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An example of corrosion rate prediction in a sub-sea gas condensate pipeline is shown in Figure 2. Here, two of the most commonly used corrosion prediction models were combined with an oil and gas threephase fluid-flow model in order to be able to calculate corrosion rate profiles along a pipeline. This can help to identify locations where variation in flow regime, flow velocity and water accumulation may increase the risk for corrosion damage. For this pipeline the temperature was 90°C at the inlet and 20°C at the outlet, and the decrease in predicted corrosion rates towards the end of the pipeline is mainly a result of the decreasing temperature. The lower corrosion rates close to the pipeline inlet are due to the effect of protective corrosion films at high temperature, which is predicted differently by the two corrosion models used. The peaks in predicted corrosion rates result from variation in flow velocity due to variations in elevation profile.

Figure 2: Predicted Corrosion Rate in a Subsea Pipeline

Use of Corrosion In hibitors

Corrosion control of carbon steel pipelines is often managed by the use of corrosion inhibitors. These are organic molecules that are added in parts per million (ppm) levels and form surface layers that reduce the corrosion reaction on the steel. Different inhibitors are used depending on the actual conditions in each pipeline. selection and qualification of inhibitors in the laboratory prior to implementation in the field is essential and, most often, dedicated laboratory experiments will have to be performed with candidate inhibitors for each field or pipeline.

A number of factors may influence inhibition in multiphase pipelines. Factors such as temperature, water-oil partitioning, water chemistry and flow conditions have been widely studied. Less attention has been paid to factors such as the composition and microstructure of the steel, the type of corrosion products formed on the steel surfaces, inhibitor adsorption on suspended particles in the produced water and inhibitor accumulation on gas bubbles, oil/water droplets and emulsions. It has been difficult to account for the effects of multiphase flow on corrosion inhibition in laboratory screening tests. Laboratory experiments at IFE have shown that steel microstructure, corrosion products on the steel surface and presence of emulsions can affect inhibitor perform-ance strongly. New test methods and equipment are being developed in order to account for the effect of multiphase flow and steel surface conditions.

The pH Stabilisation Technique

The pH stabilisation technique can be used for corrosion control in wet gas pipelines when no or very little formation water is transported in the pipeline. This technique is based on precipitation of protective corrosion product films on the steel surface by adding pH-stabilising agents to increase the pH value of the water phase in the pipeline. The pH-stabilisation technique has been taken into use in several wet gas condensate pipelines and is currently being considered for several new fields. This technique is very well suited for use in pipelines where glycol is used as hydrate preventer, as the pH stabiliser will be regenerated together with the glycol. This means that there is very little need for replenishment of the pH stabiliser.

Experiments for qualification of the pH stabilisation technique at the IFE have shown that protective films form in a short time at temperatures between 40°C and 100°C, reducing the corrosion rate to less than 0.1mm/y. At lower temperatures around 20°C, the iron carbonate precipitation is very slow and it may take several months to obtain protective corrosion films. Since the initial corrosion rate is low at 20°C and with a high pH value, it is acceptable to wait a few months for a protective corrosion film to form.

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