Internal Corrosion & Protection of it in Oil and Gas Pipelines

The pipeline costs are a considerable part of the investment in subsea projects, and for long-distance, large-diameter pipelines, they can become prohibitively high if the corrosivity of the fluid necessitates the use of corrosion-resistant alloys instead of carbon steel. Better understanding and control of the corrosion of carbon steel can increase its application range and therefore have a large economic impact.

The presence of carbon dioxide (CO2), hydrogen sulphide (H2S) and free water can cause severe corrosion problems in oil and gas pipelines. Internal corrosion in wells and pipelines is influenced by temperature, CO2 and H2S content, water chemistry, flow velocity, oil or water wetting and composition and surface condition of the steel. A small change in one of these parameters can change the corrosion rate considerably, due to changes in the properties of the thin layer of corrosion products that accumulates on the steel surface.

When corrosion products are not deposited on the steel surface, very high corrosion rates of several millimetres per year can occur. The corrosion rate can be reduced substantially under conditions where iron carbonate (FeCO3) can precipitate on the steel surface and form a dense and protective corrosion product film. This occurs more easily at high temperature or high pH in the water phase. When H2S is present in addition to CO2, iron sulphide (FeS) films are formed rather than FeCO3, and protective films can be formed at lower temperature, since FeS precipitates much easier than FeCO3.

Localised corrosion with very high corrosion rates can occur when the corrosion product film does not give sufficient protection and this is the most feared type of corrosion attack in oil and gas pipelines. In order to control the corrosion in pipelines, it is important to understand the underlying corrosion mechanisms and be able to predict whether localised corrosion will be initiated and how it can be prevented.

Prediction of Internal Corrosion in Pipelines
For oil and gas pipelines several prediction models have been developed for CO2 corrosion. The models are correlated with different laboratory data and, in some cases, also with field data from oil companies. The models have very different approaches to accounting for oil wetting and the effect of protective corrosion films, which can give large differences in behaviour between the models. It is important to understand how the corrosion prediction models handle, particularly, the effects of oil wetting and protective corrosion films when the models are used for corrosion evaluation of wells and pipelines.

Reference: Rolf Nyborg, www.touchoilandgas.com