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A/C Interference Guideline Final Report

JUNE 2014

PREPARED BY:

R.A. GUMMOW, P.ENG, NACE CORROSION SPECIALIST NO.17

CORRENG CONSULTING SERVICE INC.

2-498 MARKLAND STREET

MARKHAM, ONTARIO,

L6C 1Z6, CANADA

Contents

1.0 Introduction 1

2.0 AC Interference Modes and their Harmful Effects 2

2.1 AC Fault Conditions 2

2.1.1 General 2

2.1.2 Risk of Arcing 3

2.1.3 Coating Stress 5

2.1.4 Personnel Safety 5

2.2 Safety During Construction - Capacitive Coupling (Electrostatic Induction) 6

2.3 Steady-State Conditions 7

2.3.1 General 7

2.3.2 Personnel Shock Hazard 10

2.3.3 AC Corrosion 10

2.4 Other Harmful Effects of Steady-State Induced AC 13

3.0 Determining the Risk of AC Interference Effects 16

3.1 Risks Under Fault Conditions 16

3.1.1 Risk of Pipe Wall Damage 16

3.1.2 Risk of Coating Voltage Stress Damage 18

3.1.3 Risk of Shock Hazard on the Pipeline

Due to a Faulted Powerline Structure 18

3.1.4 Prediction of AC Voltages Under Fault Conditions 19

3.2 Risk of Shock Hazard from Steady-State AC Induction 19

3.3 Risk of AC Corrosion 23

3.4 Summary 24

4.0 Methods of Mitigating AC Interference 24

4.1 General 24

4.2 Mitigating Harmful Effects from a Powerline Fault 25

4.3 Mitigation of Electrostatically Induced Voltages 29

4.4 Mitigation of Electromagnetically Induced Voltages 30

4.4.1 General 30

4.4.2 For a New Pipeline on a Powerline ROW or a

New Powerline on a Pipeline ROW 31

4.4.3 DC Decouplers and Surge Protectors 33

4.5 Cathodic Protection Effectiveness in Mitigating AC Corrosion 37

4.5.1 Corrosion Control Criteria 37

4.5.2 Type of Cathodic Protection System 39

5.0 Monitoring Considerations 40

6.0 Summary 41

6.1 General 41

6.2 AC Interference Procedures 42

6.2.1 Preliminary 42

7.0 References Error! Bookmark not defined.

APPENDICES

Appendix A • Recommended Pipeline & Powerline Information

Appendix B • AC Interference Flow Chart

Appendix C • Glossary of Terms

Appendix D • List of Equations

A/C Interference Guideline Page 1

Introduction 1.The location of steel pipelines in the vicinity of AC power transmission facilities has resulted in mutual

electrical interference problems that can produce damaging effects on both utilities and an electrical

hazard to pipeline personnel. The pervasive use of the utility corridor concept necessitates that the

electrical interference aspects be clearly defined and guidelines to minimize the harmful effects be

incorporated into pipeline and powerline specifications, designs, and operating procedures.

This document provides guidelines for identifying, mitigating, and monitoring AC interference on:

a pipeline located on a powerline right-of-way (ROW) and vice versa;

a pipeline ROW located parallel to a powerline ROW and vice versa;

laterals or extensions to any of the foregoing pipeline-powerline situations

pipelines crossing any pipeline subject to AC electrical interference

There are three modes of AC interference that can cause damage to pipeline systems and present an

electrical shock hazard to pipeline personnel, namely; inductive coupling resistive (conductive) coupling

and capacitive (electrostatic) coupling.

Inductive coupling occurs both under steady-state (normal operation) and fault conditions and the

magnitude of the induced AC voltage depends on the phase current, on the length of co-location, on the

distance between pipeline and powerline and on the pipeline-powerline configuration. The induced voltages

reach maximum values at discontinuities and gradually attenuate along the pipeline.

The second mode of AC interference on the pipelines, defined as “resistive (conductive) coupling”, only

appears under powerline fault conditions. The fault current flowing through the grounding of the high

voltage structure (i.e. pole or tower) produces a potential rise in the neighbouring soil defined as “ground

potential rise” (i.e. GPR). Part of this rise is transferred to the pipe and would be added to the AC induced

voltage.

The third mode of interference defined as “capacitive (electrostatic) coupling” is only a concern during

construction when the pipe is elevated on skids and not in contact with the ground.

Under steady-state conditions, the AC interference could result in safety problems for people coming in

contact with the metallic pipe or its appurtenances and in accelerated corrosion on the underground

section of the pipe (i.e. AC corrosion).

Under fault conditions, the AC interference could result in damage to the pipe itself (i.e. electrical arc

between the structure grounding and the pipe), in safety concerns for pipeline personnel and in damage

to pipeline coating, isolation flanges and CP equipment.

Powerline metallic tower footings, grounding systems, and guy wires are also susceptible to electrical

interference from impressed current cathodic protection systems when the powerline is in proximity to

the impressed current groundbed or where the powerline system is in close proximity to the impressed

current protected pipeline. The identification, mitigation, and monitoring of electrical interference between

electrical powerlines and pipelines should be considered a mutual concern that requires the cooperation of

both parties to optimize the effectiveness of any corrective measures. Mitigation measures typically

require the design of AC electrical grounding systems for safety in accordance with industry electrical

standards.[i,ii]


AC Interference Modes and their Harmful 2.Effects

AC FAULT CONDITIONS

General

Under fault conditions, AC interference on buried pipelines is due to both the resistive and inductive

coupling modes.

A phase to ground fault on a powerline, usually initiated by lightning, results in the conduction of

electrical power indirectly from one or more AC powerline phase conductors via the metallic tower to

ground, as illustrated in Figure 1, or directly to ground as a result of an overhead conductor falling to

ground.

Figure 1 – Illustration of a Powerline Fault to Ground at a Tower near a Buried Pipeline

Powerline faults typically occur during inclement weather such as high winds, ice storms, or electrical

storms wherein, for the latter case, the fault is initiated by a lightning strike in the vicinity of the

powerline phase conductors and the pipeline. The probability of a lightning strike is relatively small,

especially in Canada, where the lightning ground flash density is relatively low (less than 10/km2/yr).[iii]

However, the resulting nature of the damage to a nearby pipeline can be particularly severe under some

conditions and the electrical transmission of the fault current and voltage along the pipeline can produce

a voltage hazard to personnel.

If a pipeline is in proximity to the foundation or grounding of a faulted powerline structure, there is a risk

of an arc developing from the powerline grounding to the pipeline (resistive coupling), which could result

in damage to the pipe wall and/or the coating.

Even when the separation distance between the pipeline and the powerline structure exceeds the safe

distance and arcing is prevented, significant hazards can exist for pipeline personnel and to coating

integrity of the pipeline under fault conditions. When the fault current is discharged to the ground via the

tower foundation or via grounding electrodes (i.e. on wooden poles), the potential of the ground rises to


several thousand volts (ground potential rise or GPR), which can result in a large potential differential

between the pipeline and the ground, most of which appears across the coating. However, some AC fault

current transfers through the coating and coating holidays, resulting in a portion of this GPR voltage

being transferred to the pipe (resistive coupling). Furthermore, if the powerline and the pipeline are

parallel, significant voltages can be induced in the pipeline by the fault current (inductive coupling).

Since the fault current, which is typically more than an order of magnitude higher than steady-state load

currents, is carried by only one phase conductor, the induced voltage can reach thousands of volts for the

duration of the fault. This voltage is typically opposite in phase to the GPR and therefore, vectorially

additive in terms of voltage differential.

Due to this voltage differential, personnel can be exposed to a shock hazard at above grade pipeline

appurtenances and there is a risk of coating damage close to the faulted tower, where the GPR is high

and the pipeline potential is close to zero or in opposite phase, if there is induction. A safety hazard can

also exist at above grade pipeline appurtenances or stations remote from the faulted tower, where the

GPR is close to zero, due to high voltages induced or transferred to the pipeline under fault conditions.

The presence of shield wires on a powerline also affects the GPR of the faulted tower and the electro-

magnetically induced voltages on the pipeline. The purpose of these wires is to protect the phase

conductors from lightning strikes but they can also affect the steady-state induced voltage and the

induced fault voltage. When a fault occurs on a tower a significant portion of the fault current goes to

towers upstream and downstream of the faulted tower resulting in less fault current at the faulted tower

(typically less than 20% of the total fault current) than would otherwise be expected. This means that the

GPR produced by a fault will be less at the faulted tower than if the entire fault current passed to ground

at a single tower. If there are no shield wires then all of the fault current enters the earth at the faulted

tower which produces a larger GPR, and generally represents the worst case.

Risk of Arcing

If an arc develops between the faulted structure and the pipeline (sometimes called a flashover) or a

lightning initiated arc to the pipe is sustained through the ionized soil path by the powerline voltage, then

substantial damage can be done to the pipeline coating, pipe wall (through melting), and to pipeline

facilities such as isolation fittings, bonding cables, transformer rectifiers, and monitoring equipment.

There are a number of reported cases of pipeline rupture during powerline faults caused by melting of the

pipe wall.[iv,v,vi,vii]

Besides the possible localized damage to the pipeline coating and pipe wall during a flashover, the fault

current and its associated voltage crest will be transmitted along the pipeline away from the fault location

and can produce a hazardous voltage to anyone that happens to be touching a pipeline appurtenance, such

as a valve or pipe riser, or a pipeline metallic connection, such as a cathodic protection test lead or

bonding cable. In addition to this, there is a risk of flashover at crossings with foreign pipelines and

watermains, and at isolation flanges, as well as, the potential for damage to pipeline equipment, such as

monitoring facilities and rectifiers.

Even though the probability of an individual being electrocuted during a fault is small, a powerline fault to

ground that results in an arc to the pipeline can transmit enough power to melt the wall of the pipe, if

sufficient fault current enters the pipe over the fault duration. Webster et al[viii] found that, for a 6 cycle

duration fault, perforation of steel pipe having wall thicknesses between 5.6 mm and 9.54 mm resulted

from fault currents ranging from 15.1 - 44 kA. In another study, Drakos[ix] conducted field fault tests on

35 mm diameter coated steel pipe placed near a 230 kV line. The maximum test fault current was 7.8 kA

in 100 Ohm-m clay. It was found that there was a linear relationship between the fault current magnitude

and both the depth and diameter of the melted area as shown in Figure 2.


Figure 2 – Diameter and Depth of Melted Area vs. AC Current

A melted spot on a pipe wall can be a problem even in the absence of a perforation, since there will be a

heat affected zone and rapid cooling after the fault can create a hardened surface that is susceptible to

cracking and hydrogen embrittlement.

In simulated fault tests carried out by Webster et al[x] arc damage on coated pipes was determined to be

a function of the coating type and thickness. Coal tar enamel coated pipe suffered the most pipe wall

damage and the least coating damage. Often the wall melt area was the same size as the coating damage

area. However, the coating damage areas on the polyethylene and fusion bonded coated pipe were

T h i c k n e s s o f P i p e W a l l

0 . 0 1 0 . 1 1 0

0 . 5

0 . 1

1 . 0

5

1 0

2 0

C u r r e n t E n t e r i n g P i p e , k A ( P e a k )

1 . 0

D a t a o b t a i n e d f r o m t e s t p i p e o n w h i c h o n l y o n e e l e c t r i c a l l y d a m a g e d r e g i o n o c c u r r e d . p i s a m e a s u r e d v a l u e . I

D a t a o b t a i n e d f r o m t e s t p i p e o n w h i c h s e v e r a l e l e c t r i c a l l y d a m a g e d r e g i o n s o c c u r r e d . p i s a n e s t i m a t e d v a l u e o n l y . I

M e l t e d Z o n e , m m

D i a m e t e r D e p t h


several times larger than the wall melt areas. On the other hand, arc damage caused by small fault

currents (< 1 kA) over a fault duration of 12 cycles was independent of the coating type.

Electrical components connected to the pipeline such as transformer rectifiers, operating electronics, and

monitoring equipment can be damaged as a result of a flashover at a tower, since the fault voltage crest

can extend for considerable distance along the pipeline from the fault location. Silicon diodes are

particularly susceptible to failure when subjected to a sudden voltage crest. The fault current can also burn

out pipeline bonds, resistance bonds, and insulating flanges.

Just as pipeline crossings with foreign metallic structures are critical locations for DC interference, the

same applies with respect to AC interference. The close proximity of two metallic structures creates a low

resistance current path between them, and under fault conditions could result in flashover or transfer of

the AC fault current at a crossing and cause damage to the pipeline(s) or coatings.

Coating Stress

A fault condition that does not melt the pipe wall can still cause coating damage depending on the fault

voltage appearing across the coating and the dielectric strength of the coating material. Typical dielectric

strengths of various insulating materials are shown in Table 1.

Table 1 – Dielectric Strength as a Function of Coating Material[xi]

Coating Type Dielectric Strength

Polyethylene 18.9 kV/mm

Epoxy Resin 19.7 kV/mm

Polyurethanes ~25.0 kV/mm

Enamels 47.4 kV/mm

The ability of the coating to withstand a voltage stress is also a function of the duration of the fault.

Dabkowski[xii] conducted high voltage tests on a variety of holiday free pipeline coatings by applying

voltage pulses in 500 V increments until a coating puncture occurred. The diameter of the coating

penetrations was found to be about 1 mm. The pulse period varied from about 50 ms to 1 second. A

typical fault clearing time is about 100 ms. The results of these tests are given in Table 2.

Table 2 – Coating Puncture Voltage Levels[xiii]

Coating Type Voltage Level

Fusion Bonded Epoxy 1000 v/mil

Coal Tar Epoxy 3500 v

Coal Tar 4500 v

Coal Tar Enamel 5000 v

Personnel Safety

The probability of personnel being fatally exposed to a fault current is small because the fault duration is

small, normally less than 10 cycles and the likelihood of someone being

in contact with the pipe during inclement weather is also small. For example, there are usually no barriers

around powerline towers to prevent a person from touching the tower, because the probability of

someone being exposed to a fatal voltage during a fault is very small (~10-6).[xiv]


However, because a flashover fault current or transferred fault current can be transmitted along a pipeline

for some distance from the faulted tower location, the safety of pipeline personnel should remain an

important consideration. For short duration faults, the touch voltage tolerance of an individual is directly

dependent on the weight of the person and the soil resistivity and inversely to the square root of the

exposure time as shown in the following equation[xv] for a 50 kg person.

Vtouch-tolerance = (1000 + 1.5ρ) 0.116/√t [Eqn 1]

where:

ρ = soil resistivity (Ω-m) t = time (s)

During a short duration fault, the metal-to-metal touch voltage tolerance is also given for a 50 kg person

in IEEE Std 80-2000 as follows.

V metal-metal = 116/√t [Eqn 1a]

Fault voltage values, transferred to the pipeline, need to be calculated using computer modelling

software. When calculating the maximum touch voltage, the decrement factor described in IEEE Std 80-

2000 Section 15.10, is not usually considered because the asymmetrical current is generally taken into

account when the power utility calculates the fault current as an RMS value.

A metal-to-metal touch voltage hazard can also exist across an isolating fitting during faults and in some

cases during steady-state conditions, but is eliminated if a DC decoupler is connected across the fitting. If

not, the AC voltage to ground on each side of the insulator might not be at a hazardous voltage, but

because these voltages are typically 180º out of phase, for an inline isolator, they are additive and

therefore can present a metal-to-metal touch voltage hazard.

For an isolating fitting to a lateral or one that is not on a co-located section of the pipeline, the steady-

state voltage across the isolator will not be 180º out of phase, so the AC voltage will not be greater than

the pipeline voltage to ground at that point, although a metal-to-metal touch voltage hazard would still

exist during a fault.

SAFETY DURING CONSTRUCTION - CAPACITIVE COUPLING (ELECTROSTATIC INDUCTION)

For electrostatic coupling, AC electrical energy is transferred through the electrical capacitance that exists

between the overhead phase conductors and a pipeline, which is insulated from the ground, and the

capacitance between the pipeline and earth. This situation is illustrated in Figure 3.


Figure 3 – Electrostatic (Capacitive) Coupling between Powerline Overhead Conductor and

Pipeline Sections Sitting on Insulating Skids

The overhead AC phase conductors and the pipeline supported on wooden skids form a capacitor with an

air dielectric. Similarly, the pipeline and the ground, acting as a conductive medium also form a capacitor.

The voltage difference between the overhead phase conductor and ground divides across these capacitors

in inverse proportion to the faradic value of the two capacitors. The pipeline voltage to ground is a direct

function of the overhead phase conductor voltage to earth, inversely proportional to the distance between

the pipe and overhead conductor, and independent of the length of the pipeline. Voltages as high as 1000

V have been measured on skidded up pipe located on a 120 kV powerline right-of-way. Although this

would be considered a hazardous voltage because it exceeds the 15 V touch potential limit stipulated in

the NACE SP0177-2007 standard,[xvi] the AC current is in the microampere range and therefore does not

constitute a shock hazard because it is below a current of 5 mA. However, it is considered a safety

hazard to refuel vehicles, that are located on an AC powerline right-of-way, because of the possibility of

fuel ignition. This hazard can be avoided by bonding the vehicles prior to refueling.

The electrostatic induced voltage on a pipeline is negligible on a buried pipeline, because the charge leaks

to earth through the coating, which reduces the voltage.

STEADY-STATE CONDITIONS

General

Under steady-state (normal) powerline operation, the only significant mode of AC interference on buried

pipelines is due to electromagnetic coupling.

Electrical energy can be transferred from an overhead powerline due to electromagnetic coupling wherein

an alternating current in a phase conductor causes a current to be induced in the pipeline because of the

changing magnetic flux produced by the overhead conductor phase current as illustrated in Figure 4.

Conducting Plates

Air Dielectric


Figure 4 - Electromagnetically Induced Current in a Pipeline

Every phase conductor of every circuit on one or more powerlines, which parallel the pipeline, produces a

magnetic field, the strength of which is directly dependent on the magnitude of the individual phase

current and inversely proportional to the distance between phase conductor and the pipeline. Phase

conductor currents can range from several hundred amperes to 2000 A. The resulting current in the pipe

appears as a result of only the net magnetic field produced by all the phase conductors. AC powerline circuits

consist of three phases separated by 120º, such that if a conductor is located equidistant from each phase

and if each phase was transmitting the same current there would be no net magnetic field and therefore,

no net current induced in this conductor. Of course, it is impractical to locate a pipeline equidistant from

each phase and in addition to this the phase currents in each circuit are not exactly the same (i.e. phase

imbalance). Therefore, there is inevitably a steady-state induced current in a pipeline that parallels a

powerline and that is within the influence of the magnetic field produced by the individual phase currents.

The induced alternating current in the pipeline produces a longitudinally induced voltage (Vind) along the

length of the pipeline, such that the voltage at each end of the pipe is 180º out of phase, as shown in

Figure 5.

I2

I1


Figure 5 - Illustration of Electric Charge Separation Toward the Ends of a Pipe Section

due to Electromagnetic Induction

At any instant in time the voltage between the pipeline and earth (Vg) at the end of the illustrated

pipeline will be one half the induced voltage (i.e. Vg = Vind/2) and the voltage to ground along the

pipeline between the ends will be less than Vg. The magnitude of the induced voltage is directly

proportional to the phase current, the length of parallelism, the resistance of the pipe coating, the

resistivity of the earth, the relative difference in operating magnitude of the phase currents (phase current

imbalance), and inversely proportional to the distance between the pipe and the phase conductor.

For a coated pipeline, the pipeline electrical circuit and the AC pipeline voltage profile (Vg vs. distance) is

illustrated in Figure 6 for a simple case of a single pipeline paralleling a single AC powerline. The

powerline net magnetic field induces an electric field in the pipeline which produces the AC current.

Vind

Vind

+++

++

+

+

+ ++

++

+

+

+

+ –

– –––

–

––––

––––

––


Figure 6 – Illustrating the Pipeline Electrical Circuit with Induced Voltage Generators and the

Resulting Linear Induced Voltage Profile on a Well Coated Pipeline

In the illustration there are five pipeline segments, each containing an electric field generator that is

connected in series and that results in a linearly increasing magnitude of AC voltage towards the ends,

where a voltage peak develops at the point of powerline-pipeline separation. Similar voltage peaks occur

at any location where there is an electromagnetic discontinuity between the powerline and pipeline such

as, when the pipeline crosses back and forth across the right-of-way, at powerline feeds into a sub-

station, at insulating fittings in the pipeline, and at phase transpositions on the powerline.

For a well coated pipeline closely paralleling a high voltage powerline, that is operating at high current

capacity, the induced voltage peaks can be up to hundreds of volts. As this is a steady-state voltage, it

presents three significant areas of concern, namely a shock hazard to pipeline personnel, an AC corrosion

threat to pipeline integrity, and depolarization of the pipe-to-soil potentials or cathodic protection levels.

Personnel Shock Hazard

The shock hazard arising from induced AC has been widely recognized for many years in North America,

where the NACE SP0177 Standard[xvii] stipulates that an AC voltage of 15 V or greater between a pipeline

appurtenance and ground, which could expose a person to a touch voltage, is considered a shock hazard.

This requires that the touch voltage be reduced to a safe level or the pipeline be treated as a live electrical

conductor. The 15 V limit was determined by multiplying 15 mA (considered the current limit below which a

person could let go when grasping an electrified conductor) and 1000 Ohm (conservatively considered the

human body resistance assuming a contact resistances of zero ohms).

In Europe[xviii] the touch voltage limit is typically 50 V before remedial action is required.

AC Corrosion

Although AC was known to cause corrosion of carbon steel since a 1916 report by the US National Bureau

of Standards[xix] it was not considered to be serious[xx] as long as the pipeline was cathodically polarized

to industry standards (e.g. equal to or more electronegative than -850mVCSE). However, observations of

AC corrosion on cathodically protected pipelines were reported in the early 1990s in Europe, which

prompted research investigations confirming that at certain AC current densities, AC corrosion could be

expected to occur on cathodically protected pipelines.[xxi,xxii,xxiii]


Despite numerous research studies, the AC corrosion mechanism is still not well understood, and empirical

results must be used to assess the AC corrosion risk for cathodically protected pipelines. From these early

studies, guidelines relating the probability of AC corrosion to AC current density and also the ratio of AC

current density to CP current density were derived as shown in Tables 3 and 4.

Table 3 - AC Corrosion Probability on a Cathodically Protected Steel Pipeline based on AC Current Density (iac)

[xxiv]

AC Current Density AC Corrosion Probability

iac ≤ 20A/m2 Low

20A/m2 < iac < 100A/m

2 Unpredictable

iac > 100A/m2 Expected

The European standard on evaluating AC corrosion probability stipulates an AC current density ≤ 30A/m2

as the low probability corrosion threshold.[xxv] In the unpredictable range, one source states “only current

densities above 50A/m2 are serious”.[xxvi]

Cathodic protection can mitigate AC corrosion depending on the DC current density (idc). A recent

laboratory study[xxvii] suggests that as iac increases, even greater than 100A/m2, corrosion control can still

be maintained by increasing idc as long as overprotection is avoided (i.e. Ep,off < -1200mVCSE).

The European Standard EN 12954 classifies the AC corrosion likelihood on the iac/idc ratio as shown in

Table 4.

Table 4 – AC Corrosion Probability on Cathodically Protected Steel Pipelines based on iac/idc Ratio

[xxviii]

Iac/idc Ratio AC Corrosion Probability

iac / idc < 5 Low Likelihood

5 iac / idc ≤ 10 Moderate Likelihood

iac / idc > 10 High Likelihood

There is a limit to the DC current density compared to the AC, since the AC mitigated voltage is typically

several times greater than the applied cathodic protection potential.

A NACE standard is being prepared on AC corrosion that will provide more detailed information on these

current density relationships and other aspects of AC corrosion susceptibility.

Recent research[xxix] has indicated that applying a highly negative potential can actually accelerate the AC

corrosion under some conditions. This is attributed to reduction of the spread resistance at a holiday due

to concentration of hydroxyl ions generated in the reduction reaction for high cathodic protection current

densities.

Ormellese et al[xxx] conducted AC corrosion testing on cathodically protected steel coupons in simulated soil

conditions by varying the amount of both the AC and DC current densities. The AC corrosion rates as a

function of both the AC and DC current densities are illustrated in Figure 7. They concluded that the -

850mVCSE criterion “does not ensure protection in the presence of AC interference” similar to previous

studies but also found that the “CP level may be considered effective if the protection potential is in the

range -1.0 to -1.2VCSE, provided iac / idc ratio is lower than 20 and no overprotection conditions were

established”.


Figure 7 – Residual Corrosion Rate of Carbon Steel Specimens

as a Function of AC and CP Current Density

The results also illustrate that the AC corrosion rate increased when the cathodic protection current

density was 10 A/m2. It should be noted that the foregoing two studies were not carried out in soil where

a calcareous deposit would be likely to form on the steel at the higher cathodic protection current

densities. Calcareous deposits would increase the spread resistance and lower the AC current density.

Therefore, it is questionable whether similar results would be observed in the field, since most soils contain

carbonate and bicarbonate ions that promote the formation of calcareous deposits at the pipe-earth

interface when the pH is raised by the application of cathodic protection.

Besides AC current density, there are other factors that affect the AC corrosion rate as summarized in

Table 5.[xxxi]

Table 5 - Table of Factors Other than AC Current Density Affecting the AC Corrosion Rate of Steel

Factor Effect on AC Corrosion Rate

Time Decreases with increasing time

AC Frequency Decreases with increasing frequency

Environment Increases in deaerated environments

Coating Defect Size Increases with decreasing surface area but peaks at 1cm2


OTHER HARMFUL EFFECTS OF STEADY-STATE INDUCED AC

The presence of a steady-state induced voltage on the pipeline can have harmful effects other than AC

corrosion, such as problems with the accurate measurement of pipeline polarized potentials.

Superimposed AC can cause depolarization of a pipeline, as shown in Figure 8, for steel coupon probes

attached to a polyethylene coated gas transmission pipeline.[xxxii]

Figure 8 – Off-Potential of the Probe at Test Stations

with and without Induced AC Voltage

The instant-off potentials of the steel probes for this test station survey were all shifted in the

electropositive direction when the AC was on. The largest potential differential occurred in the T40 - T45, and

T20 areas, where the AC current density was greater than 50 A/m2. The dc current density provided by

magnesium anodes also increased when the AC was on.

The increase in cathodic protection from the magnesium anodes is counter to the findings of several

researchers who have reported that the potential of the magnesium shifts electropositively as the AC

current density increases. Bruckner[xxxiii] demonstrated the magnesium anode positive shift with increasing

anode AC current density, as shown in Figure 9.


AC Current Density

0 100 300200 400 500 mA/in2

0 155 465310 620 775 A/m2

9 days

1 day

5 days

200

-200

-400

-600

-800

-1000

-1200

-1400

0

Figure 9 - Single Electrode Potential of Mg vs. AC Density in a Fe-Mg Cell

Furthermore, he found that magnesium reversed its potential and became a cathode to a steel electrode

at AC anode current densities greater than 150 A/m2. Hamlin,[xxxiv] also found that the magnesium anode

potential shifted electropositively at an AC anode current density of 100 A/m2 after 1 hour. Miura et

al[xxxv] found that the magnesium anode potential shifted to electropositive potentials vs SCE immediately

upon the application of 100 A/m2 AC current density, although the magnesium anode potential drifted

back in the electronegative direction over a 240 hour period as shown in Figure 10.


Figure 10 - Potential of Magnesium Anode vs. Time for Different AC Current

Densities and DC Current Density (redrawn from Miura, C. et al, pp. 436-437)

These AC current densities are typically an order of magnitude higher than is likely to be experienced in

actual practice. If the anode potential in the long term is unaffected by the AC current density, which

tends to depolarize the pipeline, then the anode dc current output will increase thus increasing anode

consumption and decreasing anode life.

Cathodic protection potential measurements can be in error if the voltmeter does not have a satisfactory

AC filter on the input. This is especially important when conducting close interval potential surveys, since

the trailing wire from the voltmeter to the test station will be subject to induced AC from the overhead

powerlines. The induced voltage at the voltmeter can be in-phase with the pipe induced voltage at the

test station or out of phase depending on the survey direction.

Some current interrupters have a diode connected across their output terminals which can introduce a

pipe-to-soil potential measurement error. When the cathodic protection system is interrupted, an error

appears due to the half wave rectification of the pipe AC potential by the interrupter diode. In addition,

induced AC will also be rectified at transformer-rectifier (TR) locations. If the TR is interrupted in the AC

circuit, then it will still rectify induced AC on the pipeline, such that, a true instant-off potential will not be

measured.

Time (hr.)

0 60 180120 240

-1.6

-0.8

-0.4

0.0

+0.4

-1.2 100 A/m , dc = 02 I

0.0, 0.1, 1, 10 A/m , dc = 02 I

100 A/m , dc = 10 A/m2 2I


Determining the Risk of AC Interference 3.Effects

RISKS UNDER FAULT CONDITIONS

Risk of Pipe Wall Damage

A powerline phase to ground fault at a tower that results in an arc (flashover) to a nearby pipeline can

melt the pipeline wall if it is close enough to the tower footings or powerline grounding system. This has

been considered the most serious of the AC effects on pipelines in an international survey.[xxxvi] Resistance

coupling is not only a risk when the pipeline parallels a powerline but also when a pipeline crosses a

powerline close to a tower. The risk can be assessed on the basis of the limiting ionization distance to

avoid a sustained arc which is considered the safe separation distance. This distance is a function of the

fault current magnitude and the soil resistivity. The fault current magnitude, which can be in tens of kA,

is usually calculated by the powerline utility and the value used to calculate a safe separation distance.

Sunde[xxxvii] has produced equations to calculate the safe separation distance (r) based on the lightning

fault current and soil resistivity as follows.

For ρ < 100 Ω-m r = 0.08√ If x ρ [Eqn 2]

For ρ > 1000 Ω-m r = 0.047 √ If x ρ [Eqn 3]

where:

r = distance over which arcing can occur (m)

ρ = soil resistivity (Ω-m)

If = lightning fault current (kA)

The Sunde equations are related to arcing due to lightning, hence the current in the formula is the

lightning current. For the vast majority of lightning strikes (95%), the lightning current is less than 100

kA. Considering this as a worse case, the calculated safe separation distance for 100 Ω-m and 1000 Ω-m

soil is 8 m and 14.8 m respectively. Where the soil resistivity is between 100 and 1000 Ω-m, then

Equation 2 will produce the largest ‘r’ value which should be considered the safe separation distance.

The Canadian Electricity Association (CEA) report 239T817 – Powerline Ground Fault Effects on Pipelines

describes the tests that were conducted to determine the voltages required to sustain a lightning initiated

arc to a pipeline through various soil types over a range of distances. The test results were used to

develop a regression formula giving the critical voltage to sustain an arc as a function of the separation

distance in native soil:

Vcrit = 5.801 + 0.0703 D [Eqn 4]

where:

D = separation distance (cm)

Vcrit = tower voltage rise (kV)


The CEA performed similar testing to determine the flashover distance assuming that there is no lightning

initiated arc. The test results were used to develop a regression formula giving the critical flashover

voltage to initiate and sustain an arc in native soil as a function of the separation distance in cm:

Vcrit = 18.01 + 0.1082 D [Eqn 5]

where:

D = separation distance (cm)

Vcrit = tower voltage rise (kV)

If the fault current is known, the voltage rise of the tower can be calculated. The voltage rise of the tower

can then be entered into the above regression formulas to determine the safe separation distance. The

Sunde formula can be used to determine whether there is a risk of initiation of a lightning arc, in which case

Equation 4 is applicable. If there is negligible risk of a lightning arc developing, then the arc flashover

calculation in Equation 5 can be used to calculate the safe distance.

Alternatively, when the fault current is not known, the safe separation distance to avoid a flashover can

be estimated, as a worst case, using the powerline voltage rating and the soil resistivity, as shown in

Figure 11.

Figure 11 – Flashover Distances (Linearly Extrapolated Data) vs.

Soil Resistivity for Different Transmission Line Voltages[xxxviii]

0 6500 3000015000 45000

0

20

30

40

10

500 kV

230 kV

138 kV

Soil Resistivity (ohm-cm)


This data shows that, as the soil resistivity increases the safe separation distance decreases exponentially

and, as the power line voltage rating increases, the safe separation distance also increases. Both the

voltage rating and the soil resistivity are parameters that determine the magnitude of the fault current.

Both methods require knowledge of the soil resistivity at each tower-pipeline location and soil layering

conditions, because the fault current magnitude is inversely proportional to the soil resistivity.

When the voltage rise of the tower and the soil resistivity at each tower-pipeline location is not known,

then the maximum sustained arc lengths, listed in Table 6, should be used. These are considered worst

case values, because they are based on native soil having a resistivity of 65 Ω-m and the maximum

possible phase-to-ground voltage as in Equation 4.

Table 6 – Predicted Safe Separation Distances from HVAC Towers

System Voltage

(kV)

Predicted Maximum Sustained Arc Length

(m)

35 2.5

69 5.0

120 9.1

230 18

500 41

Risk of Coating Voltage Stress Damage

Even if a safe separation distance to avoid arcing is achieved, there remains a concern of possible

damage to the coating during a fault. When there is a powerline fault at a tower, there is a ground

potential rise (GPR), which raises the potential of the earth at the pipeline with respect to remote earth. If

the pipeline parallels the powerline, there can also be induced voltage on the pipeline which would be

vectorially additive to the GPR. Any voltage transferred to the pipeline would reduce the voltage across

the coating. The voltage difference between the pipe metal and the local earth is the “coating stress”.

Under high voltage stress, there can be a dielectric breakdown of the coating, depending on the

magnitude and duration of the applied voltage, and coating type and thickness. The ground potential rise

at a distance from the tower can be calculated, if the tower grounding configuration, fault current, and

soil resistivity is known.

The NACE SP0177-2007 standard contains threshold voltage limits in the range of 2 kV for tape wraps

and coal tar enamels and 3 to 5 kV for fusion bonded epoxy (FBE) and polyethylene coatings for a short

duration fault. There is no reference for these threshold values and they appear overly conservative when

compared to the dielectric strength values listed in Table 1. Unfortunately, use of an overly conservative

coating stress voltage can result in over spending on mitigation measures especially when a powerline fault

is relatively rare. Alternatively, Table 2 lists more pragmatic coating stress voltage thresholds for

evaluating the possibility of coating damage.

Risk of Shock Hazard on the Pipeline Due to a Faulted Powerline Structure

A shock hazard to pipeline personnel and the public can arise under both powerline fault and steady-state

operation. A powerline fault is a relatively rare, short duration event, which tends to lower the risk,

especially if personnel are directed to not engage in any pipe contact work during inclement weather.

Nevertheless, the fault voltage transmitted to the pipeline can be in the range of thousands of volts and


can be transferred along the pipeline for tens of kilometers, which increases the exposure risk. As shown

in Equation 1, the voltage tolerance is a function of body weight and inversely related to the square root

of the fault duration in seconds. The probability of a shock hazard risk arising from a pipeline passing a

single tower is extremely small, especially in geographical regions where the lightning rate is low. The fact

that metallic powerline towers are seldom fenced to keep the public away from contacting them,

demonstrates that a shock hazard risk is considered to be small. Furthermore, most powerline faults are

initiated by lightning and the risk of a person being fatally struck by lightning has been estimated to be

10-7 per year.[xxxix] It follows that the shock hazard risk from a single tower-pipeline encounter is also

small.

For a pipeline that parallels a powerline for long distances and passes many towers, the shock hazard risk

increases, especially where the co-located pipeline and powerline are in a high incidence of lightning

region. At the moment there is no probability value that is generally recognized to determine whether or

not remedial action is required.

Prediction of AC Voltages Under Fault Conditions

The AC interference on a pipeline due to fault conditions cannot be measured in the field. A graphical

approach or manual calculations can be used in some simple cases to estimate the pipeline coating stress

and touch potentials due to a powerline phase to ground fault. However, in most cases modeling software

is required as there are multiple modes of AC interference acting on a pipeline due to a fault: GPR of the

ground in proximity to the faulted tower, induced AC voltages and transferred AC voltages.

RISK OF SHOCK HAZARD FROM STEADY-STATE AC INDUCTION

Whereas the probability of a shock hazard is small for fault events because of their rarity, this does not

apply to steady-state induced voltages, which are continually present on a paralleling pipeline. In terms

of a safe steady-state voltage, the magnitude of a possible touch voltage must be 15 V or less. For an

existing pipeline, the AC voltage can be determined at a test station location using a similar procedure as

for pipe-to-soil potential measurements, except with the voltmeter set on the AC voltage scale.

It should be noted however, that the powerline current loading can vary daily, weekly, and seasonally.

Phase conductor currents vary seasonally and typically peak in the summer due to air conditioning loads

and in the winter due to increased heating and lighting loads. If the AC voltage measurements are made

in conjunction with an annual cathodic protection survey, the seasonal variation should be taken into

account when assessing the touch voltage hazard. This can be accomplished by time-stamping the AC

measurements, obtaining the actual powerline loading during the survey period from the utility and

correcting the measured values for annual maximum and average powerline loading. When measured AC

voltages are between 10 to 15 V, the AC voltage should be recorded for at least 24 hours to evaluate

whether or not there is a significant daily change in powerline loading.

For new pipelines, that are to be constructed along a powerline right-of-way, an estimate of the expected

induced voltage level can be determined by field testing, as illustrated in Figure 12. This measurement

involves connecting an insulated cable to a ground rod and laying the cable on the ground along the

intended route of the pipeline for several hundred meters and then measuring the AC voltage to a ground

pin. The measured voltage is an indication of the magnitude of the longitudinal electric field (LEF) to which

the pipeline would be exposed. Multiplying this measured value by the length of parallel co-location will

provide an approximation of the total induced AC voltage on the pipeline. The peak voltage-to-ground

(Vg) would then be one-half of this total. Again, in using this approach, it is important to account for the


powerline loading at the time of the test, due to the often large daily and seasonal fluctuations in

powerline loading.

Figure 12 - Field Testing Arrangement to Determine the Longitudinal Electric Field (LEF)

Gradient Produced by an Existing Powerline

This method cannot be utilized when a new powerline is to be constructed on an existing pipeline right-of-

way and other techniques need to be employed. The longitudinal electric field (LEF) can also be estimated

by graphical means for single pipeline and single powerline arrangements, as shown in Figure 13 for a

horizontal arrangement of phase conductors and Figure 14 for a vertical arrangement of phase

conductors.[xl]

L

LEF V

L


Figure 13 - Longitudinal Electric Field for Single Pipeline and Single Powerline Arrangement for

a Horizontal Arrangement of Phase Conductors

These curves relate the longitudinally induced electric field (LEF), expressed as volts per kilometer of

parallelism per ampere of phase current, to the normalized distance ratio (d/s) between the powerline

and the center of the pipeline. For the horizontal case the normalized distance is measured from the

center of the tower, whereas for the vertical powerline phase arrangement the normalized distance is

measured from the vertical conductors, not the center of the tower. The family of curves illustrates the

effect of the ratio of phase spacing (s) and the conductor height (h) on the induced longitudinal electric

field. It is assumed that the phase currents are balanced (i.e. Ia = Ib = Ic) and that the soil resistivity is

10 Ω-m. Higher soil resistivities would result in larger LEF and lower soil resistivities would result in a

smaller LEF.

Values for the tower geometry and operating phase currents need to be obtained from the power utility.

The resulting normalized electric field is multiplied by the length of parallelism to calculate the total

longitudinally induced voltage, half of which is the peak pipeline AC voltage-to-ground (Vg) that would

appear at the end of the paralleling section. These parameters are included in the list of powerline

information, as shown in Appendix A, that is needed to assess the induced voltage magnitude. When the

estimated magnitude of the pipe-to-ground AC voltage, as calculated for the average peak phase current

loading, is in the 10-15 V range, then a more comprehensive investigation is needed using commercially

available computer programs to calculate the induced voltage profile.


Figure 14 - Longitudinal Electric Field for Single Pipeline and Single Powerline Arrangement for

a Vertical Arrangement of Phase Conductors

When there are two vertical circuits and the phases are arranged in a center line symmetrical order (i.e. a-

a, b-b, & c-c) on the tower, then the voltage calculated for a single circuit can, for approximation

purposes, be doubled which will produce a conservative estimate. This assumes that phase currents are

the same in each circuit, that the phase currents are balanced, and that both circuits exist in the

paralleling section.

For the simple horizontal and vertical powerline arrangement, the use of Figures 13 & 14 assumes that

the pipeline and powerline parallel one another at a fixed separation distance and separate from each

other at the end of the parallel run. This will produce a voltage peak (Vg) at each end of the pipeline that

is equal to one half the induced voltage (Vind), if the pipeline is well coated and the paralleling length is

not too long (i.e. where the propagation constant is small and therefore voltage attenuation is negligible).


Voltage peaks can also occur at other locations besides the ends, if there is an electromagnetic

discontinuity between the pipeline and powerline, such as where:

the paralleling pipeline crosses back and forth across the powerline or vice versa, there is an isolating fitting in the pipeline the powerline feeds an electrical substation

there is a phase transposition (phase positions are rearranged on the powerline)

For monitoring of the AC voltage on a pipeline, it is important to measure pipe-to-ground voltages at any

of the foregoing locations using existing cathodic protection test leads and other appurtenances or after

installing test facilities at these critical locations.

RISK OF AC CORROSION

The risk of AC corrosion is dependent on the AC current density, the cathodic protection current density,

and the soil conditions at a holiday, but the actual corrosion mechanism is not well understood.

Therefore, the AC current density and its ratio to the DC current density, as described in Table 3 and 4

respectively, can be used to evaluate the possibility of AC corrosion. A direct measurement of the AC

current density is not straight forward on a pipeline, unless coupons are installed at locations along a new

or existing pipeline.

A number of German researchers found that the highest corrosion penetration rate was on surface areas

of 1 to 2 cm2.[xli,xlii] Where coupons are not installed, so that the AC current can be measured directly,

then the AC current density can be estimated indirectly by calculation, if the pipeline AC voltage-to-

ground (Vg) and the soil resistivity are measured and this data is used in the following equation.

iac = 8 Vg / ρ π d [Eqn 6]

where:

iac = AC current density (A/m2)

Vg = AC voltage of pipeline with respect to earth (volts)

ρ = soil resistivity at pipe depth (Ω-m)

d = diameter of a circular holiday (m)

For AC corrosion mitigation design purposes where a 1cm2 coupon, having a diameter of

0.0113m, is intended to be used, the forgoing equation can be simplified to the following

equation.

iac = 225 Vg /ρ [Eqn 6a]

The calculated AC current density values can then be compared to the current density ranges listed in

Table 3 in order to classify the corrosion risk. To use the data in Table 4 requires knowledge of the DC

current density, which again can only be determined using buried coupons, which should have a minimum

surface area of 10 cm2 to provide a value that is within the range of the meter resolution. Both the AC

and DC coupon currents can be recorded, with a data logger or remotely monitored, to determine the

variation in the induced AC with time.


Alternatively, the AC corrosion rate can be evaluated directly using corrosion rate probes and special

instrumentation.[xliii] This information can also be obtained by remote monitoring.

For new pipelines, the AC current density can be estimated from the induced voltage profile as calculated

from modeling software before the pipeline is installed, providing that a detailed soil resistivity survey is

conducted, at close intervals, along the intended pipeline route. This information is not only useful for

determining the likelihood of AC corrosion but also for designing AC mitigation systems.

SUMMARY

Assessing the magnitude of the risk of AC interference effects, on new or existing pipelines, requires

comprehensive technical analysis to address both the powerline fault and steady-state induced conditions.

This involves collecting baseline information on both the pipeline and powerline as indicated in Appendix

A1 and A2 and determining powerline fault current effects adjacent to each tower, on the pipe wall, the

pipe coating, the pipeline electrical equipment, and the resulting safety hazard for pipeline personnel.

When a conservative safe separation distance, as indicated in Figure 11 cannot be achieved, then

computer calculations should be utilized to evaluate the risks.

The AC steady-state interference condition must also be evaluated with respect to AC corrosion, and

safety to pipeline personnel and the public. The pipeline steady-state induced voltage level should not

exceed 15 V at locations, where the public or personnel can contact the pipeline, and the AC current

density must be reduced, based on a 1 cm2 holiday, so that the AC corrosion rate is at an acceptable

value, when the cathodic protection system is operating normally. Computer modelling of the AC voltage

and current density profiles are usually required to complete this analysis.

Design and implementation of mitigation methods are often required to minimize the foregoing risks.

Methods of Mitigating AC Interference 4.

GENERAL

New projects, involving a pipeline installation on a powerline right-of-way or a new powerline installation on

a pipeline right-of-way, present an opportunity to address the potentially harmful effects before

construction starts. Existing pipelines, which are routinely being monitored for AC voltage, often require

some mitigation measures. AC interference mitigation methodology varies depending on the nature of the

AC interference. There are many mitigation options depending on the AC interference mode, some of

which are as illustrated in Figure 15.


Figure 15 – Illustration of AC Voltage Mitigation on a Pipeline by Electrical Grounding

and Gradient Control Mats at Pipeline Appurtenances

In general, the primary focus of an AC mitigation design is:

to keep a safe pipe-to-powerline separation distance to minimize the risk of arcing to the pipe during a powerline fault and,

to install gradient control mats at pipeline appurtenances to protect personnel doing pipeline contact work during a powerline fault and,

to make the pipe electrically lossy by electrically grounding the pipe to earth to prevent hazardous voltages under fault and steady-state conditions and to minimize the risk of AC corrosion.

To accomplish the foregoing, detailed information about the pipeline and powerline, as listed in Appendix

A-1 and A-2 respectively, is required before any harmful effects are identified and any mitigation system

can be designed.

MITIGATING HARMFUL EFFECTS FROM A POWERLINE FAULT

Pipelines paralleling a powerline right-of-way or crossing a powerline right-of-way near a tower or passing

close to an electrical grounding system, could be subjected to the harmful effects caused by a powerline

fault. To avoid possible dielectric stress damage to the coating and possible arc damage to the steel pipe

wall, the general approach for a new pipeline is to locate the pipeline a safe separation distance from the

electrical power system towers and electrical grounds. A conservative distance would be in accordance

with Figure 11 and Table 6 or at a minimum safe separation distance from calculations using Equations 2

and 3. These distances are required to prevent a sustained arc between the powerline grounding system

and the pipeline, but a GPR at a tower could still result in dielectric breakdown of the coating. The

expectant GPR at the pipeline must be calculated and examined with respect to the coating type and

thickness as shown in Table 2. Furthermore, the coating voltage stress can be greater than the GPR,

because of induction in the pipeline due to the imbalanced phase currents at the time of the fault. The

inductive voltage tends to be out of phase with the powerline fault voltage, which produces a voltage

across the coating thickness that is greater than just the GPR voltage.


If the coating dielectric strength could be compromised by a GPR plus the inductive voltage component or

the pipeline cannot be located a safe separation distance from a powerline tower or grounding system, then

mitigation should be considered. Although it may be the best technical solution, moving of an existing

pipeline or powerline tower is typically not feasible due to the high costs involved. However, there are some

other types of mitigation that can be considered.

Some of these involve modifications to the powerline, such as moving or removal of a ground electrode

on a wooden pole to increase the separation distance to the pipeline, or improving of the tower

grounding, which would result in a lower resistance to ground and a corresponding reduction in the tower

GPR. Another option could be to shield the portion of the pipeline that is “too close” to the tower using a

dielectric material, however this would have the negative side-effect of also shielding the pipeline from

cathodic protection current. One “shielding” approach that could be considered would be to install a

sealed dielectric casing (such as HDPE) around the pipeline in the vicinity of the tower and fill it with gel

to minimize the risk of water entering the casing and causing corrosion. It is unknown how well the seal

and gel would hold up over time, so this section of pipe should be monitored on a regular basis to ensure

that it is not corroding inside the casing.

A third approach is the installation of screening electrodes alongside the pipeline on the tower side of the

pipeline. The purpose of the screening electrodes, as schematically illustrated in Figure 16, is to intercept a

fault current and thereby shield the pipeline and coating.

Figure 16 – Screening Electrode Arrangement at a Powerline Tower to

Prevent Arc Damage and Coating Damage to the Pipeline

The screening electrode should be centered on the centerline of the tower and about 1 m from the

pipeline and extend a distance (Le) beyond the width of the tower. The distance ‘Le’ is calculated

assuming that the pipeline would receive the bulk of the fault current within a 120º arc from the

tower.[xliv] The distance Le is therefore calculated using the following equation.

Le = S x tanϴ [Eqn 7]

where ϴ is 60º and S is the pipeline-powerline separation distance.

Powerline tower footing

Screening Electrode = 60º angle

Pipeline

LS

W Separation

Distance(s)


Therefore, Le = S x 1.73 and the total length of screening electrode is

Ls = W + 2 Le [Eqn 8]

where:

Ls = total length of screening electrode arrangement (m)

Le = length of screening extending 60º beyond the width of the tower

S = separation distance between the pipe and tower or grounding system (m)

W = width of tower footing or grounding system

The screening electrode can be composed of a non-galvanic material, such as copper cable, connected to

the pipe through a DC decoupler or directly, if the screening electrode is composed of packaged zinc

anodes or a zinc ribbon surrounded by sulphate rich backfill. When individual packaged electrodes are

used, the end-to-end spacing between them should not exceed their individual length. The individual

packaged zinc anodes can be connected to an insulated header cable to reduce the number of connection

points to the structure. If the zinc screening electrodes are located where the existing pipe-to-soil on-

potential is more electronegative than -1100 mVCSE, then they should be connected through a DC

decoupler, so that the zinc electrodes do not pick-up cathodic protection current.

Unfortunately, under fault conditions, there are downsides to installing screening electrodes. It would increase

the risk of an arc developing, and much more current would be transmitted along the pipeline, upstream and

downstream from the fault location, than would be without the screening electrodes. The resulting concern

about distributing a shock hazard along the pipeline and increasing the risk of an indirect arc to other

crossing structures must be assessed before adopting screening electrodes.

Powerline faults are statistically rare, usually occurring when there are inclement weather conditions,

during which pipeline personnel are directed to avoid any pipe contact work. But there can still be a small

risk of a hazardous voltage appearing at a pipeline appurtenance. These locations include valves, cathodic

protection test stations, risers, and above ground pipe runs and inside stations.

To protect personnel from being exposed to a lethal shock hazard, when in contact with the pipeline at an

appurtenance, gradient control mats can be employed. A gradient control mat is not a grounding mat but

rather a metallic grid that is placed near the surface of the ground and connected to the pipeline so that the

touch and step voltage is reduced during a fault, as shown in Figure 17.

For example, if a powerline fault raises the potential on the pipeline to 5,000 V, then the grounding mat is

also at 5,000 V and the potential difference between the hands and feet is significantly reduced.


Figure 17 – Illustration of a Gradient Control Mat Composed of Zinc Ribbon

in a Sulphate Rich Backfill Connected Directly to the Pipe

With the gradient control mat connected directly to the pipe it will be more difficult to measure an

accurate polarized potential on the pipeline because of the influence of the zinc. To avoid this problem, the

gradient control mat can be interconnected to the pipeline via a DC decoupler. Moreover, if the zinc ribbon

is not surrounded by sulphate ion rich backfill or if another metal is used, such as copper or galvanized

steel, the gradient control mat must be connected to the pipeline through a DC decoupler.

The placement of crushed stone on the surface also reduces the risk of a shock hazard by increasing the

foot-to-ground contact resistance, thereby lowering the amount of current that would pass through the

body.

For example, the touch voltage tolerance for a 50 kg person is given in Equation 1 as:

Vtouch-tolerance = (1000 + 1.5ρ) 0.116/√t

where:

ρ = soil resistivity (Ω-m)

t = time (s)

Given a soil resistivity of 50 Ω-m and a fault time of 0.167 s (for 10 cycles) then the voltage tolerance is

calculated to be 306 V. This voltage tolerance can be increased by simply placing a layer of crushed stone

on grade. The foregoing equation is modified by a de-rating factor Cs which is calculated in the following

equation.

Cs = 1 – 0.09 (1- ρ/ρs) / (2hs +0.09) [Eqn 9]

Gradient Control

Mat (Zinc Ribbon

in Sulphate Rich

Backfill)

Clean Crushed Stone

above Gradient

Control Mat


where:

Cs = surface layer de-rating factor

ρ = underlying soil resistivity (Ω-m)

ρs = surface layer resistivity (Ω-m)

hs = thickness of surface layer (m)

the de-rating factor modifies Equation 1 for a 50 kg person as follows:

Vtouch-tolerance = (1000 + 1.5ρ x Cs ) 0.116/√t [Eqn 10]

Therefore, given a 150 mm thick layer of crushed stone having a resistivity of 3,000 Ω-m (ρ), the

calculated de-rating factor is 0.77, and using Equation 10, the touch voltage tolerance for a 50 kg person is

calculated to be 1, 204 V compared to 306 V without the surface crushed stone layer. In this example,

the use of a crushed stone layer has increased the touch voltage tolerance by about a factor of 4. This

result assumes that the crushed stone layer is well drained and not saturated with water. Frozen ground

would also have a similar effect as the crushed stone.

The combination of a gradient control mat and a 150 mm crushed stone layer is a very effective method of

mitigating a fault voltage hazard to pipeline personnel.

Besides safety considerations for personnel, some pipeline components, such as insulating fittings,

transformer-rectifiers, cathodic protection bonds, interference bonds to foreign pipelines, and monitoring

equipment electronics, need to be protected from fault voltages. Surge protectors or DC decouplers should

be connected across any insulating fitting on the main paralleling pipeline section and at any termination

points at a station. Isolation fittings, at lateral takeoffs from the co-located pipeline, should also be

protected in the same manner provided that, transferring a fault current to a lateral pipeline will not create

a shock hazard or equipment damage on the lateral or if a potential hazard is produced, then it too must

be mitigated.

Cable connections to the pipe and AC grounding facilities can be made in the same manner as used for

cathodic protection purposes. Cables, that are likely to transfer a fault current, should be sized in

accordance with Figure 2 and 3 in NACE SP0177-2007 Standard Practice.[xlv]

MITIGATION OF ELECTROSTATICALLY INDUCED VOLTAGES

As previously indicated, the electrostatically induced voltages on skidded up pipe sections, can be in the

order of 1000 V but do not present a serious shock hazard. Nevertheless, the individual sections of pipe

should be temporarily grounded in accordance with CAN/CSA-C22.3 No. 6-13 Standard.[xlvi] Once the pipe

is buried, there is no electrostatically induced voltage.


MITIGATION OF ELECTROMAGNETICALLY INDUCED VOLTAGES

General

As with the mitigation of the harmful effects of powerline faults, electromagnetically induced voltages can be

mitigated by increasing the distance between the powerline and the pipeline. Figures 13 and 14 illustrate

the benefit of increasing the separation distance on the longitudinal electric field per km per ampere.

During a fault, the pipeline also experiences an induced voltage because of the large but momentary

imbalance in the phase currents. This induced voltage often increases the voltage across the coating

because it is out of phase with the ground potential rise (GPR) caused by the fault current discharged at the

faulted tower. Therefore, increasing the powerline-pipeline distance mitigates both the hazards associated

with resistive coupling and electromagnetic induction. The AC shock hazard and AC corrosion concerns

arising from electromagnetically induced voltages must be evaluated for both new pipelines and new

powerlines that parallel each other and for existing pipelines that are paralleling a powerline right-of-way.

Besides the separation distance, mitigation of electromagnetically induced AC is focused primarily on

making the pipeline electrically lossy to AC but not DC, which can dramatically reduce the pipe-to-ground

voltage and current density at holidays as shown in Figure 18. Grounding of the pipeline through various

methods allows the AC current to pass to ground so that the voltage does not build up in the pipeline. The

grounding facilities can be distributed along the paralleling section or located at peak voltage locations. A

combination of both arrangements can be very effective.

Figure 18 – Illustration Showing Effect of an Electrically Lossy Pipeline

on the Induced Voltage Profile

-Vg

+Vg

0

Electrically short (non-lossy)

Electrically long (lossy)


For a New Pipeline on a Powerline ROW or a New Powerline on a Pipeline ROW

For new pipelines the safety procedures outlined in CAN/CSA-C22.3 No.6-13 Standard need to be

followed. This standard addresses conditions where the powerline voltages are greater than 40 kV, but it

should be noted that AC corrosion can occur when the AC powerline voltage is less than 40 kV. In some

circumstances AC corrosion during pipeline construction can be significant, particularly in the absence of

CP. Thus, the AC corrosion susceptibility of the pipeline during construction must also be addressed and

the AC mitigation system should be predesigned so that it can be installed during pipeline construction.

To design a comprehensive mitigation system usually requires computer modeling, using information

obtained from the information recommended in Appendix A, augmented by a detailed soil resistivity

survey. Installing the permanent AC mitigation system during pipeline construction will complement the

temporary grounding facilities and decrease costs of the temporary grounding facilities as well as lower

the installation costs of the mitigation system.

When a new powerline is being installed on a pipeline right-of-way, the interference effects must be

evaluated before agreeing to the co-location plan, and any AC mitigation systems should be installed prior

to energization of the powerline. For a new powerline on a pipeline ROW, the powerline phase arrangement

on a vertical double circuit tower can be chosen to produce the least electromagnetic induction. A centre

point symmetrical phase arrangement, as shown in Figure 19, produces several times less induced voltage

than the other arrangements. This also applies to an existing powerline, but the electrical power utility is

often reluctant to make phase arrangement changes because of the high cost of doing so.

Figure 19 – Different Possible Phase Arrangements on a Vertical Double Circuit Powerline

Tower

The presence of shield wires on a powerline also affects the electromagnetically induced voltages on the

pipeline. The purpose of these wires is to protect the phase conductors from lightning strikes but they can

also affect the induced voltage on the pipeline.

Galvanic anodes, distributed along the pipeline or grouped at induced voltage peaks, are an effective method

of making a pipeline electrically lossy. Zinc anodes, packaged in a sulphate ion rich backfill are preferable

to magnesium anodes, owing to their much higher efficiency and less susceptibility to AC effects on their

operation. When directly connected to the pipeline, the anodes also provide cathodic protection for the

pipeline and do not create any electrical interference on the metallic powerline towers. This avoids using


impressed current systems, which can create stray current interference, and also avoids transformer-

rectifier outages during powerline fault events. The viability of using distributed anodes depends however,

on the soil resistivity, since in high resistivity soils the output of discrete galvanic anodes can be

insufficient to provide satisfactory cathodic protection. Also, with direct connected galvanic anodes, it is

difficult to accurately measure a polarized pipe potential for comparison to industry criteria without

incorporating cathodic protection coupons at test points.

A zinc ribbon anode is also effective, especially where a very low resistance to earth is required, because

of the long length that can be installed horizontally and parallel to the pipeline. If it is intended to use the

zinc ribbon as a galvanic anode then the ribbon should be surrounded by sulphate ion rich backfill to

prevent the anode from passivating. When connected to the pipeline through a DC decoupler, the zinc

ribbon is susceptible to interference from any nearby impressed current cathodic protection systems,

depending on the length of the ribbon and the relative location of the cathodic protection groundbeds. In

some soil conditions, the zinc ribbon will passivate, increasing the AC resistance to earth and reducing the

effectiveness of the mitigation system. When in doubt about the soil conditions, the ribbon should be

surrounded in sulphate ion rich backfill.

The grounding arrangement can also be composed of stranded copper cable installed horizontally

alongside the pipeline and connected to it via a DC decoupler. A long copper cable is also susceptible to

stray current interference from nearby impressed current systems and is also subject to differential

aeration corrosion. To ensure a reasonable service life, the copper cable should be cathodically protected

with sacrificial anodes.

When the near surface soil resistivity is high, a deepwell grounding arrangement can be used to position

the grounding electrode at a depth where the earth resistivity is low. Grounding materials can be the

same as for the horizontal arrangement. However, a deepwell grounding system, being remote, is not as

effective in reducing the AC current density at a coating holiday as a horizontal arrangement placed close

to the pipeline, because the horizontal anode is close to the holiday. Another advantage of the horizontal

grounding arrangement under a fault condition, is that the AC voltage gradient near the pipeline is

reduced, owing to the near surface location of the ribbon grounding electrode compared to a deepwell

grounding electrode.

Failure of the carrier pipe inside a casing from both puncturing[xlvii] and AC corrosion[xlviii] has occurred

and, in both incidents, the casing was isolated from the pipe. The casing, when bare, has a relatively low

impedance to earth compared to the coated carrier pipe. The small separation distance between a carrier

pipe holiday and casing, through water contained in the annulus of the casing, makes the impedance of

the holiday to remote earth lower than if the casing was not present. This interior path can therefore,

transfer more current to earth than a similar sized holiday on the pipe exterior to the casing and result in

an accelerated corrosion rate. Accordingly, any casing on a pipeline, that is influenced by induced AC,

should be bonded through a DC decoupler to the pipeline, regardless of the AC induced voltage levels. A

bare casing when coupled to the pipeline through a DC decoupler, also serves as an AC ground which will

reduce the induced AC voltage as well.

Metallic vent pipes at a casing should not be placed near or against an above ground metallic object, such

as a fence or guy wire, since these objects could become energized during a powerline fault. Moreover, if

the casing is in a built up area, a gradient control mat should be installed at the base of each vent to

protect the public from a potential shock hazard. Otherwise non-metallic vent pipes should be used.

Mitigation of AC voltages and currents at crossings between an AC interfered-with pipeline and a foreign

pipeline may be required, depending on the AC interference circumstances. A foreign pipeline at a

crossing brings remote earth electrically close to the pipeline with induced AC, which can introduce a

touch potential hazard between the two pipelines or facilitate the transfer of fault current and steady-


state induced current between the pipelines. Under such conditions pipe and pipe coating damage could

occur or the AC current density could be elevated resulting in an increase of AC corrosion on both

pipelines. If there is also DC interference at the crossing, the polarized potential of the discharging

pipeline could be suppressed such that the effectiveness of the CP system in preventing AC corrosion is

compromised (i.e. the iac/idc ratio is adversely affected). Furthermore, if the DC potential of either pipeline

is elevated at the crossing, due to the stray current pick-up, AC corrosion could be accelerated (e.g.

Figure 7).

This situation presents some mitigation difficulties. If there is a mutual cathodic protection test station at

the crossing, a hazardous AC voltage could be present inside the test station between the pipeline test

leads. Secondly, if galvanic anodes are used to mitigate the DC interference, it may cause a high amount

of AC to transfer at the crossing. Moreover, if there is a resistance bond to mitigate the DC interference,

it will transfer both fault and steady-state AC current. In the case of the former, the bond could be burnt

out, depending on the magnitude of the fault current and current capacity of the bond. Although it may

be considered reasonable to place a DC decoupler between the two pipelines to mitigate the harmful AC

effects and make the pipeline electrically lossy, this should only be done with the mutual permission of

both parties. Regardless as to whether or not AC mitigation is applied, these pipeline crossings should be

considered as critical locations not only in terms of DC interference but also for AC interference.

Using DC decouplers across isolation fittings at stations also serves to make the pipeline electrically lossy, since

the station grounding system provides an alternative parallel path for the induced AC current to pass to

ground. Typically, the station electrical grounding system is also connected to the electric power distribution

grounding system, which further lowers the impedance to earth. When bonding across an isolating fitting at a

station however, it must be recognized that a portion of a powerline fault current will also seek this path and

gradient control facilities might be required inside the station to protect personnel during a fault. In addition,

surge protectors may also be required on electronic equipment inside the station.

An isolation fitting located at a lateral take-off, when bridged by a DC decoupler, provides an additional AC

grounding path depending on the lateral pipeline length and coating quality. Again, consideration must be

given to the effect on the lateral of any fault current that might travel along the lateral through the DC

decoupler.

Motorized valve locations are places where a DC decoupler can be used to shunt induced AC and a portion

of a fault current to the local electrical grounding system. Not only will this provide a steady-state

grounding path but will also aid in lowering any fault voltage gradient, although a gradient control mat

might also be needed depending on the magnitude of the fault voltage at the valve location.

DC Decouplers and Surge Protectors

Isolation fittings are subject to damage by fault currents unless surge protection measures are taken.

Numerous failures of flange isolation from fault currents have been reported. [xlix,l,li,lii,liii]

AC surge protection devices such as spark gaps, arresters, zinc grounding cells, polarization cells, and

isolation surge protectors (ISP), have been recommended[liv] to be connected across isolating fittings to

provide an alternative fault current path. Although spark gaps and arresters are effective against lightning

and smaller fault currents, they are subject to high maintenance and are not suitable for draining steady-

state induced AC, which is very often required for effective AC mitigation. Hence a class of devices called DC

decouplers, which have a low impedance to AC and a high resistance to DC, are normally utilized.


Surge protectors to handle lightning and AC fault currents are typically connected across isolating fittings

and the input/output of electronic equipment. There are a wide variety of surge protectors such as gas

filled, surface discharge, varistors and suppressor diodes, all with different AC fault handling capabilities.

The critical feature on pipelines subject to electromagnetic induced AC is the ability of the surge protector

to limit the power follow current after a fault occurrence. Surface discharge or varistors perform this

function whereas gas filled arrestors do not. There is however, a significant performance difference

between a metal oxide varistor (MOV) and silicon carbide varistor. The MOV breakover voltage is much

less than the silicon carbide, hence the MOV is more suitable for protecting electronic components, and in

particular rectifiers. MOVs can be selected

for specific breakover voltages and surge

current ratings.

Zinc grounding cells, as illustrated in Figure

20, have been used as a surge protector at

isolating flanges. They are typically

composed of two lengths of zinc anode

alloy casting, separated lengthwise with

insulating blocks and packaged with

galvanic anode backfill in a cardboard or

cloth container.

The grounding cell provides a low

impedance path for AC and a higher

resistance to DC, but only if sufficient DC

current passes through the cell to create a

cathodic polarization back voltage. It is

claimed,[lv] that this back voltage can be in

the order of 0.5 V. To provide a 0.5 V back

voltage by cathodically polarizing the zinc

more negative than -1.5 VCSE, could require

a DC density of 4 A/m2 which is over 500 mA based on the electrode dimensions for a standard size zinc

grounding cell. Moreover, AC will tend to depolarize the zinc grounding cell, which lowers its DC

resistance and allows more cathodic protection current to pass through the cell. This can make the

grounding cell ineffective in maintaining a DC step back voltage on galvanic anode protected piping. Even

when the DC drain current can be accommodated, as might be the case with an impressed current

system, the life of a zinc grounding cell will be shortened by the excessive DC current drain, necessitating

the installation of multiple cells or of cells with higher weight castings. The typical failure mode for a zinc

grounding cell is an open circuit, thereby creating a possible safety hazard. From an operational point of

view, zinc grounding cells are less desirable for mitigating AC fault and induced voltages than DC

decouplers.

Polarization cells typically have an AC impedance of about 0.1 milliohm which is dependent on the

number of plates, surface area of the plates, and spacing between plates. The cells are usually

constructed to pass high currents, in the order of tens of kA, without damage to the cell and yet be able

to offer a significant DC back voltage. Polarization cells derive their DC back voltage from both cathodic

and anodic polarization of either stainless steel or nickel plates immersed in a highly alkaline solution.

Back voltages in the order of 1.6 V can be developed with rather modest cathodic protection current

drainage (e.g. 100 mA).[lvi]

As with zinc grounding cells, AC causes depolarization and at 10A - 20A AC, the DC rises to about 400 mA

and lowers the back voltage to less than 1.35 V. Again, for a steady-state AC drain, a 400 mA DC drain may

compromise cathodic protection levels, especially on galvanically protected pipelines. Also, if the 5% KOH

solution inside the cell becomes diluted or the solution level is low due to evaporation, the solution can

Figure 20 - Typical Zinc Grounding Cell

Two 5 ft. long zincanodes separatedby insulating blocksand surrounded withlow resistivity backfill.This electrode

cathodically polarizesand resists the flowof direct current.

Typical Grounding Cell

IsolatedFlange

Cathodicallyprotected sideof isolator


over heat to the point where it will boil off resulting in an unacceptable open circuit. Moreover, corrosion

of the plates has been known to occur. Under steady-state AC current drain, the cell will continue to pass

DC and hence the possibility of corrosion arises on the anodic plates. Plate corrosion has been reported

for both nickel and stainless steel plates[lvii] under the foregoing circumstances coupled with the

superposition of DC stray current originating from a transit system.

Excessive gassing, produced during faults as the cell is depolarized and as the repolarizing DC generates

oxygen at the anode plate and hydrogen at the cathode[lviii] produces an explosion hazard. A polarization

cell failure can result in a shock hazard because of an open circuit failure mode, especially where the cell

is being relied upon to drain steady-state induced AC currents. Because of these disadvantages, solid-

state DC decouplers have generally replaced polarization cells to protect isolating fittings and to drain AC

to grounding systems.

Isolation-surge protectors (ISP) are solid-state devices which were introduced in the late 1980s as a

replacement for the polarization cell. As shown in Figure 21, they consist of three distinct circuit

components, namely; an arrester to pass lightning faults, electrolytic capacitors to drain steady-state AC,

and thyristors to pass AC fault currents.

Figure 21 - Isolator/Surge Protector Circuit Diagram(redrawn from Dairyland Electric

Industries Inc., Isolation/Surge Protector Brochure, Fig.1 p.A6)

An ISP presents an open circuit to DC up to a voltage threshold that is adjustable and a short circuit to

voltages greater than the threshold value. These devices require less maintenance than polarization cells

and are claimed[lix] to fail only in short circuit mode. The electrolytic capacitors are rated to pass the

steady-state AC current while the thyristors are rated to pass the fault current. When the electrolytic

capacitors are polarity sensitive, they can fail under AC load (usually open circuit) if the DC polarity is

reversed. This factor may preclude their use in locations subject to fluctuating DC stray currents such as

from a transit system or telluric activity.

Electrolytic Capacitor C

Gate

ThyristorsT1

T2

Inductor L

Surge Protector

GroundPipe

Positive terminal bondedto enclosure internally

Gate

+_

+_

Enclosure


The DC current loss through an isolation-surge protector (ISP) is typically low (e.g. <100 mA). Only after

the thyristors are triggered between 9.1 V and 12.5 V does the DC current increase, which would only be

for short periods. Even though both polarization cells and ISPs can theoretically pass lightning current,

lightning surges may not find this path advantageous if the cable lengths are too long. All conductors

connected to these devices must be kept short in order to minimize voltage rise caused by the conductor

inductance, if they are intended to mitigate lightning voltage crests. For an ISP connected across a

flange, a total conductor length of 20 m, and a lightning current rise of 1000 A/microsec, a voltage of

2000 V would appear across the ISP, which could be high enough to damage the flange insulation.

Therefore, where the conductors between the AC fault protector and the isolated fitting are long, a surge

protector should still be installed at the flange isolation for lightning protection purposes.

Aluminium electrolytic capacitors are sometimes used for draining steady-state induced currents to AC

grounding systems. These are polarized capacitors and therefore subject to failure under AC load if the

DC polarity reverses, as could be the case if the pipeline is exposed to DC stray currents. The failure mode

80% of the time is to a short circuited condition,[lx] which is a fail-safe condition from an AC hazard point

of view, but a cathodic protection integrity disadvantage. Sealed capacitors have been known to explode

and catch on fire when exposed to a reverse voltage under AC load. Electrolytic capacitors also have a

limited life of about 10 years and require protection from fault currents with a surge protector such as a

varistor.

Polarization cell replacement (PCR)[lxi] decoupling devices are similar to isolation surge protectors except

that the thyristors are replaced with high current capacity diodes. As with isolation surge protectors, they

can pass both AC fault current and steady-state AC providing that they are rated properly for the

intended service. They are fail-safe because they fail in the shorted mode, although the failure rate is

small. For the above reasons and, because they are solid-state, they have become the dominant type of DC

decoupling device used in the pipeline industry. The electrolytic capacitors in the PCR are not polarity sensitive

so they can be used where a pipeline is experiencing DC interference from a transit system.

Under some circumstances decoupling devices with large capacitors can cause errors in measuring an

instant-off potential especially on pipelines with impressed current systems.[lxii] This is because the

electrolytic capacitors store a DC voltage that is developed across its terminals between the pipeline and

the ground by the cathodic protection system. When the transformer-rectifier output is interrupted, the DC

voltage across the electrolytic capacitor might not decay quickly but retain a DC potential between the

earth and the pipeline, which introduces a pipe-to-soil potential measurement error that makes the pipe-

line appear more electronegative than the true polarized potential. This problem can be identified by

examining the pipe-to-soil potential with time to determine if there is a delay, as illustrated in Figure 22.


Figure 22 – Pipe Potential versus Time for TR Interruption on a Pipeline with and without a DC

Decoupler.

The decay of the DC potential across the capacitor is a function of the circuit time constant (RC) given by

the circuit resistance (R) times the farad value of the capacitor (C).

This pipe-to-soil potential measurement problem can be addressed by one or more of the following

actions.

interrupt the DC decoupler synchronously with the transformer-rectifier but this could result in a

momentary shock hazard

reduce the circuit resistance between the pipeline and DC decoupler ground

reduce the capacitance of the electrolytic capacitor, although this will increase the decoupler

impedance

install cathodic protection coupons at the pipeline test station and measure their instant-disconnect

potential

CATHODIC PROTECTION EFFECTIVENESS IN MITIGATING AC CORROSION

Corrosion Control Criteria

The application of cathodic protection current can reduce the AC corrosion rate within limits. As indicated

previously, if the AC current density at a holiday is less than 20 A/m2 and the holiday polarized potential

is more electronegative than -850 mVCSE, then the likelihood of AC corrosion is considered to be low. Even

in the absence of cathodic protection, the AC corrosion rate has been shown to be less than 1% of an

equivalent DC current density, and estimated at 0.1 mm/y at an AC current density of 20 A/m2. Further-

more, this has resulted in the claim that “only ac current densities above 50 Am-2 are serious”[lxiii] on

cathodically protected pipelines.

Industry standards recommend a minimum polarized potential of -850 mVCSE for effective corrosion control

under normal soil conditions. For AC interference conditions, it is empirically evident that, if iac at a holiday


is greater than 20A/m2, then corrosion can occur and if iac is greater than 100 A/m2, AC corrosion should

be expected. One study[lxiv] indicates that cathodic protection is effective if the polarized potential is in the

-1000 to -1200 mVCSE range, but only if the iac/idc ratio is less than 20. To satisfy this condition a higher

DC current density would be needed than for the industry standard and coupon facilities for measuring

the AC and DC current density would need to be installed. However, as indicated in Figure 7, there is a

risk of increasing the AC corrosion rate when the cathodic protection current density is in the 2 – 10 A/m2

range, especially in soil conditions where a calcareous deposit is not likely to form at a holiday.

The effectiveness of the 100 mV cathodic polarization criterion in preventing AC corrosion is a function of

the AC current density as shown in Figure 23.[lxv]

Figure 23 – 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

A/ft2)

AC corrosion control at 100 mV of cathodic polarization becomes marginal when the AC current density

approaches 50 A/m2 and a cathodic polarization shift of approximately 300 mV is required to achieve

protection when the current density is greater than 50 A/m2. At AC current densities less than 20 A/m2, the

100 mV cathodic polarization shift criterion was found to be effective.[lxvi] A disadvantage of the cathodic

polarization criterion is that, when measured by the potential decay method, it can take several days to

allow the pipeline to fully depolarize. Over this period of time the AC interference can change and affect

the polarization response. Generally, it is recommended to not use the cathodic polarization shift criterion

when there is electrical interference on the pipeline.[lxvii]


Type of Cathodic Protection System

For mitigation of hazardous AC voltages, a galvanic anode system is more effective than an impressed

current system, since the galvanic anodes serve as AC grounding points, which tend to make the pipeline

electrically lossy. Impressed current systems require supplemental grounding systems.

Galvanic anodes, such as magnesium anodes, when passing AC will have a higher consumption rate and

must be sized to accommodate the increased corrosion rate. Alternatively, zinc anodes, surrounded by

sulphate rich backfill are more efficient and have a longer service life than magnesium, especially when the

pipeline is very well coated.

A galvanic anode system, however, may not be feasible in high resistivity soils and, if directly connected

to the pipeline, make the accurate measurement of a polarized potential more difficult. Therefore,

cathodic protection coupons need to be installed at all test stations unless the galvanic anodes are

connected individually or in groups through a DC decoupler.

Impressed current cathodic protection systems assist in mitigating AC interference by making the pipeline

electrically lossy, only because some of the AC current can pass through the rectifying bridge to the

groundbed. This also results in half-wave rectification and a corresponding increase in the pipe-to-soil

potential in the vicinity of the impressed current system drain point. Impressed current systems have the

advantage over galvanic systems in that they can provide a higher current output in high resistivity soils.

They can also be operated in constant potential mode to ensure that the potential at the drain point does

not become too highly negative (> -1200 mVCSE), thus minimizing the risk of an increase in AC corrosion.

The DC output current can also be more easily monitored than for galvanic anode systems. Pipelines with

impressed current protection typically require additional AC grounding using DC decouplers between the

pipeline and any grounding facility.

The disadvantages of an impressed current system on pipelines with AC interference are that the

transformer-rectifier is subject to outages due to fault currents and switching surges, the DC current

output from the impressed current system can cause interference corrosion on powerline metallic tower

footings and grounding systems, and pipe-to-soil potentials can become electronegatively elevated if not

adjusted properly.


Monitoring Considerations 5.

A cathodically protected pipeline that is experiencing steady-state induced AC interference, requires exten-

sive monitoring facilities and monitoring protocols in order to establish the severity of the AC interference,

the effectiveness of the cathodic protection system, and the operation of the AC mitigation systems. Not

only are test stations required for normal cathodic protection monitoring but test stations need to be

installed where AC voltage peaks and AC current density peaks are located or are expected, because of

the geometrical arrangement between the powerline and pipeline. Moreover, test facilities are needed at

all AC grounding locations. Test stations, where practical, should be fabricated as dead-front construction

for personnel and public safety reasons.

The risk of an AC induced voltage hazard can be identified by simply measuring the pipeline AC voltage at

the test stations with respect to the copper-copper sulphate reference electrode, as is normally used for

recording pipe-to-soil potentials. When this voltage is greater than 10 V, the AC voltage should be

recorded for a 24 hour period to assess the daily voltage variation and to determine the maximum

voltage during the recording period. The risk of AC corrosion rests on the AC current density (iac) and the

ratio iac/idc. In general, the risk of AC corrosion needs to be investigated where the pipeline AC voltage,

expressed in mV, is greater than the soil resistivity at pipe depth, expressed in Ohm-cm (VacmV>

ρΩ-cm). Where this condition exists, iac would be greater than 20 A/m2 on a 1 cm2 holiday. For

example, soil resistivities near roads are often much lower than adjacent soil, owing to the accumulation

of salts from road de-icing practices. There are numerous instances where AC corrosion has occurred at

pipeline road crossings or where the pipeline parallels a road way. Once the soil resistivity and AC induced

voltage is known at any location the AC current density can be calculated using Equation 6a.

AC corrosion control guidelines are inextricably tied to the relationship between the cathodic protection

current density (idc) and the AC current density (iac) at a coating holiday.

Both AC and DC pipe-to-soil potentials should be monitored on a routine basis to determine if the AC

voltage is less than 15 V and at a level that would result in an acceptable AC corrosion current density,

based on a maximum of 50 mA/cm2 or an iac/idc ratio of less than 5. A maximum current density of 50

mA/cm2 is selected because there is a paucity of field information that indicates serious corrosion can

occur at current densities less than this threshold. Nevertheless, if a very conservative mitigation system

is desired, then a maximum AC current density, of either 20 mA/m2 or 30 mA/cm2, should be chosen.

Under some conditions, attempting to reduce the AC current density to these values can be prohibitively

expensive.

Most powerline phase current loading varies seasonally due to summertime air conditioning and

wintertime electrical heating and lighting. Also, seasonal moisture conditions vary from a typically wet

spring to a dry fall, which can affect the resistance of AC mitigation systems. Because of these variable

conditions, measuring of AC induced voltages and AC mitigation currents should be done more frequently

(e.g. quarterly) than is normally required for cathodic protection potentials. AC mitigation currents should

be measured using an AC clamp-on ammeter.

Also, it is important to recognize that the electrical power utility could increase the phase

current magnitudes at any time, for emergency purposes or to accommodate new load

demands, which would cause an increase in AC interference. Consequently, it is advisable to

establish a communication path with the utility so that the pipeline operator is aware of any

changes in the operation of the AC powerline and can adjust the monitoring schedule

accordingly.


Another or alternative technique to monitor the corrosion control system is by installing corrosion rate

coupons along the pipeline at critical locations and monitoring them on a routine basis, even remotely.

Also AC and cathodic protection coupons can be installed to facilitate measuring both the AC and DC

current density. AC coupons should have a surface area of 1 cm2 and the coupon AC current should be

measured routinely. From these measurements the AC current density should be calculated.

At each AC coupon location, a cathodic protection coupon, having a surface area of approximately 10

cm2, should also be installed, and the DC current should be measured using a zero resistance ammeter.

The iac and iac/idc ratio can be compared to Tables 3 and 4 to evaluate the risk of AC corrosion. Cathodic

protection coupons are also essential to enable the measurement of a representative polarized potential

on the pipeline for comparison to industry criteria. Cathodic protection coupons are indispensable where

problems in measuring an accurate instant-off potential are encountered, such as with direct-connected

anodes or as a result of the slow decay of the capacitors in DC decoupling devices. If buried reference

electrodes are used in conjunction with the cathodic protection coupons, they should be backfilled with a

bentonite/sulphate ion mixture to ensure long term reliability and performance. In addition to coupons,

AC current through DC decouplers or directly connected grounding facilities should be measured using an

AC clamp-on ammeter.

A more direct analysis of AC or DC corrosion can be obtained by running in-line inspection tools through

the pipeline sections influenced by AC interference.

For additional information pertaining to mitigation and monitoring procedures see section 6.2.

Summary 6.

GENERAL

The electrical interaction between AC powerlines and steel pipelines can result in damage to steel

pipelines and their ancillary components and create a voltage hazard to personnel and the public. When

AC transmission powerlines of greater than 69 kV or AC distribution systems of 5-49 kV are parallel to a

steel pipeline or there is a mutual crossing, an AC interference investigation is required. This broad range

of powerline voltages is intended in order to avoid overlooking a serious situation, which can only be

evaluated by considering other factors as outlined in this guideline document.

The distance between a cathodically protected pipeline and an AC powerline tower or its grounding facility

needs to be identified to determine, whether or not, it is located at a safe separation distance, in

accordance with Table 6 and Figure 11. If not, the calculation of the GPR and induced voltage resulting

from a powerline ground fault is required to determine a safe flashover distance and a calculation of the

resulting voltage stress on the coating for comparison to Table 2. Also, at this stage, the need for any

gradient control measures at appurtenances can be evaluated.

The objectives of an AC interference evaluation for a cathodically protected pipeline, that is subjected to AC

powerline fault currents and electromagnetically induced voltages, are as follows:

prevent an AC fault current from damaging the pipe wall by arcing or melting;

prevent an AC fault current from damaging the coating by exceeding the dielectric strength of the pipeline coating;

prevent damage to pipeline components such as isolating fittings, transformer-rectifiers, resistance bonds, galvanic anodes, and electrical monitoring equipment;

prevent hazardous step and touch voltages to personnel and to the public, who might come in contact with the pipeline or its appurtenances;

prevent AC corrosion of the pipeline.


To satisfy these objectives, it is necessary to investigate the possibility of AC interference, evaluate the

magnitude of the interference, design and install mitigation facilities as necessary, and monitor the

performance of the mitigation system and the cathodic protection system.

These tasks must be incorporated into an AC interference management program. The procedures in such

a program will vary depending on whether or not the project involves the following types of

pipeline/powerline situations.

A. An existing pipeline on or near an existing AC powerline ROW,

B. A new pipeline intended to be constructed on or near an AC powerline ROW,

C. An AC powerline intended to be constructed on or near a pipeline ROW,

D. A lateral being built from an existing pipeline that is exposed to AC interference,

E. An extension to a pipeline that is on or near an existing AC powerline ROW and that is within 5 km of the entrance or departure point between a powerline and a co-located pipeline.

Procedures for each of these circumstances are summarized below and included in flow chart form in

Appendix B. Values expressed in this document are guidelines only. AC interference studies and AC

mitigation designs must consider conditions where these guidelines may be too conservative or

conversely inadequate.

AC INTERFERENCE PROCEDURES

Preliminary

Regardless as to which one of the foregoing situations is involved in a pipeline project, there are a

number of procedural steps that are common to all.

For each pipeline project, the pipeline specifications and drawings must be reviewed to identify if one or

more of the five potential AC interference conditions could apply. When there is confirmation that AC

interference is a possibility, then more specific powerline and pipeline information, as listed in Appendix

A, must be obtained so that the risk of interference can be evaluated.

A soil resistivity survey is required along the route of the pipeline where the pipeline and powerline are

co-located or where a pipeline crosses a powerline ROW near a powerline metal tower or electrical

ground. Soil resistivity measurements at 1, 3, and 5 meter depths should be taken opposite each tower,

powerline ground, and pipeline appurtenance, such as cathodic protection test stations, pipeline risers,

and valves. Soil resistivities should be taken at greater depths at locations where there are powerline

transpositions, changes in pipeline/

powerline geometry, and soil stratifications.

If the AC interference situation involves a co-location of more than one pipeline or more than one

powerline, conduct computer modeling to assess the fault and steady-state induced conditions. Otherwise

follow the steps outlined for the following cases. Values expressed in this document are guidelines only.

AC interference studies and AC mitigation designs must consider conditions where these guidelines may

be too conservative or conversely inadequate.

Case A - An Existing Pipeline on or near an Existing AC Powerline ROW

Step 1: Assess whether or not there is a safe separation distance between the pipeline and tower(s) or

powerline grounding systems with reference to Figure 11 or Table 6. If not, calculate the GPR due to a

powerline fault at those towers where the safe separation distance is not obtained using fault current


values provided by the electrical utility. Use the faulted tower GPR in Equation 4 for a sustained arc to

evaluate whether there is an arcing risk and whether or not mitigation measures are needed to protect

the pipe and the coating. Regardless as to whether or not the pipe is at a safe separation distance during

a fault, assess if gradient control measures are required at appurtenances to protect personnel from a

shock hazard based on a calculation of voltage tolerance given by Equation 1.

Step 2: Measure the AC pipe-to-ground voltage (Vg) and soil resistivity at pipe depth at cathodic protection

test stations, at isolating fittings, and at locations where there is an electrical discontinuity between the

pipeline and powerline and at locations where the soil resistivity is expected to be low, such as at

roadways where de-icing salts are being applied.

Step 3: Record the pipe-to-ground AC voltage for a 24 hour period at test locations where the measured

AC voltage is greater than 5 V.

Step 4: Contact the electrical utility to determine the powerline phase current loading during the

foregoing survey period. Compare the reported powerline load current to the average and peak load

current and linearly extrapolate the measured Vg to obtain an estimate of the pipe-to-ground voltage (Vg')

when the powerline is operating at average and peak current.

Step 5: AC mitigation is required if Vg' using the values for peak load current is greater than 15 Vac, or if

the calculated current density at a 1 cm2 holiday using Equation 6a and the soil resistivity survey data for

pipe depth is greater than 50 A/m2 for the Vg’ based on the average current loading.

Step 6: If AC mitigation of the induced voltage is required, use a computer modeling program to design

an effective mitigation system.

Step 7: Install AC and DC coupons or corrosion rate probes at pipeline test stations, at locations of

electromagnetic discontinuities, and at locations where the calculated AC current density is greater than

30 A/m2, so that actual AC current densities or AC corrosion rates can be measured during future

surveys.

Step 8: Use non-metallic enclosures and install dead-front terminal enclosures at cathodic protection test

station locations.

Step 9: Install DC decouplers across any isolating joint and at bare steel casings in the piping system within

10 km of the pipeline-powerline co-location providing consideration is given to any detrimental effects

that the transferred voltage or current could have on the structure being coupled to the interfered

pipeline.

Step 10: Ensure that a minimum polarized potential of -850 mVCSE is being met on the pipeline at test

stations and locations of electrical discontinuities.

Step 11: Where possible run an in-line inspection tool through the pipeline section that is exposed to the

AC interference to assess corrosion anomalies.

Case B - A New Pipeline Intended to be Constructed on or near an AC Powerline ROW

Step 1: Assess whether or not there is a safe separation distance between the pipeline and tower(s) with

reference to Figure 11 or Table 6. If not, calculate the GPR during a powerline fault at those towers where

the safe separation distance is not obtained, using fault current values provided by the electrical utility.

Evaluate whether or not mitigation measures are needed to protect the pipe and the coating. Regardless

as to whether or not the pipe is at a safe separation distance during a fault, assess if gradient control


measures are required at appurtenances to protect personnel from a shock hazard based on a calculation

of voltage tolerance given by Equation 1. Attempt to have the pipeline rerouted in order to maintain a

safe separation distance.

Step 2: Calculate the voltage stress that would appear across the coating due to a powerline fault at a tower

or powerline grounding system and refer to Table 2 to determine if remedial measures are required.

Step 3: Conduct field measurements to estimate the longitudinal electric field (LEF) as shown in Figure 12

and calculate the total LEF, using this value and the total length of the paralleling section. Calculate the

peak pipe-to-ground voltage and extrapolate to determine the maximum Vg' based on the average and

peak phase current. This calculation assumes that the propagation constant is small and therefore gives a

conservative estimate. Measure the soil resistivity at pipeline depth along the pipeline route, especially in

areas of suspected low soil resistivity, so that the AC current density on a 1 cm2 coupon can be calculated

using Equation 6a.

Step 4: Estimate the induced voltage on the pipeline, using Figures 13 and 14, if there is a simple pipeline-

powerline co-location arrangement, or conduct computer modeling to determine the induced voltage profile

along the length of the parallel section to design appropriate mitigation measures. Mitigation is required if

the steady-state Vg' is greater than 15 V at appurtenances based on the peak load current and if iac is

greater than 50 A/m2 based on the average phase current loading

Step 5: Install mitigation measures during construction in accordance with the CSA –C22.3 No.6-13

Standard.

Step 6: Install AC and DC coupons or corrosion rate probes at pipeline test stations and at locations of

electromagnetic discontinuities so that actual AC and DC current densities can be measured as well as

polarized potentials.

Step 7: Install DC decouplers across isolating joints and at bare steel casings in the piping system within

10 km of the pipeline-powerline co-location location, providing consideration is given to any detrimental

effects that the transferred voltage or current could have on the structure being coupled to the interfered

pipeline.

Step 8: Ensure that a minimum polarized potential of -850 mVCSE is being met on the pipeline at test


Step 9: After construction and where possible, run an in-line inspection tool through the pipeline section

that is exposed to the AC interference to assess corrosion anomalies.

Case C - An AC Powerline Intended to be Constructed on or near a Pipeline ROW

Step 1: Assess whether or not there is a safe separation distance between the pipeline and tower(s) with

reference to Figure 11 or Table 6. If not, calculate the GPR during a powerline fault at those towers where

the safe separation distance is not obtained using fault current values provided by the electrical utility.

Regardless as to whether or not the pipe is at a safe separation distance during a fault, evaluate whether

or not mitigation measures are needed to protect the pipe and the coating, and if gradient control

measures are required at appurtenances to protect personnel from a shock hazard based on a calculation of

voltage tolerance given by Equation 1. Attempt to have the powerline rerouted in order to maintain a safe

separation distance.

Step 2: After the powerline route is finalized, calculate the voltage stress that would appear across the

coating due to a powerline fault at a tower or powerline grounding system and refer to Table 2 to

determine if remedial measures are required.


Step 3: If the powerline has vertical double circuit towers, instruct the power utility to arrange the

phases in a centre point symmetrical configuration.

Step 4: Estimate the induced voltage on the pipeline, using Figures 13 and 14, if there is a simple

pipeline-powerline co-location arrangement, or conduct computer modeling to determine the induced

voltage profile along the length of the parallel section and to design mitigation measures.

Step 5: Using the calculated induced voltage values and soil resistivity data, measured at the proposed

pipe depth, calculate the expected AC current density from Equation 6a to determine the AC current

density based on the average phase current loading and the Vg' based on the peak current loading.

Mitigation is required if the steady-state Vg' is greater than 15 V at appurtenances based on the peak

load current and if iac is greater than 50 A/m2 based on the average phase current loading

Step 6: Install AC and DC coupons or corrosion rate probes at pipeline test stations and at locations of

electromagnetic discontinuities and at locations where the AC current density threshold is exceeded so

that actual AC and DC current densities or corrosion rates can be measured.

Step 7: Install DC decouplers across any isolating joint and at any bare steel casings in the piping system

within 10 km of the pipeline-powerline co-location, providing consideration is given to any detrimental

effects that the transferred voltage or current could have on the structure being coupled to the interfered

pipeline.

Step 8: Ensure that a minimum polarized potential of -850mVCSE is being met on the pipeline at test


Step 9: Where possible run an in-line inspection tool through the pipeline section that is exposed to the

AC interference before and after construction of the AC powerline, to assess and compare corrosion

anomalies.

Case D - A Lateral being Built from an Existing Pipeline that is Exposed to AC Interference

Step 1: Measure and record the pipe-to-ground AC voltage at the lateral location for a 24 hour period and

measure the soil resistivity at the tie-in location.

Step 2: Contact the electrical utility to determine the powerline fault current at the closest tower to the

tie-in and calculate the fault voltage at the tie-in. If this voltage would create a personnel shock hazard,

based on the calculated voltage tolerance from Equation 1, then touch potential mitigation is required at

the lateral take-off riser and at appurtenances along the lateral if the lateral is electrically continuous with

the co-located pipeline.


foregoing measurement period. Compare the reported powerline load current to the peak load current

and linearly extrapolate the measured Vg to obtain an estimate of the pipe-to-ground voltage (Vg') when

the powerline is operating at peak current. If Vg' is greater than 15 V then mitigation is required at the

tie-in and consideration must be given to providing mitigation facilities for a distance along the lateral.

Step 4: Calculate the AC current density at the tie-in using Equation 6a, based on a 1 cm2 holiday for the

calculated Vg' when the powerline is operating at the average phase current loading using measured soil

resistivity data at pipe depth. If the AC current density is greater than 50 A/m2 then mitigation of the

induced voltage is necessary at the tie-in and consideration must be given to providing mitigation

facilities for a distance along the lateral.


Step 5: If either of the foregoing conditions require mitigation, then computer modeling of the lateral

must be completed.

Step 6: If Vg' is greater than 15 V at peak load current then construction of the lateral must be done in

accordance with CSA-C 22.3 No. 6-13 Standard.

Step 7: If mitigation of induced AC is required on the lateral then AC and DC coupons or corrosion rate

probes should be installed at dead front test stations along the lateral for a 10 km distance.

Step 8: Install a DC decoupler across any isolating fitting(s) at the lateral take-off and at any isolating

fittings within 10 km of the take-off providing consideration is given to any detrimental effects that the

transferred voltage or current could have on the structure being coupled to the interfered pipeline.

Step 9: Maintain a minimum polarized potential of -850 mVCSE on the lateral piping within 10 km of the

tie-in.

Case E - An Extension to a Pipeline that is on or near an Existing AC Powerline ROW and that is

within 5 km of the Entrance or Departure Point between a Powerline and a Co-located Pipeline.

Step 1: Measure and record the pipe-to-ground AC voltage at the start of the extension location for a 24

hour period and also measure the soil resistivity at this location.

Step 2: Contact the electrical utility to determine the powerline fault current at the closest tower to the

tie-in and calculate the fault voltage at the tie-in. If this voltage would create a personnel shock hazard,

based on the calculated voltage tolerance from Equation 1, then touch potential mitigation is required at

above-grade pipeline appurtenances and at test stations for the next 5 km.


foregoing measurement period, the average operating current, and the peak load current. Compare the

reported powerline load current to the peak load current and linearly extrapolate the measured Vg to

obtain an estimate of the pipe-to-ground voltage (Vg') when the powerline is operating at peak current. If

Vg' is greater than 15 V at the tie-in, then mitigation at pipeline appurtenances for a distance of 5 km

form the tie-in is required.

Step 4: Calculate the AC current density at the tie-in using Equation 6a, based on a 1 cm2 holiday, using

the calculated Vg' when the powerline is operating at average current loading, and the soil resistivity at

pipe depth. If the AC current density is greater than 50 mA/cm2, then mitigation of the induced voltage is

necessary at the tie-in and along the extension for a distance of 5 km.

Step 5: If the AC current density is greater than 50 A/m2, computer modeling of the extension must be

completed.

Step 6: If Vg' is greater than 15 V, then construction of the extension for the next 5 km must be done in

accordance with CSA-C 22.3 No. 6 Standard.

Step 7: If mitigation of induced AC is required on the extension then AC and DC coupons or corrosion rate

probes should be installed at test stations along the extension for a 5 km distance.

Step 8: Install DC decoupler across any isolating fitting(s) at the extension tie-in and at any isolating

fittings within 5 km of the extension providing consideration is given to any detrimental effects that the

transferred voltage or current could have on the structure being coupled to the interfered pipeline.


Step 9: Install dead-front test stations on the extension for a distance of 5 km from the tie-in.

Step 10: Maintain a minimum polarized potential of -850 mVCSE on the extension piping within 5 km of

the extension.


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