An increasing number of offshore developments are based on transporting unprocessed or partially processed multiphase well streams from satellite wells to main platforms, existing installations on neighbouring fields or onshore processing facilities. Corrosion, scale formation and salt accumulation represent increasing challenges for the operation of subsea multiphase pipelines. Corrosion-resistant alloys such as 13% Cr steel and duplex stainless steel are often used downhole and, recently, also for short flowlines. For long-distance, large-diameter pipelines, carbon steel is the only economically feasible alternative and corrosion has to be controlled by chemical additives to the transported fluids.
The presence of carbon dioxide (CO²), hydrogensulphide (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 drastically 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 (mm/y) can occur. This ‘worst case’ corrosion is the easiest type to study and reproduce in the laboratory. When CO² dominates the corrosivity, the corrosion rate can be reduced substantially under conditions where iron carbonate 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 value in the water phase. When H²S is present in addition to CO², iron sulphide films are formed rather than iron carbonate, and protective films can be formed at lower temperature, since iron sulphide precipitates much easier than iron carbonate.
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.
Prediction of Pipeline Corrosion
Several prediction models have been developed for CO² corrosion of oil and gas pipelines. The models have very different approaches in accounting for oil wetting and the effect of protective corrosion films, and this can produce significant differences in behaviour between the models. Some of the models have a very strong effect of oil wetting for certain flow conditions, while others do not consider oil wetting effects at all. Some models include strong effects of protective iron carbonate films, especially at high pH value or high temperature. The models are correlated to different laboratory data and, in some cases, also to field data from the individual company. It is important to understand how the corrosion prediction models handle especially the effects of oil wetting and protective corrosion films when the models are used for corrosion evaluation of wells and pipelines. Most of the models cannot be used in situations where H²S or organic acids dominate the corrosion process.
An important aspect in corrosion evaluation of oil and gas wells and pipelines is to obtain a realistic estimate of the actual pH value in the water phase. When formation water is produced it is important to obtain good water analysis data, especially with respect to bicarbonate and organic acids. The actual pH value must be calculated from the CO² and H²S partial pressure, temperature, bicarbonate content in the water and ionic strength. When only condensed water is present the dissolved corrosion products may increase the pH value significantly.
Figure 1: Example of Model Runs for an Oil Well
In a joint industry project at the Institute for Energy Technology (IFE), the different CO² corrosion prediction models were evaluated and compared with actual field data gathered from the participating oil companies. Figure 1 shows an example of measured and predicted corrosion rates for an oil well where the corrosion rate was relatively low except at a depth of 90 metres where a failure occurred. Model A takes much account for effects of oil wetting and protective corrosion films. This model predicts the low corrosion rates downhole quite well, but it is unable to predict the failure close to the wellhead. Model B takes little account for effects of oil wetting and protective corrosion films. This model is able to predict the high corrosion rate leading to the failure, but it does not predict the low corrosion rates further down in the well. Model C takes more account for protective corrosion films at high temperature and predicts highest corrosion rate close to the wellhead where the failure occurred. The models behaved differently for other field cases, and none of them are able to provide reliable predictions for all cases.
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