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.
A major application for the pH-stabilisation technique has been the Troll pipelines. The Troll field, originally developed by Shell and operated by Statoil, is a large gas-condensate field in the Norwegian sector of the North Sea. The field commenced operation in 1996. The water depth is about 300 metres and, in order to minimise the size of the offshore production facilities, it was decided to perform a simple processing with only removal of free water offshore. This solution meant that wet gas with CO² had to be transported in two 36-inch pipelines over a distance of 65km from the platform to shore. The Troll field is a ‘sweet’ gasfield with a CO² content of 0.3%. The pipeline inlet and outlet temperature is 50ºC and 5ºC, respectively. Monoethylene glycol is injected at the pipeline inlet in order to control hydrate formation. It was originally decided to use glycol as the only additive with a rather large corrosion allowance, as the low CO² pressure gave a low corrosivity in the system.
The target was to reach a corrosion rate of less than 0.2mm/y. The amount of glycol had to be increased above what was needed for hydrate control in order to reach this corrosion rate. During the first year of production, precipitation of corrosion products from the pipeline started to present problems in the onshore glycol regeneration units. The dissolved iron from the pipeline formed scales on the surfaces in the heat exchangers and boilers and some precipitated as particles in the bulk phase. The estimated amount of corrosion products was 20 tons in the first year of operation. This was not regarded as a corrosion problem in the pipelines, but as a process problem in the onshore processing plant. In order to reduce the amount of dissolved corrosion products in the pipeline and avoid a costly rebuilding of the gas processing plant, it was decided to reduce the corrosivity further by applying the pH-stabilisation technique.
The pH value at the outlet of the pipeline prior to pH stabilisation was close to six. Based on results from laboratory testing and calculations at the IFE, it was decided to increase the pH value in the pipeline to 7.4. This was done by injecting a sodium-hydroxide solution into the lean glycol tank that is operated at ambient pressure. The concentration of dissolved iron, which has the potential to form scale in the process equipment was reduced from around 100ppm to less than 5ppm after six weeks, as shown in Figure 3. This corresponds to a corrosion rate far below 0.1mm/y. Very little precipitation takes place in the process system today and the system has been operated with success since the treatment was carried out in 1997.
Figure 3:Iron Content After pH Stabilisation of the Troll Pipelines
When glycol is used to prevent hydrate formation, it is convenient to transport and inject the pH stabiliser together with the glycol. The pH stabiliser is regenerated together with the glycol and the consumption is therefore very low. However, under some conditions with high CO² partial pressure, the demand for pH stabiliser can be so high that it is not possible to dissolve enough pH stabiliser in the glycol. The pH-stabilisation technique cannot be used for pipelines carrying large quantities of formation water due to formation of carbonate scale at the elevated pH value. Replenishment of pH stabiliser may become costly for systems where even small amounts of formation water are carried over from the offshore processing. When the glycol is regenerated, the salts will be accumulated in the regenerated glycol. When salts are removed, the pH stabiliser will usually also be removed, and even a small formation water carry-over may then require considerable replenishment of the pH stabiliser.
The pH-stabilisation technique has been used mostly for wet gas pipelines without any H²S in the gas, but is now being taken into use also for pipelines with considerable amounts of H²S in addition to CO². Here, the corrosion product depositing on the surface will be iron sulphide instead of iron carbonate. These sulphide films have different protective properties than the iron carbonate films forming in sweet systems. Localised corrosion in the form of pitting is the critical factor in H²S-containing systems. The application limits for the pH-stabilisation technique in wet gas pipelines containing high amounts of H²S and CO² are being studied in an on-going joint industry project at the IFE.
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