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Internal Corrosion in Natural Gas Pipelines

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Corrosion is defined as the degradation of a material or its properties due to a reaction with the environment and is one of the most common pipeline integrity threats for operators. External corrosion may be visually inspected during excavation; however, due to accessibility, additional non-destructive examination (NDE) methods must be utilized to identify the presence and severity of internal corrosion.


Understanding the chemistry and electrical properties of how corrosion occurs aids in mitigating the presence of corrosion, specifically internal corrosion.

Product Number: 51323-19507-SG
Author: Christopher A. Walker
Publication Date: 2023
$20.00
$20.00
$20.00

Internal corrosion is a time-dependent integrity threat that occurs when contaminates are found in natural gas such as chlorides, carbon dioxide (CO2), hydrogen sulfide (H2S), and water or other contaminants. The identification, mitigation, and repair of this threat can be costly and time consuming for operators; however, if proper actions are not implemented to ensure pipeline integrity, internal corrosion may occur and potentially lead to pipeline failure. Identification of internal corrosion is typically determined through in-line inspection (ILI) technologies or internal corrosion direct assessment (ICDA), where ILI is not practical. Preventative measures such as product quality control, corrosion inhibitors, cleaning pigs, and internal coating systems can be employed to limit the impact of internal corrosion. Once internal corrosion has been identified, repair options should be considered to restore the integrity of the pipeline.


Internal corrosion in natural gas pipelines is more challenging to observe and mitigate than external corrosion due to accessibility. The intent of this document is to discuss how internal corrosion occurs, identifying locations of internal corrosion, mitigation techniques, and repair options.

Internal corrosion is a time-dependent integrity threat that occurs when contaminates are found in natural gas such as chlorides, carbon dioxide (CO2), hydrogen sulfide (H2S), and water or other contaminants. The identification, mitigation, and repair of this threat can be costly and time consuming for operators; however, if proper actions are not implemented to ensure pipeline integrity, internal corrosion may occur and potentially lead to pipeline failure. Identification of internal corrosion is typically determined through in-line inspection (ILI) technologies or internal corrosion direct assessment (ICDA), where ILI is not practical. Preventative measures such as product quality control, corrosion inhibitors, cleaning pigs, and internal coating systems can be employed to limit the impact of internal corrosion. Once internal corrosion has been identified, repair options should be considered to restore the integrity of the pipeline.


Internal corrosion in natural gas pipelines is more challenging to observe and mitigate than external corrosion due to accessibility. The intent of this document is to discuss how internal corrosion occurs, identifying locations of internal corrosion, mitigation techniques, and repair options.

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This study collected and analyzed field data to validate the probabilistic model developed previously for predicting internal corrosion threats resulting from condensed water from nominally dry natural gas.
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