A Glycol/Water Co-Condensation Model to Investigate the Influence of Monoethylene Glycol on Top-of-the-Line Corrosion Shaoqiang Guo,* , ** Fernando Farelas,* and Marc Singer ‡, * ABSTRACT A mechanistic model was developed to predict the co- condensation of water and monoethylene glycol (MEG) at the top of a wet gas pipeline. The dropwise condensation process of water and MEG in the presence of noncondensing gas (CO 2 ) is modeled based on a set of equations that describe the simultaneous heat and mass transfer to the condensed droplets. The model can predict the MEG concentration in the con- densing phase, and the condensation rate of water and MEG. The accuracy of the model predictions was evaluated by comparison with flow loop experimental data. The results showed a decrease in condensation rate and increase of MEG content in the condensing phase with the increase of MEG content at the bottom of line. However, this effect is not significant unless the MEG content in the bottom liquid phase is higher than 70 wt%. Long-term corrosion experimental results showed that the presence of 50 wt% and 70 wt% MEG at the bottom liquid phase has a minimal effect on the top-of-the-line corrosion (TLC) rate, while the presence of 90 wt% MEG decreases the TLC rate significantly due to a sharp change of both condensation rate and the MEG content in the condensing phase. KEY WORDS: carbon dioxide, condensation, mechanistic model, monoethylene glycol, top-of-the-line corrosion INTRODUCTION For economic reasons and operational flexibility, unprocessed wet gas is often directly transported in subsea pipelines to onshore processing plants for dehydration, rather than being dried on offshore plat- forms. During the wet gas transportation, the water vapor in the hot gas stream will condense on the internal pipe wall due to the cooler outside environment. The dissolution of corrosive gases such as carbon dioxide (CO 2 ) and hydrogen sulfide (H 2 S) in the condensed water can cause severe corrosion problems on the pipe wall. Top-of-the-line corrosion (TLC) can be a more serious concern than the bottom-of-the-line corrosion in oil and gas industry because: first, continuous condensation of water vapor constantly dilutes the dissolved iron ion in the condensed water droplets and challenges the formation of the protective corrosion product layer such as FeCO 3 in CO 2 corrosion envi- ronment; second, traditional corrosion inhibitors which are injected into the liquid phase at the bottom of line are often nonvolatile and cannot reach the condensed water at the top of the line. So far, most research has been focused on vari- ous parameters influencing TLC such as condensation rate, temperature, flow velocity, CO 2 and H 2 S partial pressures, and acetic acid concentration, as well as amines. 1-8 However, results on the effect of mono- ethylene glycol (MEG) on TLC have been less publicized. In fact, large amounts of MEG are often injected in subsea wet gas pipelines as a hydrate inhibitor. The subsea wet gas pipelines with its typical operational pressure have a potential risk of gas hydrate formation Submitted for publication: November 15, 2016. Revised and accepted: January 25, 2017. Preprint available online: January 26, 2017, http://dx.doi.org/10.5006/2335. ‡ Corresponding author. E-mail: singer@ohio.edu. * Institute for Corrosion and Multiphase Technology, Ohio University, 342 W. State St., Athens, OH 45701. ** Corrosion and Protection Center, Institute for Advanced Materials and Technology, University of Science and Technology Beijing, Beijing 100083, PR China. 742 ISSN 0010-9312 (print), 1938-159X (online) 17/000125/$5.00+$0.50/0 © 2017, NACE International CORROSION—JUNE 2017 CORROSION ENGINEERING SECTION