Abstract

In wet gas pipelines, Monoethylene glycol (MEG) is a widely used hydrate inhibitor which has been shown to decrease the corrosion rate of carbon steel in CO2 environments. In a top of the line corrosion (TLC) situation, MEG is also known to affect both water condensation and TLC rates. However, the extent of its effect on corrosion depends mainly on the concentration of MEG present in the condensed water. Until now, rather scarce and conflicting information exist on this topic. This work presents a mechanistic water/MEG co-condensation model in the presence of a noncondensing gas (CO2). The model predictions of condensation rate and MEG concentration in the condensing phase are compared with loop test results, showing good agreement. The results show that an increase of the MEG content at the bottom of the line decreases the water condensation rate and increases the MEG content of the condensing phase at the top of the line. However, this effect is not significant unless the MEG content in the bulk liquid phase is higher than 70-80 wt%. Long term corrosion experiments are also presented showing that the injection of 50 wt% and 70 wt% MEG at the bottom have a minimal effect on both general and localized corrosion rates. On the other hand, the presence of 90 wt% MEG at the bottom of the line decreased the top of the line corrosion rate significantly due to a sharp decrease in condensation rate and a significant increase in MEG content in the condensing phase.

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 platforms. During wet gas transportation, the water vapor in the gas phase will condense on the internal pipeline surface due to the difference of temperature between the wet gas stream and the outside environment, leading to top of the line corrosion (TLC). TLC is caused by the dissolution of corrosive gases, like carbon dioxide and hydrogen sulfide, in the condensed water. The presence of acetic acid can also enhance TLC. In sweet environment, the initially high rates of iron dissolution lead to the rapid development of a corrosion product layer (FeCO3) on the steel surface. The protectiveness of this layer is constantly challenged by the continuous condensation of water vapor and renewal of water droplets. At low water condensation rates, TLC rates remain manageable. At high water condensation rates, TLC can become a serious issue, leading to pipe failures. The water condensation rate has long been recognized as the key factor influencing the rate of top of the line corrosion in CO2 environments. In addition, top of the line corrosion can be a serious concern in the oil and gas industry due to the limited options for corrosion mitigation. The traditional corrosion inhibitors injected in the liquid phase at the bottom of the pipeline are often non-volatile and cannot reach the condensed water at the top of the line.

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