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AC induced corrosion on onshore pipelines - Part 2

By Roger Ellis Shell UK, Stanlow, Pipeline Manager.

Discussion on the AC effects.
The intelligent pig survey in 1999, confirmed that the corrosion was ongoing in Longton. pH measurements were carried out on the exposed pipe at the sites of the corrosion pits in Autumn of 1999. Of the ten tests carried out, three were neutral and seven were very alkaline at 11-12. This indicates the cathodic reaction 2H2O+O2+e->40H- was occurring and that the cathodic protection system was working. The high pH also indicates that SRB activity was not the cause of the corrosion as SRB's require a near neutral environment to proliferate.

The X-Ray diffraction analysis carried out on the corrosion deposits did not determine the presence of iron sulphides, which would indicate the corrosion, is not being driven microbially.

The AC potentials measured over a period of 7 days at the defect areas were in the range 4 - 18V for most of the time and varied considerably over the 24 hour clock.

This is below the 15V criteria set by NACE above which mitigation measures are considered necessary. The level of 15V however, is set for safety reasons and has nothing to do with corrosion.

The ac current densities measured in the coupons installed in the defect areas at 40 - 160Am -2 are well above the presently accepted threshold at which ac corrosion is likely to occur.

The most probable cause of the corrosion was concluded to be AC induced.

Causes of AC corrosion
It has been demonstrated in the 1960's that under laboratory conditions ac can cause corrosion of cathodically protected steel.

It was not recognized until comparatively recently that ac corrosion of cathodically protected pipelines can and does occur. Most of the detailed research work on this subject originated in Germany where the problem was recognised in the late 1980's early 1990's. AC corrosion occurs at small coating holidays on well coated pipelines when the pipeline suffers from induced ac voltages.

Pipelines which parallel overhead power can have ac voltage induced on them. The ac current flow in the power line conductors produce an alternating magnetic field. An ac potential can be induced in an adjacent structure within that magnetic field and a current flow may occur in that structure. The magnitude of this induced potential depends on many factors

  • The configuration of the power line and pipeline e.g. length of parallelism and relative changes in direction.
  • The current load on the powerline.
  • The balance between the phases.
  • The dielectric strength of the pipeline coating.
  • The soil resistivity.

In general terms the greater the power load on the overhead line, the longer the parallelism, the closer the proximity, the better the coating quality on the pipeline, the more likely it is that significant ac potentials will be induced on the pipeline.

For many years, the general view on the corrosion industry has been that alternating current causes 1 % of the corrosion of the equivalent direct current.

The results of a research project in Germany has shown that:

  • Corrosion is unlikely at ac densities < 20 A/m2.
  • Corrosion rates > 0. 1 mm/yr can occur at ac densities > 100 A/m2.

For ac densities > 20 A/m2 the protective potential criteria usually used for cathodic protection does not apply.

Ignoring the polarisation resistivities, the ac density at a coating defect with a diameter d is given by the following equation:
vI= 8 x V/prd     ---(1)
Where V is the ac voltage on the pipeline,
pis the soil resistivity
I is the effective ac current density.

Tests on coupons have shown that the corrosion rate reaches a maximum for coating holidays of 1 cm2. Although the current densities would be greater for smaller defects, below a certain size it is considered that the corrosion product blocks the passage of current.

The research has also shown that the soil properties also have an effect on the rate of ac corrosion. Anaerobic soil or soils containing carbonate and bicarbonate ions tend to have higher ac corrosion rates whilst neutral media containing significant amounts of salts are considerably less aggressive.

The level of ac potential on the pipeline does not reflect whether corrosion is occurring, nor does it reflect the rate of corrosion if it is occurring. The 15V level of ac potential set in NACE and Canadian Standards above which mitigation action is required, is set at this level for safety, and has no bearing on the corrosion aspects.

It is reasonable to assume that if the soil resistivity is low enough, high ac densities can be achieved at low ac potentials.

If equation 1. is used then it is apparent that a 100 A/M2 current density can be produced at a 1 cm2 holiday in 1,000 ohm cm soil with an ac potential as low as 4.4V. The frequency of the ac is reported to have little effect on the corrosion rate unless very low frequencies are used.

Some research suggests an incubation period of 30 to 120 days for current densities of 100 and 50 A/M2 respectively, after which corrosion rates increased. Other studies have shown that the corrosion rate decreases with time regardless of the ac density.

The actual mechanism of ac corrosion is not fully understood. The ac potentials may have an effect on the dc polarisation of the pipe. Alternative theories centre on the irreversible nature of the corrosion reaction: 2Fe > Fe2+ + 2e-; which will occur during the anodic half cycle.

The characteristics of ac corrosion on pipelines can be summarised as follows:

  • The corrosion causes a hemispherical pit
  • High pH conditions may be found in the pit
  • A hard mound of corrosion product is produced above the pit
  • The area may be well protected by the CP system.

Cases of AC corrosion have been identified in a number of European Countries, Germany, Switzerland, France and Belgium and in North America in Canada. Shell were the first company to identify the problem in the UK.

Prediction of AC corrosion
The mechanisms of AC corrosion are not fully understood but prediction and means of mitigation are. In the section of NWeP from Carlisle to Garstang the running of an intelligent pig had not proved to be technically feasible. The intelligent pig identifies the consequences of corrosion and it was recognised that the threats could be identified.

To experience AC corrosion a number of factors need to be present and these can be determined.

  • A pipeline with a coating that has a high dielectric strength, i.e. a good insulator such as FBE or 3 layer polyethylene.
  • A means of inducing AC onto the pipeline and relative changes in direction of pipeline and power lines. i.e. overhead power lines.
  • A soil of low resistivity providing a good route to earth for the current.
  • A high current density measured through a small coupon ideally 1 cm2.
  • A coating defect and a means of determining it.

By undertaking analysis and measurement of the pipeline route sections were determined in which AC induced corrosion would be most likely to occur. In these sections the direct current voltage gradient (DCVG) technique was used to determine areas of coating breakdown. Field digs were undertaken to verify the pipeline condition. No serious metal loss features were found though indications of the early stages of AC corrosion were evident in a number of sites. The majority of the pipeline length was not considered to be susceptible to the AC effect.

Technological advances allowed the pipeline to be pigged in the summer of 2001. The detailed results and field verification are currently under review. The initial findings however have concluded that metal loss features have only been identified in areas where AC would have been predicted and where mitigation is already planned or in place. Detailed correlation of the DCVG work and intelligent pig work continues.

Mitigation of AC corrosion
Research suggests that the rate of ac corrosion decreases with time. However, this cannot be relied upon.

The work carried out so far at the defect locations has included the removal of the existing coating and the application of a new coating based on a recommended repair system.

This will prevent further corrosion at the defect locations provided the coating remains intact. However despite the 100% holiday detection prior to backfill, it is considered that coating holidays may be still be present or could occur in the future. The pipeline could therefore experience ac corrosion in the future should current density levels be high. Continuous monitoring is necessary.

Whilst the mechanism of ac corrosion is not fully understood the mitigation measures are. The pipeline needs to be earthed using a system compatible with the cathodic protection system such that the ac current densities are reduced below 20 A/m2. The risk of ac corrosion occurring should be reduced to a tolerable level.

Mitigation Measures have been implemented by the installation of earthing systems. This earthing comprises 150m length of zinc ribbon installed parallel to the pipe 2.5m from the pipe centre line.

Calculations show that the installation of a 150m length of ribbon should reduce current density levels of 35-500 A/m2 to between 2-32 A/m2. These calculations do however ignore the effect the earthing will have on the ac potential. The earthing reduces the ac potential and so measured current densities are much lower, well below the 20A/m2 threshold criteria above which ac corrosion is considered too occur. A target ceiling of 15A/m2 was used for the design basis for the mitigation systems. Monitoring is being and will continue to be carried out over an extended period using data loggers to verify on going levels of current density. Where possible 1cm2 coupons have been installed to allow ongoing monitoring.

AC current density monitoring will form an ongoing part of the pipeline integrity management system.