In the last six years or so there has been a flurry of reports of AC corrosion on buried pipelines. Statistics are difficult to acquire, mainly because the link between AC and corrosion has not always been made. What we do know is that within the last 11 years more than 20 AC corrosion incidents have been reported in Europe with the probability that many others have gone unrecognised.

There is every likelihood the risks from AC corrosion will increase because of greater demand for electricity, with a consequent increase in the power and installation of overhead powerlines, and better coating quality on buried pipelines.

Electric shock

External corrosion on buried pipelines is caused by a current exchange between the soil and the pipe. In the case of AC corrosion the current magnitude and direction will be dependent upon the induced voltage. The induced voltage is, in its turn, due to a number of factors including the distance between the phase cables, the distance between the overhead powerlines and the pipe, the current flowing in the overhead power line and the isolation resistance of the pipeline coating.

As a rule of thumb, these characteristics are relevant for overhead lines carrying >110kV, when the distance between the overhead lines and the pipe is < 150m, and the pipe is at least 2,000m long.

Without going into detail of the method of induction it will be sufficient to say the AC is induced by the fluctuating magnetic field associated with the current flow in the overhead lines. The voltage induced is influenced by soil resistivity, pipeline coating, and pipeline wall thickness and diameter. Amongst other things the amount of current flow at a coating defect will depend on the size of the coating defect and the value of the induced voltage.

A little physics will see us through some of these points;

  • a current flow will always have a magnetic field associated with it. The strength of the field is directly proportional to the magnitude of the current,
  • voltage induced into the pipeline will be related directly to the magnetic field strength and the rate of change,
  • the corrosion is irreversible. If the pipeline is subjected to an AC interference and the conditions permit corrosion to occur during one half cycle the corrosion will not ‘reverse’ during the other half cycle, corrosion will, therefore, be cumulative each half cycle,
  • at the phase boundary (metal/soil interface) there is an electrolytic double layer caused by different levels of charge on the pipe and the soil. This is, in effect, a two-plate capacitor.
  • capacitance is measured in farads and has a simple relationship with charge and voltage: C = q/V farads, where q is the charge in coulombs and V is the potential difference in volts between the soil and the pipe. The capacitance depends on the thickness, area and composition of the dielectric – in this case the coating. This capacitate effect is significant because it affects the phase angle of the induced current.
  • Corrosion occurs on buried pipelines where the current leaves the pipe. This usually occurs at an unintentional coating defect (holiday). For a circular coating defect with a diameter (d) the current density (J) may be estimated from the expression:

    J = 8(E-EN)/((pi * d * p) + (8 * rp))

    where E = potential or AC voltage to remote earth

    EN = natural potential

    r = soil resistivity

    rp = polarization resistivity

    Disregarding the polarization resistivity, the AC current density is 225A/m2 and the current density of the anodic (corrosive) halfwave is 125A/m2 when a voltage of 20v ac and a soil resistivity of 20 ohms m exists with a coating defect (d) of 1 cm. From this example it is clear the AC current density is several orders of magnitude greater than the normal protective current density for bare steel.

    Laboratory tests have shown the effect of the effective capacitance, which is influenced by the coating, is to drain some of the AC corrosion current. This drain can be represented by the phase angle (F) and can be developed to show that two components of current flow through the pipe/soil interface. The tests have shown the phase angle is about 20° and that more than 60% of the alternating current flows across the ohmic resistance of the interface.

    In simple terms this means induced AC voltage can cause corrosion on a cathodically protected pipe, and the greater the induced voltage the greater the risk. It also means high-quality coatings increase the risk of AC corrosion at coating defects. It should also be noted that the corrosion mechanism is not yet fully understood, and measurement, quantification and remediation can all be affected.

    If it happens, corrosion will occur at coating defects on an otherwise well coated pipeline. The dilemma is how to establish whether AC corrosion is likely to exist, or if corrosion has been found whether or not it was caused by AC Visual inspection of existing AC corrosion will reveal crater-like local corrosion with characteristic bulges in the coating.

    There are no set rules for protection criteria for the assessment of AC corrosion risk. As a guideline the following criteria can be used;

  • the ratio between the AC and DC current densities: >0.5 low risk, <0.5 greater risk,
  • when AC current density is > 30A/m2,
  • pipe-to-soil potential (off) is more positive than -0.950V (with respect to a copper/copper sulphate reference electrode).

    If any two of the above criteria are met there is a high probability that AC corrosion can take place. In simple terms there are three ways to stop the risk of corrosion from AC Remove or stop the AC, make sure there are no coating defects on the pipeline, make sure the current density at any coating defects will be less than 30A/m2 and the polarized pipe-to-soil potential is not more positive than -0.950V. In many cases these measures are easier to implement in theory than practice, nevertheless here are some useful guidelines.

    At appropriate locations, install devices to remove the AC from the pipeline without affecting the integrity of any applied or proposed cathodic protection. There are a number of ways to do this, but the best way is to use solid-state threshold conducting devices such as the isolating surge protector (ISP) or polarization cell replacement (PCR). One well established manufacturer of these devices is DEI of Stoughton, Wisconsin. The company produces an excellent free booklet which describes the problems of induced AC and the function/specification of their mitigation devices.

    It is unlikely it will ever be possible to ensure there will be no coating defects over the lifetime of a buried pipeline. The best way to locate coating defects is probably by using DC voltage gradient (DCVG), a proven technique, which needs to be undertaken by competent personnel. DCVG is an excellent tool which permits accurate location of coating defects under almost all circumstances, even in the presence of stray DC current, but it may also be the most misused. Experience shows it is vital to ensure the survey is properly specified, and the operators properly trained and qualified. In the past this has been cowboy territory.

    When addressing current density and pipe-to-soil potentials, if coating defects cannot be repaired for any reason, coupons should be installed so accurate measurements of AC and DC current density can be made. This is another specialist job, with serious consequences if incorrectly undertaken, which should only be entrusted to competent personnel.

    There is not much help available from the existing British Standard for cathodic protection but there are a number of useful papers and guidelines from other sources.

    Words of advice

    By far the most useful guideline is published by Ceocor and is entitled AC Corrosion on Cathodically Protected Pipelines: Guidelines for Assessment and Mitigation Measures. Ceocor is a European group which deals with the corrosion of pipelines. It produces a wide range of technical guidelines which incorporate the experience and knowledge of many of Europe’s pipeline operators and corrosion specialists.


    the rot

    On an existing pipeline the risk from AC corrosion can be assessed by:

    • a study of the pipeline route to establish whether the route is parallel

      to overhead power cables,

    • soil resistivity measurements at suitable locations and intervals,
    • measurement of AC potentials,
    • installation of coupons at key locations,
    • measurement / calculation of AC and DC current densities at coupons,
    • location of coating defetcs by above ground surveys conducted by competent

      personnel – poorly specified and poorly conducted surveys are probably

      the single greatest source of false judgements on external corrosion

      risks on buried pipelines.

    Further detail of measurements and observations are contained in the

    CEOCOR handbook. Armed with this information judgements can be made to

    determine what mitigation steps, if any, are necessary.

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