Top-of-line corrosion (TLC) in carbon steel pipelines carrying moist gas is caused by the condensation of water in the presence of CO2 and is difficult and expensive to mitigate. Modeling TLC allows operators to plan mitigation strategies that may reduce costs and production delays. The TLC rate is proportional to the rate of condensation and is affected by the solubility of the corrosion products. When Mono-Ethylene Glycol (MEG) is present, it evaporates and condenses with the water. Depending on mass transport rates, the gas phase may get depleted of MEG. Equilibrium calculations may not necessarily predict the condensation rate and the composition of the condensing aqueous phase correctly.
In this work, in-situ refractometry was used to study the co-condensation of water and MEG. A water/MEG mixture was heated to generate a vapor-saturated gas phase which was transported by a gas stream through heated tubes over the window of a refractometer with precisely controlled temperature. The composition of the condensed liquid was monitored over time. By varying the temperature of the condensation surface, valuable data were generated, providing insight into how the composition of the co-condensed phase develops and how it relates to thermodynamic equilibrium and mass transfer.
Top-of-Line Corrosion (TLC) is a practical but costly problem for unprocessed natural gas transport. Utilizing multiphase pipelines instead of processing the well-fluids offshore has required massive modeling development to control hydrate formation and corrosion.1 At the inlet of the pipelines, the gas, and other well fluids have much higher temperatures than the pipelines’ outside environment, e.g., cold ocean water or river water. Therefore, the gas cools along the way to the processing facility. This temperature change also decreases the saturation levels of vapor in the gas, leading to condensation when the vapor concentrations (or vapor pressure) exceed the gas's saturation limit. The water vapor carried by the gas (often referred to as moisture) condenses due to the cooling of the pipeline wall and forms a liquid phase allowing acid species from the gas (e.g., CO2, organic acids) to dissolve. These reactions produce a corrosive environment on the inner surface of carbon steel pipelines.1 In a pipeline operating with a stratified flow regime, a gas stream separates a bottom-of-line (BOL) liquid stream (consisting of, e.g., formation water, injected fluids, and a mix of different condensed species) and the top-of-line (TOL) liquid phase. The TOL liquid has the form of droplets or film hanging from the steel surface.2 While corrosion caused by the BOL aqueous phase can typically be mitigated by chemical means (inhibition, pH stabilization), reducing TLC is more challenging. In this context, models that predict TLC rate are very important tools that potentially reduce the use of expensive corrosion-resistant alloys (CRAs).
