Abstract
Many approaches have been used for modeling Top of Line Corrosion (TLC). One common principle is that TLC is limited by the amount of iron that can be transported with the condensed water. This means that the TLC rate is proportional to the condensation rate and proportional to the solubility of iron in the condensing phase. Therefore, TLC rate modeling typically involves a combination of condensation rate calculations and chemical equilibrium calculations. The presence of organic acid will reduce the pH and increase the iron solubility in the condensing water. It is therefore important that the chemical equilibrium calculations also include the effect of organic acids. Condensation of pure water is well understood and calculation of condensation rates has been implemented in several multiphase flow software packages on the market.
Glycol injection is applied to many gas transport pipelines to avoid hydrate formation. Mono Ethylene Glycol (MEG) is commonly used for this purpose; typically about 80 wt.% MEG is injected at the well head and the aqueous phase at the end of the pipeline contains about 40 wt.% MEG. The effect of MEG on internal condensation in pipelines has been less investigated. When MEG is present it will reduce the water vapor pressure but at the same time a small amount of MEG will evaporate and be present in the gas phase. If the chemical calculations are based on condensing the gas phase components without resupply to maintain the chemical equilibrium (e.g. due to slow kinetics), the condensing phase will be almost pure water. If complete chemical equilibrium is assumed, the condensing phase will contain much more MEG, and in principle it will have almost the same MEG content as the aqueous phase at the bottom of line.
This paper discusses various TLC modeling approaches, in particular how the corrosion rates are affected by MEG and organic acids.
