Polarization potentials with no ohmic components shall only be provided for new pipelines and rehabilitated pipelines.

Russia is an active member of ISO, and ISO 15589-1 may be increasingly used.


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UNITED STATES OF AMERICA

Cathodic protection requirements for natural gas pipelines are contained in 49 CFR Part 192,132Appendix D, as follows:

• Criteria for cathodic protection of steel, cast-iron, and ductile-iron structures:

(a) a negative (cathodic) voltage of at least —0.85 volt with reference to a saturated copper-copper sulfate half- cell Protective current is applied in accordance with the sections on "Interpretation of Voltage Measurement" and "Reference Half Cells" of Appendix D of 49 CFR Part 192, which are summarized below:

(b) a negative (cathodic) polarization voltage shift of 100 mV, which is determined in accordance with the sections on "Determination of Polarization Voltage Shift" and "Reference Half Celle of Appendix D of 49 CFR Part 192, which are summarized below;

(c) a voltage that is at least as negative (cathodic) as that which was established at the beginning of the Tafel segment of the E-log-I curve, and this voltage shall be measured in accordance with the sections on "Determination of Polarization Voltage Shift" and "Reference Half Celle of Appendix D of 49 CFR Part 192, which are summarized below;

(d) a minimum negative (cathodic) voltage shift of 300 mV, which is produced by the application of protective current, and the voltage shift must be determined in accordance with the sections on "Interpretation of Voltage Measurement" and "Reference Half Celle of Appendix D of 49 CFR Part 192, which are summarized below. This criterion of voltage shift applies to structures that are not in contact with metals that have different anodic potentials;

(e) a net protective current from the electrolyte into the structure that is measured by an earth current technique. This is applied at predetermined current discharge points (anodic) of the structure.

• Criteria for cathodic protection of aluminum structures:

(a) A minimum negative (cathodic) voltage shift of 150 mV, which is produced by the application of protective current, and the voltage shift must be determined in accordance with the sections on "Interpretation of Voltage Measurement" and "Reference Half Cells" of Appendix D of 49 CFR Part 192, which are summarized below. The exceptions to (a) are provided in subpoints (c) and (d);

(b) A minimum negative (cathodic) voltage shift of 100 mV, which must be determined in accordance with Sections III and IV of Appendix D of 49 CFR Part 192. The exceptions to (b) are provided in subpoints (c) and (d);

(c) Notwithstanding the alternative minimum criteria listed in subpoints (a) and (b), if aluminum is cathodically protected at voltages greater than 1.20 V as measured with reference to a copper-copper sulfate half-cell (in accordance the section on "Reference Half Celle of Appendix D of 49 CFR Part 192, which is summarized below) and is compensated for voltage drops other than those across the structure-to-electrolyte boundary, it may experience corrosion that results from the build-up of alkali on the metal surface. Unless previous test results indicate that no appreciable corrosion will occur in the particular environment, voltage greater than 1.20 V may not be used;

(d) Careful investigation/testing must be made before CP is applied to stop pitting attacks on aluminum structures in environments with a natural pH greater than 8 because aluminum may suffer from corrosion under high-pH conditions and because application of CP has a tendency to increase the pH at the metal surface.

• Criteria for cathodic protection of copper structures:

(a) a minimum negative (cathodic) polarization voltage shift of 100 mV, which is determined in accordance with the sections on "Determination of Polarization Voltage Shift" and "Reference Half Celle of Appendix D of 49 CFR Part 192, which are summarized below;

• Criteria for cathodic protection of metals with different anodic potentials:


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(a) A negative (cathodic) voltage that is equal to that which is required for the most anodic metal in the system must be maintained. The negative (cathodic) voltage must be measured in accordance with the section on "Reference Half Cells" of Appendix D of 49 CFR Part 192, which is summarized below;

(b) Amphoteric structures that could be damaged by high alkalinity (see subpoints (b) and (c) under the section "Criteria for Cathodic Protection of Aluminum Structures") must be electrically isolated with insulating flanges or the equivalent.

• Interpretation of voltage measurement in 49 CFR Part 192, Appendix D is as follows:

(a) Voltage (IR) drops other than those across the structure electrolyte boundary must be considered for valid interpretation of the voltage measurement, according to subpoints (a) and (b) of the section on "Criteria for Cathodic Protection of Steel, Cast-Iron, and Ductile-lron Structures," and subpoint (a) of the section on "Criteria for Cathodic Protection of Aluminum Structures."

• Determination of polarization voltage shift in 49 CFR Part 192, Appendix D is as follows:

(a) The polarization voltage shift must be determined by interrupting the protective current and measuring the polarization decay. When the current is initially interrupted, an immediate voltage shift occurs, and the voltage reading after the immediate shift must be used as the base reading from which to measure polarization decay, as specified in subpoint (c) of the section on "Criteria for Cathodic Protection of Steel, Cast-Iron, and Ductile-Iron Structures," subpoint (b) of the section on "Criteria for Cathodic Protection of Aluminum Structures," and the section on "Criteria for the Cathodic Protection of Copper Structures."

The following section covers reference half-cells:

(a) Except as provided in the section on "Criteria for Cathodic Protection of Aluminum Structures," and the section on "Criteria for the Cathodic Protection of Copper Structures," negative (cathodic) voltage must be measured between the structure surface and a saturated copper-copper sulfate half-cell that are in contact with the electrolyte;

(b) Other standard reference half-cells can be substituted for the saturated copper-copper sulfate half-cell, and two commonly used reference half-cells are as follow, as well as their voltage equivalents:

(i) Saturated KC1 calomel half-cell: —0.78 V;

(ii) Silver-silver chloride half-cell used in seawater: —0.80 V.

(c) An altemate metallic material or structure may be used, in addition to the standard reference half-cells. The altemate metallic material or structure may be used if its potential stability is assured as well as if its voltage equivalent referred to a saturated copper-copper sulfate half-cell is established.

• Cathodic protection requirements for hazardous liquid pipelines are contained in 49 CFR Part 195,133 Subpart H, as follows:

(a) Cathodic protection must comply with one or more applicable criteria and other considerations for CP that are contained in NACE Standard RP0169 (2002 edition), "Control of External Corrosion on Underground or Submerged Metallic Piping Systems," Paragraphs 6.2 and 6.3.


000273

Andrew Hevle - Invoice INV-771203-3VOPV2, downloaded on 3/9/2014 2:10PM - Single-user license only, copying/networking prohibited.

ISBN

1-5

7590- 0

35-1

NA

CE

Inte

rnat

ion

al

Andrew Hevle - Invoice INV-771203-3VOPV2, downloaded on 3/9/2014 2:10PM - Single-user license only, copying/networking prohibited.

SP

0169

-20

13

Exhibit F

000276

Paper No.

04210 CORROSION2004

Testing and Mitigation of AC Corrosion on 8" Line: A Field Study

Roger Floyd Manager of Pipeline Integrity Koch Pipeline Company L.P.

P.O. Box 29 Medford, Oklahoma 73759

ABSTRACT

Induced Alternating Current on buried pipelines is not new, but the corrosive action of this current on the pipeline is not well known or well documented. Little information is available on how to identify the effects of induced A/C and then develop a program to mitigate the current to acceptable levels. There is also little documentation on how to provide a monitoring system to insure the continued mitigation.

This paper is an attempt to inform the pipeline community of the possibility of AC corrosion on select lines. By conducting various field and laboratory tests, the pipeline company has identified A/C corrosion as the reason for a release in Rockwall County Texas. This paper outlines those tests, their results, the mitigation program developed to remedy the problem, and the monitoring program implemented to insure that the integrity of the system is being maintained.

Keywords: Alternating Current, Anomaly Investigation, MIC, Coupon, A/C corrosion, A/C corrosion rate, Zinc grounding cell.

INTRODUCTION

On August 29,2002 Koch Pipeline Company L.P. (Koch) experienced an in-service leak on a section of a liquid butane pipeline in Rockwall County Texas. The pipeline is an 8-inch diameter by 0.188-inch (4.7mm) nominal wall thickness, API 5L X52 pipe and was installed in 1999. The external coating on the line is a mill applied fusion bonded epoxy at a nominal 16 mil (.4mm) thickness. The girth welds are coated with heat shrink sleeves. Cathodic protection is supplied by impressed current deep anode systems.

The leak resulted from an external corrosion pit containing a through-wall pinhole penetration. The outside dimensions of the corrosion pit were approximately 1-inch by 2-inch (25mmx5Omm).

This paper presents the results and conclusions of analyses of the tasks performed to identify and mitigate this problem. The paper contains the findings and recommendations related to the following activities:

1. Anomaly Investigations 2. Data Review and Analysis

Copyright ©2004 by NACE International. Requests for permission to publish this manuscript in any form, in part or in whole must be in writing to NACE International, Publications Division, 1440 South Creek Drive, Houston, Texas 77084-4906. The material presented and the views expressed in this paper are solely those of the author(s) and not necessanly endorsed by the Association. Pnnted in U.S.A.

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3. Initial Coupon Test Station Testing and Analysis.

ANOMALY INVESTIGATIONS

Koch performed an in-line inspection (ILI) using a magnetic flux leakage tool to detect and characterize corrosion caused metal loss on this section. Based upon the results of the inspection, several locations were identified for excavation and direct examination.

CC Technologies Services, Inc was retained by Koch to collect information during the excavations, to evaluate the effectiveness of the cathodic protection system, and to provide information as to the cause of the defects.

The testing performed at each excavation site consisted of:

• Visual observation of the pipe line right-of-way • Pipe-to-soil potential measurements • Soil resistivity measurements • Linear polarization resistance • Microbiological influenced corrosion (MIC) investigation • Supporting analysis

1. Qualitative testing (MICKit IV) for chemical species 2. Electrolyte pH 3. Pipe conditions 4. Coating conditions

Visual observation of the pipe line right-of-way:

The right-of-way was visually inspected for low areas and areas containing foreign structures including the support towers for the overhead high voltage A/C power lines.

Pipe-to-soil Potential Measurements:

Pipe to soil potentials were collected in the area of the anomaly in a clockwise orientation around the pipeline segment. These potential measurements were used to establish the presence of CP and stray electrical currents.

Soil Resistivity Measurements:

The soil resistivity was calculated from resistance measurements on soil samples that were collected at pipe depth during the excavation. Resistance measurements were made using the Wenner Four Electrode Method (ASTM Standard G57-78) and a manufactured soil test box with 4 electrodes.

Once the resistivity was determined, the calculated resistivities were analyzed to determine the relative corrosivity of the environment and the design requirements for any proposed cathodic protection. The following is a general guideline used for determining corrosivity of soils and water.

Resistivity Classification <500 ohm-cm Extremely Corrosive 500 to 1,000 ohm-cm Very Corrosive 1,000 to 10,000 ohm-cm Corrosive 10,000 to 20,000 ohm-cm Mildly Corrosive >20,000 ohm-cm Progressively Less Corrosive

2 000278

Linear Polarization Resistance Measurement:

This technique involves the application of a small DC polarization at a specified rate. The polarization resistance is defined as the slope at Ecorr of the resulting linear plot of voltage vs. current density.

The test was carried out using a specifically designated Polarization Resistance Monitor PR4500, which automates the measurement and data processing.

Microbiological Influenced Corrosion Investigation:

In order to characterize any observed corrosion and determine if the corrosion was the result of bacteria, the following procedures were utilized at each excavation site.

Before excavation of the pipeline, the topography of the surrounding area of the dig site and the soil type was noted. This information was useful in assessing the likely conditions that support various types of bacteria.

Soil was carefully removed from the pipe surface to expose the metal surface, without removing any products adhering to the pipe surface. The following were noted during the pipe examination:

1. Coating type (e.g., coal tar, asphalt, bitumen, tape), type of damage (e.g. disbonding, holidays, blistering, seam tenting, cracking, and wrinkling), extent of damage (% of exposed area), and location (circumferential and longitudinal position on pipe in relation to weld seams and coating seams, if present).

2. Corrosion and/or CP surface products present 3. Location (see above) 4. Type (e.g., deposit, nodule or films). 5. Color (e.g., brown, black, white or gray). 6. Smell (e.g. none, earth, rotten eggs). 7. Soil Type (e.g., sand, gravel, silt, clay, rock). 8. Soil moisture (e.g., wet, dry).

Once the pipe was exposed, the soil and any suspected deposits were sampled and, if possible, tested immediately. The deposits around the suspected area of corrosion were carefully removed using a knife. Sample contamination was kept to a minimum.

A minimum of three samples were collected at each excavation. Two samples were taken from one or more of the following locations (where applicable):

• Undisturbed soil immediately next to the exposed pipe steel surface or at an area of coating damage. • A deposit associated with visual evidence of pipe corrosion. • A scale of biofilm on the steel surface or the backside of the coating if present. • Liquid trapped behind the coating.

Additional samples were taken from fresh, undisturbed soil at pipe depth at least I m transverse to the pipe at both upstream and downstream ends of the excavation. These locations were used as references from which to determine if the bacteria count near the pipe was elevated.

The soil, film, or liquid samples were tested using a MICkit III or MICkit V. The samples were labeled and tested as per the detailed procedures outlined in the MICkit. Each MICkit III or MICkit V tests for the presence and count (bacterium/nil) of four or five types of viable bacteria. The bacteria tested in the MICkit III are:

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• Sulfate reducing bacteria (BIO-SRB) • Acid producing bacteria (BIO-APB) • Aerobic bacteria (BIO-AERO) • Anaerobic facultative bacteria (BIO-THIO)

The bacteria tested by the MICkit V are: • Sulfate reducing bacteria (BIO-SRB) • Acid producing bacteria (BIO-APB) • Aerobic bacteria (BIO-AERO) • Iron-related (depositing) bacteria (BIO-IRB) • Low-nutrient bacteria (BIO-LNB)

The presence and viability of these four or five types of bacteria were tested in each of the four or five colored strings of bottles in each tray. The bottles in each string contained a fast acting nutrient specific to the bacterium tested. For MICkit III, the tests gave a quantitative indication of the viability of each bacterium from 10 to 105 bacterium/ml by the serial dilution of the sample and subsequent growth in each string; MICkit V gave a quantitative indication from 10 to 104 bacterium/ml.

Supporting Analyses:

Corrosion and other types of deposits on the pipe were analyzed in the field using the MICkit IV to assist in interpretation of MIC and other corrosion or CP products. The kit was used to quantitatively analyze for the presence of carbonate (CO3+2), sulfide (S-2), ferrous iron (Fe +2), ferric iron (Fe+3 ) , calcium (Ca+2), and hydrogen (H-", pH) ions.

The deposits were compared to the characteristics shown below to assess whether the product was indicative of corrosion or CP.

Positive Result

SRB Corrosion Film

Corrosion Oxide

CP Film

CO3-2 Yes Yes

S-2 Yes

Fe+2 Yes Yes Yes

Fe+3 Yes Yes

Ca+2 Yes

pH Elevated

The pH of the electrolyte at the pipe surface and in corrosion pits was tested using hydrion paper. If a coating was present, the coating was carefully sliced to a length to allow the test paper to be slipped behind the coating. The coating was pressed against the pH paper for a few seconds and the pH paper removed. The color of the paper, in relation to the chart provided with the paper, was noted and recorded. Where possible, the pH of groundwater away from the pipe in the ditch was determined for a reference. The two pH values were compared to determine if the pH near the pipe was elevated. An elevated pH indicates the presence of CP current reaching the pipe. A

4 000280

pH above 9 would be considered elevated for most soils. It is not uncommon to measure a pH of 12 to 14 at the pipe surface for coated steel adequately protected by CP systems. In an active corrosion pit, the pH typically is in the acidic range.

The surface of the pipe was also inspected for corrosion. Where possible, a pit gauge was used to measure the depth of the corrosion. The length of the corrosion area was also measured in the circumferential and longitudinal directions.

ANOMALY INVESTIGATION RESULTS

Several areas were excavated and the anomalies in the pipe evaluated using the above detailed examination. The findings are summarized below:

These sites consisted of flat terrain. Initial observations revealed a soil profile consisting of three distinct layers. The top layer, the organic layer, was very thin (about 6 inches). The second layer, (going down in depth) consisted of a ten-foot layer of black moist clay material. The third layer, which encased the pipeline two feet above and below, consisted of a brown moist clay soil with little to no gravel in the soil matrix. The soil samples were tested for soluble cations, soluble anions, moisture content, MIC, electrical resistivity, pH and conosion rate (using linear polarization resistance). The results are shown in Table 1. The soils can be classified as clay with high moisture content, rich in bacteria and falling into a category of highly corrosive.

Initial observations of the area surrounding the anomaly revealed a black granular deposit approximately two inches in diameter located at the 12 o'clock orientation. This deposit was collected and used to determine the detection of problem causing bacteria involved in microbiological influenced corrosion. On site qualitative testing for chemical species within the corrosion product produced the following results:

pH >10 Carbonate (CO3) Positive Sulfide (S) Negative Ferrous Iron (Fe2) Positive Fenic Iron (Fe3) Positive Calcium (Ca2) Negative

The presence of an elevated pH and a positive reaction to carbonate indicate the presence of cathodic protection. The positive tests for ferrous and ferric ions however, and the corrosion anomaly itself, indicate that either the cathodic protection film formed after the corrosion had occurred or another con-osion mechanism is contributing to the problem. No sulfides (often observed in corrosion products resulting from MIC corrosion) were found.

Inspection of the defects revealed an isolated smooth round corrosion morphology that was uncharacteristic of either microbial influenced corrosion or conventional direct stray current corrosion. A corrosion rate of 60 mils (1.5mm)per year (mpy) in the presence of cathodic protection can not be easily explained, absent some accelerating factor such as MIC or stray current interference. Testing of the corrosion products showed no evidence of any bacteria related by-products and the corrosion morphology was not typical of these bacteria related corrosion mechanisms.

In DC stray current interference, the conosion products are soluble due to the low pH at the discharge location and the pitting is generally found to be free of corrosion products. In the observations made during this study the corrosion products were present in the pits and the pH was found to be indicative of effective CP. These discrepancies led to the possibility of a non-traditional corrosion mechanism such as AC corrosion.

5 000281

DATA REVIEW AND ANALYSIS

The available information related to the operation of the cathodic protection system, the results of the in line inspection and the physical characteristics of the right-of-way were reviewed. This information was used to identify physical or operational factors that possibly contribute to the observed corrosion.

A review of the annual survey data, bimonthly rectifier readings and an On/Off close interval survey data show apparent satisfaction of industry criteria for effective corrosion mitigation. Nothing in the review of the CP history suggests a plausible explanation for the rapid rate of corrosion experienced on this pipeline. In addition, the records indicate that the cathodic protection rectifiers have been maintained in continuous operation and that, where necessary, repairs to rectifier components have been carried out in a timely manner to minimize rectifier outages.

Various attempts were made at correlating anomaly location, close interval survey data, and the physical location of the power lines, especially in the areas where HVAC lines and pipelines shared the right-of-way. A plot was developed and overlays measured pipe-to-soil AC potentials with the number of ILI corrosion anomalies per linear foot of pipe in a given segment. Twenty-seven external coupon stations were installed on the pipeline, at one-mile intervals, to measure the DC potentials, AC potentials and current densities. The plot of the AC potentials and defects are shown in Figure 1.

This data indicate that the highest population of ILI corrosion anomalies are located in the first five miles where the AC potentials typically exceeded 4.0V.

INITIAL COUPON TEST STATION TESTING AND ANALYSIS

Coupon test stations provide an alternative to conventional off-potential measurement for evaluating the effectiveness of a CP system. The concept involves the burial of a bare coupon near the pipe surface, with the coupon normally shorted to the pipe through the test station. In this manner, it is expected that the coupon will be polarized to a similar potential as a holiday of similar surface area. To make a potential measurement locally at the coupon surface, a plastic tube is installed to within 0.5 inch of the top of the coupon. The reference tube is filled with soil to insure that the oxygen diffusion to the coupon surface is similar to that of the pipe. By placing the reference tube very near the coupon, the IR-drop in the coupon to soil potential measurement is minimized. The coupon can be interrupted by breaking the connection between the coupon and the pipe, thereby interrupting all of the CP current to the coupon.

Measurements typically made with coupon test stations include the off-potential of the polarized coupon, the on-potential of the pipe measured through the reference tube, current to (or from) the coupon and polarization formation or decay. In addition to these standard cathodic protection related measurements, the coupons also permit the measurement of AC potential and AC current density. While AC potentials can be recorded with respect to operating pipelines, it is impossible (without the use of a coupon or similar device) to directly measure the amount of AC current flowing to and from a holiday on the pipe surface. The coupon test stations provide the necessary data to assess the likelihood that AC interference is contributing to the observed corrosion.

AC corrosion on buried or submerged structures is not a well-understood phenomenon. Recently, AC corrosion and its mitigation have produced and increased concern among pipeline operators. This is typically focused on the safety of operators or others that might come in contact with structures, not with corrosion. Studies performed in the 1950-60s indicated that the AC corrosion rate of steel is low and it is in the range of 0.1 to 1 percent of a like amount of DC current'. In 1986 a corrosion failure on a high-pressure gas pipeline in Germany indicated that the root cause of the failure was AC corrosion2. This corrosion failure initiated numerous field and laboratory research and testing programs to assess the nature of the AC corrosion problem. One of the core findings of the

6 000282

original AC corrosion studies and the most recent work on AC corrosion is that for AC to have a noticeable effect on the corrosion rate, AC current densities must be very high.3 The following general statement has been developed from recent studies. • AC Current Density <20A/m2-No AC induced Corrosion • AC Current Density >20A/m2 but <100A/m2 — Corrosion is unpredictable and influenced by many

environmental factors • AC Current Density >100A/m2 —AC Corrosion likely to occur

This data implies (and is supported by numerous case studies) that AC corrosion is most likely to occur only on well-coated structures where the AC current is shown to transfer from very small holidays in the coating, thereby reaching the excessive current densities listed above.

Following the installation of the coupon test stations, initial measurements and close interval survey data was collected at each station. The pertinent data collected at the four stations in the most effected area are listed in Table 2 and discussed in detail by site below.

Nevada Booster Station The Nevada Booster Station CTS is located adjacent to the perimeter fence over the line heading south from the station. At this location measurements on both the pipe and coupon indicated that from a cathodic protection standpoint, the piping is well protected with off-potentials of —1.291VCSE and —1.265VCSE on the pipe and coupon respectively. The native (un-polarized coupon) at this site had a free corrosion potential of — 0.858VCSE. The close interval survey collected upstream and downstream of the coupon test station is presented in Figure 2 and shows adequate DC potentials and generally flat (neither increasing or decreasing) AC potentials. The coupon was also collecting DC current from the CP system at a current density of 3.00A/m2. The AC potential recorded at this site was 1.73V and the coupon was found to have an AC current density of 23.68A/m2.

Rustic Meadows This CTS is located one mile south of Nevada Booster. At this location measurements on both the pipe and coupon indicated that from a cathodic protection standpoint, the piping is well protected with off-potentials of — 1.242VCSE and —1.173VCSE on the pipe and coupon respectively. The native (un-polarized coupon) at this site had a free corrosion potential of —0.868VCSE. The close interval survey data collected upstream and downstream of the coupon test station is Figure 3 and shows adequate DC potentials and increasing AC potentials as the survey proceeded south toward the Highway 66 test station. The coupon was also collecting DC current from the CP system at a current density of 8.32A/m2. The AC potential recorded at this site was 9.7V and the coupon was found to have an AC current density of 239.08A/m2.

Highway 66 The Highway 66 CTS was installed on the North end of the Highway 66 crossing, across the street from the electric power substation. At this location measurements on both the pipe and coupon indicated that from a cathodic protection standpoint, the piping is well protected with off-potentials of —1.230VCSE and —1.056VCSE on the pipe and coupon respectively. The native (un-polarized coupon) at this site had a free corrosion potential of —0.832VCSE. The close interval survey data collected upstream and downstream of the coupon test station is presented in Figure 4 and shows adequate DC potentials and a generally flat (neither increasing or decreasing) AC potential profile of nearly eight to ten volts (zinc grounding cells on versus grounding cells off).

The coupon was also collecting a high DC current density from the CP system at 4.80A/m2. The A/C potential recorded at this site was 9.30V and the coupon AC current density was found to be 144.13Vm2.

Parker Road The Parker Road CTS was installed on the North side of the Parker Road crossing. At this location measurements on both the pipe and the coupon indicated that from a cathodic protection standpoint, the location is well protected

7 000283

with off-potentials of —1.224VCSE and —1.220VCSE on the pipe and coupon respectively. The native (un-polarized coupon) at this site had a free corrosion potential of —0.806VCSE. The close interval survey data collected upstream and downstream of the coupon test station is presented in Figure 5 and shows adequate DC potentials and generally a flat AC voltage profile (neither increasing or decreasing).

The coupon was also collecting a high DC current density from the CP system at 3.42 A/m2. The AC potential recorded at this site was 5.50V and the coupon AC current density was found to be 113.31A/m2.

CORROSION MORPHOLOGY

Inspection of the corrosion pits on the failed piece of pipe and at the five anomaly investigations revealed an isolated smooth round corrosion morphology that was uncharacteristic of either microbial influenced corrosion or conventional direct current stray current corrosion. This is puzzling given the apparent rapid penetration of the pipeline at the leak site in a three-year period, which would equate to an annual corrosion rate in excess of 60 mils. A 60 mil per year (mpy) corrosion rate in the presence of cathodic protection cannot be easily explained, absent some accelerating factor such as MIC or stray current interference. All five anomaly locations investigated were found to be the result of external corrosion pitting with a similar morphology to that of the leak site. Corrosion products collected from four of the five locations were black, moist and granulated (paste) and the underlying pipe substrate was shinny. The depth of the five anomalies ranged from 53 mils (0.053 inches) to 120 mils (0.120 inches) and all were located in FBE coated pipe. The coating in the area surrounding the pits was brittle and had poor adhesion.

Samples of corrosion products from the anomalies were analyzed using energy dispersive spectroscopy (EDS) and were found to contain primarily iron. A typical EDS spectra of the corrosion products is shown in Figure 6.

AC CORROSION

AC current densities measured at the recently installed coupon test stations exceeded cited levels that typically produce corrosive effects. Table 2 summarizes the AC current densities observed at these locations. As shown, three of the sites tested have AC current densities in excess of the 100A/m2 threshold for likely corrosion effects. In fact, Rustic Meadows site had a current density of over twice the threshold amount. The Nevada Booster site showed the lowest AC current density from the coupon measurements though the value (23.7A/m2) is still within the range that could produce corrosive effects.

No information is currently available to allow for the calculation of a corrosion rate under the high levels of AC current discharge and under the high levels of cathodic protection observed on this line. Studies have shown that the effects of AC corrosion can be reduced or mitigated with effective CP but the studies do not adequately address a wide range of soil conditions or wide ranges of AC current discharge levels. CP criteria relating to the control of AC corrosion has recently been recommended in the German Standard DIN 50 925 which states that AC current densities should be maintained below 30 Ahn2.

At least one study has indicated that at AC current densities in excess of 70 A/m2, AC corrosion is probable despite a high level of cathodic protection. The development of a relationship between AC current discharge, corrosion and cathodic protection levels is very dependent upon the local environmental conditions and must be evaluated on a case-by-case basis. Utilizing the data collected from the coupon test stations; the relationship between the measured pipe-to-soil AC potential and the AC coupon current density can be plotted. This relationship is presented in Figure 7.

8 000284

MITIGATION METHODS

The installation of zinc grounding cells at selected locations on the pipeline was chosen as the best method to mitigate the AC currents on the pipe. The line had two existing zinc grounding cells, Nevada Booster and the railroad near the sub station. Table 3 summarizes the AC potential and AC current density relief provided while the cells are bonded to the structure. The reduction in AC potential is observed to be greatest at Highway 66, which is within approximately 600 feet of the railroad zinc cell installation. At the Highway 66 location the coupon AC current density was similarly reduced by over 22percent while the zinc cells were connected. It should be noted that little effects are recognized for the zinc cells installed at Nevada Booster. This is due to the fact that the cells at the booster station are installed across an insulating flange for the purpose of eliminating the chance of an AC arc across the insulator

CONCLUSIONS

The following conclusions have been drawn based upon review of the information available to date:

1. The excessive AC current densities observed on the coupon test stations and the physical and chemical analysis indicate that the likely cause of the observed corrosion anomalies is AC corrosion. This conclusion is supported by the correlation of higher defect occurrences within areas of higher AC potentials.

2. The cathodic protection system is and has been operating at levels which should be able to adequately protect the pipeline in the absence of severe AC current discharge(s)

3. The existing AC mitigation system (2 zinc grounding cells) reduces the AC potential to maintain safe step-and-touch potentials, but has not sufficiently reduced the AC current discharges (at the locations tested) to a level which would permit the CP system to overcome its detrimental effects. The installation of additional grounding cells will be required to mitigate the AC current discharges to acceptable levels.

4. The recently installed coupon test stations provide a means of measuring AC current.

CURRENT STATUS AND FUTURE PRACTICES

As of this date, 13 zinc grounding cells have been added to the system and 27 coupon test stations have been installed. These test stations are monitored on a monthly basis and the current densities have been reduced to levels below 100 A/m2. The test stations will continue to be monitored monthly for the next year.

A second in line inspection was conducted on the line in April with no new defects detected. Several existing defects were excavated and inspected with no significant change in the findings. Another inspection is scheduled for the end of the year.

A meeting has been set with the power company to review steps which can be taken to notify our company of any changes in the loads on the overhead AC lines and to inform them of our findings to date.

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TABLES Table 1: Soil Samples

Parameter Sample identification NC-02-11 NC-02-12 NC-02-13 NC-02-P1 NC-02-P3 NC-02-P3 9/11/02

Soil Color Black, Tan, Yellow, White

Black with sorne Tan

Yellow, Tan, some Black, Red

Tan, Gray, Yellow Tan, Black, Gray, Yellow Tan, Gray, Yellow

Soluble Cations (ppm)

Potassium

iron

Calcium Magnesium

Sodium

150 Min 200 Max 2 5 Min 7 5 Max

41 0

240

150 Mtn 200 Max 2 5 Min 7 5 Max

365 45

425

80 Min 90 Max

2 5 Min 62 5 Max

23 0

820

150 Mtn 200 Max 2 5 Mtn 7 5 Max

58 17

430

150 Min 200 Max 2 5 Min 7 5 Max

90 6

275

150 Min 200 Max 7 5 Min 25 Max

35 0

800

Soluble Anions (ppm)

Sulfates

Nitrates

Nantes

Chlondes Bicarbonates

Carbonates Sulfide

100 Min 250 Max

10 Min 20 Max

0 Min 1 Max 34

401 0 0

1000 Min 2000 Max

10 Min 20 Max

0 Min 1 Max 65

116 0 0

2000 Min Max

5 Min 10 Max 0 Min 1 Max 451 207 0 0

150 Min 200 Max 10 Min 20 Max 0 Min 1 Max

11 1172

0 0


84 431 0 0


10 843 180 0

MIC Analyses

Aerobic (col/mL)

Anaerobic (coVmL)

Acid-Producing (col/mL)

Sutfate-Reducing (col/mL)

lron-Related (col/mL)

10 Min 100 Max 4 Days 10 Min

100 Max 4 Days 10 Min

100 Max 4 Days

Min 0 Max

27 Days

10 Min 100 Max 4

Days 100 Min


1000 Max 4 Days

Min 0 Max

27 Days 0 Min 10 Max 4

Days

10 Min 100 Max 4

Days 10 Min

100 Max 4 Days

100 Min 1000 Max

4 Days Min


1000 Max 4 Days

10000 Min - Max 5 Days

10000 Min - Max 3

Days 10000 Min

- Max 3 Days 0 Min - Max

10 Days 10000 Min

- Max 10 Days

100 Min 1000 Max

3 Days 1000 Min


1000 Max 3 Days 0 Min - Max

10 Days 1000 Min

10000 Max 5 Days

10 Min 100 Max 3 Days 100 Min

1000 Max 3 Days

10000 Min - Max

10 Days 0 Min - Max

10 Days 10 Min

100 Max 3 Days

0 Min 10 Max 4 Days

Miscellaneous pH

Resistivity (as-received), ohm-cm Resistivity (saturated), ohm-cm

Moisture, % Corrosion Rate (mpy)

Corrosion Rate (mm/y) Ecor, mV CSE

Polanzation Resistance, ohm Solution Resistance, ohm

7 92 370 490

33 41 23 64 0 60

-765 0 105 274

7.74 340 340

27 26 33 43 0 85

-676 4 74

120

8 63 230 220

22 90 57 75 1 47

-665 2 43 82

7 97 490 500 32 2

12 27

-752.8

7 45 460 500 32 0 7 82

-784 6

11.17 450 570 28 4 7.98

-527 9

Potential Measurements VDC 12 00 position

3 00 position 6 00 poston 9 00 poston

-1 437 -1 42 -1 326 -1 438 -1 421 -1 326 -1 444 -1 421 -1 326 -1 446 -1 42 -1 33

Potential Measurements VAc 9 7 3 34 3 35

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Table 2: Summary of Pertinent Coupon Data

Lomlion chpm Fttelid Rpe Rietd - 03...pn With (rrA) Cagn 0..ffert Density OW) CCU-Ft:tete

(\k&CEE) PC Riertid (VAsCSE)

CCCff-Riertid (V-xe-CEE)

PC Rialid (VAs-CEE)

CC PC CC PC

Paige. Rped -122) 553 -1224 HO 3o2 lcao 342 11331

HgwytE6 154To+73 -1.0E6 9.33 -1.233 9.33 424 1272 480 144.13

Rstic Mieixis -1.173 9.70 -1242 9.70 7.34 211.0 a32 233.03

Nevate BzcstEr 15-412-ffi -1.235 1.73 -la 1.73 21E6 20.9 aco 2365

Table 3. Summary of Effects of Zinc Grounding Cells on AC Potentials and Current Density

Location Pipe AC Potential (VCSE) Coupon AC Current Density (A/m2) Zinc On Zinc Off Zinc On Zinc Off

Parker Road 5.6 6.4 113.3 130.3

Highway 66 15426+73 9.3 11.3 144.1 176.1

Rustic Meadows 9.7 10.8 239.1 269.7

Nevada Booster 15332+36 1.72 1.76 23.7 24.4

11 000287

—4—AC Potential

—et—Anomalies Per Foot

0 00

290 00 292 00 294 00 296.00 298 00 300 00 302 00 304 00 306 00 308 00

M Ile Post

0 310 00

14 00

12 00

10 00

L.) 8 00

.72

a e. 6 00

4 00

2 00

0 021

0 018

- 0 015

0 012

g

0 009 g •Ft

0 006

0 003

02

—•— DC (a) rc - —a— oc (ao Zrc —a— DC (an Zrc af —s— AC Zrc —a— AC Zrc af

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FIGURES

Figure 1:AC Potential and Defects

Figure2: Nevada Booster CIS

Wyatt lEboster Station (-I5322406)

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Distance (ft) Ws & d/s of coupon

12 000288

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1600

1400

1200

1000

800

600

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AC Zinc Off

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Figure 3: Rustic Meadows CIS

Rustic Meadows (-15412+09)

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13 000289

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Figure 4: Hwy 66 CIS

Hwy. 66 (-15427+09)

1600

-100 -90 -80 -70 -60 -50 -40 -30 -20 -10 0 10 20 30 40 50 60 70 80

Distance (ft) u/s & Ws of coupon

14 000290

—4,— DC (On) Zinc On —s— DC (Off) Zinc On —A—DC (On) Zinc Off —x— DC (Off) Zinc Off —)AC Zinc On —4.—AC Zinc Off

Figure 5: Parker Road

1450

1400

1150

1100

Parker Rd. (-15547+42)

-100 -90 -80 -70 -60 -50 -40 -30 -20 -10 0 10 20 30 40 50 60 70 80 90 1

Distance (ft) u/s & d/s of coupon

Pot

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1300

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15 000291

2.0 4.0 6.0 0.0 8.0 10.0

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16 000292

REFERENCES

1. M.Yumovich, N. Thompson, "AC Corrosion", PRCI project.

2. Kulman, F.E., "Effects of Alternating Currents in Causing Corrosion", Corrosion, Vol. 17, pp. 34-35, March 1961.

3. Williams, J.F., "Corrosion of Metals Under the Influence of Alternating Current", Materials Protection, Vol. 5, pp. 52-53, February, 1966.

4. Bruckner, W.H., "The Effects of 60 Cycle Alternating Current on the Corrosion of Steels and Other Metals Buried in Soils", University of Illinois Bulletin 470, November, 1964.

5. Prinz, W., Schoneich, H.G., "Alternating Current Corrosion of Cathodically Protected Pipelines", 1992 International Gas Research Conference, Volume 3, pp. 71-80, 1992.

6. Ragault, I., "AC Corrosion Induced by VHV Electrical Lines on Polyethylene Coated Steele Gas Pipelines", NACE Corrosion 98, Paper No. 557, 1998.

7. Pourbaix, A., Carpentiers, P., Gregor, R., "Detection and Assessment of Alternating Current Corrosion", Materials Performance, pp. 34-37, March 2000.

8. Wakelin, R.G., Gummow, R.A., Segall, S.M., "AC Corrosion — Case Histories, Test Procedures and Mitigatioe, NACE Corrosion 98, Paper No. 565, 1998.

17 000293

Exhibit G

000294

Paper No.

04206 CORROSION2004

AC CORROSION: CORROSION RATE AND MITIGATION REQUIREMENTS Mark Yunovich and Neil G. Thompson

CC Technologies Laboratories, Inc. 6141 Avery Road, Dublin OH 43016

ABSTRACT Despite the existing body of research data and some empirical evidence apparently implicating AC currents as deleterious to the buried pipelines, there remained a need to further investigate the issue, especially the conditions at which AC currents may pose a threat to underground structures and cathodic protection requirements needed to mitigate the possible adverse AC current effects. Of a particular interest were the following two issues: (1) the effect of AC current density on the corrosion rate and (2) cathodic polarization requirements necessary to mitigate the impact of AC current. This paper describes an extensive laboratory-based study of carbon steel specimens exposed to soils under the influence of AC and CP polarization. The primary conclusions are that AC corrosion may take place even at AC current densities considered 'safe'. To overcome the effects of the AC currents, the current needs to be mitigated first; mitigation of AC potentials to values below 15V may not be sufficient with respect to AC current densities at the coating holidays. Application of increased cathodic protection current (>150 mV of polarization) may be required to control AC corrosion.

Keywords: AC current density, corrosion rate, mitigation, AC corrosion

INTRODUCTION

The phenomenon of alternating current (AC)-enhanced corrosion has been considered by many authors since the early 1900s. However, for many years, corrosion experts did not regard corrosion due to alternating currents on metallic structures as a very important phenomenon. AC corrosion was not well understood for two reasons: (1) the electrochemical phenomena of corrosion are normally attributed to direct current; and (2) the instruments normally used to measure the electric parameters in direct currents can not correctly detect the presence of AC current with frequencies between 50 and 100 Hz.

Copyright ©2004 by NACE International. Requests for permission to publish this manuscript in any form, in part or in whole must be in writing to NACE International, Publications Division, 1440 South Creek Drive, Houston, Texas 77084-4906. The material presented and the views expressed in this paper are solely those of the author(s) and not necessarily endorsed by the Association. Printed in U.S.A.

1 000295

The body of literature 1291 indicates that AC-corrosion or AC-enhanced corrosion is a bona fide phenomenon. Probabilistically, higher AC current densities are likely to result in accelerated corrosion of steel. There is an inverse relationship between the impact of AC current and its frequency; however, there appears to be a tacit agreement that at prevailing commercial current frequencies (such as 50 or 60Hz) corrosion is possible, even on the cathodically protected pipelines. General corrosion rates due to AC corrosion are not necessarily 'abnormally high (the authors of this study have encountered naturally occurring rates of an existing pipeline which were far greater), but the rates are certainly multiples of the 'prevailing' corrosion rates of steel in soil in absence of AC.

Several publications have suggested that enhancement of corrosion of the affected structures takes place during the anodic half-cycle of the AC sine wave. Furthermore, it is generally accepted that the AC-enhanced corrosion rate amounts to only a small fraction (on the order of 1% or less) of that caused by DC currents of the same magnitude. Based on these observations, some articles concluded that the threat of AC-enhanced corrosion, even if potentially present, could be easily mitigated with cathodic protection.

The Japanese stud y1201 on two cathodically protected buried pipelines used buried 10 cm2 coupons to monitor the efficiency of impressed current CP protection and the level of AC reduction (using decoupling devices and magnesium anodes as grounding devices); without actually reporting on the findings, the study shows the following diagram to illustrate the adopted criteria for DC and AC currents (see FIGURE 1).

Despite the existing body of research data and some empirical evidence apparently implicating AC currents as deleterious to the buried pipelines, there remained a need to further investigate the issue, particularly the conditions at which AC currents may pose threat to underground structures and cathodic protection requirements needed to mitigate the possible adverse AC current effects. Of a particular interest were the following two issues: (1) the effect of AC current density on the corrosion rate and (2) cathodic polarization requirements necessary to mitigate the impact of AC current.

EXPERIMENTAL APPROACH

The experimental approach consisted of testing carbon steel specimens exposed to soil. The protocol utilized three identical, closely spaced carbon steel specimens encased in epoxy with an exposed area of 0.71 cm2 each. The top, exposed surface of the specimens is shown in FIGURE 2; the finish is 600 grit.

The AC current was passed between Specimen A and Specimen B. The third specimen served as a control. The AC current was supplied by a variable output transformer (variac); to achieve the desired CP polarization, a pencil-shaped individual magnesium anode was used. The current was measured as a potential drop over a resistor of a known value; the currents to Specimens A and B were balanced with variable potentiometers. To prevent DC and AC current drainage to the AC and DC loops, a capacitor and a diode were installed in the respective sides of the circuit. The overall electrical circuit is shown in FIGURE 3. The specimens were buried in large soil cells (about 5-gallon capacity), approximately 6 inches

2 000296

deep in Dublin, OH (DOH) soil at 100% moisture saturation. The large soil volume and moisture content provided ample means of heat dissipation. Each soil test contained a single set of coupons because multiple sets could not be tested in the same cell due to considerable interference problems. A closely placed Cu/CuSO4 reference electrode measured on- and off-potentials of Specimens A and B and the corrosion potential of the control.

The targeted experimental variables were as follows: • AC target current density:

o 20 A/m2 (Low) O 500 A/m2 (High)

• CP target potential shift: o 0 mV (No CP) O 100 mV (Low) O 300 mV (High)

The number of specimens tested for each of the experimental conditions (36, including 24 test specimens and 12 controls) is shown in TABLE 1. The duration of each test was 14 days. The measurements of and adjustments to currents and potentials were made daily. At the end of the test, the data was analyzed and the actual AC current densities and CP potential shifts were determined by calculating time-weighted averages for both variables. For the subsequent analyses, to reduce scatter, the AC/CP test conditions were grouped into the High/Low categories similar to those shown in TABLE 1, except the cut-offs for each category were based on the actual rather than target levels of AC and CP to assure that the test conditions where the target AC/CP values were not attained would still fall into the proper category. The cut-off criteria for the final categorization are presented in TABLE 2.

Quantification of the relationship between the AC current density, CP potential shift, and effective corrosion rate was performed utilizing Veeco® non-contact optical profiler Wyco NT3300, which rapidly measures heights from Angstroms to millimeters, with vertical resolution to 0.1 nm.

RESULTS

The appearance of the specimens immediately following the 14-day test exposure and after cleaning with the inhibited acid solution is shown in FIGURE 4 (example for low AC — no CP). The analysis is based on the 10-point mean values (determined by taking the difference between the average depths of the 10 highest peaks and the 10 deepest valleys), which represent localized depth of penetration (pitting). In keeping with the approach described earlier, these were averaged between the two specimens (A and B) in each test and then between the duplicates for each test condition. Furthermore, considering the variability from test to test in the depths of penetrations of the control specimens, it was decided to present and analyze the results as ratios between the test specimens and the control specimen exposed to the same test condition. The results of the averaging are presented in a graph form in FIGURE 7. Individual results (including the actual rather than target AC and CP values) are shown in TABLE 3.

3 000297

A sampling of the tremendous volume of data produced by the optical profiler was used to create two- and three-dimensional representations of the measured surfaces. The two-dimensional representations providing quantitative depth measures are shown in FIGURE 5 (example for low AC + no CP). To help the reader to create a more comprehensive picture of the extent of attack on the test and control specimens, three-dimensional topographies are shown in FIGURE 6 (example for low AC + no CP).

The graph shows that in the absence of CP, higher AC current densities lead to a higher corrosion rate. The data also suggests that even at "Low AC + No CP" conditions, at AC densities which are considered 'safe by many publications, the observed increase in corrosion rate (relative to a control) is by a factor of 2. The results for the "AC + CP" conditions are less definitive. Thus, both "Low AC + Low CP" and "Low AC + High CP" conditions indicate that AC/soil corrosion was mitigated such that the depth of penetration of the test specimens was lower than that for the controls. The data for the "High AC" categories is not consistent, with the "High AC + Low CP" results suggesting protection and "High AC + High CP" results showing that protection could not be achieved.

DISCUSSION

Relationship between AC current density — CP shift — corrosion rate The AC current density — CP potential shift — Depth of penetration relationship is best evaluated by using contour plots. The plot presented in FIGURE 8 uses the data shown in TABLE 3, which represents the relative depths of penetration (ratios) averaged between the two test specimens (A and B) for each tested condition. The data was not averaged between the duplicate tests for each tested condition so that individual test conditions could be represented. The interpolation process attempts to express trends suggested in data, so that, for example, high points might be connected along a ridge rather than isolated by bull's-eye type contours). The plot in FIGURE 8 includes all TABLE 3 data. The high relative depth of penetration for the "High CP + High AC" condition is a significant anomaly, which requires further examination. If these datapoints are removed (shaded cells in TABLE 3), the plot takes the shape shown in FIGURE 9.1 Removing these data has minimal effect on the plots in the range of AC current density less than 200 A/m2.

A blown-up portion of the graph in FIGURE 9 is shown in Figure 10. The "best date contour plot corroborates what is stated in some of the published literature, e.g., mitigation of AC-enhanced corrosion is possible only for the AC current densities below a certain threshold. It also reiterates the notion that low' AC current densities appear to be capable of causing considerable corrosion. NOTE: The contour plots are provided for the sole purpose of illustrating the methodology for establishing an AC-enhanced corrosion mitigation criterion, including both AC current density levels and applied CP component. The data plotted represents too few datapoints to be used as a definitive guide. It is clear that with sufficient data, AC mitigation / CP polarization criterion could be established.

i The choice regarding which of the datapoints are inconsistent with the rest of the set is not easy. It is understood that, given that the overall number of tests is relatively small, removing 2 points could lead to dramatic changes in the appearance of the plotted data.

4 000298

Most agree that >100 A/m2 AC corrosion is likely and, furthermore, some indicate that CP is not effective in mitigating the phenomenon at current densities greater than 100 A/m2. The presented results would agree that 100 A/m2 is large enough to cause significant attack. Furthermore, this study also provided limited data that at high AC current densities (-500 A/m2) increasing CP did not mitigate AC corrosion (actually made it worse).2

The majority of the studies indicated that AC corrosion is possible at current densities between 20 to 30 A/m2. It is, however, proposed that any AC current density increases corrosion, and the --20 A/m2 used in this study produced a 90% increase in corrosion compared to the no-AC condition (see TABLE 3). Therefore, until more detailed data is produced for soil, 20 Nm2 should be considered sufficient enough to cause significant AC corrosion.

AC Mitigation At present in the U.S., AC mitigation is mostly driven by the safety considerations. The primary focus of these efforts is to reduce the induced AC voltage below the 15V to assure the compliance with the NACE Standard RP0177 "Mitigation of Alternating Current and Lightning Effects on Metallic Structures and Corrosion Control Systems". Typical means of AC mitigation include installation of the zinc/magnesium ribbon anodes or prepackaged magnesium anodes, which may be coupled to the pipe through a diode circuit to limit the corrosion of the zinc/magnesium to "free corrosion". Additional means of AC mitigation involve installation of grounding electrodes coupled to the pipe via capacitors or polarization cells as to not introduce additional burden on the existing CP system. The available field data indicate that the above-mentioned AC mitigation methodologies are reasonable for mitigating AC voltage/currents. The proposed mechanism (to be discussed in future publications) suggests that it is reasonable to decrease the magnitude of AC through whatever means applicable to the existing pipeline conditions. The key aspect is that AC must be mitigated to relatively low levels; the NACE safety standard in RP0177 may not be sufficient in many cases.

Considering that the primary factor in determining the possibility for the presence of AC corrosion is the AC current density, monitoring the current density rather than an AC voltage is crucial to assessing the AC current-related hazards to a buried pipeline. It is a very important departure from the prevailing practices of measuring (and mitigating) the AC voltages on the buried pipelines, notwithstanding the fact that the reduction of AC potentials is expected to reduce the AC current magnitude as well.. Field data shows that a relatively small-sized defect (6 to13 cm2) in the coating on the pipe in a relatively low-resistivity soil could have AC current density in excess of 100 Nm2, while the AC voltage could be as low as 6V.

Monitoring of the AC current density may be accomplished by installing coupon test stations (CTS) along the affected structure. The choice of the installation sites would be predicated on information gleaned from field measurements, such as a close interval survey consisting of both DC and AC pipe-to-soil potential readings.

Deployment of the existing mitigation measures constitutes a proper course of action, as it leads to the reduction of the AC current density on the existing defects in the pipeline coating. In addition, the mitigation criteria should put the emphasis on mitigating the AC current density,

2 Whether or not this finding represents an anomaly requires further investigation.

5 000299

Documents

NACE International carefully removed from the pipe; see