In a Nutshell:

Corrosion does not happen overnight or by chance. It is the most common time-dependent threat for pipelines. Pipeline operators worldwide spend billions of dollars mitigating the effects of corrosion. Managing this threat is critical in ensuring the future integrity of a pipeline. For effective corrosion management, the cause of the corrosion must be known, and reliable estimates of the corrosion growth rate are a critical input. In this article, our expert Nancy Espinoza outlines the importance of accurate corrosion diagnosis using in-line inspection (ILI) data as well as additional information and surveys available.

Corrosion is one of the most common threats in hydrocarbon pipelines. Identifying this major threat is possible due to the complete range of tools designed for this purpose and the subsequent improvement of the available technology over the years.

Once corrosion has been identified in a pipeline, it is critical to apply proper assessment methods to determine its acceptability, followed by estimating corrosion growth rates that will result in approximate repair dates for anomalies that could compromise the safe operation of the pipeline. However, the required efforts to control corrosion do not end there. It is important to understand not only whether corrosion is currently a threat for the pipeline but how that corrosion came to occur in the first place and how to prevent it from becoming a critical threat.


It is no secret that corrosion does not happen simply by chance. There is always one or multiple factors that contribute to the origin of corrosion and that will potentially allow corrosion to continue growing.

Inspecting with an appropriate ILI technology will give an operator a great insight into what is happening inside the pipeline: Is internal or external corrosion present on the pipeline? If so, where it is concentrated, and what are its dimensions? But, most of the time, ILI data itself will not necessarily be enough to determine potential origins of corrosion. More information and other surveys or records are necessary to identify the cause of the problem and, consequently, the proper way to treat it.

Some examples of the information required for internal and external corrosion diagnoses are:

Information required for internal and external corrosion diagnosis

All the available information can then be processed and analyzed together with ILI data in order to find the causes or mechanism of the corrosion.


When the causes of the corrosion are clear, is possible to better understand the threat, how the lack of mitigation measures or the low efficiency of the measures currently applied are propitiating corrosion and subsequently identify suitable ways to mitigate it. The purpose of mitigation measures will be to define a corrosion management strategy that can prevent the existing anomalies from growing until critical dimensions and prevent new corrosion from initiating.

Furthermore, with a clear idea of the corrosion mechanism present in the pipeline, it becomes easier to recognize the appropriate model to estimate more accurate corrosion growth rates; for example, segmentation criteria could be applied to divide a pipeline into sections with the same corrosion cause or mechanism where corrosion will potentially be growing at a similar rate. This will permit to refine estimated repair dates, define a suitable re-inspection interval and therefore support better future integrity decisions.

Here are a few cases to understand corrosion diagnosis.

Case A

Case A

  • Crude oil pipeline with onshore and offshore sections.
  • All the external corrosion anomalies were reported in the onshore section.
  • Further review of the fittings reported by the ILI and satellite imagery (using GPS data obtained from ILI inspection) revealed that most of the onshore section was actually unburied pipelined exposed to a saline environment and held by metallic supports.
  • Therefore, even if the cathodic protection installed for the onshore section was operating within acceptable parameters, the protection will not cover unburied pipeline. The saline environment together with damaged external coating and the direct contact of the pipeline with metallic supports were determined as the potential causes of the external corrosion reported.
  • Several actions were recommended to mitigate corrosion, such as repair any damaged coating in the unburied sections of the pipeline and rearrange the metallic support to avoid direct contact between them and the pipeline.

Case B

Case B

  • Crude oil pipeline with considerable internal corrosion reported mainly in the bottom of the line (around 06:00 position).
  • Information about the pipeline revealed certain water content reported in the product. Moreover, the product is transported in batches with periods of weeks without flow and there was no internal cleaning program in place nor use of inhibitors.
  • The internal corrosion was determined to be caused by the water present in the product that will accumulate at the bottom of the pipeline and stagnate in this position during the days the pipeline remains without flow hence causing internal corrosion.
  • Proposed mitigation measures included the use of an appropriate inhibitor and periodical internal cleanings to remove the stagnant water that is allowing the corrosion to occur.

Case C

Case C

  • Natural gas onshore pipeline with over 40 years in service.
  • Only a group of shallow internal corrosion reported.
  • A detailed review of the elevation profile of the pipeline and satellite imagery revealed the corrosion was concentrated in one spool at a river crossing with a low elevation point.
  • A detailed comparison between the most recent and a previous inspection available demonstrated most of the anomalies were previously reported with similar depths.
  • Internal corrosion was determine to be pre-service, likely originated from water remaining from pressure test before the commissioning of the pipeline and therefore growth from these anomalies was not expected.
  • No mitigation activities required.

As in every one of the examples showed, ILI data was essential for identifying corrosion and starting to determine the causes, but the additional information gathered made it possible to draw specific conclusions and make subsequent recommendations. Both of these were as detailed and precise as the existing information would allow.


Of course, every pipeline is different, and many factors may contribute to the presence of corrosion, including environment, operational conditions, type of product and mitigation measures in place, among many others. Nevertheless, the key is having enough reliable information available to achieve an accurate diagnosis.

Therefore, in order for the corrosion diagnosis to be successful, any of the available pipeline data can make a difference, including any surveys performed in previous years, changes in operation conditions, repair/failure history, etc. Even what might appear to be a less important piece of information might help when diagnosing corrosion.

Going back to the examples shown, identifying that the onshore section of the pipeline had unburied sections in Case A was key to determining the cause of corrosion. Without this discovery, it could have been assumed that the cathodic protection system was potentially being ineffective when in reality its effectiveness is irrelevant for the unburied sections of the pipeline. Meanwhile, for Case B, the water content and operation conditions allowed for a more acute way to determine the origins of internal corrosion. And as for Case C, the previous inspection became the key piece in confirming the reported corrosion in the river crossing was not new corrosion and therefore remained inactive.


Once mitigation measures have been implemented, every part of the process should be properly documented. Every record and piece of data will be useful in determining the effectiveness of the implemented measures, making adjustments as needed or trying a different corrosion management strategy, thus making appropriate integrity management decisions.

In addition, when a new inspection is performed, a set of new questions will appear: Is corrosion still happening in the same locations? Is it new corrosion, or is it corrosion found in a previous inspection? Have the previous anomalies grown since the last time the pipeline was inspected?

In this stage, for example, it can be reviewed whether the repairs performed to the coating in Case A were enough to protect the pipeline from the aggressive environment and whether the type and dose of inhibitor used in Case B in the past few years have proven to be adequate for corrosion mitigation.

If the answer to these questions is negative, then a change in strategy will be needed and further information required, together with additional analysis and consultancy to define a best corrosion management strategy for the pipeline. Every new ILI inspection, survey and/or maintenance activity performed on the pipeline will provide a new layer of information, thereby creating a continuous cycle of questions and answers in the search for the most suitable corrosion mitigation strategy.