A primary benefit for surface mitigation is ease of installation and a lower associated cost. Mitigation

installed in the same trench beside the pipe during pipeline construction further reduces installation costs.

Typical industry construction estimates indicate that the cost of a single drilled deep well anode installation

may be ten times the cost of a 1,000-foot surface installation, if installed during pipe construction. This

would indicate that each deep well anode would need to replace approximately 10,000 feet of surface

mitigation before it is economically viable from a ground resistance standpoint alone. That said, the decision

between surface and deep grounding installation methods most often comes down to a number of other

considerations, including construction access, grounding distribution, and contractor preference in addition

to cost alone. [Appendix C contains a simplified summary, presents the pros and cons for various mitigation

materials and methods for reference.] The comparison information provides guidance and demonstrates the

comparative benefits of each approach based on various soil resistivity layers.

5.5 Additional Mitigation Methodologies

The AC mitigation techniques discussed utilize low-resistance grounding to transmit induced AC voltage to

ground. While grounding can be an effective mitigation technique for many interference cases, recent

industry experience has identified collocations where induced potentials or current density reduction to

adequate levels cannot be achieved by grounding alone. This is generally due to a combination of elevated

transmission currents and unfavorable soil resistivity conditions. Trends in the power transmission industry

have led to increased power capacity and corresponding operating currents, for some long distance

transmission systems as shown. This increase in operating current has a direct effect on the level of EMI. In

many cases, this has presented a significant challenge for achieving adequate mitigation on pipelines

crossing or collocated with the power transmission lines. In these cases, additional mitigation techniques

should be considered.

In terms of risk reduction or prevention, the approach to AC interference mitigation can be categorized on a

primary, secondary, or tertiary level. Primary prevention targets controlling or reducing the source of the

risk, through elimination or control. Secondary prevention targets reducing exposure to a risk factor, and

tertiary prevention targets treating the response or consequences of the risk factor, generally after exposure

to the risk. By these terms, a standard practice of mitigating AC induction by grounding alone is considered

a tertiary form of mitigation. That is to say, the treatment targets only the consequence of the interference

by reducing the detrimental AC effects at the pipeline level, after allowing the pipeline to be exposed to the

interference risks. While not currently in widespread application, further research of primary and secondary

risk controls should be considered in future development, to reduce overall interference and risks associated

with AC interference, especially considering cases that cannot be effectively mitigated by traditional means.

While the concepts presented may not be readily employed by pipeline operators without further research,

they are presented to address the need for continued research and development of more robust high voltage

interference mitigation methodologies, and pursue improved collaboration between the power line and

pipeline operators.

5.5.1 Primary Threat Control of AC Interference

Although mitigation grounding is a common industry practice, cases exist where grounding alone is

insufficient to reduce interference levels on collocated pipelines. For such cases, additional techniques should

be considered. From an engineering risk basis, with respect to overall risk reduction, a preferred approach is

to reduce the source of interference. Specifically, this means reducing the interference prior to it reaching

the pipeline, generally through design controls during the development phase prior to construction, where

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modifications to the pipeline or transmission line are possible. The level of interference experienced at the

pipeline is dependent on the magnitude of EMI generated at the source, and the collocation parameters that

limit the EMI levels reaching the pipeline. Specifically, revising collocation routing, and tower and circuit

configuration modifications can reduce or optimize the level of EMI produced. Conductor arrangements can

be designed to balance individual phases producing the lowest levels of EMI for a given circuit configuration.

For a given circuit configuration (single circuit horizontal/vertical, double circuit horizontal/vertical/delta, etc.)

there exists an ideal phase sequence which minimizes the LEF at the pipeline location and thus results in

lower magnitudes of AC interference. Dabkowski studied the magnitudes of the LEF for varying circuit types

and phase sequence. The results demonstrated that for a single horizontal circuit a reduction of up to 9

percent of the LEF may be achieved, by choosing the proper phase sequence.24 With the single circuit

vertical case, the LEF at the pipeline location could be reduced by as much as 15% with the proper phase

sequence.

The double circuit vertical tower configuration presents a unique scenario for phase sequencing. There are

36 possible phase sequences, classified into five sets of phase combinations: center point symmetric, full roll,

partial roll upper, partial roll lower, and center line symmetric. The LEF magnitude between the various

phasing configurations can vary significantly.29 Generally, the ideal phase sequence for a double vertical

circuit is the center point symmetric phase configuration, which generates an LEF approximately 65% to 90%

less than the center line symmetric phase configuration.29 This is significant when considering this is simply

the result of the physical interaction between conductors, and primary mitigation reduction at the source

reduces the interference levels that ever reach the collocated pipeline. Additionally, optimization of the

phase configuration does not require unconventional installation methods to obtain this reduction in LEF

magnitude.29 It is recognized that for existing installations, pipeline operators generally may not be able to

influence HVAC power design; however, for new construction and power system expansions where

interference is a concern, communication between pipeline operators and transmission owners of possible

effects is recommended in order to review possible interference hazards prior to construction. Where

possible, pipeline and HVAC power line design controls can limit EMI and interference on adjacent pipelines.

The addition of phase transpositions along a given collocation can also act to reduce the overall EMI

influencing a collocated pipeline. However, phase transpositions should only considered as part of a detailed

analysis, as the discontinuity presented by a phase transposition can create a localized point of elevated

interference, and may have further impact on the power transmission design.24 However, where appropriate,

phase transpositions can create discontinuities and effectively break up long line interference built up on

long collocations. Further, in areas where construction access may be limited, phase transpositions can be

located strategically to reduce interference at the source.

5.5.2 Secondary Threat Control of AC Interference

With respect to overall threat reduction, a secondary control works by means of isolating a threat from a

structure. In the case of AC interference, this specifically means intercepting and grounding the EMI prior to

reaching the pipeline.

One proposed example is overhead shielding, which is used to mitigate AC interference in other industries

including rail transport systems, but is notably less common in mitigating AC interference on pipelines. An

overhead shielding technique works by placing a conductor, grounded at regular intervals, within a targeted

region between the pipeline and the adjacent transmission line. This shielding conductor, located in the

same LEF generated by the conductor circuit, induces a current and an accompanying LEF 180 degrees out

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of phase with the field generated by the transmission line. In so doing the conductor acts to cancel part of

the LEF generated by the transmission line, resulting in lower levels of induction on the pipeline. Dabkowski

studied the effectiveness of this technique for the same tower configurations discussed in Section 5.5.1.29

The results indicated a substantial reduction in the induced potential on the pipeline was possible; however,

the mitigating effectiveness was highly sensitive to loading conditions, and the precise location of the

shielding conductor. For the single circuit horizontal circuit, an auxiliary overhead ground wire resulted in a

reduction of approximately 25% in the LEF, and thus the corresponding induction on the pipeline. The ideal

placement of this overhead auxiliary shield wire was approximately the same height as the phase wires,

which for single circuit horizontal circuits may make this solution impractical. For the single circuit vertical

tower configuration, Dabkowski found a maximum LEF reduction of approximately 60% to 75% by mounting

the overhead shield wire at an optimum height on the tower centerline. Reductions in the LEF generated by

the double circuit vertical configuration were found to be range from 50%-95%. However, when examining

slight imbalances of +/-5 to 15% between phase wires, the benefits realized by this auxiliary shield wire

quickly diminished to 20% or less when compared to uniform current across all phase wires of the

circuit.2923 While this is generally not a common practice in mitigation of pipeline interference, overhead

shielding has been considered and studied in the past, and is used within other industries. Specific overhead

shielding installations require detailed design, and precise locating but this approach may present an

alternative means of mitigation where ineffective through more traditional means. Further research and

testing is required on a case-specific basis to determine if this is a viable technique.

Fault and arc shielding, which are used to reduce the risk of damage to the pipeline and the coating near

tower grounds during fault conditions are another form of secondary risk control. Fault protection typically

takes the form of a parallel shield wire, similar to mitigation ribbon discussed in Section 5.2. However, the

primary function of fault and arc shielding protection acts to intercept transmission line fault current and

transfer to ground prior to reaching the pipeline. For this reason, the location and placement of the arc

shielding mitigation is far more critical when protecting against conductive (fault) interference than for

inductive interference.

5.5.3 Tertiary Threat Control of AC Interference

With respect to overall risk reduction, tertiary controls rely on reducing the consequences of the threat after

exposure to the structure. Per this definition, typical grounding mitigation can be considered a tertiary

control. Mitigation grounding works by transmitting the AC potential to ground, only after it has already

reached the pipeline. While grounding has proven to be an effective means of mitigation for many historical

installations, and installation is generally within the capabilities and access of the pipeline operators,

scenarios occur where grounding alone is not sufficient to reduce interference to acceptable levels.

Ideally, a combination of primary, secondary, and tertiary mitigation techniques would provide the highest

level of threat reduction and protection for the pipeline. However, addressing a threat at the lowest level

possible will provide reduction in severity, increasing the likelihood that mitigation will be effective. That is

to say, reducing AC interference at its source or shielding EMI from reaching an adjacent pipeline can

provide greater risk reduction than simply allowing the interference to pass to the structure and dissipating

to ground via tertiary mitigation methods. In practice however, it may not always be possible or practical to

address interference at a primary or even secondary level. Tertiary mitigation through low resistance

grounding techniques may provide adequate risk reduction for a majority of interference collocations.

However, further research and continued development into additional mitigation techniques would benefit

the industry.

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5.6 MONITORING

As mentioned previously, the measurement or calculation of AC current density has been the primary

indicator to determine the likelihood of AC corrosion across industry in North America. It is possible to

measure AC current density on a representative holiday through the installation and use of metallic coupons

or ER probes. A test wire connected to the coupon, routed to the surface and connected to the pipeline

through a test station is an example of a simple installation. By inserting an ammeter into the circuit, an AC

and DC current can be measured which when can be used to calculate the current density at that location.

In many cases, test stations with coupons also include additional instrumentation such as ER probes and

reference electrodes. The ER probes provide a time based corrosion rate while the reference electrodes

provide both and AC and DC pipe-to-soil potentials for comparison.

Using coupon test stations (CTS), and ER probes, real-time monitoring can provide a better understanding of

the interference effects acting on a collocated pipeline. However, as previously discussed, the magnitude of

interference depends on the magnitude of current loads on the associated power lines. Correlation of the

CTS and ER probe data with power line loads provides a thorough understanding of the system performance.

While it has historically been difficult to obtain this information from power line operators, there is a

recognized need to have good understanding of the operating power line loads to determine relevance of

coupon test station or ER probe data. Additionally, best practices dictate obtaining data over a

representative period (days or weeks as relevant) in order to assess the interference response during high

load conditions. A measurement for AC potential or AC current density at a single point in time with

unknown operating current loads may not be representative of the actual risk for interference on the

pipeline.

6 GUIDELINES FOR INTERFERENCE ANALYSIS

The following steps are provided as best practice procedures for determining where detailed analysis is

recommended based on the results of this study, industry standards, historical technical publications, and

previous industry experience.

Pipeline operators are faced with many existing and new construction pipelines collocated and crossing

power line ROW. Little guidance exists to assist in selecting and prioritizing collocations for detailed analysis

and modeling. Under certain conditions, it may be possible to justify the low likelihood of AC interference,

and exclude specific locations from further detailed modeling with detailed monitoring, or justification that

the risk due to interference is low.

It is recommended to collect the following information, where possible, to determine if a detailed AC analysis

is required. Appendix D is a sample of data to collect from the powerline company. Use the corresponding

severity limits in Sections 6.1.1 through 6.1.5 to assist with this methodology:

• Peak and Emergency load rating (amps) for collocated power lines

• Line rating (kV) for collocated power lines

• Soil resistivity along the collocation at multiple depths

• Collocation and / or crossing routing geometry for the pipeline and power line

• AC pipe-to-soil (P/S) measurements (for existing pipelines)

• AC Current density using coupons or probes where previously installed

• Maximum fault potential and fault clearing time

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Detailed "analysis" in the context of this document refers either to data collection using detailed monitoring or to specific application of numerical calculation of interference magnitudes. This analysis is done using detailed computer modeling or similar application of interference calculation methods.

6.1 Severity Ranking Guidelines

This section provides general guidance with respect to the relative severity ranking for the identified

variables with respect to their impact on the severity of AC interference.

6.1.1 Separation Distance

Separation distance and load current are key factors in determining whether a collocation will experience

significant AC interference. Generally, the separation distance is readily available or easily determined, so it

is often a primary screening variable. However, it has been shown that significant interference is possible for

distances greater than 1,000 feet when considering collocations with load capacity greater than 1,000

amps.2 It is therefore recommended to consider collocations within 2,500 feet, and the decision for further

analysis should also incorporate estimate of the power line current.

Severity ranking for separation distance is provided in Table 3.The following generalized rankings have been

determined through review of industry data, parametric studies, and historical experience.

Table 3-Severity Ranking of Separation Distance

Separation Distance - D (Feet) Severity Ranking of HVAC Interference D< 100 High

100 <D<500 Medium

500 < D < 1,000 Low 1,000 <D< 2,500 Very Low

6.1.2 HVAC Power Line Current

The magnitude of transmission line currents is one of the most influential parameters determining the

likelihood and severity of AC interference. However, there is often debate as to which load rating to consider

for interference analysis and mitigation design. HVAC power lines generally have multiple ratings that

specify the operating loads allowable during normal operation and peak or emergency load ratings allowable

during short duration scenarios. Ultimately, the load rating considered should be a risk-based decision made

by the pipeline operator, considering the frequency of occurrence for the load level, typical duration

throughout operation, and the consequence associated.

From a personnel safety standpoint, it is recommended to consider the maximum load that a power line can

carry for any duration. The terminology for this varies among transmission operators, but it is commonly

referred to as "Emergency Load", defined as the maximum load a transmission circuit is capable of carrying

for a short duration such as during an emergency or maintenance condition. Considering personnel safety,

elevated step or touch potential could pose an instantaneous threat as a shocking hazard, regardless of

duration of the elevated power line current. As the pipeline operator is generally unaware of an emergency

load condition on the power line, it may not be feasible to reduce or prevent exposure during even a short-

duration elevated current load. It is therefore generally best practice to consider the maximum capacity or

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emergency loading conditions when assessing the risk of personnel safety threats such as shocking, unless

other provisions can be made to prevent exposure.

However, AC corrosion is a time-dependent threat. The magnitude of AC current density possible on a

pipeline under AC interference will be sensitive to the current load on the adjacent HVAC conductor. While

emergency loads, or other spikes in power line current may cause an elevated current density, the

associated corrosion damage may be low as the duration is limited.

The power line current is often the most controlling parameter influencing the magnitude of AC interference.

For this reason, we recommend obtaining the power line load limits from the relevant power transmission

operator when assessing the risk of AC interference on a given pipeline. These limits should include the

various operating ratings (generally 'Normal', 'Peak', and 'Emergency), the allowable duration for each, and

expected frequency of occurrence.

Transmission operating parameters are not always readily available to pipeline operators, and this

information may be difficult to obtain. However, the power line current is a primary factor, and the relevance

and accuracy of an AC analysis may vary greatly with the accuracy of the operating current. Where actual

load data is unavailable, published reference currents for various HVAC power line ratings are available in

literature24. However, these guidelines are for reference only, and may provide over or under conservative

results. In practice, there are cases where the operating currents provided for a specific power line

significantly exceeded these estimates. Additionally, as discussed in Section 4.2.1, increase load capacity on

new and upgraded systems may result in load ratings above the provided reference levels.

Severity rankings associated with HVAC load current for a collocated power line is provided in Table 4.

The following generalized rankings have been determined through review of published technical literature,

industry data, parametric studies, and historical experience.

Section 5.2.1 contains further background and detailed information for effects of power line phase current.

Table 4-Relative Ranking of HVAC Phase Current

HVAC Current - / (amps) Relative Severity of HVAC Interference

/ > 1,000 Very High

SOO< / > 1,000 High

250 < / < 500 Med-High

100< / < 250 Medium

/< 100 Low

6.1.3 Soil Resistivity

Soil resistivity affects both the magnitude of induced AC and the susceptibility to AC corrosion. The AC

corrosion process, as presented in Section 3.3.1 is a function of the AC current density at a coating holiday,

which in turn is dependent on the level of AC voltage on the pipeline and the local spread resistance. The

bulk soil resistivity is a primary factor controlling overall level of induction, while the local soil resistivity near

a holiday is a primary factor in the corrosion activity, as discussed in Section 4.2.2. The following

generalized severity rankings have been determined based on industry experience and guidance provided in

EN 15280:2013, with respect to AC corrosion.I5

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Table 5-Relative Ranking of Soil Resistivity

Soil Resistivity - p (ohm-cm) Relative Severity of HVAC Corrosion

p < 2,500 Very High

2,500 <p( 10,000 High

10,000 <p< 30,000 Medium

p> 30,000 Low

6.1.4 Collocation Length

The collocation length of the pipeline and transmission line affects the magnitude of induced AC potential

accumulating on the pipeline as it defines the length of the pipeline exposed to the LEF of the phase wires.

The following generalized rankings have been determined through parametric studies, and historical

experience.

Table 6-Relative Ranking of Collocation Length

Collocation Length: L (feet) Relative Severity

L> 5,000 High

1,000 < L< 5,000 Medium

L< 1,000 Low

6.1.5 Collocation / Crossing Angle

The angle of collocation or crossing of the pipeline and power line limits the influence of induction. The

following generalized rankings have been determined through parametric studies, and historical experience.

Table 7-Relative Ranking of Crossing Angle

Collocation/Crossing Angle - 0 (°) Relative Severity

0 < 30 High

30<0<60 Med

0 > 60 Low

6.2 Recommendations for Detailed Analysis

The guidance parameters presented are based on industry literature and standards where available. Where

guidance has not previously been provided, qualitative classifications have been provided to aid in severity

ranking and prioritization. The qualitative guidance parameters have been determined based on published

industry guidance, numerical modeling parametric studies, previous analytical experience, laboratory studies,

and failure investigations for AC corrosion related damage. The intention is not to replace or remove detailed

analysis from the design decisions, but rather to aid in severity ranking and prioritization when determining

where additional detailed analysis and mitigation design is required.

The guidelines within should be used by the operators as part of an overall risk-based decision. The details

within this report and this section can only provide guidance regarding the severity of HVAC interference or

AC corrosion. When determining whether to perform further detailed analysis, add location specific

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monitoring, or where no further action is required, possible consequences must be a part of the decision

process and reviewed on a case-specific basis.

As discussed in Section 4.2, collocations with power lines operating at greater than 1,000 amps are subject

to interference under conditions where likelihood would otherwise be low. Special consideration required for

collocations where the power line loads are greater than or equal to 1,000 amps. For this reason, an

understanding of the power line load current is necessary for evaluating the need for further analysis. The

two cases below provide an assessment of collocations and crossings encountered, based on:

Case 1 - Current Load greater than or equal to 1,000 amps, pipeline crossing or collocated within 2,500

feet

Case 2 - Current Load less than 1,000 amps, pipeline crossing or collocated within 1,000 feet

6.2.1 Case 1

For scenarios where power line current is known or can be estimated to operate at or above 1,000 amps,

and a steel pipeline is crossing or collocated within 2,500 feet of the power line, a detailed analysis is

recommended when one or more of the following conditions are met:

o Collocation Length severity is characterized as "High"

o Soil resistivity severity is characterized as "High" or worse

o Three or more of the variables identified in Section 6.1 are categorized as "Medium" or worse

6.2.2 Case 2

For scenarios where power line current is known or estimated to operate below 1,000 amps, and a steel

pipeline is crossing or collocated within 1,000 feet of the power line, a detailed analysis is recommended

when one or more of the following conditions are met:

o Phase current severity is characterized as "High" or worse

o Collocation length severity is characterized as "High"

o Soil resistivity severity is characterized as "High" or worse

o Three or more of the variables of severity rankings identified in Section 6.1 are categorized as "Medium" or worse

High angle crossings, with crossing angles of greater than 60°, while considered low-risk for inductive

interference, are susceptible to fault or lightning arcing, as well as coating breakdown due to fault voltage.

Crossings with an angle greater than 60° may still be susceptible to inductive interference if subject to very

high current load, or multiple HVAC power lines.

6.2.3 Faults As fault conditions are generally infrequent and of short duration, it is not practical to obtain measurements

of AC potential during a fault condition. Analysis of fault voltages generally requires numerical modeling.

Fault current levels or estimates of possible magnitudes, are generally obtained by HVAC power line

operators and can vary significantly depending on tower design, power capacity, and location relative to

substation and generation source.

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Whenever a pipeline crosses or is collocated in close proximity within 500 feet an HVAC tower, it is

susceptible to faults. Detailed calculations or modeling is required to determine the possibility of fault arcing

and possible coating damage due to GPR.

6.2.4 Fault Arcing Distance

When a pipeline crosses or is collocated in close proximity to an HVAC tower ground, a theoretical fault

arcing radius can be calculated. The fault arcing radius is the distance from a HVAC tower ground that a

sustained lighting or fault arc may reach an adjacent metallic structure. The arcing radius is primarily a

function of the fault or lightning current and the local soil resistivity magnitude, and is estimated using

equations 2 and 3 based on Sunde's equations for lightning arc distance.3° The equations presented were

developed to predict a safe separation distance considering an elevated current due to lightning strike, and

can be utilized to provide an estimate of possible fault arcing distance from a faulted high voltage tower

ground as well.

ra =0.08.‘11acx—e-

100

ra = 0.047. jlaax

If p 100,000 Q•cm (2)

if p > 100,000 Q•cm (3)

Where: ra= arc distance in m

p= soil resistivity in Q•cm

/„= the fault current in kA

6.3 Data and Documentation Requirements

Where the Severity Rankings Guidelines criteria indicated a more detailed analysis is necessary, collect the

following information where possible, to facilitate development of an AC interference model. Appendix D

contains a sample data log provided for reference:

Pipeline Parameters:

• Routing geometry

• Depth of cover

• Diameter

• Coating details

• Coating resistance

• Existing CP installations

• Location of bonds

• Soil resistivity at multiple depths and locations along the ROW

• Location of insulating joints

Power line Parameters:

• Routing geometry

• Number of circuits

• Conductor configuration (dimensions, orientation, phasing)

• Conductor loading (Peak and Emergency current)

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• Tower ground resistance

• Maximum fault voltage

• Fault clearing time

• Shield wire configuration

6.4 General Recommendations

As the operating current is a controlling parameter influencing AC interference, it is recommended to obtain

the power line load current from the relevant electrical utility operator when assessing a collocation for the

threat of AC interference. Historically, lack of collaboration between pipeline and power line operators has

led to projects being assessed without accurate understanding of the power line data. This can lead to either

an overly conservative and costly design or an under-designed system not adequately reducing the

interference. Collaboration between the respective pipeline and power line operators is critical to accurate

assessment and efficient mitigation of any possible interference effects.

In addition to the assessment described in previous sections, the following general recommendations apply

for collocations and crossings where AC interference is a concern:

• Install coupon test stations or ER probes to monitor AC Current density, a coupon surface area of

1.0 cm2 is recommended.

During pipeline construction near HVAC transmission lines, confirm that the contractor safety

program complies with the recommended 15 VAC limit for shock hazards, and applicable OSHA

construction standards as referenced in Section 3.2.2.

• Record AC pipe-to-soil potentials along with the DC pipe-to-soil potentials during the annual cathodic

protection survey on sections where AC interference threats may exist. This can provide information,

should the power transmission company change its operating parameters, or unexpected changes

occur between the pipeline and transmission line.

• Request power line loads corresponding to the time of AC pipe-to-soil potential measurement to

provide thorough understanding of the interference measurements

• Measure soil resistivity at locations where AC interference threats may exist. This data can be used

with the measured AC potentials to estimate theoretical AC current density for specific locations in

the absence of coupons or ER probes.

• Operating personnel should be trained in the hazards and safe practices associated with working on

pipelines subject to HVAC interference

• Suspend work (when possible) along the collocated or crossing section of pipeline during weather conditions that may lead to a transmission line fault.

Safety precautions are required when making electrical measurements:

• Only knowledgeable and qualified personnel trained in electrical safety precautions install, adjust,

repair, remove, or test impressed current cathodic protection and AC mitigation equipment.

• Properly insulated test lead clips and terminals should be used to prevent direct contact with the

high voltage source.

• Attach test clips one at a time using a single-hand technique for each connection when possible.

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• Extended test leads require caution near overhead HVAC power lines, which can induce hazardous

voltages onto the test leads, or present a source of data error.

52 000110

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CORROSION 98, Paper No. 565, 1998

33. S. Goidanich, "Influence of Alternating Current on Metals Corrosion," PhD thesis, Politecnico di Milano, 2005.

34. P. Nicholson, "High Voltage Direct Current Interference With Underground/Underwater Pipelines,"

CORROSION 2010, NACE Paper No. 10102

54

000112

APPENDIX A LITERATURE REVIEW

000113

Where published, historically identified corrosion defects and pipeline failures associated with AC corrosion

degradation were reviewed and are presented to demonstrate the magnitudes and variability in corrosion

rates possible with AC accelerated corrosion. The general findings, discussion, technical details, and results

are utilized and summarized throughout this document.

This lack of industry consensus on the subject of AC corrosion guidelines has led to varied practices among

pipeline operators in regards to mitigating AC interference on pipelines. As part of this study, The INGAA

Foundation requested a review of industry practices and procedures related to AC interference. The INGAA

Foundation provided DNV GL with the procedures related to AC interference or mitigation for 10 pipeline

operators who are members of the Foundation. The primary finding from this review is that there is

significant variation in company procedures with respect to AC interference. Based upon this review, all of

the procedures provided address a safety concern and define a maximum allowable AC pipe-to-soil potential

limit for above grade appurtenances. Faults were included as a concern/risk for pipelines in close proximity

to HVAC power lines in almost all of the procedures. However, few addressed coating stress limit above

which mitigation is required. For current density criteria, several procedures had clearly defined limits, while

others addressed it as a concern for AC corrosion but did not specify a targeted limit of AC current density or

define limits for mitigation.

Case Studies

Numerous studies, both laboratory and field based, have been performed that attempt to determine

magnitudes of corrosion rates associated with AC interference. However, reviewing available technical

literature confirms a wide range of experimental rates, and a scarcity of controlled field measured rates.

Where published, historically identified corrosion defects and pipeline failures associated with AC corrosion

degradation have been reviewed and are presented to demonstrate the magnitudes and variability in

corrosion rates possible with AC accelerated corrosion.

Field investigations reported by Ragault31 considering a coated cathodically protected pipeline, identified

corrosion rates between 12 and 54 mpy (0.3 and 1.4 mm/yr), for AC current densities ranging between 84

and 1,100 A/m2.

Wakelin, Gummow, et a132 provided three case studies where field inspections identified defects as AC

corrosion-related degradation. Based on inspection intervals and corrosion degradation, corrosion rates were

identified ranging from 17 to 54 mpy (0.4 to 1.4 mm/yr) for AC current densities between 75 and 200 A/m2.

A German field coupon study, published by Prinz, and Shoneich,7 indicated general AC corrosion rates

between 2 to 4 mpy (0.015 to 0.1 mm/yr) for a current density of 100 A/m2, and 12 mpy (0.3 mm/yr) at

400 A/m2. However, pitting rates were considerably greater and showed a wider range between 8 and 56

mpy (0.2 to 1.4 mm/yr), with considerably less dependence on AC density.6

A doctoral thesis study by Goidanich presents similar findings concluding that AC current density as low as

10 A/m2 may be considered hazardous as the experimental studies showed it nearly doubled the free

corrosion rate of the experimental samples in simulated soil tests.33

A 1998 report by Wakelin, Gummow, et al published by NACE reviewed several case studies dating back to

the 1960s where AC corrosion was identified or suspected to be the primary mechanism of degradation. The

report summarized recorded details on multiple case studies with specific focus on comparison of corrosion

rates and AC current density where known. In 1991, a failure investigated on a 12-inch diameter pipeline

concluded AC accelerated corrosion after only four (4) years of service. Induced AC potentials measured as

56

000114

high as 28 volts. Based on the nominal wall thickness and time to leak, an average pitting rate for the

through wall pit was estimated to be greater than 55 mpy. Two other case studies indicated the average AC

induced corrosion rates for the identified sites between 11 and 24 mpy.

A 2004 paper by Hanson and Smart, published by NACE, presents a case study for a gas pipeline installed in

the summer of 2000.8 The pipeline was collocated in a shared ROW with a 230 kV transmission line for

approximately 9 miles, and then entered a shared power corridor with six power transmission lines, two of

which were rated at 500 kV, all within sufficient proximity of the pipeline to cause interference. A leak

occurred within 5 months of installation, before the line was in operation. Several other leaks were identified

shortly after, with four leaks within close proximity. Induced AC potential measurements found AC voltages

as high as 90 volts on the pipeline. The failure assessment indicated the corrosion was due to induced AC

corrosion, and estimated rates in excess of 400 mpy.

The majority of literature reviewed indicates AC corrosion rates in the range of 5 to 60 mpy.3 9' 19 However,

cases have been identified with localized corrosion rates significantly greater, in excess of 400 mpy. There is

general agreement that higher AC current density leads to greater risk of AC corrosion. While higher current

density may lead to accelerated corrosion rates, the correlation is not simple or direct.

International Standards

Review and comparison of multiple international standards identified the consistencies and variations across

accepted industry standards.

Recent laboratory and field work has focused on the interaction between AC and DC current density in

determining overall risk of AC corrosion, and the latest European standards reflect this as discussed in

Section 3.3.1.1.15 However, there is no generally accepted method of correlating current density or any

other measurable indicator to an expected corrosion rate. A direct method of approximating the AC corrosion

rate using a buried coupon or probe would provide accurate information.

The Canadian Standards Association (CSA), NACE International (NACE), and the European Committee for

Standardization (CEN) have developed published standards addressing HVAC interference issues, as below:

• CAN/CSA-C22.3 No. 6-13 "Principles and Practices of Electrical Coordination Between Pipelines and

Electric Supply Lines

• NACE SP0177-2014 "Mitigation of Alternating Current and Lightning Effects on Metallic Structures

and Corrosion Control Systems

• CEN EN 50443:2012 "Effects of Electromagnetic Interference on Pipelines Caused by High Voltage

AC Electric Traction Systems and/or High Voltage AC Power Supply Systems"

• CEN EN 15280:2013 "Evaluation of AC Corrosion likelihood of buried pipelines applicable to

cathodically protected pipelines"

Of these standards, the first three primarily discuss safety issues, interference effects, and mitigation

systems but do not explicitly address criteria for AC corrosion control. The European Standard

EN15280:2013 deals specifically with corrosion due to AC interference, and establishing criteria or tolerable

limits for interference effects, as presented in Section 3.3.1.1.

NACE Standard Practice 5P0177-2014, Mitigation of Alternating Current and Lightning Effects on Metallic

Structures and Corrosion Control Systems, addresses problems caused primarily by the proximity of metallic

57 000115

structures to AC power transmission systems. In this standard practice document, SP0177-2014 defines a

steady state touch voltage of 15 volts or more with respect to local earth at above-grade or exposed

sections and appurtenances to constitute a shock hazard. Findings presented in the standard indicate the

average hand-to-hand or hand-to-foot resistance for adult male ranges from 600 ohms to 10,000 ohms.

NACE uses "a reasonable safe value" of 1,500 ohms (hand-to-hand or hand-to-foot) for estimating body

currents. Based upon work by C.F. Dalziel regarding muscular contraction, SP0177-2014 indicates the

inability to release contact occurs between 6 mA and 20 mA for adult males.1° Ten milliamps (hand-to-hand

or hand-to-foot) is recognized as the maximum safe let-go current. This 15-volt safety threshold is therefore

determined based upon 1,500 ohms hand-to-hand or hand-to-foot resistance and an absolute maximum let-

go current of 10 mA. However, under certain circumstances, an even lower value is required. One such

circumstance specifically identified where a lower touch potential safety threshold should be considered is

"areas (such as urban residential zones or school zones) in which a high probability exists that children (who

are more sensitive to shock hazard than are adults) can come in contact with a structure under the influence

of induced AC voltage."1° This standard practice document requires remedial measures to reduce the touch

potential on the pipeline where shock hazards exist.

During construction of metallic structures in regions of AC interference, SP0177-2014 requires minimum

protective requirements of the following:

• "On long metallic structures paralleling AC power systems, temporary electrical grounds shall be

used at intervals not greater than 300 m (1,000 feet), with the first ground installed at the

beginning of the section. Under certain conditions, a ground may be required on individual structure

joints or sections before handling."

• "All temporary grounding connections shall be left in place until immediately prior to backfilling.

Sufficient temporary grounds shall be maintained on each portion of the structure until adequate

permanent grounding connections have been made."

The intent of the temporary grounds is to reduce AC potentials on the structure, and thus the shock hazard

to personnel during construction. 5P0177-2014 advises against direct connections to the electrical utility's

grounding system during construction as this could actually increase the probability of a shock hazard to

personnel.

Regarding AC corrosion, there are no established criteria for AC corrosion control provided in SP0177-2014.

Further, this standard states that the subject of AC corrosion is "not quite fully understood, nor is there an

industry consensus on this subject. There are reported incidents of AC corrosion on buried pipelines under

specific conditions, and there are also many case histories of pipelines operating under the influence of

induced AC for many years without any reports of AC corrosion."

While not a Standard Practice document, NACE published "AC Corrosion State-of-the-Art: Corrosion Rate,

Mechanism, and Mitigation Requirements"1 in 2010, providing guidance for evaluating AC current density,

and providing recommended limits as discussed in Section 3.3.1.1.

The State-of-the-Art report also cites European Standard CEN/TS 15280:200615, which previously offered

the following guidelines related to the likelihood of AC corrosion:

'The pipeline is considered protected from AC corrosion if the root mean square (RMS) AC density is

lower than 30 A/m2 (2.8 Afit2).

58 000116

In practice, the evaluation of AC corrosion likelihood is done on a broader basis:

• Current density lower than 30 A/m2 (2.8 A/ft2): no or low likelihood;

• Current density between 30 and 100 A/m2 (2.8 and 9.3 A/ft2): medium likelihood; and

• Current density higher than 100 A/m2 (9.3 Afit2): vety high likelihood"

EN 15280:2013

The latest revision of EN 15280:2013 was revised to present criteria based upon the AC interference and DC

current due to CP. EN 15280:2013 presents using the cathodic protection system of the pipeline to ensure

the levels of induced AC potential do not cause AC corrosion under the following conditions:

1. AC voltage on the pipeline should be decreased to a target value, which should be less than 15 V

(measured over a representative time period, i.e. 24 hr)

2. Effective AC corrosion mitigation can be achieved while maintaining cathodic protection criteria as

defined in EN 12954:2001

3. One of the following conditions is satisfied in addition to items 1 and 2:

o Maintain AC current density (RMS) over a representative period of time (i.e. 24 hr) less than

30 A/m2 (2.8 A/ft2) on a lcm2 coupon or probe

o If AC current density is greater than 30 A/m2 (2.8 A/ft2), maintain the average cathodic (DC)

current density over a representative period of time (i.e. 24 hr) less than 1 A/m2 on a lcm2

coupon or probe

o Maintain a ratio between AC current density and DC current density (JAc/JDC) less than 5

over a representative period of time (i.e. 24 hr)

The NACE State-of-the-Art report also references experimental studies by Yunovich and Thompson that concluded

"AC density discharge on the order of 20 A/m2 (1.9 Afit2) can produce significantly enhanced

corrosion (higher rates of penetration and general attack without applied CP). Further, the authors

stated that there likely was not a theoretical 'safe' AC density (i.e., a threshold below which AC does

not enhance corrosion); however, a practical one for which the increase in corrosion because AC is

not appreciably greater than the free-corrosion rate for a particular soil condition may exist."1

59

000117

APPENDIX B COATING RESISTANCE ESTIMATES

000118

Pipe Coating Conductance/Resistance

Pipe Line Corrosion and Cathodic Protection, Marshall E. Parker & Edward G. Peattie

No . Coating Quality

Soil Resistivity

Conductance Range

Resistance Range

umhos/ft2 ohm-m' ohm-ft2 Kohm-ft2

1 Excellent High 1 10 92,903 9,290 1,000,000 100,000 1,000 100

2 Good High 10 50 9,290 1,858 100,000 20,000 100 20

3 Excellent Low 50 100 1,858 929 20,000 10,000 20 10 4 Good Low 100 250 929 372 10,000 4,000 10 4

5 Average Low 250 500 372 186 4,000 2,000 4 2

6 Poor Low 500 1,000 186 93 2,000 1,000 2 1

PRCI

No. Coating Quality

Soil Resistivity (ohm-m)

Coating Resistance (Kohm-ft2)

1 Excellent 25 Multiply Soil Resistivity (ohm-m) by 5 5 125

Excellent 50 Multiply Soil Resistivity (ohm-m) by 5 5 250

Excellent 200 Multiply Soil Resistivity (ohm-m) by 5 5 1,000

Excellent 600 Multiply Soil Resistivity (ohm-m) by 5 5 3,000

2 Good 25 Multiply Soil Resistivity (ohm-m) by 2 2 50

Good 50 Multiply Soil Resistivity (ohm-m) by 2 2 100

Good 200 Multiply Soil Resistivity (ohm-m) by 2 2 400

Good 600 Multiply Soil Resistivity (ohm-m) by 2 2 1,200

3 Fair 25 Multiply Soil Resistivity (ohm-m) by 0.5 0.5 13

Fair 50 Multiply Soil Resistivity (ohm-m) by 0.5 0.5 25

Fair 200 Multiply Soil Resistivity (ohm-m) by 0.5 0.5 100

Fair 600 Multiply Soil Resistivity (ohm-m) by 0.5 0.5 300

000119 61

APPENDIX C MITIGATION COMPARISON SUMMARY

000120

Zinc Ribbon

Advantages • Can typically be installed during pipeline construction minimizing installation costs • Cost of raw material is typically one third the cost of copper • Can be trenched or plowed in relatively inexpensively after pipeline installation • Typically results in very low resistances • Historically has performed as intended • Surface mitigation ribbon can double as shielding for fault mitigation

Disadvantages • Zinc clad ribbon is more difficult to work with compared to copper • Life expectancy is generally less than comparable copper installation

Copper Cable Advantages

• Can typically be installed during pipeline construction minimizing installation costs • Can be trenched or plowed in relatively inexpensively after pipeline installation • Typically results in very low resistances • Historically has performed as intended • Surface mitigation cable can double as shielding for fault mitigation • Depending on the size cable the material cost of a copper installation can be lower than a zinc

installation Disadvantages

• Cost of raw material is typically higher than the cost of zinc • Risk of having a more noble metal (cathodic) near or connected to pipeline even if through a

decoupler

Deep Grounding (anodes used as the ground) Advantages

• May be advantageous when surface resistivity is extremely high Disadvantages

• Typically high cost for both installation and materials • Generally not suitable for mitigating ground potential rises (GPR) or arcing issues associated

with faults

Shallow Grounding (driven ground rods or bored ribbon or cable) Advantages

• Can be used to supplement horizontal ribbon or cable installation if required • Magnitude of the surface resistivity affects the resistance

Disadvantages • Generally not suitable for mitigating ground potential rises (GPR) or arcing issues associated

with faults

Engineered mitigation and/or Additives (no specific product identified) Advantages

• Could increase design life Disadvantages

• Typically increases the material costs

Notes: 1) These are typical statements and there are instances where they do not apply. 2) All mitigation installations are considered connected through a decoupling device such that there is

no direct passage of DC current to or from the mitigation.

000121 63

APPENDIX D DATA REQUEST TEMPLATE

000122

Company: Project: Project Number:

Hicih Volta e Alternatin Current HVAC Power Transmission Parameters

General 1 Owner: 2 Power transmission voltage (kV): 3 Average Tower Span (feet)

4 Substation ground grid impedance (ohms): Phase Wires

5 No. of circuits: 6 Circuit type:

Conductors: 7 No. 1 average height (ft):

8 No. 1 average horizontal distance (ft): 9 No. 1 phasing (degrees):

10 No. 2 average height (ft): 11 No. 2 average horizontal distance. (ft): 12 No. 2 phasing (degrees): 13 No. 3 average height (ft): 14 No. 3 average horizontal distance (ft):

15 No. 3 phasing (degrees):

16 Other: Cable Sag, Lowest point (feet):

Circuit Loading 17 Peak loading (amps): 18 Emergency loading (amps): 19 Emergency loading time (hours):

Shield Wires 20 No. of conductors: 21 No. 1 type: 22 No. 1 conductor GMR (ft): 23 No. 1 conductor resistance (ohms/mil): 24 No. 1 average height (ft): 25 No. 1 average horizontal distance (ft): 26 No.2 type: 27 No. 2 conductor GMR (ft): 28 No. 2 conductor resistance (ohms/mil): 29 No. 2 average height (ft): 30 No. 2 average horizontal distance (ft):

Fault Current Parameters 31 Fault clearing time (cycles): 32 Average tower resistance (ohms):

33 Beginning of Collocation: Total from left substation

from right substation

34 Middle of Collocation: Total from left substation

from right substation

35 End of Collocation: Total from left substation

from right substation

000123 65

Company: Project: Project Number:

Pipeline Parameters

NO, iniorniation Rsquestid 1, „. :''''•'• ..., , -',-)..y s, ' : Pipolini 1" PlpeJhe 2 „

'Pipenrio 3

1 General Pipeline number:

2 Pipeline owner: 3 Pipeline name: 4 Product transported: 5 Diameter (in.): 6 Burial depth (ft.): 7 Wall Thickness (inch): 8 Length of Collocation (feet/miles):

_ _Coatings 9 Coating type (majority):

10 Coating resistance (kohm-ft2): 11 Coating thickness (mils):

Cathodic Protection 12 Location of cathodic protection: 13 Resistance of cathodic protection groundbed(s): 14 Bonding to foreign pipelines? (Y/N): 15 Existing AC mitigation measures? (Y/N): 16 Describe existing AC mitigation:

66 000124

Exhibit C

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NACE SP0177-2014 (formerly RP0177)

$ `••• I INTERNATIONAL

tem No. 21021

Mitigation of Alternating Current and Lightning Effects on Metallic Structures

and Corrosion Control 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 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 assumes no responsibility for the interpretation or use of this standard by other parties and accepts responsibility for only those official NACE interpretations issued by NACE in accordance with its governing procedures and policies which preclude the issuance of interpretations by individual volunteers.

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

Revised 2014-03-08 Revised 2007-06-22

Reaffirmed 2000-09-19 Revised March 1995 Revised July 1983

Approved July 1977 NACE International

1440 South Creek Drive Houston, Texas 77084-4906

+ 1 281-228-6200

ISBN 1-57590-116-1 @ 2014, NACE International

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SP0177-2014

Foreword

This standard practice presents guidelines and procedures for use during design, construction, operation, and maintenance of metallic structures and corrosion control systems used to mitigate the effects of lightning and alternating current (AC) power transmission systems. This standard is not intended to supersede or replace existing electrical safety standards. As shared right-of-way and utility corridor practices become more common, AC influence on adjacent metallic structures has greater significance, and personnel safety becomes of greater concern. This standard addresses problems primarily caused by proximity of metallic structures to AC-powered transmission systems.

The hazards of lightning and AC effects on aboveground pipelines, while strung along the right-of-way prior to installation in the ground, are of particular importance to pipeline construction crews. The effects of AC power lines on buried pipelines are of particular concem to operators of aboveground appurtenances and cathodic protection (CP) testers, CP designers, safety engineers, as well as maintenance personnel working on the pipeline.

Some controversy arose in the 1995 issue of this standard regarding the shock hazard stated in Section 5, Paragraph 5.2.1.1 and elsewhere in this standard. The reason for a more conservative value is that early work by George Bodierl at Columbia University and by other investigators has shown that the average hand-to-hand or hand-to-foot resistance for an adult male human body can range between 600 ohms and 10,000 ohms. A reasonable safe value for the purpose of estimating body currents is 1,500 ohms hand-to-hand or hand-to-foot. In other work by C.F. Dalziel2 on muscular contraction, the inability to release contact occurs in the range of 6 to 20 mA for adult males. Ten mA hand-to-hand or hand-to-foot is generally established as the absolute maximum safe let-go current. Conservative design uses an even lower value. Fifteen volts of AC impressed across a 1,500 ohm load would yield a current flow of 10 mA; thus, the criterion within this standard is set at 15 volts. Prudent design would suggest an even lower value under certain circumstances.

Many are now concerned with AC corrosion on buried pipelines adjacent to or near overhead electric transmission towers. This subject is not quite fully understood, nor is there an industry consensus on this subject. There are reported incidents of AC corrosion on buried pipelines under specific conditions, and there are also many case histories of pipelines operating under the influence of induced AC for many years without any reports of AC corrosion. The members of NACE Task Group (TG) 025 agreed that criteria for AC corrosion control should not be included in this standard. However, the mitigation measures implemented for safety and system protection, as outlined in this standard, may also be used for AC corrosion control.

This standard was originally published in July 1977 by Unit Committee T-10B on Interference Problems and was technically revised in 1983 and 1995, and reaffirmed in 2000 by T-10B. NACE continues to recognize the need for a standard on this subject. Future development and field experience should provide additional information, procedures, and devices for Specific Technology Group (STG) 05, "Cathodic/Anodic Protection," to consider in future revisions of this standard. This standard was revised in 2007 and 2014 by TG 025, "Alternating Current (AC) Power Systems, Adjacent: Corrosion Control and Related Safety Procedures to Mitigate the Effects." It is sponsored by STG 03, "Coatings and Linings, Protective—Immersion and Buried Service," and STG 35, "Pipelines, Tanks, and Well Casings." This standard is issued by NACE under the auspices of STG 05.

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 terrn may is used to state something considered optional.

NACE International

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SP0177-2014

Mitigafion of Alternating Current and Lightning Effects on Metallic Structures

and Corrosion Control Systems

Contents

1. General 1 2. Definitions 1 3. Exposures and Effects of Alternating Current and Lightning 3 4. Design Considerations for Protective Measures 5 5. Personnel Safety 15 6. AC and Corrosion Control Considerations 19 7. Special Considerations in Operation and Maintenance of Cathodic Protection and

Safety Systems 21 References 22 Bibliography 23 Appendix A: Wire Gauge Conversions 24 FIGURES Figure 1: Approximate Current Required to Raise the Temperature of Stranded Annealed

Soft-Drawn Copper Cable 9 Figure 2: Allowable Short-Circuit Currents for Insulated Copper Conductors 11 Figure 3: Allowable Short-Circuit Currents for Insulated Copper Conductors 12 Figure 4: Zinc Ribbon Ampacity 13 TABLES Table 1: Maximum 60 Hz Fault Currents—Grounding Cables 8 Table 2: Average Impedance for Various Conductor Sizes 10 Table 3: Human Resistance to Electrical Current 16 Table 4: Approximate 60-Hz Alternating Current Values Affecting Human Beings 16 Table A1: Wire Gauge Conversions 24

ii NACE International

000129

SP0177-2014

Section 1: General

1.1 This standard presents acknowledged practices for the mitigation of AC and lightning effects on metallic structures and corrosion control systems.

1.2 This standard covers some of the basic procedures for determining the level of AC influence and lightning effects to which an existing metallic structure may be subjected and outlines design, installation, maintenance, and testing procedures for CP systems on structures subject to AC influence, primarily caused by proximity of metallic structures to AC power transmission systems. However, this standard is not intended to be a design guide or a "how-to" engineering manual to perform AC interference studies or mitigation designs.

1.3 This standard does not designate procedures for any specific situation. The provisions of this standard should 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 professional education and related practical experience, are qualified to engage in the practice of corrosion control on metallic structures. Such persons may be registered professional engineers or persons recognized as being qualified and certified as corrosion specialists by NACE, if their professional activities include suitable experience in corrosion control on metallic structures and AC interference and mitigation.

1.4 This standard should be used in conjunction with the references contained herein.

Section 2: Definitions

2.1 Definitions presented in this standard pertain to the application of this standard only. Reference should be made to other industry standards when appropriate.

AC Exposure: Alternating voltages and currents induced on a structure because of the AC power system.

AC Power Structures: The structures associated with AC power systems.

AC Power System: The components associated with the generation, transmission, and distribution of AC.

Affected Structure: Pipes, cables, conduits, or other metallic structures exposed to the effects of AC or lightning.

Bond: A low-impedance connection (usually metallic) provided for electrical continuity.

Breakdown Voltage: A voltage in excess of the rated voltage that causes the destruction of a barrier film, coating, or other electrically isolating material.

Capacitive Coupling: The influence of two or more circuits upon one another, through a dielectric medium such as air, by means of the electric field acting between them.

Circular Mil: A unit of area of round wire or cable equal to the square of the diameter in mils (1 mil = 0.0254 mm = 25.4 pm).

Coating Stress Voltage: Potential difference between the metallic surface of a coated structure and the earth in contact Wth the outer surface of the coating.

Coupling: The association of two or more circuits or systems in such a way that energy may be transferred from one to another.

Dead-Front Construction: A type of construction in which the energized components are recessed or covered to preclude the possibility of accidental contact with elements having electrical potential.

Electric Field: One of the elementary energy fields in nature. It occurs in the vicinity of an electrically charged body.

Electric Potential: The voltage between a given point and a remote reference point.

NACE International 1

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SP0177-2014

Electrolytic Grounding Cell: A device consisting of two or more buried electrodes installed at a fixed spacing, commonly made of zinc, and resistively coupled through a prepared backfill mixture. The electrical characteristics of a grounding cell include a small degree of resistance and a subsequent reduced voltage drop across the cell during a fault condition.

Fault Shield: Shallow grounding conductors connected to the affected structure adjacent to overhead electrical transmission towers, poles, substations, etc., to provide localized protection to the structure and coating during a fault event from nearby electric transmission power systems.

Gradient Control Mat: A system of bare conductors connected to the affected structure and placed on or below the surface of the earth, usually at above grade or exposed appurtenances, arranged and interconnected to provide localized touch-and-step voltage protection. Metallic plates and grating of suitable area are common forms of ground mats, as well as conventional bare conductors closely spaced.

Gradient Control Wire: A continuous and long grounding conductor or conductors installed horizontally and parallel to the affected structure at strategic lengths and connected at regular intervals to provide protection to the structure and coating during steady-state and fault AC conditions from nearby electric transmission power systems.

Ground: An electrical connection to earth.

Ground Current: Current flowing to or from earth in a grounding circuit.

Grounded: Connected to earth or to some extensive conducting body that serves instead of the earth, whether the connection is intentional or accidental.

Grounding Grid: A system of grounding electrodes consisting of interconnected bare conductors buried in the earth to provide a common electrical ground.

Ground Potential Rise: Ground Potential Rise or Earth Potential Rise (as defined in IEEE(1) Standard 367)3 is the product of a ground electrode impedance, referenced to remote earth, and the current that flows through that electrode impedance. This occurs when large amounts of electricity enter the earth. This is typically caused when substations or high-voltage towers fault, or when lightning strikes occur (fault current). When currents of large magnitude enter the earth from a grounding system, not only does the grounding system rise in electrical potential, but so does the surrounding soil. The resulting potential differences cause currents to flow into any and all nearby grounded conductive bodies, including concrete, pipes, copper wires, and people.

Inductive Coupling: The influence of two or more circuits on one another by means of changing magnetic flux linking them together.

Let-Go Threshold Current: Maximum value of electric current through the body of a person at which that person can release himself or herself.

Lightning: An electric discharge that occurs in the atmosphere between clouds or between clouds and the earth.

Load Current: The current in an AC power system under normal operating conditions.

Lumped Grounding: Localized grounding conductors, either shallow or deep, connected to the affected structure at strategic locations to provide protection to the structure and coating during steady-state and fault AC conditions from nearby electric transmission power systems.

Magnetic Field: One of the elementary energy fields in nature. It occurs in the vicinity of a magnetic body or current-carrying medium.

Over-Voltage Protector (Surge Arrester): A device that provides high resistance to direct current (DC) and high impedance to AC under normal conditions within the specified DC and AC threshold rating and "closee or has a very low resistance and impedance during upset conditions.

Potential: See Electric Potential.

(I) Institute of Electrical and Electronics Engineers (IEEE), Three Park Avenue, 17th Floor, New York: NY 10016-5997.

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Potential Gradient: Change in the potential with respect to distance.

Reclosing Procedure: A procedure that normally takes place automatically whereby the circuit breaker system protecting a transmission line, generator, etc., recloses one or more times after it has tripped because of abnorrnal conditions such as surges, faults, lightning strikes, etc.

Resistive Coupling: The influence of two or more circuits on one another by means of conductive paths (metallic, semi-conductive, or electrolytic) between the circuits.

Shock Hazard: A condition considered to exist at an accessible part in a circuit between the part and ground or other accessible part if the steady-state open-circuit AC voltage is 15 V or more (root mean square [rms]). For capacitive build-up situations, a source capacity of 5 mA or more is recognized as a hazardous condition. For short-circuit conditions, the permissible touch-and-step voltages shall be determined in accordance with the methodology specified in accordance with IEEE Standard 80,4 or equivalent standard.

Solid-State DC Decoupler: A dry type of DC decoupling device comprising solid-state electronics. The electrical characteristics of a solid-state decoupler are high resistance to low-voltage DC and low impedance to AC.

Step Potential or Step Voltage: The potential difference between two points on the earth's surface separated by a distance of one human step, which is defined as one meter, determined in the direction of maximum potential gradient.

Switching Surge: The transient wave of potential and current in an electric system that results from the sudden change of current flow caused by a switching operation, such as the opening or closing of a circuit breaker.

Touch Potential or Touch Voltage: The potential difference between a metallic structure and a point on the earth's surface separated by a distance equal to the normal maximum horizontal reach of a human (approximately 1.0 m [3.3 ft]).

Varistor: A shunt mode device with a nonlinear current-voltage characteristic used to protect circuits against excessive transient voltages, and is non-conductive during normal operations when the voltage across it remains well below its clamping (i.e., let-through) voltage.

Voltage: The difference in electrical potential between two points.

Section 3: Exposures and Effects of Altemating Current and Lightning

3.1 Introduction

3.1.1 This section outlines the physical phenomena by which AC, AC power systems, and lightning can affect metallic structures.

3.2 Resistive Coupling (Electrolytic)

3.2.1 Grounded structures of an AC power system share an electrolytic environment with other underground or submerged structures. Coupling effects may transfer AC energy to a metallic structure in the earth in the form of alternating current or potential. Whenever a power system with a grounded neutral has unbalanced conditions, current may flow in the earth. Substantial currents in the earth may result from phase-to-phase-to-ground or phase-to-ground faults. A metallic structure in the earth may carry part of this current. Also, a structure in the earth coated with a dielectric material may develop a significant AC potential across the coating.

3.2.2 Resistive coupling is primarily a concern during a short-circuit condition on a power system, for example, when a large part of the current in a live conductor flows into the earth by means of the foundations and grounding system of a tower, pole, or substation. This current flow raises the electric potential of the earth near the structure, often to thousands of volts with respect to remote earth, and can result in a considerable stress voltage across the coating (see Paragraph 4.13) of a long metallic structure, such as a pipeline. This can lead to arcing that damages the coating, or even the structure itself. This difference in potential between the earth and the structure can represent an electric shock hazard. The effect of resistive coupling is usually concentrated in the vicinity of each of the first few power system poles or towers nearest the short-circuit location and near any substations involved in the short circuit. Under some circumstances, the electric potential of the structure may be raised enough to transfer hazardous potentials over considerable distances, particularly if the structure is well coated. Resistive coupling effects are strongly dependent on a number of factors, the most important of which are:

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(a) The total short-circuit current;

(b) The power line overhead ground wire type and length back to the source;

(c) The size of the foundations and grounding systems of the poles, towers, or substations through which the current is flowing;

(d) The electrical resistivity of the soil as a function of depth; and

(e) Separation distance between power systems and the affected metallic structure.

The electrical layering of the soil alone can easily change resistive coupling effects by an order of magnitude or more.

3.3 Capacitive Coupling

3.3.1 The electric field associated with power conductors causes a well-defined current to flow continuously between a nearby aboveground metallic structure and the earth, whether that aboveground structure is grounded or simply suspended in the air. This current flows from the structure to the earth partially through the air as a displacement current and partially through conductive or semi-conductive paths such as deliberate grounds, wooden supports, or human beings touching the structure. The magnitude of the total current flowing from the structure is a function of the size of the structure, its proximity to the power conductors, the voltage level of the power conductors, and their geometrical arrangement. The total current flowing between the metallic structure and earth distributes itself between the different available paths to earth in direct proportion to the relative conductivity of each path. For example, a 100 ohm ground rod would carry 10 times as much current to earth as a 1,000 ohm human being, thus reducing the magnitude of the available shock current by a factor of 10. Capacitive coupling is typically a hazard during construction with respect to electric shock or arcing when the structure is on insulating supports prior to lowering in or connecting to an adjacent section. Ground rods and bonding often provide sufficient protection. The need for additional grounding may be verified with a simple voltmeter test.

3.4 Inductive Coupling

3.4.1 AC flow in power conductors produces an alternating magnetic field around these conductors, thereby inducing AC potentials and current flow in an adjacent structure. The magnitude of the induced potential depends on many factors. The most important are:

(a) The overall separation distance between the structure and the power line;

(b) The length of exposure and the power line current magnitude;

(c) Changes in the arrangement of power line conductors or in separation distance;

(d) The degree to which current flowing in one power line conductor is balanced by the currents flowing in the others because of conductor arrangement and current distribution;

The type of conductor used for the lightning shield wires on the power line;

The coating resistance of the structure;

The grounding present on the structure; and

The soil resistivity as a function of depth.

3.4.2 Grounding is usually present to some degree because of leakage across the coating or anodes of the CP system connected to the structure. Induced voltages increase in magnitude during fault conditions. The coating stress voltages caused by the inductive coupling near a short-circuit location tend to reinforce those caused by resistive coupling; therefore, both factors must be considered. The same is true for touch-and-step voltages. Hazardous induced potentials can easily extend over distances of many kilometers (miles), both within a power line corridor and beyond the extremities of the corridor. Considerable power may be transferred to a structure by means of inductive coupling and can result in currents of tens or even hundreds of amperes flowing in the structure during peak power system operating conditions, and thousands of amperes during short-circuit conditions. Potential peaks tend to occur at locations in which there are abrupt changes in the parameters. These are usually locations in which power lines and structures deviate away from or cross one another at

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substations or at power line phase transposition locations. Installing grounding at one location can make matters significantly worse elsewhere; therefore, the whole system should be carefully considered when designing mitigation.

3.5 Power Arc

3.5.1 During a fault-to-ground on an AC power system, the AC power structures and surrounding earth may develop a high potential with reference to remote earth. A long metallic structure, whether coated or bare, tends to remain at remote earth potential if not running parallel to the AC power lines. Worse still, if the structure runs parallel to the AC power lines, the induced potential on the structure tends to be opposite in polarity to the earth potential near the fault location at any given instance in time. Either way, if the resulting voltage to which the structure is subjected exceeds the breakdown voltage of any circuit element, a power arc can occur, damaging the circuit elements. Elements of specific concem include coatings, isolating fittings, bonds, lightning arresters, and CP facilities. If the potential gradient in the earth is large enough to ionize the soil for a finite distance, a direct arc from the power system ground to the structure may occur within that distanœ and result in coating damage, arc burn, or puncture/failure of the structure.

3.6 Lightning

3.6.1 Lightning strikes to the power system can initiate fault current conditions. Lightning strikes to a structure or to earth in the vicinity of a structure may produce electrical effects similar to those caused by AC fault currents. Lightning may strike a metallic structure at some point remote from AC power systems, also with deleterious effects.

3.7 Switching Surges or Other Transients

3.7.1 A switching surge or other transient may generate abnormally high currents or potentials on a power system, causing a momentary increase in inductive and capacitive coupling on the affected structures.

Section 4: Design Considerations for Protective Measures

4.1 Introduction

4.1.1 This section describes various protective measures used to help mitigate AC effects on metallic structures subject to hazardous AC conditions, minimize damage to the structures, and reduce the electrical hazard to people coming in contact with these structures.

4.1.2 The measures listed may be used to mitigate the problems of power arcing, lightning arcing, resistive coupling, inductive coupling, and capacitive coupling.4'" These measures may also be used to mitigate AC corrosion.

4.1.3 Design considerations should include steady-state conditions (including touch voltage and maximum pipe potentials during normal, emergency, and future loads) and fault conditions (including touch-and-step voltage, avoidance of pipe wall puncture and arc burns, and tolerable coating stress voltages).

4.1.4 Design mitigation objectives should be clearly defined. As a minimum, the mitigation objectives should include the maximum steady-state voltage at above-grade portions and appurtenances, maximum pipe potential (ground potential rise [GPR]) for the normally buried and inaccessible portions, touch-and-step voltage criteria at above-grade portions and appurtenances during fault conditions, and the maximum coating stress voltage during fault conditions.

4.2 Fault Shields, Lumped Grounding, and Gradient Control Wires

4.2.1 Fault shields consist of shallow grounding conductors (i.e., electrodes) connected to the affected structure adjacent to overhead electrical transmission towers, poles, substations, etc. They are intended to provide localized protection to the structure and coating during a fault event from a nearby electric transmission power system. Fault shields may reduce the possibility of damaging the coating or structure under fault conditions.

4.2.2 Lumped grounding consists of a localized conductor or conductors connected to the affected structure at strategic locations (e.g., at discontinuities). It is intended to protect the structure from both steady-state and fault AC conditions. Lumped grounding systems may be installed in shallow or deep configurations, depending on the site-specific parameters. Lumped grounding may reduce the steady-state touch voltages and the possibility of damaging the coating or structure under fault conditions; however, grounding between the lumped grounding locations may be required for complete protection.

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4.2.3 Gradient control wires consist of a continuous and long grounding conductor or conductors installed horizontally and parallel to a structure (e.g., pipeline section) at strategic lengths and connected at regular intervals. They are intended to provide protection to the structure and coating during steady-state and fault AC conditions from nearby electric transmission power systems. Gradient control wires may reduce the steady-state voltages and the possibility of damaging the coating or structure under fault conditions.

4.2.4 Among the factors that influence mitigation design is the extent to which the structure is affected and the magnitude of the electrical potential between the structure and earth. These factors vary from one location to another and must be calculated or determined for each specific location. A combination of the above methods may be utilized, depending on the specific AC mitigation requirements.

4.2.5 Electrodes constructed of materials that are cathodic to the protected structure must be connected to the structure through a DC decoupling device, unless both the structure and electrode are cathodically protected as a single unit. Electrodes constructed of materials that are anodic to the protected structure may be connected directly to the structure; however, the CP design and monitoring requirements must be verified to be compatible with this type of circuitry.

4.2.6 Other types of systems may be designed for protection against faults on miscellaneous underground or aboveground structures, including measures implemented by the electric power line operator or utility.

4.3 Gradient Control Mats

4.3.1 Gradient control mats, bonded to the structure, are used to reduce electrical touch-and-step voltages in areas where people may come in contact with a structure subject to hazardous potentials. Permanent mats bonded to the structure may be used at valves, metallic vents, CP test stations, and other aboveground metallic and nonmetallic appurtenances in which electrical contact with the affected structure is possible.

4.3.2 Gradient control mats shall be large enough to extend through and beyond the entire area on which people may be standing when contacting the affected structure. They shall be installed close enough to the surface to adequately reduce touch-and-step voltages for individuals coming in contact with the structure.6 Gradient control mats shall be engineered to provide acceptable touch-and-step voltages during both load and fault conditions, accounting for the local soil conditions.

4.3.3 Gradient control mats, regardless of materials of construction, must be bonded to the structure. Good grounding practice suggests a minimum of two (2) connections to the protected structure. If CP of the structure becomes difficult because of shielding, a DC decoupling device may be installed. Connections to the structure should be made aboveground to allow a means of testing for the effect of the gradient control mat in reducing AC potentials and its effectiveness on the CP system. Care should be taken to prevent the possible establishment of detrimental galvanic cells between the gradient control mat and structures that are not cathodically protected.

4.3.4 A bed of clean, well-drained gravel can reduce the shock hazard associated with touch-and-step voltages. Although an excellent practice, if hazardous conditions exist for pipeline applications, increasing the surface resistance should be used to augment the grounding system and not as a sole protection measure, as it may not be well maintained and kept clean. The thickness of the bed should be no less than 76 mm (3.0 in). Gravel should be a minimum of 13 mm (0.50 in) in diameter. The hazards of step voltages at the edge of a mat may be mitigated by extending the gravel beyond the perimeter of the grounding mat.

4.4 Independent Structure Grounds

4.4.1 Wherever a metallic structure subject to hazardous AC that is not electrically connected to an existing grounded structure is installed, it shall have an independent grounding system. This grounding system may consist of one or more ground rods and interconnecting wires. Care shall be taken to interconnect all components of the structure to be grounded properly. Factors considered in the design of the grounding system of an independent structure include the resistivity of the soil and the magnitude of the induced potential and current that the designer expects the structure to encounter under all possible conditions.

4.4.2 When an independent metallic structure or its grounding system is in close proximity to an existing grounded structure, an electrical hazard may develop for any person contacting both structures or their grounds simultaneously. In such cases, both grounding systems shall be connected, either directly or through a DC decoupling device, unless it is determined that such a connection is undesirable. The electrical and CP designers should both be involved with this evaluation. For more details on designing systems for independent structures, see IEEE Standard 80.4

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4.5 Bonding to Existing Structures

4.5.1 One available means of reducing induced AC potentials on a structure involves bonding the structure to the power system ground through adequately sized cables and decoupling devices. Such bonds may, under fault conditions, contribute to increased potentials and currents on the affected structure for the duration of the fault. If the bonded structure is aboveground, or well-insulated from earth, elevated potentials may be created and exist temporarily along the entire length of the bonded structure. In such instances, additional protective devices may be required outside the immediate area of the origin of electrical effects. Close coordination should be maintained with all other utilities in the area, especially with those utilities to which bond connections are proposed. The corresponding utilities shall be notified in advance of the need to bond to their structures and shall be furnished with details of the proposed bonding arrangements. A utility may prefer to have the connection to its structures made by its own personnel. Other methods of reducing AC potentials should be considered before committing to bonding. The increased hazards during fault conditions and extra installation requirements may make this method questionable from safety and economic perspectives.

4.5.2 Whenever such a bond is installed, full consideration must be given to mitigation of hazardous AC transferred to the influenced structure.

4.6 Distributed Anodes

4.6.1 Whenever distributed galvanic anodes are used as part of the grounding system to reduce the AC potential between a structure and earth, they should be installed in close proximity to the protected structure and away from power system grounds. Connecting anodes directly to the affected structure, without test connections, may be desirable. However, the CP design and monitoring requirements must be verified to be compatible with this type of circuitry. Direct connection reduces the number of points at which people can come in contact with the structure and offers the shortest path to ground. If it is desirable for measurement purposes to open the circuit between the distributed grounding system and the structure, the test lead connection should be made in an accessible dead-front test box. When galvanic anodes are used as part of a grounding system, the useful life of the electrode material should be considered. Norrnal deterioration and consumption of the anode material increases the grounding system resistance.

4.7 Casings

4.7.1 Bare or poorly coated casings may be deliberately connected to a coated structure through a DC decoupling device to lower the impedance of the structure to earth during steady state and surge conditions and to avoid arcing between the structure and the casing. Any exposed and accessible portion, including metallic casing vents, should be considered as an aboveground appurtenance.

CAUTION: Choosing not to interconnect a pipeline to a casing through a DC decoupler on a pipeline subjected to AC interference could result in accelerated AC corrosion at holidays in a coating on a carrier pipe.

4.8 Connector (Electrical and Mechanical) and Conductor Sizes

4.8.1 All anodes, bonds, grounding devices, and jumpers must have secure, reliable, low-resistance connections to themselves and to the devices to which they are attached. Structure members with rigid bolted, riveted, or welded connections may be used in lieu of a bonding cable for part or all of the circuit. Steady-state conductor sizing should consider the AC load with the mitigation applied. For adequate fault sizing of conductors, refer to Table 1 and Figures 1, 2, 3, and 4. For wire gauge conversions, refer to Table A1 in Appendix A (nonmandatory). All cables, connections, and structural members should be capable of withstanding the maximum anticipated magnitude and duration of the surge or fault currents with mitigation applied.

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Table 1 Maximum 60 Hz Fault Currents-Grounding Cables(A)

Cable Size

Fault Time rms(61 Amperes Cable Size Fault Time rmst`') Amperes

AWGt") Cycles Copper Aluminum AWG(b) Cycles Copper Aluminum 1 15 10,550 6,500 3/0 15 26,500 16,500

30 7,500 4,600 30 18,500 16,500 60 5,300 3,200 60 13,000 8,000

1/0 15 16,500 10,500 4/0 15 30,000 21,000 30 11,500 7,500 30 21,000 15,000 60 8,000 5,300 60 15,000 10,000

2/0 15 21,000 13,000 250 MCMP

15 35,000 25,000

30 15,000 9,000 30 25,000 17,500 60 10,000 6,500

(A) Based on 30 °C (86 °F) ambient and a total temperature of 175 °C (347 °F) established by the Insulated Cable Engineers Association (ICEA)(2) for short-circuit characteristic calculations for power cables. Values are approximately 58% of fusing currents. (B) American Wire Gauge (AWG). For wire gauge conversions, refer to Table A1 in Appendix A (nonmandatory). (C) Root mean square (D) MCM = 1,000 circular mil

4.8.2 Mechanical connections for the installation of pemianent protective devices should be avoided when practical except when they can be inspected, tested, and maintained in approved aboveground enclosures. When practical, field connections to the structure or grounding device should be made by the exothermic welding process or appropriate pin brazing methods. However, compression-type connectors may be used for splices on connecting wires. Mechanical connectors may be used for temporary protective measures, but extreme care should be taken to avoid high-resistance contacts. Soft-soldered connections are not acceptable in grounding circuits.

Figure 1 is based on the assumption that no heat is radiated or conducted from the cable to the surrounding media during a fault period. Electrical energy released in the cable equals the heat energy absorbed by the cable. This is illustrated in Equation (1):

I2Rt = CFQ (1)

where:

I = fault current in amperes R = average AC resistance (in ohms) of conductor over temperature range T1 to T2 in °C (°F) t = fault duration in seconds Q = heat energy in kJ (BTU) CF = conversion factor = 1,000 for SI units (1 W=J/s and 1,000 J/kJ) and 1,055 for U.S. units (1,055 W-s/BTU)

Q is calculated using Equation (2):

Q = CM (T2- T1) [Thermodynamics] (2)

where:

C = average specific heat in kJ/kg °C (BTU/lb °F) of annealed soft-drawn copper over the temperature range T1 to T2 M = mass of copper in kg (lb) Ti and T2 = initial and final temperatures respectively in °C (°F).

(2) Insulated Cable Engineers Association (ICEA), P.O. Box 1568, Carrollton, GA 30112.

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Figure 1 was developed using C = 0.104 BTU/lb °F, T1 = 68 °F, and T2 = 1,300 °F. Typical resistance values are shown in Table 2.

2 3 4 5 0 7.0 9 A 2 3 4 5 6 7 4010

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Figure 1: Approximate Current Required to Raise the Temperature of Stranded Annealed Soft-Drawn Copper Cable 684 °C (1,232 °F) Above an Ambient Temperature of 20 °C (68 °F)(3)

(3) This figure was developed by Ebasco Services, inc. (now Raytheon Company, 870 Winter St., Waltham, MA 02451), who graciously allowed its publication in the original standard.

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Table 2 Average Impedance for Various Conductor Sizes(A)

Conductorm Average 60 Hz Impedance (Ohms/1,000 ft)

Average 60 Hz Impedance (Ohms/km)

#6 AWG 0.923 3.03 #2 AWG 0.366 1.20

#1/0 AWG 0.2295 0.753 #4/0 AWG 0.1097 0.360 250 MCM 0.0968 0.318 500 MCM 0.0492 0.161

1,000 MCM 0.0259 0.0850 2,000 MCM 0.0151 0.0495 4,000 MCM 0.00972 0.0319

(A) Fusing current is 10% higher than current for 684 °C (1,232 °F) temperature rise. (B) For cable sizes in metric units, see Appendix A.

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Figure 2: Allowable Short-Circuit Currents for Insulated Copper Conductors'

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Figure 3: Allowable Short-Circuit Currents for Insulated Copper Conductors'

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Figure 4: Zinc Ribbon Ampacity(4) Experimental results for 60 Hz current required to raise the temperature of three sizes of cast- and rolled-zinc ribbon anode from 20 °C (68 °F) to 250 °C (482 °F).°

Super: 25.4 mm x 31.75 mm (1 in x 1.25 in) Plus: 15.88 mm x 22.22 mm (0.625 in x 0.875 in) Standard: 12.7 mm x 14.22 mm (0.50 in x 0.56 in)

Note: A design reduction factor should be determined by the user and applied in conjunction with the data in Figure 4, and connections to the ribbon steel core must be equivalent to the design ampacity requirement.

4.9 Isolation Joints

4.9.1 Although isolation joints (including flanges and fittings) can be installed to divide a structure into shorter electrical sections or to isolate a section adjacent to an AC power system from the remainder of the structure, this practice must be considered carefully for the specific application. When used to reduce the length of pipeline exposed to AC at the entrance and exit of AC right-of-ways, the beneficial grounding effect from the remaining pipeline is lost, and AC potentials may increase on the isolated section. The voltage is reduced in proportion to the length of the sections if used in the joint corridor; however, a potential hazard may exist across the isolation joint and as a minimum requires fault protection. Hazardous conditions may be transferred to the other side of isolating devices, where mitigation and protection measures may not be present during a fault even without protection devices. Therefore, the AC interference study and mitigation design shall not ignore pipe sections and appurtenances that are normally DC isolated. DC decouplers or other devices that continuously pass AC should be utilized in most cases of steady-state AC interference. In cases in which the steady-state concerns are low, but faults are a possibility, over-voltage protection devices that close during an electrical disturbance should be provided. The breakdown voltage for a typical isolation joint is in the range of 3 kV; however, arcing can occur at much lower voltages without dielectric breakdown. Arcing conditions must also be avoided in hazardous (classified) locations.

(4) Courtesy of the Platt Bros. and Company, lnc., 2670 S. Main St., Waterbury, CT 06721.

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4.10 Electrolytic Grounding Cells, Solid-State DC Decouplers, Polarization Cells, and Other Devices

4.10.1 The coordinated selection and installation of electrolytic grounding cells, solid-state DC decouplers, polarization cells (2.5 V DC maximum threshold), or other devices between the affected structure and suitable grounds should be considered where arcing and induced AC potentials could develop. These devices may eliminate or greatly reduce the induced potentials resulting during norrnal operation or surge conditions and also reduce the possibility of arcing and structure damage. Polarization cells and solid-state DC decouplers should be considered for steady-state AC interference applications, as these devices pass AC continuously. The device and installation must be rated for the area classification, when installed in a hazardous location.

4.10.2 When polarization cells (2.5V DC maximum threshold), electrolytic grounding cells, solid-state DC decouplers, or other devices are used, they must be properly sized, located, connected, and physically secured in a manner that safely conducts the maximum amount of anticipated surge current. Cables connecting these devices to the structures shall be properly sized, as described in Paragraph 4.8.1. Cables should be kept as short and straight as possible. An adequately sized bypass circuit should be provided prior to any electrical isolation of the grounding device during testing and maintenance.

4.11 Over-Voltage Protectors

4.11.1 Surge arresters are available in many different types and for many applications. These include lightning arresters, spark gaps, and solid-state electronic devices. These devices may be used between structures and across pipeline electrical isolating devices, generally when steady-state interference is not a problem. However, one restriction to the use of arresters is that a potential difference develops before the arrester conducts. With certain types of arresters, this potential may be high enough to become hazardous to people coming in contact with the arrester. When arresters are used, they must be connected to the structure through adequately sized cables, as described in Paragraph 4.8.1. Arresters require a reliable, low-resistance ground connection. They should be located close to the structure being protected and have a short, straight ground path. Short lead length is especially important for lightning protection when the voltage build-up caused by lead induction can be significant. An adequately sized bypass circuit should be provided prior to any isolation of the grounding device during testing or maintenance.

4.11.2 Certain types of sealed, explosion-proof, enclosed, or repetitive transient arresters may be used in locations where a combustible atmosphere is anticipated, but only if it can be determined that the maximum possible power fault current does not exceed the design rating of the arrester. Open spark gaps shall not be used in these locations. The device and installation must be rated for the area classification, when installed in a hazardous location.

4.12 Stray Direct Current Areas

4.12.1 Galvanic anodes (including those in electrolytic grounding cells), grounding grids, or grounds directly connected to the structure may pick up stray DC in areas where stray direct currents are present. This current could possibly discharge directly to earth from the structure at other locations, resulting in corrosion of the structure at those points. Also, DC pickup by the structure could lead to DC discharge to earth through the galvanic anodes or grounding devices, resulting in increased consumption of the anode material or corrosion of grounding rods and an increase in their effective resistance to earth. The use of DC decoupling devices should be considered in these cases.

4.13 Coating Stress Voltage

4.13.1 External pipeline coatings can be subjected to stress voltages during a fault event on a nearby high-voltage power system. Both conductive and inductive components of a fault contribute to the stress voltage, with the conductive component acting on soil potentials and the inductive component acting on the pipeline steel potentials. Typically, the pipeline steel potential tends to be of opposite polarity to that of the earth potential so that the total coating stress voltage is on the same order as the sum of the magnitudes of the inductive and conductive components. Properly designed mitigation (i.e., grounding) can reduce the coating stress voltage to protect the coating from disbondment or damage. This, in effect, also provides some protection to the pipeline itself, as the tolerable coating stress voltages listed in Paragraph 4.13.2 do not exceed the conditions reported where there is risk of damage to the pipe.9

4.13.2 Limiting the coating stress voltage should be a mitigation objective. Expected threshold values for coatings differ with type and the cited reference and are generally considered to be in the range of 1 to 1.2 kV for bitumen:9 as low as 3 kV for coal tar and asphalt,11 and 3 to 5 kV for fusion-bonded epoxy (FBE)11'12 and polyethylene,12 for a short-duration fault.

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4.14 Minimum Separation Distance

4.14.1 A lightning strike may initiate an arc from a power line structure ground to a nearby buried structure, which, if close enough, may sustain an ionized path for an ensuing phase-to-ground fault current. The fault current carries much more energy than the initial lightning current because of its much greater duration, and may result in severe damage to the buried structure. Laboratory testing has shown that shielding conductors connected to the buried structure cannot be relied on to intercept the power arc." A minimum separation distance shall be maintained between powerline structure grounds and buried structures in order to ensure an arc initiated by lightning cannot be sustained by the fault current. The separation distance is measured from the nearest buried power system grounding conductor, which may extend beyond the tower foundation footings. Guy wire anchors that are electrically continuous with the power system grounding or shield wire shall be considered to be part of the power system grounding, as shall any buried structural steel or rebar in structural footings.

4.14.2 The sustainable arc length is a function of the GPR of the faulted power line structure and of the soil resistivity. Testing has been performed up to tower-ground-to-pipeline voltages of approximately 45 kV and power arcs were found to be sustained up to distances of up to 5.5 m (18 ft) at this voltage.li

4.14.3 It should be noted that it is common for power structure grounds of adjacent structures to be interconnected, with the result that the GPR value during fault conditions is only a fraction of the operating voltage of the power line. A study should be performed to determine the actual transmission line structure GPR during fault conditions and the resulting required separation distance to prevent a sustained power arc.

Section 5: Personnel Safety

5.1 Introduction

5.1.1 This section recommends practices that contribute to the safety of people who, during construction, system operation, corrosion survey, or CP maintenance of metallic structures, may be exposed to the hazards of AC potentials on those structures. The possibility of hazards to personnel during construction and system operation because of contact with metallic structures exposed to AC electrical or lightning effects must be recognized and provisions made to alleviate such hazards. The severity of the personnel hazard is usually proportional to the magnitude of the potential difference between the structure and the earth or between separate structures. The severity also depends on the duration of the exposure. Before construction work is started, coordination with the appropriate utilities in the area must be made so that proper work procedures are established and the construction does not damage or interfere with other utilities equipment or operations. In some cases, the electric utility can shut down the electrical transmission facility or block the reclosing features. These possibilities should be explored with the electric utility.

5.1.2 The electric utility may designate a coordinator while the project is in progress.

5.1.3 Each utility should be aware of the others' facilities and cooperate in the mitigation of the electrical effects of one installation on the other. The mitigation required for a specific situation must be based on safety considerations with good engineering judgment.

5.1.4 Increasing the separation distance between facilities is generally effective in reducing the electrical effects of one installation on another.

5.2 Recognition of Shock Hazards to Personnel

5.2.1 AC potentials on structures must be reduced to and maintained at safe levels to prevent shock hazards to personnel. The degree of shock hazard and the threshold levels of current that can be tolerated by human beings depend on many factors. The possibility of shock from lower voltages is the most difficult to assess. The degree of shock hazard depends on factors such as the voltage level and duration of human exposure, human body and skin conditions, and the path and magnitude of any current conducted by the human body. The magnitude of current conducted by the human body is a function of the intemal impedance of the voltage source, the voltage impressed across the human body, and the electrical resistance of the body path. This resistance also depends on the contact resistance (e.g., wet or dry skin, standing on dry land or in water), and on the current path through the body (e.g., hand-to-foot, hand-to-hand, etc.). Tables 3 and 4 indicate the probable human resistance to electrical current and current values affecting human beings.

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Table 3 Human Resistance to Electrical Current"

Dry skin 100,000 to 600,000 ohms Wet skin 1,000 ohms Internal body—hand to foot 400 to 600 ohms Ear to ear about 100 ohms

Table 4 Approximate 60-Hz Altemating Current Values Affecting Human Beings

Current Effects 1 mA or less No sensation—not felt. 1 to 8 mA Sensation of shock—not painful; individual can let go at will; muscular control not lost. 8 to 15 mA Painful shock—individual can let go at will; muscular control not lost. 15 to 20 mA Painful shock—muscular control lost; cannot let go. 20 to 50 mA Painful shock—severe muscular contractions; breathing difficult. 50 to 100 mA Ventricular fibrillation—Death results if prompt cardiac massage not administered. 100 to 200 mA Defibrillator shock must be applied to restore normal heartbeat. Breathing probably

stopped. 200 mA and over

Severe bums—severe muscular contractions; chest muscles clamp heart and stop it during shock. Breathing stopped—heart may start following shock, or cardiac massage may be required.

Source: Typical industry values

5.2.1.1 Safe limits must be determined by qualified personnel based on anticipated exposure conditions. For the purpose of this standard, a steady-state touch voltage of 15 V or more with respect to local earth at above-grade or exposed sections and appurtenances is considered to constitute a shock hazard.

5.2.1.2 It must be recognized that when touch voltages are below 15 V, the current may be dangerously high in the structure and continuity provisions and other procedures are mandatory prior to separating affected sections. All precautions must be implemented to eliminate the possibility of a person being placed in series with this current.

5.2.1.3 During short-circuit conditions, the permissible touch-and-step voltages at above-grade portions of the structure and appurtenances should be determined in accordance with the methodology specified in IEEE Standard 804 or other analogous methodologies, such as the International Electrotechnical Commission (IEC).(5)

5.2.1.4 In areas (such as urban residential zones or school zones) in which a high probability exists that children (who are more sensitive (o shock hazard than are adults) can come in contact with a structure under the influence of induced AC voltage, a lower touch voltage shall be considered.

5.2.1.5 The beginning sensation of shock, which may occur at 1 to 8 mA, may not be painful or harmful to a human being, but may lead to an accident by causing rapid involuntary movement of a person.

5.2.2 In areas of AC influence, measured AC voltages between a structure and either an adjacent structure, a ground, or an electrolyte are considered an indication that further investigation is needed to determine whether AC mitigation is required.

5.2.3 When the touch voltage on a structure presents a shock hazard, the voltage must be reduced to safe levels by taking remedial measures. In those cases in which the voltage level cannot be practically reduced to a safe level on aboveground appurtenances by fault shields, gradient control wires, lumped grounding, AC continuity, etc., other safety measures shall be implemented to prevent shock to operating and maintenance personnel and to the public (see Paragraph 4.3) to satisfy the requirements in Paragraph 5.2.1. The use of dead-front construction may be utilized in lieu of gradient control mats for test stations and other CP equipment enclosures when approved by the owner; however, caution is advised, and it must be recognized that this does not reduce any hazardous voltage present.

15) International Electrotechnical Commission (IEC), 3, rue de Varembé, P.O. Box 131, CH —1211, Geneva, Switzerland.

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5.3 Construction

5.3.1 Severe hazards may exist during construction of facilities adjacent to AC power systems. A competent person shall be in charge of electrical safety. This person shall be fully aware of proper grounding procedures and of the dangers associated with inductive and capacitive couplings, fault current, lightning, etc., on aboveground and underground structures. The person must also know the hazards of the construction equipment being used as related to the "limit-of-the-approach" regulations goveming them.14 The person shall be fumished with the instrumentation, equipment, and authority required to implement and maintain safe working conditions.

5.3.2 The AC potential difference between a structure and the earth may be substantially reduced by appropriate grounding procedures. The AC potential difference between structures may be reduced by appropriate bonding procedures. The AC potential difference between separate points in the earth may be reduced through the use of appropriate grounding grids. The grounding or bonding procedure for safe construction activities depends on the type, magnitude, and duration of the AC exposure. Each situation shall be analyzed by a competent person, and safe operating procedures shall be employed during the entire construction operation.

5.3.3 During the construction of metallic structures in areas of AC influenœ, the following minimum protective requirements are prescribed:

(a) On long metallic structures paralleling AC power systems, temporary electrical grounds shall be used at intervals not greater than 300 m (1,000 ft), with the first ground installed at the beginning of the section. Under certain conditions, a ground may be required on individual structure joints or sections before handling.

(b) All temporary grounding connections shall be left in place until immediately prior to backfilling. Sufficient temporary grounds shall be maintained on each portion of the structure until adequate permanent grounding connections have been made.

5.3.4 Temporary grounding connections may be made to ground rods, bare pipe casing, or other appropriate grounds. These temporary grounding facilities are intended to reduce AC potentials. Direct connections made to the electrical utility's grounding system during construction could increase the probability of a hazard during switching surges, lightning strikes, or fault conditions, and may intensify normal steady-state effects if the grounding system is carrying AC; such connections should be avoided when possible.

5.3.5 Cables used for bonding or for connections to grounding facilities shall have good mechanical strength and adequate conductivity. As a minimum, copper conductor 35 mm2 (0.054 in2) (No. 2 AWG) stranded welding cable or equivalent should be used. See Table 1 and Figures 1, 2, and 3 for cable sizes adequate to conduct the anticipated fault current safely.

5.3.6 Temporary cable connections to the affected structure and to the grounding facilities shall be securely made with clamps that apply firm pressure and have a current-canying capacity equal to or greater than that of the grounding conductor. Clamps shall be installed so that they cannot be accidentally dislodged.

5.3.7 All permanent cable connections shall be thoroughly checked to ensure that they are mechanically and electrically sound and properly coated prior to backfilling.

5.3.8 The grounding cable shall first be attached to the grounding facilities and then securely attached to the affected structure. Removal shall be in reverse order. Properly insulated tools or electrical safety gloves shall also be used to minimize the shock hazards. THE END CONNECTED TO THE GROUND SHALL BE REMOVED LAST.

5.3.8.1 In those instances in which high power levels are anticipated in the grounding cable, the following procedure should be used to prevent electrical arc burns or physical damage to the coating or metal on the structure.

(a) The grounding clamp shall be connected to the structure without the ground lead.

(b) The grounding cable shall first be connected to the grounding facility.

(c) Next, the grounding cable shall be connected to the grounding clamp on the structure.

5.3.9 All grounding attachments and removals shall be made by, or under the supervision of, the person in charge of electrical safety.

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5.3.10 If hazardous AC potentials are measured across an isolating joint or flange, both sides of the joint or flange shall be grounded and/or bonded across. If required, a permanent bond shall be made before the temporary bond is removed.

5.3.11 Before the temporary grounding facilities are removed, provisions must be made to perrnanently control the effects of AC potentials on the affected structure. These provisions depend on the type of CP, the type of structure, and the anticipated magnitude of AC potentials.

5.3.12 Vehicles and other construction equipment are subject to existing electrical safety regulations, when operated in the vicinity of high-voltage AC lines.15

5.3.12.1 Metallic construction sheds or trailers, fences, or other temporary structures shall be grounded if subject to hazardous AC influence.

5.3.13 The person in charge of electrical safety shall communicate at least daily with the utility controlling the involved power lines to ascertain any switching that might be expected during each work period. This person may request that reclosing procedures be suspended during construction hours and may explore the possibility of taking the power line out of service. This person shall also be kept informed of any electrical storm activity that might affect safety on the work site. This person shall order a discontinuation of construction during local electrical storms or when thunder is heard.

5.3.14 The use of electrically isolating materials for aboveground appurtenances such as vent pipes, conduits, and test boxes may reduce shock hazards in specific instances. However, electrical wires permanently attached to the pipeline, such as CP test wires, may have a high possibility of a shock hazard because they cannot be isolated from the pipe (see Paragraph 7.2.6).

5.4 Operations and Maintenance

5.4.1 Maintenance of structures and CP facilities under conditions that include AC potentials may require special precautions. Warning signs shall be used as a minimum precaution. All maintenance shall be performed by or under the supervision of a person familiar with the possible hazards involved. Personnel must be informed of these hazards and of the safety procedures to follow.

5.4.2 Testing of devices intended to limit AC potentials shall be in accordance with manufacturers recommendations and performed under the supervision of a person familiar with the possible hazards involved. In those areas in which the presence of combustible vapors is suspected, tests must be conducted before connections are made or broken to determine that the combustible vapor level is within safe limits. No more than one device intended to limit the AC potential should be disconnected at any one time. When a single protective device is to be installed, a temporary shunt bond, with or without another decoupling device, must be established prior to removing the unit for service.

5.4.3 Testing of CP systems under the influence of AC potentials must be performed by or under the supervision of a qualified person. In all cases, tests to detect AC potentials shall be performed first, and the structure shall be treated as a live electrical conductor until proven otherwise. CP records should include the results of these tests.

5.4.4 Test stations for CP systems on structures that may be subject to AC potentials shall have dead-front construction to reduce the possibility of contacting energized test leads. Test stations employing metallic pipes for support must be of dead-front construction.

5.4.5 Safe work practices must include attaching all test leads to the instruments first and then to the structure to be tested. Leads must be removed from the structure first and from the instruments last.

5.4.6 When structures subject to AC influence are exposed for the purpose of cutting, tapping, or separating, tests shall be made to determine AC potentials or current to ground. In the event that potentials or currents greater than those permitted by Paragraph 5.2 are found, appropriate remedial measures shall be taken to reduce the AC effects to a safe level. In the event this cannot be achieved, the structure shall be regarded as a live electrical conductor and treated accordingly. Solid bonding across the point to be cut or the section to be removed shall be established prior to separation, using as a minimum the cable and clamps outlined in Paragraphs 5.3.5 and 5.3.6.

5.4.7 On facilities carrying combustible liquids or gases, safe operating procedures require that bonding across the sections to be separated precede structure separation, regardless of the presence of AC.

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Section 6: AC and Corrosion Control Considerations

6.1 Introduction

6.1.1 This section recommends practices for determining the level of AC influence and lightning effects to which an existing metallic structure may be subjected. This section also outlines several points for consideration regarding the effects these potentials may have on corrosion control systems and associated equipment.

6.2 Determination of AC Influence and Lightning Effects

6.2.1 A CP system design should include an evaluation to estimate the level of AC potentials and currents under normal conditions, fault conditions, and lightning surges. Because significant AC potentials may be encountered during field surveys, all personnel shall follow proper electrical safety procedures and treat the structure as a live electrical conductor until proven otherwise.

6.2.2 Tests and investigations to estimate the extent of AC influence should include the following:

(a) Meeting with electric utility personnel to determine peak load conditions and maximum fault currents and to discuss test procedures to be used in the survey.

(b) Electrical measurement of induced AC potentials between the affected structure and ground.

(c) Electrical measurement of induced AC current on the structure.

(d) Calculations of the potentials and currents to which the structure may be subjected under normal and fault conditions.16

6.2.3 A survey should be conducted over those portions of the affected structure in which AC exposure has been noted or is suspected. The location and time that each measurement was taken should be recorded.

6.2.3.1 The potential survey should be conducted using a suitable AC voltmeter of proper range. Contact resistance of connections should be sufficiently low to preclude measurement errors because of the relationship between external circuit impedance and meter impedance. Suitable references for measurements are:

(a) A metal rod.(6)

(b) Bare pipeline casings, if adequately isolated from the carrier pipe.

(c) Tower legs or power system neutrals, if in close proximity to the affected structure. (Meter connections made to tower legs or power system neutrals may present a hazard during switching surges, lightning strikes, or fault conditions.)

6.2.3.2 The presence of AC on a structure may be determined using a suitable AC voltmeter to measure voltage (IR) drop at the line current test stations. This method, however, provides only an indication of current flow, and cannot be readily converted to amperes because of the AC impedance characteristics of ferromagnetic materials. A clamp-on AC ammeter may be used to measure current in temporary or permanent bond and ground connections. Instrumentation with sufficient resolution may be used to measure current at buried coupons that are connected to the structure to provide an indication of the local AC leakage current density.

6.2.3.3 Indications of AC power levels on affected structures may be obtained by temporarily bonding the structure to an adequate ground and measuring the resulting current flow with a clamp-on AC ammeter while measuring the AC potential. Suitable temporary grounds may be obtained by bonding to tower legs, power system neutral, bare pipeline casings, or across an isolating joint to a well-grounded system. DC drainage bonds existing on the structure under investigation should also be checked for AC power levels.

(6) Following meter hookup, the reference rod should be inserted deeper into the earth until no further potential increase is noted. This reduces the possibility of high-resistance contact errors in the measurement.

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6.2.3.4 Locations indicating maximum AC potential and current flow values during the survey discussed in Paragraphs 6.2.3 through 6.2.3.2 should be surveyed with recording instruments for a period of 24 hours or until the variation with power line load levels has been established.

6.2.3.5 These survey data should be reviewed with electric utility personnel for the purpose of considering the power line operating conditions at the time of the survey.

6.2.4 To facilitate AC interference studies and to design mitigation measures, the following data are typically required:

(a) Powerline cross-sectional dimensions, phasing, conductor types, and static wire bonding information;

(b) Powerline structure grounding details (including footings) and substation ground resistances;

(c) Substation and power plant grounding system dimensions, if close to pipelines;

(d) Single line diagrams for power lines within interference corridor;

(e) Single phase-to-ground currents for representative faults on all power lines;

(f) Load current details for all power lines, including maximum load unbalance and system operating frequency;

(g) Maximum fault clearing time for each power line;

(h) Details on nearby power plants fed by any of the pipelines in the interference corridor;

(i) Alignment drawings of pipelines and appurtenances, power lines and structures, and power line installations (substations and power plants) throughout the common corridor and up to extremities of pipelines and power lines;

(j) Pipeline characteristics, dimensions, and design inforrnation;

(k) Soil resistivity measurements up to pin (electrode) spacings of 100 m (328 ft) or more at representative locations throughout the common corridor;

(I) Drawings and locations of exposed appurtenances (scraper traps, valves, metering stations, etc.);

(m) Pipeline coating resistance and coating characteristics and thickness; and

(n) CP anode bed locations, dimensions, and design information.

6.3 Special Considerations in CP Design

6.3.1 AC influence on the affected structure and its associated CP system should be considered.

6.3.2 CP survey instruments should have sufficient AC rejection to provide accurate DC data.

6.3.3 The AC in the structure to be protected may flow to ground through CP equipment. Current flowing in the CP circuits under normal AC power system operating conditions may cause sufficient heating to damage or destroy the equipment. Heating may be significantly reduced by the use of properly designed series inductive reactances or shunt capacitive reactances in the CP circuits.

6.3.3.1 Rectifiers should be equipped with lightning and surge protection at the AC input and DC output connections. Efficiency filters appear to be of value in lightning areas.

6.3.3.2 Resistance bonds for the purpose of DC interference mitigation should be designed for the maximum normal AC and DC current flow to prevent damage to the bond. Installation of solid state DC decouplers, polarization cells, or other devices in parallel with DC resistance bonds may prevent damage to bonds. Installation of semiconductors in DC interference bonds between cathodically protected structures may result in undesirable rectification.

6.3.3.3 When bonds to other structures or grounds are used for AC considerations, the requirements as described in Paragraph 4.2.5 apply in order to maintain effective levels of CP.

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6.3.3.4 Semiconductor drain switches (reverse current) for the mitigation of stray DC from transit systems should be provided with surge current protection devices.

6.3.4 In DC stray current areas, the grounding methods should be chosen to avoid creating interference problems.

Section 7: Special Considerations in Operation and Maintenance of Cathodic Protection and Safety Systems

7.1 Introduction

7.1.1 This section outlines safe maintenance and testing procedures for CP systems on structures subject to AC influence.

7.2 Operation and Maintenance of CP Systems

7.2.1 CP rectifiers that are subject to damage by adjacent electric utility systems may require inspections at more frequent intervals than rectifiers not subject to electric system influence.

7.2.2 CP testing or work of similar nature must not be performed on a structure subject to influence by an adjacent electric utility system during a period of thunderstorm activity in the area.

7.2.3 Positive measures must be taken to maintain continuous rectifier operation when repeated outages can be attributed to adjacent electric utility system influences. One or more of the following mitigation measures may be employed:

(a) Transient lightning arresters capable of repetitive operations across the AC input and DC output terminals.

(b) Heavy-duty choke coils installed in the AC and/or DC leads.

7.2.4 If galvanic anodes are used for CP in an area of AC influence, and if test stations are available, the following tests should be conducted during each structure survey using suitable instrumentation:

(a) Measure and record both the AC and DC current from the anodes.

(b) Measure and record both the AC and DC structure-to-electrolyte potentials.

7.2.5 At all aboveground pipeline metallic appurtenances, devices used to keep the general public or livestock from coming into direct contact with the structure shall be examined for effectiveness. If the devices are found to be ineffective, they shall be replaced or repaired immediately.

7.2.6 In making test connections for electrical measurements, all test leads, clips, and terminals must be properly insulated. Leads shall be connected to the test instruments before making connections to the structure. When each test is completed, the connections shall be removed from the structure before removing the lead connection from the instrument. All test connections must be made on a step-by-step basis, one at a time.

7.2.7 When long test leads are laid out near a power line, significant potentials may be induced in these leads. The hazards associated with this situation may be reduced by using the following procedures:

(a) Properly insulate all test lead clips, terminals, and wires.

(b) Avoid direct contact with bare test lead terminals.

(c) Place the reference electrode in position for measurement prior to making any test connections.

(d) Connect the lead to the reference electrode, and reel the wire back to the test location.

(e) Connect the other test lead to the instrument and then to the structure.

(f) Connect the reference electrode lead to the instrument.

(g) When the tests are complete, disconnect in reverse order.

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NOTE: Close-interval pipe-to-electrolyte surveys using long lead wires require special procedures and precautions.

7.2.8 Tools, instruments, or other implements shall not be handed at any time between a person standing over a ground mat or grounding grid and a person who is not over the mat or grid.

7.2.9 Grounding facilities for the purpose of mitigating AC effects should be carefully tested at regular intervals to ascertain the integrity of the grounding system.

7.2.9.1 No disconnection or reconnection shall be allowed when a flammable or explosive atmosphere is suspected without first testing to ensure a safe atmosphere.

7.2.9.2 No one shall make contact with the structure, either directly or through a test wire, while a grounding grid is disconnected for test purposes.

7.2.9.3 Measurement of the resistance to earth of disconnected grounds shall be made promptly to minimize personnel hazards.

7.2.10 All interference mitigation devices and test equipment should be maintained in accordance with the manufacturer's instructions.

7.2.11 DC decouplers and their effects should be considered for DC pipe-to-soil voltage readings and coating holiday survey measurements. Waveform analysis may assist in determining these effects and whether corrective measures are required to obtain accurate measurements.

References

1. G. Bodier, Bulletin de la Société Frangaise des Electriciens, October 1947.

2. C.F. Dalziel, "The Effects of Electrical Shock on Man," Transactions on Medical Electronics, PGME-5, Institute of Radio Engineers,M 1956. (Available from IEEE.)

3. IEEE Standard 367 (latest revision), "Recommended Practice for Determining the Electric Power Station Ground Potential Rise and Induced Voltage from a Power Faulr (New York, NY: ANSI/IEEE).

4. IEEE Standard 80 (latest revision), "Guide for Safety in AC Substation Grounding" (New York, NY: IEEE).

5. NFPA(8) Standard 70 (latest revision), "National Electrical Code" (Quincy, MA: National Fire Protection Association). Also available from the American National Standards Institute (ANSI),(9) New York, NY.

6. ANSI/IEEE Standard C2 (latest revision), "National Electrical Safety Code (NESC) (New York, NY: ANSI/IEEE)

7. ICEA P-32-382 (latest revision), "Short-Circuit Characteristics of Insulated Cable," (Carrollton, GA: !CEA).

8. J.H. Michel, "Ampacity Characteristics of Zinc Ribbon," CORROSION/2005, paper no. 621 (Houston, TX: NACE, 2005).

9. B. Favez, J.C. Gougeuil, "Contribution to Studies on Problems Resulting From the Proximity of Overhead Lines with Underground Metal Pipe Lines, paper no. 336, Conference Internationale des Grands Reseaux Electriques a Haute Tension, Paris, France, 1966.

10. CIGREM Working Group 36.02 Guide, "Guide on the Influence of High Voltage AC Power Systems on Metallic Pipelines," 1995.

(nThe Institute of Radio Engineers (IRE) and the American Institute of Electrical Engineers (AIEE) merged in 1963 to form the Institute of Electncal and Electronics Engineers (IEEE). (8) National Fire Protection Agency (NFPA), 1 Batterymarch Park, Quincy, MA 02169-9101. (8) Amencan National Standards Institute (ANSI), 1899 L St. NW, llth Floor, Washington, DC 20036. (10) International Council on Large Electronic Systems (CIGRE), 21 rue d'Artois, 75008 Paris, France.

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11. J. Dabkowski, "Induced AC on Pipelines," CORROSION/90, paper no. 240 (Houston, TX: NACE, 1990).

12. J. Dabkowski, M.J. Frazier, "Power Line Fault Current Coupling to Nearby Natural Gas Pipelines, Volume 3: Analysis of Pipeline Coating Impedance," EPRI Report EL-5472, August 1988.

13. C. Webster, J. Zawadski, T. Stefanski, "Powerline Ground Fault Effects on Pipelines," Canadian Electrical Association (CEA)(11) Report No. 239 T 817, December 1994.

14. Accident Prevention Manual for Business and Industry: Engineering and Technology, 12th ed. (Itasca, IL: National Safety Council,(12) 1992).

15. OSHA(13) Standard 2207, Part 1926 (latest revision), "Construction, Safety, and Health Regulations" (Washington, DC: OSHA).

16. Mutual Design Considerations for Overhead AC Transmission Lines and Gas Transmission Pipelines, Volume 1: Engineering Analysis, and Volume 2: Prediction and Mitigation Procedures, AGA" Catalog No. L51278 (Arlington, VA: AGA, 1978). Published in conjunction with The Electric Power Research Institute (EPRI).(15)

17. D.G. Fink, J.M. Carroll, Standard Handbook for Electrical Engineers, 10th ed. (New York, NY: McGraw-Hill, 1968).

Bibliography

CAN/CSA-C22.3 No. 6-M91 (latest revision). "Principles and Practices of Electrical Coordination between Pipelines and Electric Supply Lines." Etobicoke, ON: CSA.(16)

CGA(17) Standard OCC-3-1981 (latest revision). "Recommended Practice OCC-3-1981 for the Mitigation of Altemating Current and Lightning Effects on Pipelines, Metallic Structures, and Corrosion Control Systems." Toronto, ON: CGA.

Gilroy, D.E. "AC Interference—Important Issues for Cross Country Pipelines." CORROSION/2003, paper no. 699. Houston, TX: NACE, 2003.

Gummow, R.A., R.G. Wakelin, and S.M. Segall. "AC Corrosion—A New Challenge to Pipeline Integrity." CORROSION/98, paper no. 566. Houston, TX: NACE, 1998.

Inductive Interference Engineering Guide. Murray Hills, NJ: Bell Telephone Laboratories, March, 1974. (Available through local Bell System Inductive Coordinator.)

Lichtenstein, J.A. "Alternating Current and Lightning Hazards on Pipelines." MP 31, 12 (1992): pp. 19-21.

Lichtenstein, J.A. "Interference and Grounding Problems on Metallic Structures Paralleling Power Lines." Proc. Western States Corrosion Seminar. Houston, TX: NACE, 1982.

Mame, D. McGraw — Hill's National Electrical Safety Code (NESC) Handbook, New York, NY: McGraw - Hill Professional, 2002.

"Some Safety Considerations for Pipelines near Overhead Power Lines." NACE AudioNisual Presentation. Prepared by Work Group WG 025a. Houston, TX: NACE, 2004.

Southey, R.D., and F.P. Dawalibi. "Advances in Interference Analysis and Mitigation on Pipelines." In NACE International Canadian Region International Conference, Corrosion Prevention '95, held October 31, 1995. Houston, TX: NACE, 1995.

(11) Canadian Electricity Association (CEA), 275 Slater St., Suite 1500, Ottawa, Ontario K1P 5H9, Canada. (12) National Safety Council (NSC), 1121 Spring Lake Drive, Itasca, IL 60143-3201. (14) American Gas Association (AGA), 400 North Capitol St. NW, Suite 450, Washington, DC 20001. (15) Electric Power Research Institute (EPRI), 3420 Hillview Ave., Palo Alto, CA 94304. (16 CSA International (CSA), 178 Rexdale Blvd., Toronto, Ontario M9W IR3, Canada. (17) Canadian Gas Association (CGA), 350 Sparks St., Suite 809, Ottawa, Ontario K1R 7S8, Canada.

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Wakelin, R.G., R.A. Gummow, and S.M. Segall. "AC Corrosion—Case Histories, Test Procedures, and Mitigation." CORROSION/98, paper no. 565. Houston, TX: NACE, 1998.

Westinghouse Transmission and Distribution Handbook. Newark, NJ: Westinghouse Electric Corp. Relay-Instrument Division, 1950.

Appendix A Wire Gauge Conversions

(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 provides the nearest metric size for the conductor sizes mentioned in this standard.

Table A1 Wire Gauge Conversions17

Conductor Size Diameter in mil Nearest metric size (mm1) Diameter in mm of nearest metric size

4,000 MCM 2,000 2,000 50.5 2,000 MCM 1,410 1,000 35.7 1,000 MCM 1,000 500 25.2 500 MCM 707 240 17.5 250 MCM 500 120 12.4 4/0 AWG 460 120 12.4 3/0 AWG 410 80 10.01 2/0 AWG 365 70 9.44 1/0 AWG 325 50 7.98 1 AWG 290 50 7.98 2 AWG 258 35 6.68 4 AWG 204 25 5.64 6 AWG 162 16 4.51 8 AWG 128 10 3.57 10 AWG 102 6 2.76

ISBN 1-57590-116-1 24 NACE International

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Item No. 24242 NACE International Publication 35110

This Technical Committee Report has b?en prepared by NACE International Task Group 327, "AC Corrosion State-of-the-Art: Corrosion Rate, Mechanism, and Mitigation Requirements."

AC Corrosion State-of-the-Art: Corrosion Rate, Mechanism, and Mitigation Requirements

©January 2010, NACE International

This NACE International (NACE) technical committee report 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 from manufacturing, marketing, purchasing, or using products, processes, or procedures not included in this report. Nothing contained in this NACE report 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 report should in no way be interpreted as a restriction on the use of better procedures or materials not discussed herein. Neither is this report intended to apply in all cases relating to the subject. Unpredictable circumstances may negate the usefulness of this report in specific instances. NACE assumes no responsibility for the interpretation or use of this report by other parties. Users of this NACE report are responsible for reviewing appropriate health, safety, environmental, and regulatory documents and for determining their applicability in relation to this report prior to its use. This NACE report 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 report.

Users of this NACE report 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 report.

CAUTIONARY NOTICE: The user is cautioned to obtain the latest edition of this report. NACE reports are subject to periodic review, and may be revised or withdrawn at any time without prior notice. NACE reports are automatically withdrawn if more than 10 years old. Purchasers of NACE reports may receive current information on all NACE International publications by contacting the NACE FirstService Department, 1440 South Creek Drive, Houston, Texas 77084-4906 (telephone +1 281-228-6200).

Foreword

This technical committee report represents the current understanding of the corrosion phenomenon associated with alternating current (AC) interference on buried steel pipelines. The purpose of this state-of-the-art report is to begin the development of corrosion protection criteria with regard to AC corrosion. In the past 20 years, AC corrosion has become recognized as a threat to the integrity of underground structures, especially to buried pipelines sharing the right-of-way with high-tension electrical lines.

Every attempt was made to incorporate as many published accounts into this report as possible, including multiple international sources. However, given the increased awareness of AC corrosion by pipeline operators and the corrosion community at large, a considerable amount of literature on the subject exists, and some most recent publications might have been left out of the report. The report addresses AC corrosion characteristics and proposed mechanisms and describes the currently used approaches to protection and monitoring. It is intended for use by pipeline operators and others concerned with control of AC corrosion.

* Chair Mark Yunovich, Honeywell Process Solutions, Houston, TX.

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The report also identifies existing knowledge gaps and briefly outlines the path forward. Four case studies are presented in Appendix A. The issue of AC interference (and AC corrosion) mitigation is deliberately presented in brief; AC mitigation is the primary focus of Task Group (TG) 025, "Alternating Current (AC) Power Systems, Adjacent: Corrosion Control and Related Safety Procedures to Mitigate the Effects."

This technical committee report has been prepared by TG 327, "AC Corrosion State-of-the-Art: Corrosion Rate, Mechanism, and Mitigation Requirements." TG 327 is administered by Specific Technology Group (STG) 35, "Pipelines, Tanks, and Well Casings." This report is issued by NACE International under the auspices of STG 35.

NACE technical committee reports are intended to convey technical information or state-of-the-art knowledge regarding corrosion. In many cases, they discuss specific applications of corrosion mitigation technology, whether considered successful or not. Statements used to convey this information are factual and are provided to the reader as input and guidance for consideration when applying this technology in the future. However, these statements are not intended to be recommendations for general application of this technology, and must not be construed as such.

Introduction

The phenomenon of AC corrosion has been considered by many authors since the early 1900s. However, the mechanisms of AC corrosion are still not completely understood. The body of recent (post-1980) literature indicates that AC corrosion or AC-enhanced corrosion (ACEC) is a bona fide effect (reported corrosion rates up to 20 mpy [0.5 mm/y], with pitting rate considerably higher); there appears to be a tacit agreement that at prevailing commercial current frequencies (such as 50 or 60 Hz) corrosion is possible, even on cathodically protected pipelines.

AC corrosion on cathodically protected pipelines is not well understood, despite discussion about it dating back to the late 19th century. For many years, corrosion experts did not consider corrosion attributed to alternating currents on metallic structures very important. In 1891, Mengarinit concluded that corrosion ("chemical decomposition") by AC (1) is less than that caused by the equivalent direct current (DC), (2) is proportional to the AC, (3) there exists a threshold AC density below which no "decomposition of electrolyte" occurs, and (4) the extent of corrosion decreases with increased AC frequency.

In 1916, McCollum, et al.2 published a research paper that concluded iron does not suffer from attack when a limiting frequency of the current (somewhere between 15 and 60 Hz) is reached. AC corrosion was not well understood for two reasons: (1) the electrochemical phenomenon of corrosion is normally attributed to DC, and (2) the instruments normally used to measure the electric parameters in direct currents cannot correctly detect the presence of AC with frequencies between 50 and 100 Hz.3 Recently, concern for AC corrosion mitigation has been increasing because AC interference has been shown to affect cathodically protected underground structures and increase safety concerns (i.e., high AC step-and-touch potentials). Factors that contribute to AC interference on pipelines include (1) the growing number of high-voltage power lines, (2) AC operated high-speed traction systems, (3) high isolation resistance of modern pipeline coatings, and (4) coating integrity.'

Characteristics of AC Corrosion

Corrosion Rate

There is a scarcity of data on the magnitude of the corrosion rate of steel in soils influenced by AC. The general understanding is that higher alternating currents lead to higher risk of AC corrosion. Ragault4 reiterates this notion and states that field investigations of conditions on a coated, cathodically protected pipeline with AC density ranging between 84 and 1,100 A/m2 (7.8 and 102 A/ft2) (with on-potentials between —2.0 and —2.5 V) did not show any clear relationship between AC density and corrosion rate (found to be between 12 and 54 mpy [0.3 and 1.4 mm/y]). Wakelin, et al.5 reports that three field studies and inspections found rates ranging from 17 to 54 mpy (0.4 to 1.4 mm/y) for AC densities between 75 and 200 A/m2 (7 and 19 A/ft2). A German field-based coupon study6 revealed rates scattered between 2 and 4 mpy (0.05 and 0.1 mm/y) at 100 A/m2 (9.3 Aift2) and 12 mpy (0.3 mm/y) at 400 A/m2 (37 A/ft2); the rate of pitting was more

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scattered-between 8 and 56 mpy (0.2 and 1.4 mm/y), and it showed much less pronounced dependence on the AC density.

A 1964 work by Bruckner' (sponsored by the American Gas Association [AGA])(1) showed that in soils with pH between 6 and 7, the corrosion rate of steel is below 3 mpy (0.08 mm/y) at 155 A/m2 (144 A/ft2) and between 10 and 20 mpy (0.25 and 0.5 mm/y) at 775 A/m2 (72 A/ft2). A paper by Song, et al.8 reports corrosion rates as measured on coupons installed for 6 and 12 months next to a buried cathodically protected pipeline, which were exposed to AC with a carrier frequency of 60 Hz, but with an appreciable contribution of a 180 Hz harmonic. The rates were found to be linearly increasing with AC density (less than 10 mpy [0.25 mm/y] for densities below 100 A/m2 [9.3 A/ft2] and between 5 and 25 mpy (0.13 and 0.64 mm/y) for densities between 100 and 500 A/m2 [9.3 and 46 A/ft2]); on-potentials were generally over -0.9 V. The German field study8 observed pitting corrosion rates of 210 mpy (5.3 mm/y) associated with AC densities between 20 and 200 A/m2 (1.9 and 19 A/ft2).

A number of recent publications presented the results of laboratory and field evaluation using coupons and probes. Short-term field testing by Nielsen and Galsgaard8 recorded peak AC corrosion rates as high as 10 mm/y (400 mpy); Gregoor and Pourbaix1° reported short-term laboratory-based rates between 0.01 and 0.25 mm/y per each A/m2 (4.2 and 106 mpy/A/ft2) of AC density, with actual observed rates falling between 0.65 and 3.4 mm/y (26 and 130 mpy). Shoeneich" reported corrosion rates from buried coupons exposed to 1 to 91 Nm2 (0.09 to 8.5 A/ft2) of AC density under cathodic protection (CP) potentials more negative than -0.95 V (vs. copper/copper sulfate reference electrode [CSE]); the observed rate did not exceed 0.02 mm/y (0.8 mpy).

A laboratory study by Yunovich and Thompson12 revealed that in the absence of CP, corrosion rates ranged from 3.5 to 8.2 mpy (0.09 to 0.21 mm/y).

Song, et al.8 suggest that for a given AC density, the corrosion rate tends to decrease with time and that there may even be an "incubation" period of one or more months, depending on the current density.

Morphological Characteristics

Goran13 studied AC in the field on steel test coupons. The test coupons were cathodically protected and exposed to different AC densities. The series of tests consisted of one with 10 V AC applied to the test coupons for approximately two years, and another one with 30 V AC during CP for 1.5 years. From the results and observations, he concluded the appearance of corrosion could be divided into three groups:

• Small point-shaped attacks evenly distributed across the surface (uneven surface);

• Large point-shaped attacks evenly distributed across the surface (rough surface); and

• A few large, deep local attacks on an otherwise uncorroded surface ("pocked" surface).

Nielsen and Cohn14 describe a distinct tubercle of "stone-hard soil," comprising a mixture of corrosion products and soil that is often observed to grow from the coating defect in connection with AC corrosion incidents. The specific resistivity of such a tubercle can be expected to be lower than the specific resistivity of the surrounding soil. In addition, the effective area of the tubercle is considerably greater than the original coating defect. Both processes tend to decrease the spreading resistance of the associated coating defect during the corrosion process, making the corrosion process autocatalytic in nature. Ragault4 describes 31 AC corrosion cases on a polyethylene-coated gas transmission line and notes that the corrosion product consisted mostly of magnetite mixed with soil. Williams18 also indicates that the corrosion product on steel under AC influence was mainly magnetite.

Some examples of the photographic evidence culled from the investigations of underground pipeline failures attributed to AC corrosion are shown in Figures 1 and 2.

(1) American Gas Association (AGA), 400 N. Capitol St. NW, Washington, DC 20001.

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Figure 1: Leak site on underground natural gas transmission pipeline (attributed to AC corrosion), before and after cleaning. The arrow indicates the leak.16

Figure 2: External corrosion site on a natural gas transmission pipeline (attributed to AC corrosion), before and after cleaning.17

Bolzoni, et al.,18 who studied AC influence in solutions, report that the AC led to growth of thick but nonadhering corrosion products; the research results suggested that corrosion caused by AC was likely to be localized.

If one follows the checklist presented in the 2000 CEOCORM proceedings3 to determine whether the corrosion attack is caused by AC based on the morphology of the damaged site, the answer is not clear. The questionnaire posts such questions as (1) is there a coating defect, (2) is the shape of corrosion damage a rounded pit, (3) is the size of the pit much larger than the size of the associated coating defect, (4) is the soil resistivity low/very low, and several others. After one answers these and several other questions, the authors conclude that if "many of the answers are "yes," then it "probably' is an AC corrosion case. Wakelin, et al.5 describes Canadian AC case histories and offers another similar checklist to determine whether the cause of corrosion could be attributed to AC. The approach is to eliminate all other culprits (e.g., microbiologically influenced corrosion [MIC]) and evaluate the characteristics of the damaged region, paying particular attention to whether the pit has a rounded bottom and whether soil and corrosion products had formed a hard dome over the pit.

AC Density

Studies performed in the 1950s and 1960s indicated that the AC-enhanced corrosion of steel is low, being in the range of 0.1 to 1% of a similar amount of DC-enhanced corrosion. Within this range (below 1%), Pookote

(2) CEOCOR, c/o CIBE, rue aux !eines, 70, B-1000 Brussels, Belgium

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and Chin18 observed an increase in corrosion rate upon increasing AC density. Funk and Schoeneich8 reported the results of a two-year field study, which showed similar trends for both general corrosion rate and pitting. Gummow, et al.2° compiled an extensive literature survey on the subject of AC corrosion in 1998, when similar findings by many other researchers were presented. A 2005 study by Goidanich, et aI.21 reached a similar conclusion that DC equivalent percentage (defined as the ratio between observed corrosion rate to that expected for the DC of the same magnitude) for carbon steel in simulated soil solution is lower than 4%. The researchers also observed that this parameter tended to decrease with increased current density.

In 1986, a corrosion failure on a high-pressure gas pipeline in Germany was attributed to AC corrosion. This failure initiated field and laboratory investigations that indicated induced AC-enhanced corrosion can occur on coated steel pipelines, even when protection criteria are met. In addition, the investigations ascertained that above a minimum AC density, typically accepted levels of CP would not control AC-enhanced corrosion. The German AC corrosion investigators conclusions can be summarized as follow:22

1. AC-induced corrosion does not occur at AC densities less than 20 A/m2 (1.9 Afit2);

2. AC corrosion is unpredictable for AC densities between 20 to 100 A/m2 (1.9 to 9.3 Nft2);

3. AC corrosion occurs at current densities greater than 100 A/m2 (9.3 A/ft2); and

4. The highest corrosion rates occur at holidays with a surface area between 100 and 300 mm2 (0.2 and 0.5 in2).

(Note: These conclusions refer to steel structures that would be considered adequately protected in absence of AC; the European standard guidelines below introduce further discussion.)

Prinz23 reported that since 1986, several cases of corrosion damage to cathodically protected pipelines have occurred in Germany and Switzerland as a result of AC with a frequency of both 16-2/3 and 50 Hz. In 1993, following a coating defects survey conducted in France, 31 cases of AC corrosion were found on a polyethylene-coated steel gas transmission pipeline (running parallel to a 400 kV high-voltage alternating current [HVAC] line) with relatively high (on-potentials in excess of —2.0 V CSE) levels of CP.4 The author of the study concluded the following factors increase AC corrosion risks: (1) a low level of CP (i.e., low DC density) with a high level of AC density, (2) small size of coating defects, and (3) low soil resistivity. Wakelin, et al.8 reported several corrosion anomalies occurring on pipelines exposed to induced AC interference in Canada. The above-cited literature survey2° concluded that corrosion rates in the presence of AC:

• Increased in chloride-containing or deaerated environments;

• Increased with decreasing AC frequency (under 100 Hz);

• Increased with decreasing holiday surface area reaching a maximum for a holiday surface area of 645 mm2 (1.00 in2 );

• Decreased with increasing CP current density; and

• Decreased with time.

Whereas many authors have concluded that there is a threshold AC density below which AC corrosion is not a factor, the magnitude of the threshold is being debated. Chin and Fu24 studied mild steel exposed to a passivating sodium sulfate solution and observed that at 2,000 Nm2 (190 Nft2), the passive layer appeared to be completely destroyed. In addition to the 20 A/m2 (1.9 Nft2) cited above, the literature suggests that densities in excess of 30 A/m2 (2.8 Nft2) could be detrimental to buried steel structures.28

On the basis of laboratory tests, Pourbaix, et al.28 concluded that AC corrosion is not related to any particular critical AC density value. In 1978, Jones27 published the results of a study of low-alloy and carbon steel in sodium chloride solution, which observed an increase of corrosion rate of four to six times when the specimens in deaerated conditions were exposed to a 60 Hz current with a density of 300 A/m2 (28 Nft2), but found no acceleration of corrosion under aerated conditions. A German standard, DIN 50925,28 adopts a

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value of 30 A/m2 (2.8 A/ft2); Handbook of cathodic corrosion protection by Baeckmann and Schwenk29 cites a value of 20 A/m2 (1.9 A/ft2).

European Standard CEN/TS 152803° offers the following guidelines:

The pipeline is considered protected from AC corrosion if the root mean square (RMS) AC density is lower than 30 A/m2 (2.8 NW).

In practice, the evaluation of AC corrosion likelihood is done on a broader basis:

Current density lower than 30 A/m2 (2.8 Nft2): no or low likelihood;

• Current density between 30 and 100 Nm2 (2.8 and 9.3 Nft2): medium likelihood; and

• Current density higher than 100 Nm2 (9.3 Nft2): very high likelihood.

The standard also discusses the AC risk in terms of the ratio between AC and CP currents (assuming that the required protective CP potentials [see further discussion] are met):

• I / ACI DC is less than 5—AC corrosion likelihood is low;

• IACJIDC is between 5 and 10—AC corrosion likelihood can exist and further investigation is typically necessary; and

• IAC/IDC is greater than 10—AC corrosion likelihood is considered to be high and mitigation measures are normally taken (e.g., by using appropriate grounding).

Recent experimental studies by Yunovich and Thompson12 concluded that AC density discharge on the order of 20 A/m (1.9 Nft2) can produce significantly enhanced corrosion (higher rates of penetration and general attack without applied CP). Further, the authors stated that there likely was not a theoretical "safe" AC density (i.e., a threshold below which AC does not enhance corrosion); however, a practical one for which the increase in corrosion because AC is not appreciably greater than the free-corrosion rate for a particular soil condition may exist.

The conclusions of the doctoral thesis by Goidanich31 are similar in nature; the findings suggest that the current density of 10 A/m2 (0.93 Alft2 ) may be hazardous, as it has increased the corrosion rate by two-fold in a simulated soil solution compared to the AC-free conditions (without CP).

AC Voltage

If one knows the soil resistivity and the pipeline's AC voltage, the risk of AC corrosion can be estimated using the following simple formula in Equation (1) to calculate AC density:

• _ 8VAC 1 - pth

(1)

where:

i = AC density VAC = AC voltage of pipeline to remote earth p = soil resistivity d = diameter of a circular holiday having an area equal to that of the actual holiday

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R2 = 0.8355 ""-E-

2 4 10 8 12 6

AC Pipe Potential (VCSE)

300 0

250 0

200 0

a) 0 150 0

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The formula is applicable to cases when the holiday size is greater than the thickness of the coating, which, for practical purposes, applies to the vast majority of situations.

Thus, for the case of a 100 mm2 (0.155 in2) holiday on a pipe in 1,000 acm soil, where the induced AC voltage on the pipeline is 10 V, the AC density at the holiday would be 255 A/m2 (23.7 A/ft2); for the above-cited density of 100 A/m2 (9.3 A/ft2), the AC voltage would be 4.4 V.

This particular example has in fact been observed in a real-life case of pipeline failure investigation.32 The pipeline was buried in low-resistivity soil (200 to 600 û cm); the AC voltage measurements showed values between 3 and 10 V. The AC density measurements using buried coupon test stations (CTS) indicated that, on several occasions, the density was in excess of 100 A/m2 (9.3 AM2). The plot in Figure 3 illustrates correlation between the actual observed pipe potential and current density.

Figure 3: Relationship between measured AC pipe potential and measured coupon current density.32 (1 A/m2 = 9.30 x 10-2 Nft2)

Some boundary conditions are often considered when assessing the "practical" risks of AC corrosion using the above estimates. For example, if one considers an AC density of 20 Nm2 (1.9 A/ft2) as the threshold in 1,000 Ocm soil and a 10 mm2 (0.02 in2) holiday, the typical maximum AC voltage estimated by Equation (1) is 0.785 V. This magnitude of AC voltage is not uncommon on pipelines in non-AC interference areas. However, as illustrated in Figure 3, under certain conditions, the AC interference levels are sometimes brought below 1.5 V AC in order to lower the AC densities to reduce the risk of AC corrosion (in accordance with Equation [1]).

This suggests that assessment of AC corrosion threat (and, for that matter, AC mitigation) on the basis of AC voltage can be misleading. At present in the U.S., AC mitigation is mostly driven by safety considerations. The primary focus of these efforts is to reduce the induced AC voltage below 15 V with respect to local earth for steady-state conditions on above-grade portions, where personnel could readily come in contact with the pipeline or an appurtenance, to ensure compliance with NACE SP0177.33

On the other hand, in Germany, the same threshold is 65 V.34 Considering that the primary factor in determining the possibility for the presence of AC corrosion is the AC density, monitoring the current density rather than an AC voltage is used to assess the AC-related hazards to a buried pipeline.

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This is a departure from the prevailing practices of measuring (and mitigating) the AC voltages on buried pipelines, notwithstanding the fact that the reduction of AC potentials is expected to reduce the AC leakage current density magnitude as well.

European Standard CEN/TS 152803° explains that reducing the AC corrosion likelihood on a buried pipeline means that pipeline AC voltage does not at any time exceed 10 V over the entire pipeline, or 4 V where the local soil resistivity measured along the pipeline is less than 2,500 acm. However, these limits are sometimes considered overly restrictive for many pipelines influenced by overhead 50 and 60 Hz HVAC power systems without a history of corrosion failures. When pipeline systems run concurrently with electrical transmission lines for significant lengths at close separation distances, especially in high-resistivity areas with complex electromagnetic fields and conductor geometries, even the 15 V AC limit results in extensive and expensive mitigation.

Frequency Effects

As mentioned earlier, published accounts19• 24•354° indicate that there is an inverse relationship between AC-induced corrosion and the frequency of the signal—the corrosion rate decreases with increasing frequency. While one can assume that at very high frequencies, AC is not expected to influence the corrosion process, as evidenced by the published case studies, AC at power frequencies of 50 or 60 Hz can cause corrosion of affected structures (see further discussion in the next section). Also, the magnitude of the potential shifts caused by the AC signal decreases with the frequency.

The frequency also affects pit morphology, pit density, and passivity current density (decrease with increasing frequency.)24'32,39

The following example (taken from the Yunovich and Thompson study41) shows estimated current flow through the steel specimen exposed to soil using an equivalent analog circuit (Randle's model), shown in Figure 4. The circuit consists of a double layer capacitance (C1), solution resistance (Rs), and "effective resistance (Reff), representing the combination of the charge-transfer and Warburg (diffusion-related) impedances. The circuit also incorporates an AC power source (V1). (See more on this subject in the AC Corrosion Mechanism section of this report.)

The analysis used a commercial electrical circuit modeling software that can simulate electric circuitry behavior and calculate (over a range of imposed AC voltage frequencies) the current passing through each component of an electrical circuit for given parametric values. The circuit in Figure 4 uses actual experimentally observed values (24 V AC was imposed on the specimen to achieve the AC density of approximately 400 A/m2 [37 A/ft2]).

The results of the simulation for the case illustrated in Figure 4 are shown in Figure 5, which shows the current passing through Re (related to corrosion process) and the current passing through Rs (the total current in the circuit). As seen, there is a sharp dropoff in the Reff current as the impedance of the capacitor in series with Reff diminishes with increasing frequency, thus "short-circuiting" the Reff resistance connected in parallel. However, although most of the current at 60 Hz passes through the capacitance and thus does not affect corrosion reactions, there is a nontrivial amount of AC (119 pA, approximately 0.3% of the total) that still passes through the Reff at 60 Hz.

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Figure 4: Electrical equivalent circuit:"

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40mA

(60Hz, 34.432mA)

0 0 0

30mA

20mA

10mA

(60Hz,118.908uA)

OA 0Hz 10Hz o I(Reff) ME -I(Rs)

a 20Hz 30Hz 40Hz 50Hz 60Hz

Frequency

Figure 5: An illustration of a simulation run (upper line shows total AC in the circuit; lower line shows current passing though Ref ).41

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AC Corrosion Mechanism

Given the often-present differences in conclusions published on the subject of AC corrosion, there is no agreement on a mechanism for the phenomenon, particularly as it applies to corrosion in soils. There is a controversy about the direction of AC polarization of metal—to more negative or positive potentials (e.g., Pookote and Chin19 and Hamlin42). There appears to be a consensus on one aspect of AC corrosion: the corrosion rate associated with a particular AC density is less than 1% of that caused by DC of similar magnitude (a dissenting study by Radeka, et al.43 suggests that in seawater the AC "efficiency" is between 6 and 14% for 60 Hz densities between 20 and 150 Aim [1.9 and 14 A/ft2]). An early work by Williams15 (1966) dismissed the notion that AC corrosion is the result of the waveform rectification at the steel surface and suggested that the mechanism of the attack is essentially that of DC corrosion. A study by Juetner, et al.44 on a ring-disk (mild-steel Pt) electrode in water-based solutions of sulfates, carbonates, and chlorides at AC densities up to 200 A/m` (19 Affi2) concludes that there were no indications of a change in the anodic or cathodic reaction mechanism. Gummow, et al.2° present summaries of several of the quoted studies; the proposed explanations focus on the effect of AC corrosion current passing through the resistive components of the corrosion circuit on the anodic and cathodic reactions.

Several publications addressing the AC corrosion mechanism are discussed in further detail.

Electrical Equivalent Circuit Analysis

Nielsen and Cohn14 offer a more extensive discussion of the aspects of the AC corrosion model; an extended summary of the article is presented below.

Pipelines with highly resistant coatings are susceptible to induction of AC from high-voltage power lines. The AC current appears to be a source of corrosion at coating defects where the AC discharges from the pipe. Equivalent circuits modeling AC corrosion can be helpful in understanding the corrosion process and underlying mechanisms.

Figure 6 shows a schematic of an equivalent AC corrosion circuit suggested by Nielsen. The AC and DC sources impose a DC and AC voltage in between the pipeline and remote earth at a specific location or coating defect. The AC source represents AC induction, whereas the DC source represents the CP system.

The corrosion reaction in this example consists of the nonequilibrium reaction sequence of the oxidation of iron (VB1) and the reduction of one of the three VB2 equilibrium reactions (see Equations [2] through [5]).

VB1. Fe° = Fe++ + 2e-. (2)

VB2. 40H- = 2H20 + 02 + 4e-. (3)

VB2. H2 = 2H+ + 2e-. (4)

VB2. H2 + 20H- = 2H20 + 2e-. (5)

The equilibrium potentials for two such electrochemical reaction schemes are represented by E01 and E02 in Figure 6, being additional electrochemical or electromotive forces defining the open-circuit DC potential.

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/AC v

E01

E02

CI

VB1 —A— VB2

C2

Wlc

Wla

W2c

W2a

IDC

AC source (Induction)

CD

DC source (CP-rectifier)

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Remote earth

Figure 6: Schematic of a proposed AC corrosion equivalent circuit."

Electrochemical equilibrium processes existing at the steel surface are associated with an equilibrium potential (E0). The equilibrium potential can be calculated using the Nernst equation, Equation (6):

E0 = E0 +—

RT In

aB

nF BaA (6)

where:

E° = standard equilibrium potential; R = gas constant; T = absolute temperature; n = number of valence electrons; F = Faradays constant; and

= activity or concentration of the species X of equilibrium equation [aA = bB +

Hence, E01 and E02 represent the equilibrium potentials of two Volmer-Butler reaction schemes (VB1 and VB2) occurring at the corrosion interface, such as (1) iron dissolution (oxidation)-1a and iron re-deposition (reduction)-1c and (2) water/oxygen/hydrogen oxidation-2a and water/oxygen/hydrogen reduction-2c.

In a simpler Randle's circuit (similar to the one shown in Figure 4), polarization resistance represents the charge transfer resistance of the slowest process. In the proposed circuit, there are individual charge transfer resistances for each single process and illustrated as a diode element in the equivalent diagram, Figure 6. At potentials different from the equilibrium potential, the process proceeds with a rate that can be described by the Faraday current according to the Volmer-Butler equation (Equations [7a] and [7b]). The Volmer-Butler equations relate to a single electrode process, consisting of anodic and cathodic current-potential characteristics.

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1F,a = 10 CA,surface exp

(E E

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(7a) CA bulk _ , _

1F,c = 10 CB,surface

exp7 E — E 0 \ - (7b)

CB,bulk Pc

where:

IF = Faradaic current related to the process; = Exchange current related to the process;

Cl, surface = Surface concentration of species i; C,, bulk = Bulk concentration of species i; E = Polarized potential (off-potential); E, = Equilibrium potential of the process as given by Equation (6); and Ra, ß = Tafel slope related to the anodic and cathodic reactions.

To each of the individual processes, a diffusion impedance or diffusion element is attached and symbolized by W (for Warburg impedance). This impedance restricts the rate by which the reactions can occur as a result of diffusion limitations of reactants (and products for that matter). It is noted that this impedance is frequency dependent. The Faraday current passing through the circuit is determined by the sum of the Volmer-Butler impedance and the Warburg diffusion impedance. These describe, basically, the degree to which the electrochemical reactions are fast enough to occur at the relevant frequency.

The Volmer-Butler theory only applies to the current passing through the polarization resistance component of the interface and does not apply to the current that passes through the capacitive component. The capacitive nature of the electrochemical interface imparts frequency dependence to the portion of current that passes through the polarization impedance/resistance.

Nielsen, et al.45 attribute the AC corrosion process to the Volmer-Butler element represented as VB1 and VB2 in Figure 6. AC corrosion occurs if the charge during the anodic half-cycle exceeds the cathodic charge (Equation [8]). However, if the opposite occurs, corrosion does not take place. This is possibly an overly simplified statement of an AC corrosion mechanism.

la (At) > lc (At) (8)

The R. element in Figure 6, the spread resistance, is controlled by factors relating to the resistance of the soil solution, porosity, and geometric factors at the interface between the soil and the coating defect. An ohmic resistance or IR drop develops when current flows from remote earth to a coating defect of the pipeline through the soil.

Figure 7 shows the effect of the defect configuration on the pipe-to-soil resistance. Thus, a bare surface (Figure 7a) results in only a soil resistance. However, a coated surface with a holiday gives rise to both soil resistance and spread resistance. A large IR drop develops near the vicinity of the pipe-to-soil interface where the coating defect is present. A geometric spread effect is produced as a result of concentrated current flux lines allowed by the defect geometry to spread out from the narrow coating defect. When the area of the defect is taken into account, small defects have smaller spread resistances (per unit area) compared with larger coating defects.

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Figure 7: Illustration of geometrical effects on pipe to soil resistance.24

Because of the low impedance of the capacitance, the spread resistance, Rs, is the dominating (greatest) impedance element at 50/60 Hz in the current path between a coating defect and remote earth, thus controlling the AC magnitude.

AC Effect on Corrosion Process in Absence of Cathodic Protection

Using extensive laboratory work, Yunovich and Thompson41 used a conventional electrochemistry approach (modified Randle's equivalent analog circuit depicted in Figure 4 and described earlier) to develop an AC corrosion model in the absence of CP. As discussed, only a small amount of the 60 Hz AC discharge passes through the resistive component of the equivalent circuit, which results in corrosion (metal loss) reactions. The AC passing through this resistive component produces both anodic and cathodic polarization shifts (sinewave dependent), resulting in a net increase in the average corrosion rate compared to the free corrosion rate.

The proposed model for AC corrosion does not invoke any new electrochemical concepts and is based on the conventional (DC) treatment of the corrosion processes. AC corrosion is characterized by the rapid formation of a diffusion controlled (Warburg) process for corrosion in soils. Although diffusion controlled, the overall impedance decreases as the total AC increases.

In this analysis, it is assumed that the metal loss reactions are nonreversible, and the reduction reaction is the conventional oxygen-water reduction. Likewise, it is assumed that metal loss is the only available oxidation reaction. Prior work indicates that the application of CP results in possible nonmetal-loss oxidation reactions. For the following example, no CP is assumed. It is realized that each reaction sequence has a specific time constant associated with that specific reaction. Therefore, the above assumption implies that the time constant is sufficiently fast that the reaction sequence is applicable at 60 Hz.

An example of a corrosion process under the influence of AC signal is illustrated in the schematic in Figure 8. The graph is based on realistic potential and current values; the assumed Eccs-r is —700 mV .(CSE) and iCorr IS 4.7 mA (which corresponds to a corrosion rate of 3 mpy (0.08 mm/y) for a 4,580 mm2 [7.1 specimen). As seen from the graph, the imposition of an AC signal results (shown by the "ABOCK sinewave) in the potential shifts in anodic (positive) and cathodic (negative) direction of the corroding metal during the respective halves of the sinusoid; the absolute value of the potential shift is 150 mV.

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0 1 icor(

1.0

jAC-Red

10 lAc

1.4C-Red

100

IAC-Ox

Log Current (µA)

Z P

ote

n tia

l (V

, CS

E)

-0.6

-0.7

-0.8

-0.9

-0.4

-0.5

-1.0

-1.2

• •

Fe -*Fe.2 + 2e" [Oxidation Reaction]

2H20 + 02 + 4e" -÷40H" [Reduction Reaction]

• • • • •

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Figure 8: Schematic of proposed mechanism of AC-enhanced corrosion.

The relationship between potential (E) and current (i) is semi-logarithmic The dependence of the anodic potentials (Ea) can be approximated with a linear equation of the type Ea = fllogOa) + b, where ß is the Tafel slope of the anodic process, and ia is the anodic reaction current. During the anodic part of a single period of the sinewave (ABO), the anodic current density increases to the value denoted iaAc _ox, during the cathodic part, the anodic current density decreases to the value denoted icAc-ox. During the semi-log dependence between potential and current, the average anodic current for a single AC sinewave period (iAc) is greater than the icor, value for freely corroding conditions in the absence of AC Therefore, in this example, the presence of the AC signal equivalent to a + 150-mV peak polarization shift produced an increase in the oxidation current from 4.7 pA to 13 pA, which corresponds to an increase in corrosion rate from 3 to 8 5 mpy (0.08 to 0 22 mm/y).

The above example illustrates the proposed underlying principle for the AC-enhanced corrosion mechanism- polarization of the metal sample by the imposed AC produces a net anodic (oxidation) current greater than the free-corrosion current, thus leading to accelerated corrosion attack. A more rigorous analysis of the proposed model follows below. The example is still based on the realistic values assumed above.

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Assuming that the E = f(i) relationship is defined by Equation (9):

E = flalog(i) + b

(9)

where Ra is the Tafel slope for a corroding metal in soil (assumed to be 150 mV per decade of current).

In order to determine the value of the free member b, two more values are needed (E and i). Following the above example, the value of E is assumed to be —700 mV; the value of i is assumed to be equal to the magnitude necessary to produce a "typical" corrosion rate. Equation (10) yields the value of i:

r (mpy)= 129 x ia (10) AnD

where:

r = corrosion rate in mil per year 129 = conversion factor to convert units3 i = corrosion current, mA A = specimen area, cm2 a = atomic weight of iron (55.8 g) n = the valence of the dissolving iron (2) D = density (7.87 g/cm3)

For the average corrosion rate of 3 mpy (0.08 mm/y), substituting the values in Equation (10) yields the corrosion current value of 4.7 mA (based on the area of a sample of 71 mm2).

Next, the value of b is calculated by substituting —700 mV and 4.7 mA into Equation (9) to produce the answer 99.8 mV.

Further assume that the potential shift due to the AC signal is defined by Equation (11):

EAC= Eosin (2-rrft) (11) where:

EAC = potential at time t due to the AC signal Eo = amplitude of potential shift of corroding metal due to AC (assumed to be 150 mV) f = frequency of the signal (60 Hz or 0.0167 seconds)

Rearranging Equation (9) and substituting the assumed and calculated values, one arrives at the relationship between current i and potential EAC as shown in Equation (12):

Ecorr +E AC —b

i - - 10 a = 10

Ecorr+E0 sin(270)—b

ßa (12)

The graph in Figure 9 illustrates an example of the change in EAc and the resultant current for a single period of a sinewave. As seen during the anodic semi-cycle, the current exhibits shifts to considerable magnitudes, much greater than the free corrosion current. During the cathodic semi-cycle, the oxidation current decreases compared to the free corrosion current, but not to the same degree as the increase during the anodic semi-cycle. Therefore, the complete AC cycle results in a net positive increase in the oxidation current. This is consistent with Figure 8.

(3) The conversion factor is based on Faradays constant (96,487 coulombs) and units for area, density, and passing charge; it is used to arrive at the desired units for corrosion rate (mils per year) while using metric-based units for the input parameters.

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-0.200 5 00E-05

-0.900 0 250 300 50 100 150 200

Degrees

0 00E+00 350

-0.400 3 50E-05

- 3 00E-05

- 2 50E-05

2 00E-05

- 1 50E-05

•/** 1 00E-05

w

a! -0.600

-0.800

4 50E-05

• Potential, V

4 00E-05

-II- Current, A I

-0.300

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Figure 9: Potential and current shifts for a single period of 60-Hz current producing 150 mV of potential shift:"

As the current distribution in time has been determined, it is possible to calculate the metal loss associated with each current and determine the corrosion rate. The graph in Figure 10 shows the calculated metal loss versus time for a single period of imposed AC and also depicts the cumulative metal loss for the same time. Based on the graphed data, the estimated AC corrosion rate produced by the imposed AC signal with the assumed characteristics is 8.5 mpy (0.22 mm/y).

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0) 1.5E-12

o

:5 .co

313 1E-12

5E 13

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2 5E-12 8E-11

7E-11

— 6E-11 Metal loss, g

—x— Cumulative 5E-11

metal loss, g

— 4E-11

3E-11

2E-11

1E-11

50

100

150 200

250

300

350

Degrees

Figure 10: Instant and cumulative metal loss for a single period of 60 Hz AC producing 150 mV of potential shift.

In the preceding example, conventional polarization analysis was used to estimate the increase in corrosion rate as a result of an applied AC voltage. Furthermore, this analysis predicts the parameters that have the most significant effect on ACEC are those that determine the amount of current that passes through the effective resistance of the equivalent circuit.

The model suggests that alternating currents (60 Hz) cause anodic (positive) polarization shifts during the positive portion of the imposed AC sinewave along with cathodic polarization shifts in the negative portion of the AC sinewave; the net result is an increase in the average oxidation (metal loss) current compared to the free corrosion condition. The proposed model for the AC mechanism showed excellent correlation with the experimental results.

Earth Alkaline Versus Alkaline Cations

In accordance with the above, Stalder46 proposes that AC corrosion may be affected by the chemical composition of the environment at the steel-soil interface and its impact on the spread resistance. This theory considers the concentration ratio between earth alkaline cations (such as Ca2+ and Mg2+) and alkaline cations present in the soil (such as Na+, K+, or Li+). Earth alkaline cations such as calcium and magnesium form hydroxides [Ca(OH)2 and Mg(OH)2] caused by the surplus of hydroxide ions in the environment produced by the CP reactions. Hydroxides may be converted into carbonates (CaCO3 and MgCO3) in the presence of carbon dioxide (CO2). Hydroxides and carbonates of earth alkaline cations produce solid precipitates with low solubility. In comparison, hydroxides and carbonates formed with cations such as sodium and potassium (Na0H, KOH, and Na2CO3) are soluble. The resistive solid deposits act to increase the spread resistance (R8) associated with the coating holidays. Therefore, Stalder suggests that earth alkaline cations in the soil (which promote the formation of highly resistive deposits) may lead to a higher spread resistance and a correspondingly lower magnitude of AC at the coating holiday (lower risk of AC corrosion).

In addition to the greater spread resistance, earth alkaline cations have been shown to passivate the anodic branch of the metal dissolution (VB1) process at pH values as low as 6. This would also have the effect of decreasing AC corrosion caused by a Volmer-Butler anodic dissolution mechanism. Therefore, Stalder

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Cu

mu

lati

ve w

eig

ht l

oss

, g

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proposed that the ratio of earth alkaline cations to alkaline cations is critical to identifying areas where AC corrosion is most probable.

Alkalization Mechanism

The above theories by Stalder on earth alkaline versus alkaline cations provided the basis for the alkalization theory. Nielsen, et al.45'47-51 further develop this theory.

In brief, this mechanism proceeds when hydroxide (OH-) produced by CP current accumulates in the near surroundings of the coating defect (Figure 11). The combined action of potential vibration caused by the AC and adequately high pH induces corrosion attacks. Potential fluctuations between the immunity and passivity regions of the Pourbaix diagram (Figure 12) may cause corrosion as a result of different time constants associated with iron dissolution (fast) and subsequent formation of passive film (slower). At very alkaline pH (14), the formation of dissolved HFe02- may stabilize corrosion at a very high penetration rate.

Pipe surface

OH— neutralization base neutralization effect

(BN E)

OH- Time to reach critically high pH value

INCUBATION PERIOD

Outflux (Diffusion - texture)

Influx (60

Accumulation (pH increase)

Figure 11: Mass balance schematics for OH- ions produced by CP at a coating defect.

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1.500

1.000

a 0.500 (.)

w > 0 000

Lu -0.500

-1.000

-1.500

0 2 4 6 8 10 12 14 16

pH

Figure 12: Pourbaix diagram showing unsafe region with respect to AC corrosion.47

Furthermore, it has been illustrated by laboratory soil box experiments as well as field investigations that the DC density has a significant effect on the spread resistance and accordingly on the AC density and corrosion rate.

Soil box experiments were run over three weeks each and were performed in alkaline pore solution in inert quartz sand.5° In all experiments, the AC voltage was controlled at 15 V. Six experiments were conducted, and the electrical parameters and corrosion rate were monitored using an electrical resistance probe.9 The test duration was over two to three weeks each, and the experiments differed by the applied polarization (ON) potential (-850, —950, —1,100, —1,200, —1,250, and —1,300 mV CSE, respectively).

Figure 13 through 16 show some results from these studies. All data from the six experiments have been merged into the graphs. Figure 13 shows that AC density increases as the DC density is increased. Data in Figure 14 suggest that the spread resistance is inversely proportional to the DC density. Figure 15 and Figure 16 show that the corrosion rate increases as a function of not only AC density (Figure 15) but also DC density (Figure 16). The researchers attribute the latter trend to the alkalization at the steel interface as a result of accumulation of hydroxide ions. As such, the authors theorize that DC can influence the AC corrosion process, and that excessive CP is normally avoided. These conclusions were adopted by the European standard.39

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+ -850 mV DC

0 -950 mV DC

x -1,100 mV DC

A -1,200 mV DC ... -1,250 mV DC x -1,300 mV DC

600

500 E

';', 400 -- cn c .8 300

200 = o 0 < 100

Cathodic current density (A/m2)

Figure 13: Correlation between AC and DC current densities—NaOH soil box. (1 A/m2 = 9.3 x 10-2 Aflt2)

21

o 0 0

0 1

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+ -850 mV DC ° -950 mV DC A -1,200 mV DC . -1,250 mV DC

x -1,100 mV DC x -1,300 mV DC

0.20 ..---..

CV -850 mV E E 0.15 _c 0 -950 mV a) c) c ca 0.1 0 -1,100 mV

0 0 :iniii

0

0 1, 2 -1,250 mV 7.1 -1,300 mV

EL2 \ x \ x x x xx x % x zaa0110000111111.1.10, P

cu 0.05 )mminwomerawi, .

(r) 0_

t -1,200 mV

0.00 '''' I" ' I" " I ' ' . . 1 . . i , l , i " i

-14 -12 -10 -8 -6 -4 -2

Cathodic current density (A/m2)

Figure 14: Correlation between DC current density and spread resistance—NaOH soil box. (1 A/rn2 = 9.3 x 1cr2 Ant2)

22

-1,300 mV

-1,250 mV

4111

-850 mV -950 mV

litellikilliip

a 1111111, -1,200 mV

ANIIIIIMill* ' -1,100 mV

0 0 0

V

Corr

osi

on

rate

(p

m/y

)

250

200

150

100

50

0

-50

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+ -850 mV DC 0 -950 mV DC

x -1,100 mV DC

A -1,200 mV DC _ -1,250 mV DC x -1,300 mV DC

0 100 200 300 400 500 600

AC current density (A/m2)

Figure 15: Correlation between AC current density and corrosion rate—NaOH soil box. (1 A/m2 = 9 x 10-2 AJft2)

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o o o CO

Cor

rosi

on ra

te (p

m/y

)

250

200

150

100

50

0

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+ -850 mV DC 0 -950 mV DC x -1,100 mV DC A -1,200 mV DC _ -1,250 mV DC x -1,300 mV DC

-1,100

-1,200 mV

mV -850 mV

111111 1 -950 mV

•

-14 -12 -10 -8 -6 -4 -2

Cathodic current density (A/m2)

Figure 16: Correlation between DC current density and corrosion rate—NaOH soil box. (1 A/m2 = 9.3 x 10-2 A/ft2)

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Effects of AC on Overpotential

As discussed earlier, there is empirical evidence that AC might cause polarization (potential shift) of the affected structure. Bockris and Reddy52 suggested that some degree of AC "current rectification" may take place at the steel interface, and the difference in the anodic and cathodic Tafel slopes of the corrosion process results in the net positive or negative potential shift.

Other authors24.39.53-56 also pointed out that the ratio of the anodic and cathodic Tafel slopes determine the sensitivity of the corroding system with regard to the AC caused polarization. If the potential shift is asymmetrical (r = 1), when an external sinusoidal potential excitation is applied, a net DC (rectification current) results. However, regardless of the ratio, if the corrosion process is controlled by activation polarization, under AC influence, corrosion (or exchange) current density would be expected to increase, which could lead to corrosion.

The acceleration of the corrosion rates in the presence of AC has been attributed by some authors19'27 to reduction of polarization of both the anodic and cathodic areas, as well as the passivation24'57'59 of the affected material. Authors observed that the corrosion potential is shifted in the negative direction24'57 and that the exchange current density increases and the Tafel slopes decrease correspondingly.19,27

Lazzari, et al.59 suggest that more than one of the theories proposed in literature are eligible for consideration, thus proposing a "mixed" mechanism. The authors discuss the issue of reversibility of cathodic and anodic processes and state that the process occurring during the anodic half-cycle of the AC signal might not be completely reversed during the cathodic half-cycle. As a result, the double-layer chemistry can be affected, which in turn would influence the corrosion kinetics, leading to changes in the polarization behavior and shifts of corrosion (or equilibrium) potential.

Therefore, considering that in most cases the principal anodic process during the anodic half-cycle is metal dissolution and the principal cathodic one during the cathodic half-cycle is either oxygen reduction or hydrogen evolution, similarly to Yunovich and Thompson12 and Nielsen and Cohn,14 the authors conclude that the charge during the anodic cycle (metal dissolution) is greater than the charge during the cathodic cycle (metal deposition).

Cathodic Protection

The issue regarding what level of CP should be applied to mitigate AC corrosion is not without controversy.

Historically, the thought advocated by some was that applying CP in accordance with industry standards could adequately control AC-enhanced corrosion. However, as mentioned above, multiple failures of pipelines under CP, primarily in Europe, have been attributed to AC corrosion. The 1986 German investigation of an AC corrosion failure reported a high pitting rate despite CP current density of 1.5 to 2 A/m2 (0.14 to 0.19 A/ft2) and on-potentials of —1.8 to —2.0 V (CSE).6 The literature survey by Gummow, et al.29 cites the follow-up investigation to the failure; it was found that increasing the CP current density to 5 A/m2 (0.47 A/ft2) reduced the corrosion rate at 50 A/m2 (4.7 A/ft2) AC by a factor of two. The survey also cites an example when AC corrosion could be mitigated at CP current densities of 4 A/m2 (0.37 A/ft2), yet in another example that even at 10 A/m2 (0.93 A/ft2) of DC density, AC corrosion rernained considerable at AC densities of 100 to 200 A/m2 (9.3 to 19 A/ft2).

A report by Frazier69 indicated that the coupons immersed in a simulated ground electrolyte and exposed to intermittent application of AC and CP were found to be adequately protected by 100 mV of cathodic polarization.

The German standard29 requires limiting current density while maintaining about 1 Nm2 (0.093 A/ft2) of DC density on coated pipelines. A 1986 study by Hamlin42 states that metals (including pipeline steel) under the influence of AC could be protected, but "usually at higher initial current densities."

Several recently published accounts warrant a further discussion. Hosokawa, et al.61 present the results of a study that found AC corrosion could be mitigated to a corrosion rate of 0.4 mpy (0.01 mm/y) if AC density is below 70 Nm2 (6.5 A/ft2), but the AC-related attack remained probable if the AC density was over the threshold value. The study, carried out on two cathodically protected buried pipelines, used buried 100 mm2

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(0.2 in2) coupons to monitor the efficiency of impressed current CP and the level of AC reduction (using decoupling devices and magnesium anodes as grounding devices); without actually reporting on the findings, the study shows Figure 17 to illustrate the adopted criteria for DC and AC.

0.01 o l 10 20

100

DC Current Denstty.loc (A/m2)

Figure 17: AC and DC density relationship to achieve protection."

Figure 17 brings forth the notion of a CP "effectiveness threshold in the presence of alternating currents, i.e., it suggests that if AC density is in excess of a certain value (70 A/m2 [6.5 A/ft2]) as proposed by the quoted study), CP is not likely to have an effect unless the AC levels are reduced below the "threshold" at which CP can mitigate corrosion.

The authors also set the upper limit on CP current at 20 A/m2 (1.9 A/ft2) as a result of concerns of overprotection. Thus, the paper offers the following combination of AC and CP criteria for AC corrosion mitigation (which, according to the specific field evaluations, was proved to be adequate):

Protection achievable if:

(a) for 0.1 Nm2 (9.3 x 10-3 M12), lcp 1.0 Nm2 (9.3 x 10-2 Nft2), limit IAC (rms) < 25 Nm2 (2.3 A/ft2)

(b) 1.0 A/m2 (9.3 x 10-2 A/ft2) Icp 20 A/m2 (1.9 A/ft2), limit IAC (rms) < 70 A/m2 (6.5 Afft2)

As discussed earlier, following the notion that alkalinization at the steel interface has an impact on AC corrosion, Nielsen47 presents the results of field tests and proposes that "the CP level has a dramatic influence on the AC corrosion procese and that "excessive" CP can exacerbate AC attack. The values reported in the article show that at direct currents about 10 A/m2 (0.93 A/ft2) and off-potentials of approximately —1,100 mV (CSE), corrosion rates gradually increased to as high as 10 mm/y (400 mpy) (as measured by electrical resistance probes over a 2 week period).

These results were incorporated in European Standard CEN/TS 15280,3° which requires users of the standard to lower the pH at the steel/electrolyte interface by adjusting the CP "Eon" to obtain a CP "Eoff" that is more negative than, and as close as possible to, the limiting critical potential in EN 1295462 (which is —850 mV [CSE] for steel or iron in aerobic soils and —950 mV [CSE] in anaerobic soil with sulfate reducing bacteria).

Gregoor and Pourbaixl° posit in contrast that, based on a large number of short-term laboratory tests, protection from AC corrosion is only achievable when the potential of steel is within the "immunity' region of the Pourbaix diagram. In the tests, this corresponded to the imposed CP potentials more negative than —

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1,150 mV (CSE). Using Pourbaix diagram considerations, the authors postulate that, given the highly alkaline environment at the coating defects on the CP protected steel in soil, it is imperative to keep the "true" CP potentials more negative than the offered criterion. The authors comment that the proposed AC corrosion protection criterion might not be practical, and they advocate the use of mitigation measures (grounding) to mitigate AC current discharge from the pipe holidays. No consideration was given to the effect of such low potentials on coating adhesion and hydrogen-induced cracking in steel.

Another publicationn discusses the results of a laboratory study. The paper concludes that, based on weight loss and electrochemical measurements, CP of carbon steel can be achieved at potentials more negative than —1,150 mV (CSE). Corrosion protection is considered in terms of DC and AC density ratio (iDdiAc); according to the conclusions, the ratio is higher than 3 mADC/AAC. Using the empirically derived relationship, the following correlation between the CP current density for bare steel, iprot (111A/1112), is given in Equation (13) for the conditions when known AC density is above 30 A/m2 (2.8 A/fr):

iprot = L KAC 1AC

Where: = oxygen limiting current density (mA/m2);

iAC = AC density (A/m2); and KAC = a constant, estimated in the range 2 to 5.

(13)

The paper also notes that the "conventione —0.85 V (CSE) CP criterion is not adequate in the presence of AC interference.

While there is an apparent contradiction between the proposed polarization potential values between the European standare and the two publications described above,10' 63 it can be argued that these positions have the same goal. The notion of reducing both the CP levels and the concomitant pH values is aimed at ensuring that the potential fluctuations of steel caused by the AC are "contained" within the passivity/immunity region of the Pourbaix diagram (see hatched region in Figure 12 for an illustration).

Similarly, the position advocating much lower (more negative) polarization potentials seeks the same—ensuring that the steel potentials fall within the immunity region at all times, albeit at what are likely to be high(er) pH values. However, given the slope of the Fe/HFe02- equilibrium at high pH, the latter position would use more stringent control of potentials in the presence of AC influence. Also, besides the practical considerations with regard to maintaining such negative polarization (which might not be achievable in some conditions), the impact on coating disbondment and hydrogen-induced cracking becomes a concern.

With regard to the alkalization theory, elevated pH is likely to be present in conditions in which soil moisture content is limited. In such soils, the abundance of oxygen supply to the steel surfaœ and constraints on the outward migration of the hydroxide ions caused by low moisture content lead to hydroxide concentration buildup at the surface. It has been demonstrated in laboratory studies64 and observed in the field that relatively low CP potentials (off-potentials of approximately —850 mV [CSE]) give rise to pH values in excess of 12 at the steel surface. If the applied potentials are kept at the levels suggested on the basis of alkalinization's impact on AC corrosion, according to the Pourbaix diagram-based reasoning, the steel would be in the potential-pH region where AC corrosion might be likely.

One other aspect of the CP requirements for AC corrosion protection that has not been adequately addressed in the published literature is the polarization shift. Yunovich and Thompson12 have demonstrated that at low (20 A/m2 [1.9 A/ft2]) AC densities, steel specimens exposed to soil have achieved protection under 100 mV of polarization shift. The contour plot of AC density-CP polarization shift-depth of penetration (normalized to the control specimens) is shown in Figure 18. However, the plot is based on a limited number of tests and is not the definitive guideline.

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Figure 18: Contour plot of AC density (A/m2, horizontal axis)—CP polarization shift (mV, vertical axis)—Depth of penetration relative to control (%). No shading—protection achieved; light shading—marginal protection; dark shading—no apparent protection. (1 A/m2 = 0.093 Nft)

AC Mitigation Methods

AC mitigation in conjunction with CP is frequently used to minimize any effect of AC interference. Historically, several methods, such as installation of decoupling or grounding devices, were used to reduce AC interference. As shown above, although increasing the CP current density is reported to reduce AC corrosion, AC corrosion can ostensibly remain significant, even when "conventional" CP criteria are being met. Further, it is argued that increasing CP to control AC corrosion can result in the opposite effect because of increased pH and reduced spread resistance at the defect in the coating.

Therefore, the typical means of controlling AC corrosion is to provide grounding at critical locations to transfer the discharge point of the AC from the pipeline to the grounding conductors. Computer modeling has shown that properly located earthing conductors reduce the pipe leakage current density by an order of magnitude or more.66 The induced current in the pipe is likely to increase after mitigation is installed; however, the discharge density is normally reduced, and the grounding conductors discharge the bulk of the current if properly designed. Although the major industry emphasis for AC mitigation has been for touch voltage considerations, it is thought that in locations in which adequate mitigation (e.g., grounding) has been installed to reduce the coating stress voltage during faults to under 5 kV, and a touch voltage is maintained below 15 V at above-grade portions and appurtenances, and step-and-touch voltages during faults comply with the criteria in IEEE Standard 80,66 AC corrosion may not be of great concern

Mitigation installed for electrical safety considerations generally has a beneficial effect on controlling AC corrosion. However, the mitigation measures are installed at regularly spaced intervals along the affected pipeline section. In addition to personnel safety, the criteria for successful AC voltage mitigation normally

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include considerations for reducing AC corrosion likelihood. In many cases, the effectiveness of the mitigation measures is only evaluated with regard to steady-state touch voltage conditions, which might not be sufficient for AC corrosion control. Mitigation is also often installed for fault (inductive and conductive) conditions, as fault can be more extensive than mitigation installed only for reducing steady state touch voltages. However, measures provided to satisfy both steady-state and fault mitigation objectives appear to also reduce AC corrosion risk.

As the literature survey indicates, AC voltages are not necessarily related to the probability of corrosion, and AC density is typically a more reliable metric for assessing AC-enhanced corrosion risk. Furthermore, there is no definitive agreed-on threshold of AC leakage density.

One experimental observation that is relevant to AC mitigation is that the efficiency (the ratio of the observed weight loss to the theoretical one) of sacrificial anodes, which are routinely used for AC mitigation, apparently decreases as AC interference increases. Recent research63 suggested the consumption rate of Mg anodes increased about 10 times at AC density above 7 A/m2 (0.65 A/ft2).

Careful consideration and thorough documentation is utilized during the installation of mitigation measures, as the presence of foreign metal objects electrically continuous with the pipeline (such as the grounding devices) affect common indirect inspection techniques used for external corrosion direct assessment (ECDA) of underground structure conditions.

AC Corrosion Monitoring

Considering that it is relatively simple to measure AC voltage on a buried pipeline, AC potential measurements (such as AC close interval survey [CIS]) have been the primary parameter for characterizing the AC level on pipelines. However, measuring AC voltage is primarily a measure of IR drop in the ground and has all of the problems of dealing with IR drop in pipe-to-soil potential measurements. That is, the IR drop (and therefore AC voltage measurement) is dependent on several factors, including soil resistance, spread resistance, holiday size, holiday distribution, overall coating condition, etc. Although AC voltage is generally an appropriate measure for safety concerns (step-and-touch voltages), AC voltage is not normally a good parameter to assess the likelihood of AC corrosion. On the other hand, once relationships have been established between AC density and AC voltage measurements at local sites, AC voltage surveys are sometimes used to apply those relationships along that right-of-way. Whereas estimates of the AC density are sometimes made using the AC voltage (assuming that information is available with regard to the coating defect size and soil resistivity), some argue that caution should be exercised while making calculations—using Equation (1), in very low-resistivity soils, potentials as low as 1 V AC would imply an AC leakage density "sufficiently high" to be considered hazardous, which seemingly runs contrary to some field experiences.

The measure typically used is the polarized potential (off-potential). Unfortunately, prior studies have specifically addressed the problems of making "fasr (in this case, somewhere around 300 measurements per second to characterize a 60 Hz signal) off-potential measurements, especially on pipelines. Inductive effects (spiking) typically require 100 to 500 ms to make a measurement of most pipelines, compared to the 17 ms of a single 60 Hz cycle. Further, potential measurement alone does not "fix" the conditions at the steel/soil interface; as discussed earlier, knowledge of pH is a component of determining whether the potentials fall in the immunity region on the Pourbaix diagram.

As such, for AC monitoring, AC density appears to be a reliable measurable parameter related to AC corrosion. Because the current density and not just current flow in the ground is typically measured, the use of CTSs has been suggested by many.

The CTS-based approach is capable of determining the AC discharge on the fixed area coupon(s), and thus provides a means to estimate the AC density and, with the proper criterion, the probability of AC corrosion at a defect of similar size to the coupon area. Furthermore, the CTS coupons also register the changes in the currents and potentials (both AC and DC) as a result of the operation (or lack) of AC mitigation measures such as individual Mg anodes or Zn ribbon anodes.

One question associated with the use of the CTS coupons for the purposes of assessing the probability of AC corrosion is the choice of coupon sizes. Gummow, et al.2° present a brief discussion on this subject, noting that the published literature strongly suggests that the preferred size for the coupon is 100 mm2 (0.2 in2), as

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several field studies had found that this is the size of the holiday for which the most AC corrosion took place. The cited publications also have indicated that the holidays smaller than 3 mm2 (0.005 in2) did not suffer from AC corrosion. When coupons are used for corrosion monitoring, consideration is generally given to the geometry of the coupon. In other words, a large flat coupon is not expected to have the same spread resistance as a long cylindrical one, especially if the overall area is small. However, the geometry-related effects for all but small-area coupons are expected to be secondary to the impact of coupon location, placement, and depth of burial on the AC current monitoring accuracy.

Funk and Schoeneich6 also commented on the use of buried coupons for AC corrosion; the authors concluded that because of the temporal dependence of the corrosion rate, the coupons should be buried for at least one year. The primary purpose of the coupons in this study was determination of the corrosion rate by weight loss measurements, as opposed to the use of the CTS coupons for monitoring.

Another presented conclusion is that multiple coupons (at least three) should be installed in each location known or suspected to have AC corrosion problems such that the probability of encountering the worst case is increased.

As an alternative to coupons, electrical resistance probes are sometimes used; these are still subject to the sensor size considerations. The end users typically consider the costs and benefits of each of the technologies.

One important aspect of monitoring (whether CTS or resistance probe-based) is the duration of data logging. The following two charts in Figure 19 and 20 are taken from a CORROSION 2007 paper;67 the paper discusses field data collected from CTS located near the pipelines sharing the right-of-way with HVAC transmission lines.

As seen in both charts, there are significant variations in the induced AC density on collocated pipelines that are the result of HVAC line loading changes. Figure 19 is a plot of AC density (calculated using the area of a CTS coupon) over a 20 day period taken at 1 hour intervals (average) during July and August 2006.

Figure 20 is a plot of the measured coupon AC density over a 3 day period taken at 1 minute intervals (average current during the recorded minute) at the same coupon.

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60

50

NE 40

Pa A 1 30

1 20

10

0 7/19 7/20 7/21 7/22 7/23 7/24 7/25 7/26 7/27 7/28 7/29 7/30 7/31 8/1 8/2 8/3 8/4 8/5 8/6 8/7 8/8 8/9 8/10 8/11 8/12 8/13

Figure 19: AC density at a coupon over 20 days in July/August 2006.

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Typical time of day technician takes reading

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10

0 14-Jul-06 14-Jul-06 15-Jul-06 I5-Jul-06 15-Jul-06 15-Jul-06 16-Jul-06 16-Jul-06 16-Jul-06 16-Jul-06 17-Jul-06 17-Jul-06 17-Jul-06 17-Jul-06

Figure 20: AC density at a coupon over 3 day period in July 2006.

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The author comments that the highest induced AC potentials are typically found during the daytime when the readings taken by corrosion technicians (as opposed to the data gathered over a longer period of time by acquisition devices) are typically collected. The primary conclusion is that the duration of monitoring could have a major role in deciding the likelihood of AC corrosion attack.

The approach to on-site monitoring/assessment of AC corrosion risk in the absence of the (semi) permanently installed CTS is not specifically addressed by the reviewed publications. It is feasible that the monitoring could entail placement of a temporary coupon in order to log the current density of the AC discharge from the coupon; a less desirable alternative (subject to the discussions above) typically would consist of taking pipe-to-soil AC potential readings and making soil resistivity measurements at the collection site(s). These data then can be used to estimate the current density (via, e.g., Equation [1]).

Summary

The body of literature indicates that AC corrosion or AC-enhanced corrosion has become accepted as a bona fide phenomenon, which constitutes a shift from the earlier paradigm. Probabilistically, higher AC densities are likely to result in accelerated corrosion of steel. There is an inverse relationship between the impact of AC and its frequency; however, there appears to be a consensus that at prevailing commercial current frequencies (such as 50 or 60 Hz) corrosion is possible, even on cathodically protected pipelines.

General corrosion rates that are the result of AC corrosion are not necessarily "abnormally high (much higher naturally occurring rates of an existing pipeline have been reported), but the rates are certainly multiples of the "prevailing" corrosion rates of steel in soil in the absence of AC.

Although some investigators have attempted to explain mechanisms of AC corrosion, there is a lack of technical consensus on the mechanism and the extent of the effect of AC on underground metallic structures. The published data possess a great deal of scatter; in many cases testing environments were not necessarily representative of conditions existing on buried pipelines, or the results are only applicable to a specific situation.

As there is still debate as to how AC affects corrosion rate and when there is a high likelihood of AC corrosion (conflicting accounts on whether there is a "safe threshold value of AC density below which AC corrosion is not likely to be a concern), there are no agreed-on criteria for AC corrosion protection. As discussed, the European standard3° advocates judicious use of CP current in order to avoid alkalinization, which, accordin2 to the theory, reduces the resistance at the steel interface and promotes corrosion. Other publicationei propose the use of very negative (-1,100 mV [CSE]) polarization potentials to protect from AC corrosion; both practical and technical issues can make this approach less attractive.

There is also an opinion61 that AC corrosion control might only be feasible when AC corrosion current density is brought below a certain value.

Discussion of AC mitigation indicates that while the use of 15 V (currently used as the personnel safety threshold value in the U.S.) as the criterion for low AC corrosion likelihood may lead to underestimating AC corrosion threats in some instances, it is still used as a target, as the reduction of AC voltage leads to the attendant reduction of AC discharging from the pipeline. However, while AC voltage is an appropriate measure for safety concerns (step-and-touch voltages), it is not a reliable metric to assess the likelihood of AC corrosion.

Therefore, the choice of AC monitoring approach typically involves methodologies that permit the measurement of current density. The most forward application of such an approach is the use of CTS; alternatively, temporarily installed electrical resistance probes are often used for periodic monitoring of conditions. Duration of monitoring sometimes plays a role in determination of the AC corrosion threat; longer duration times are typically employed to capture periods of both high and low AC interference.

Path Forward

The primary conclusion stemming from the state-of-the-art literature review is that there are sizeable knowledge gaps in both the fundamental understanding of AC corrosion phenomenon and the practical aspects regarding the approach to AC corrosion monitoring, mitigation, and control.

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In particular, more experimental and field-based work might establish the protection criteria for AC corrosion by determining whether a// expected AC interference conditions can be controlled by CP or whether some threshold level of AC would control the impact. The published accounts with regard to appropriate CP levels in the presence of AC interference are seemingly contradictory. There are no known published accounts with regard to the polarization shift criterion.

Certain commonly used means of AC mitigation are likely topics for further investigation. Recent data63 suggest that the current efficiency of galvanic anodes employed to reduce AC interference levels may be substantially lower in service because of increased corrosion rates.

The expanded body of evidence addressing the above gaps would enable undertaking the next logical step—development of a standard for AC corrosion monitoring, mitigation, and control. The European corrosion community has already taken this step by adopting a standard approved in 2006 (CEN/TS 15280: 2006).3° CEOCOR, a Belgium-based association of corrosion professionals and experts comprising 14 member countries, publishes a booklet25 with guidelines for AC corrosion risk assessment. Both publications were cited in this report; the criteria and recommendations in these documents are based on the existing understanding of AC corrosion and thus have the same knowledge gaps.

References

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3. L. Di Biase, "Corrosion due to alternating current on metallic buried pipelines: background and perspectives," Committee on the Study of Pipe Corrosion and Protection, 5th International Congress, held 2000 (Bruxelles, Belgium, CEOCOR, 2000).

4. I. Ragault, "AC Corrosion Induced by V.H.V Electrical Lines on Polyethylene Coated Steel Gas Pipelines," CORROSION/98, paper no. 557 (Houston, TX: NACE, 1998).

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8. H. Song, Y. Kim, S. Lee, Y. Kho, Y. Park, "Competition of AC and DC Current in AC Corrosion Under Cathodic Protection," CORROSION/2002, paper no. 117 (Houston, TX: NACE, 2002).

9. L.V. Nielsen, F. Galsgaard, "Sensor Technology for On-Line Monitoring of AC Induced Corrosion Along Pipelines," CORROSION/2005, paper no. 375 (Houston, TX: NACE, 2005).

10. R. Gregoor, A. Pourbaix, "Detection of AC Corrosion," 3R International 42, 6 (2003): pp. 289-395.

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12. M. Yunovich, N.G. Thompson, "AC Corrosion: Corrosion Rate and Mitigation Requirements," CORROSION/2004, paper no. 206 (Houston, TX: NACE, 2004).

13. C. Goran, "Alternating current corrosion on cathodically protected steel in soil—A long term field investigation," 5th International Congress, held 2000 (Bruxelles, Belgium, CEOCOR, 2000).

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14. L.V. Nielsen, P. Cohn, "AC corrosion and electrical equivalent diagrams," 5th International Congress, held 2000 (Bruxelles, Belgium, CEOCOR, 2000).

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22. G. Helm, T. Helm, H. Heinzen, W. Schwenk, "Investigation of Corrosion of Cathodically Protected Steel Subjected to Alternating Currents," 3R International 32, 5 (1993): p. 246.

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26. A. Pourbaix, P. Carpentiers, R. Gregoor, "Detection and Assessment of Alternating Current Corrosion," Materials Performance 38, 3 (2000): pp. 34-39.

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29. W. von Baeckmann, W. Schwenk (eds.), Handbuch des Kathodischen Korrosionsschutzes, (Weinheim, Germany: Wiley-VCH, 1999).

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31. S. Goidanich, "Influence of alternating current on metals (sic) corrosion," PhD thesis, Politecnico di Milano, 2005.

(4) Deutsches Institut fur Normung (DIN), Burggrafenstrasse 6, D-10787 Berlin, Germany. (5) British Standards Institute (BSI), 389 Chiswick High Rd., London, UK W44AL.

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32. R.D. Floyd, "Testing and Mitigation of AC Corrosion on 8" Line: A Field Study," CORROSION/2004, paper no. 210 (Houston, TX: NACE, 2004).

33. NACE SP0177 (latest revision), "Mitigation of Alternating Current and Lightning Effects on Metallic Structures and Corrosion Control Systeme (Houston, TX: NACE).

34. Technical Recommendation No. 7, "Measures for the installation and operation of pipelines in the vicinity of three-phase high-voltage systems and single-line traction systems" (Heidelberg, Germany: WVEW(6)).

35. S.Z. Fernandes, S.G. Mehendale, S. Venkatachalam, "Influence of Frequency of Alternating Current on the Electrochemical Dissolution of Mild Steel and Nickel," Journal of Applied Electrochemistry 10, 5 (1980): pp. 649-654.

36. M.L. Mateo, T. Fernandez Otero, D.J. Schiffrin, "Mechanism of Enhancement of the Corrosion of Steel by Alternating Currents and Electrocatalytic Properties of Cycled Steel Surfaces," Journal of Applied Electrochemistry 20, 1 (1990): pp. 26-31.

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40. R.L. Ruedisueli, H.E. Hager, C.J. Sandwith, "An Application of a State-of-the-Art Corrosion Measurement System to a Study of the Effects of Alternating Current on Corrosion," Corrosion 43, 6 (1987): pp. 331-338.

41. M. Yunovich, N.G. Thompson, "AC corrosion: mechanism and proposed model,", Proceedings of International Pipeline Conference 2004, paper no. IPC04-0574, held October 4-8, 2004 (Materials Park, OH: ASME(7)).

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44. K. Juetner, M. Reitz, S. Schaefer, H. Schoeneich, "Rotating ring-disk studies on the impact of superimposed large signal AC currents on the cathodic protection of steel," Electrochemical Methods in Corrosion Research VI, Materials Science Forum, 289-292, 2 (1998): p. 107.

45. L.V. Nielsen, K.V. Nielsen, B. Baumgarten, H. Breuning-Madsen, P. Cohn, H. Rosenberg, "Induced Corrosion in Pipelines: Detection, Characterization and Mitigation," CORROSION/2004, paper no. 211 (Houston, TX: NACE, 2004).

46. F. Stalder, "Influence of soil composition on the spread resistance and of ac corrosion on cathodically protected coupons," Proceedings of the 5th International Congress, held 2002. (Groniue, Holland: CEOCOR).

47. L.V. Nielsen, "Role of Alkalization in AC Induced Corrosion of Pipelines and Consequences Hereof in Relation to CP Requirements," CORROSION/2005, paper no. 188 (Houston, TX: NACE, 2005).

(6) Wirtschaftsgesellschaft der Elektrizitatswerke mbH (WVEW), Häusserstr. 36 36 , 69115 Heidelberg, Germany 69115. MASME International (ASME), 9639 Kinsman Rd., Materials Park, OH 44073.

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48. L.V. Nielsen, P. Cohn, "AC corrosion in pipelines. Field experiences from a highly corrosive test site using ER corrosivity probes," Proceedings of the eh International Congress, held 2003 (Groniue, Holland: CEOCOR).

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52. J.O.M. Bockris, A.K.N. Reddy, Modern electrochemistry - An Introduction to an Interdisciplinary Area, Vol. 2 (New York, NY: Plenum Press, 1970).

53. S.B. Lalvani, X.A. Lin, "A Theoretical Approach for Predicting AC-Induced Corrosion," Corrosion Science 36, 6 (1994): pp. 1039-1046.

54. U. Bertocci, "AC Induced Corrosion. The Effect of an Alternating Voltage on Electrodes Under Charge-Transfer Control," Corrosion 35, 5 (1979): pp. 211-215.

55. R.W. Bosh, W.F. Bogaerts, "A Theoretical Study of AC-Induced Corrosion Considering Diffusion Phenomena," Corrosion Science 40, 2/3 (1998): pp. 323-336.

56. S.B. Lalvani, X. Lin, "A Revised Model for Predicting Corrosion of Materials Induced by Altemating Voltages," Corrosion Science 38, 10 (1996): pp. 1709-1719.

57. D.T. Chin, P.Sachdev, "Corrosion by Alternating Current: Polarization of Mild Steel in Neutral Electrolytes," Journal of Electrochemical Society 130, 8 (1983): pp. 1714-1718.

58. T.C. Tan, DT. Chin, "Effect of Alternating Voltage on the Pitting of Aluminium in Nitrate, Sulfate and Chloride Solutions," Corrosion 45, 12 (1989): pp. 984-989.

59. L. Lazzari, S. Goidanich, M. Ormellese, M.P. Pedeferri, "Influence of AC on Corrosion Kinetics for Carbon Steel, Zinc and Copper," CORROSION/2005, paper no. 189 (Houston, TX: NACE, 2005).

60. M.J. Frazier, "Induced AC Influence on Pipeline Corrosion and Coating Disbondment," GRI, Project No. A381, December 1994.

61. Y. Hosokawa, F. Kajiyama, Y. Nakamura, "New CP Criteria for Elimination the Risks of AC Corrosion and Overprotection on Cathodically Protected Pipelines," CORROSION/2002, paper no. 111 (Houston, TX: NACE, 2002).

62. DIN EN 12954 (latest revision), "Cathodic protection of buried or immersed metallic structures. General principles and application for pipelinee (Berlin, Germany: DIN)

63. S. Goidanich, L. Lazzari, M. Ormellese, M.P. Pedeferri, "Effect of AC on cathodic protection of carbon steel in simulated soil conditions," EUROCORR 2006, paper no. 279, (Maastricht, Netherlands: EFC(8)).

64. L.I. Freiman, M. Yunovich, "Special Behavior of Steel Cathode in Soil and Protection Assessment of Underground Pipe with a Buried Coupon," Protection of Metals 27, 3 (1991): pp. 437-447.

65. D.E. Gilroy, "AC interference-Important Issues for Cross Country Pipelines," CORROSION/2003, paper no. 699 (Houston, TX: NACE 2003).

(8) European Federation of Corrosion (EFC), 1 Carlton House Terrace, London SW 1Y 5DB, UK.

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66. ANSI/IEEE Standard 80 (latest revision), "IEEE Guide for Safety in AC Substation Grounding" (New York, NY: IEEEM).

67. P.D. Simon, "Dynamic Nature of HVAC Induced Current Density on Collocated Pipelines," CORROSION/2007, paper no. 650 (Houston, TX: NACE, 2007).

68. P. Simon, "Case Histories Where AC Assisted Corrosion was Identified Below the 15 VAC Safety Threshold," presented at the NACE Eastern Area Conference, October 8, 2007.

69. L. Di Biase, "Corrosion Due to Alternating Current on Metallic Buried Pipelines: Background and Perspectives," Proceedings of the 1995 II National Conference, held November 21-22, 1995 (Milano, Italy: APCE(10), 1996), pp. 6-10.

Appendix A: Case Studies

This appendix is intended to provide supplementary information only, although it may contain mandatory or recommending language in specifications or procedures that are included as examples of those that have been used successfully. Nothing in this appendix shall be construed as a requirement or recommendation with regard to any future application of this technology.

Case Study 1 (Adapted From Reference 33)

Background

On August 29, 2002, a pipeline operator experienced an in-service leak on a section of a liquid butane pipeline in Rockwall County, Texas. The pipeline was an 8 in (203 mm) diameter by 0.19 in (4.8 mm) 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 (FBE) at a nominal 16 mil (0.41 mm) thickness. The girth welds are coated with heat-shrink sleeves. CP is supplied by impressed current deep anode systems.

The leak resulted from an extemal corrosion pit containing a through-wall pinhole penetration (see Figure A1). The outside dimensions of the corrosion pit were approximately 1 x 2 in (25 x 51 mm).

(9) Institute of Electrical and Electronics Engineers (IEEE), 3 Park Avenue, 17th Floor, New York, NY 10016 (1°)Association for the Protection from Electrolytic Corrosion (APCE), 30 Via G. Avezzana, Milano, Italy 20139 . >fit American Petroleum Institute (API), 1220 L St. NW, Washington, DC 20005

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Figure At Location of external through-wall corrosion pit

The company performed an in-line inspection (ILI) using a magnetic flux leakage tool to detect and characterize corrosion-caused metal loss on this section. Based on the results of the inspection, several locations were identified for excavation and direct examination. A service company was retained by the pipeline operator to collect information during the excavations, to evaluate the effectiveness of the CP 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 pipeline right-of-way

• Pipe-to-soil potential measurements

• Soil resistivity measurements

• Linear polarization resistance

• Microbiologically influenced corrosion (MIC) investigation

• Supporting analysis

1. Qualitative testing for chemical species

2. Electrolyte pH

3. Pipe conditions

4. Coating conditions

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Anomaly Investigation Results

Several areas were excavated and the anomalies in the pipe evaluated using the above detailed examination. 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 in [152 mm]). The second layer (going down in depth) consisted of a 10 ft (3 m) layer of black moist clay material. The third layer, which encased the pipeline 2 ft (0.6 m) 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 corrosion rate (using linear polarization resistance). The soils can be classified as clay with high moisture content, rich in bacteria, and falling into a highly corrosive category.

Initial observations of the area surrounding the anomaly revealed a black granular deposit approximately 2 in (51 mm) 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 microbiologically influenced corrosion. On-site qualitative testing for chemical species within the corrosion product produced the following results:

• pH >10

• Carbonate (CO3-) Positive

• Sulfide (S2-) Negative

• Ferrous Iron (Fe2+) Positive

• Ferric Iron (Fe3+) Positive

• Calcium (Ca2+) Negative

The presence of an elevated pH and a positive reaction to carbonate indicate the presence of CP. The positive tests for ferrous and ferric ions, however, and the corrosion anomaly itself indicate that either the CP film formed after the corrosion had occurred or another corrosion mechanism was contributing to the problem. No sulfides (often observed in corrosion products resulting from MIC) were found.

Inspection of the defects revealed an isolated smooth, round corrosion morphology that was uncharacteristic of either MIC or conventional direct stray-current corrosion. A corrosion rate of 60 mpy (1.5 mm/y) in the presence of CP cannot 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 corrosion products are soluble as a result of 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 nontraditional corrosion mechanism, such as AC corrosion.

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 CP rectifiers have been maintained in continuous operation and that, when 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, CIS data, and the physical location of the power lines, especially in the areas in which 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 1 mile (1.6 km) intervals, to measure the DC potentials, AC potentials, and current densities. The plot of the AC potentials and defect distribution (in number of anomalies per linear foot of pipe) are shown in Figure A2. These data indicate that the highest population of ILI corrosion anomalies is located in the first 5 miles (8 km) where the AC potentials typically exceeded 4.0 V.

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0 0 0

C/1

AC

Pot

enti

al (V

CS

E)

14.00

10.00

12.00

8.00

4.00

2.00

6.00

0.00

0.003

0.021

0 015

0.009

0.006

0.018

o_

—•--AC Potential

—E—Anomalies Per Foot

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290.00 292.00 294.00 296.00 298.00 300.00 302.00 304.00 306.00 308.00 310.00

M Ile Post

Figure A2: AC potentials and "defect density" (anomalies per linear foot of pipe). (1 ft = 0.3 m)

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CTSs provide an alternative to conventional off-potential measurement for evaluating the effectiveness of a CP system.

Following the installation of the CTS, initial measurements and CIS data were collected at each station. The pertinent data collected at the four stations in the most affected area are listed in Table A1 and discussed in further detail.

Table A1: Summary of Pertinent CTS Data

Location AC Density, A/m2 (A/ft2) Possible Corrosive Effect

Nevada Booster 23.7 (2.20) AC corrosion unpredictable

Rustic Meadows 239.2 (22.22) AC corrosion likely

Highway 66 144.1 (13.39) AC corrosion likely

Parker Road 113.2 (10.52) AC corrosion likely

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 CP standpoint, the piping is well protected with off-potentials of —1.291 V (CSE) and —1.265 V (CSE) on the pipe and coupon, respectively. The native (unpolarized coupon) at this site had a free corrosion potential of —0.858 V (CSE). The CIS collected upstream and downstream from the CTS showed adequate DC potentials and generally flat (neither increasing nor decreasing) ACpotentials. The coupon was also collecting DC from the CP system at a current density of 3.0 A/m2 (0.28 A/ft4). The AC potential recorded at this site was 1.73 V, and the coupon was found to have an AC density of 23.69 A/m2 (2.201 A/ft2).

Rustic Meadows

This CTS is located one mile (1.6 km) south of Nevada Booster. At this location, measurements on both the pipe and coupon indicated that from a CP standpoint, the piping is well protected with off-potentials of —1.242 V (CSE) and —1.173 V (CSE) on the pipe and coupon, respectively. The native (unpolarized coupon) at this site had a free corrosion potential of —0.868 V (CSE). The CIS data collected upstream and downstream from the CTS showed adequate DC potentials and increasing AC potentials as the survey proceeded south toward the Highway 66 test station. The coupon was also collecting DC from the CP system at a current density of 8.32 A/m2 (0.773 Nft2). The AC potential recorded at this site was 9.7 V, and the coupon was found to have an AC density of 239.16 A/m2 (22.219 A/ft2).

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 CP standpoint, the piping is well protected with off-potentials of —1.230 V (CSE) and —1.056 V (CSE) on the pipe and coupon, respectively. The native (unpolarized coupon) at this site had a free corrosion potential of —0.832 V (CSE). The CIS data collected upstream and downstream from the CTS showed adequate DC potentials and a generally flat (neither increasing nor decreasing) AC potential profile of nearly 8 to 10 V (zinc grounding cells on versus grounding cells off). The coupon was also collecting a high DC density from the CP system at 4.80 A/m2 (0.446 A/ft2). The AC potential recorded at this site was 9.30 V, and the coupon AC density was found to be 144.17 Nm2 (13.394 Afit2).

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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 CP standpoint, the location was well protected with off-potentials of -1.224 V (CSE) and -1.220 V (CSE) on the pipe and coupon, respectively. The native (unpolarized coupon) at this site had a free corrosion potential of -0.806 V (CSE). The CIS data collected upstream and downstream from the CTS showed adequate DC potentials and generally a flat AC voltage profile (neither increasing nor decreasing). The coupon was also collecting a high DC density from the CP system at 3.42 A/m2 (0.318 A/ft2). The AC potential recorded at this site was 5.50 V, and the coupon AC density was found to be 113.24 A/mI (10.52 Afft2).

Table A2 summarizes potential and current CTS data.

Table A2: Current and Potential Data from CTSs

Location

Coupon Potential Pipe Potential Coupon

current, mA

C oupon current density,

Airti2 (Am)

DC Off- Potential

(V vs. CSE)

AC Potential

(V vs. CSE)

DC Off- Potential

(V vs. CSE)

AC Potential

(V vs. CSE) DC AC DC AC

Parker Road

-1.220 5.50 -1.224 5.60 3.02 100 0 ' 3'42

(0.318) 113.23 (10.52)

Highway 66 -1.056 9.30 -1.230 9.30 4.24 127.2 4'80

(0.446) 144.17

(13.394) Rustic

Meadows -1.173 9.70 -1.242 9.70 7.34 211.0 8'32

(0.773) 239.16

(22.219) Nevada Booster

-1.265 1.73 -1.291 1.73 2.65 20.9 3'00 (0.28)

23.69 (2.201)

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 MIC or conventional DC stray-current corrosion. 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 shiny. The depth of the five anomalies ranged from 53 to 120 mil (1.3 to 3.0 mm/y), and all were located in FBE-coated pipe. The coating in the area surrounding the pits was brittle and had poor adhesion.

Mitigation Methods

The installation of zinc grounding cells at selected locations on the pipeline was chosen as the appropriate method to mitigate the alternating currents on the pipe. The line had two existing zinc grounding cells, Nevada Booster and the railroad near the substation. Table A3 summarizes the AC potential and AC density relief provided, while the cells are bonded to the structure. The reduction in AC potential was observed to be greatest at Highway 66, which is within approximately 600 ft (180 m) of the railroad zinc cell installation. At the Highway 66 location, the coupon AC density was similarly reduced by over 22%, while the zinc cells were connected. Few effects are recognized for the zinc cells installed at Nevada Booster. This is because 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.

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Table A3: Summary of Effects of Zinc Groundinq Cells on AC Potentials and Current Densit

Location Pipe AC Potential, V (CSE) Coupon AC Density, A/m2 (Nft2)

Zinc On Zinc Off Zinc On Zinc Off Parker Road 5.6 6.4 113.2 (10.52) 130.4 (12.11) Highway 66 9.3 11.3 144.1 (13.39) 176.2 (16.37)

Rustic Meadows 9.7 10.8 239.2 (22.22) 269.9 (25.07) Nevada Booster 1.72 1.76 23.7 (2.20) 24.4 (2.27)

Conclusions

The following conclusions can be drawn based on review of the information:

1. The excessive AC densities observed on the CTS 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 CP system is and has been operating at levels that should be able to protect the pipeline adequately in the absence of severe AC 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 discharges (at the locations tested) to a level that would permit the CP system to overcome the detrimental effects. The installation of additional grounding cells mitigates the AC discharges to acceptable levels.

4. The recently installed CTS provide a means of measuring AC current.

Case Study 2 (Adapted From Reference 16) Background

During routine inspection of a natural gas transmission line (25 bar [2,500 kPa or 363 psi], 150 mm [5.9 in] inner diameter, 4.5 mm [0.18 in] wall thickness, 45 years in service), a leak was identified by discoloration of plants. The area was excavated (Figure A3), and the leaking section of the pipe (1.5 m [4.9 ft] long) was transferred to the laboratory for examination, together with samples from the surrounding soil. The backfill was original soil of silty clay texture. The leak was located in the 6 o'clock position and was covered by a large cap (approximately 200 mm [8 in] diameter) of hard, agglomerated soil.

Figure A3: Excavation site.

The pipeline runs in parallel to a railway (16 2/3 Hz system) for approximately 10 km (6 mi), and the leak occurred at the end of this section. The pipe is coated with bitumen, and the CP is checked every three years by extensive measurements. The protection criterion was met at all times, and the last check did not indicate

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an existing defect. The influence of AC was known for some time, but was not considered to be critical. Measurements after the failure indicated peak AC voltages of 20 to 30 Vrms in the affected region (Figure A4).

[ V ]

30.0

26_0

22.0

18.0

14.0

10.0

6 0

2 0

12:00 15 00 18 00 21 00 00 00 03 00 06:00 09 00 1200, 15 00 18.00 21 00 00 00 D3 00 0E00 3108.05

01 09 05

0209. 05

Figure A4: Record of AC voltage over 2 days.

Visual Examination

Figure A5 shows the hard cap of soil adhering to the pipe and covering the leak. Polyester resin was used to impregnate the surface of the cap to stabilize its structure.

Figure A5: The pipe with a cap of solidified soil covering the leak.

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