Over the past decades, several corrosion prediction models have been developed for Upstream Oil and Gas process conditions. These models provide the unmitigated corrosion rates in typical sweet or sour conditions. However, the practice of field operations is typically based on the mitigated corrosion rate. Therefore, the predicted unmitigated corrosion rates cannot directly be used to understand real-life situation unless the effect of mitigation is effectively considered. Currently, the mitigated corrosion rate is typically quantified via a very simplified method (e.g. corrosion inhibitor availability).

Corrosion prediction is designed to look forward and, ideally, should also be part of corrosion and asset integrity management. For this purpose, a robust analysis of the mitigation practices and methods is essential. This paper provides an overview of aspects to be considered when predicting mitigated corrosion rate for the case of continuous corrosion inhibitor (CI) injection as the mitigation barrier. It is proposed to use a combination of models to calculate the mitigated corrosion rate in a practical and reliable way. It is recognized that partitioning of the CI among different phases is a key aspect in relation to the field application of inhibitors. Therefore, guidance is provided to incorporate this as part of the corrosion mitigation and its prediction.


Due to the potential impact of corrosion in oil and gas production, the phenomena of CO2 corrosionH2S corrosion and organic acid corrosion are heavily studied. For materials selection as well as asset integrity and corrosion management, the threat of corrosion needs to be identified and evaluated, before mitigation strategies can be defined[1,2]. For this purpose, a wide range of corrosion prediction models have been developed [3-30].

The following type of models can be distinguished:

- The earliest models, typically empirical and semi-empirical models for CO2 corrosion[3-7]

- Mechanistic models for corrosion tests-methods[9] and later to real process flowing conditions[10,11] and electrochemical models[12].

- Inclusion of a wider range of relevant corrosion mechanisms[8,14,19,20] first inclusion of organic acids[8] and more recently H2S corrosion[15-17]

- Including specific phenomena like top of line corrosion[24-30] and oil-wetting[31,32].

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