This study investigates localized CO2 corrosion on carbon steels in wet gas services both experimentally and theoretically. A 100 mm I.D., 40 meter long flow loop is employed to perform the corrosion studies along the top and the bottom of the pipe under stratified and annular flow conditions. Various corrosion monitoring techniques, including ER, LPR, and WL, and surface analysis techniques, including SEM/EDS, MM, and XRD are used during the experiments and for post-test analysis.

The parametric study involves the systematic investigation for the effect of temperature, CO2 partial pressure, Cl-, pH, and flow regimes on localized corrosion and formation of corrosion product films. Localized corrosion is found only at high temperature (90°C) in both Cl- containing and Cl- free solutions (with different pitting density). It also occurs at lower pH (4.5~6.0) while at pH 6.2 very protective films form and no localized corrosion is identified. CO2 partial pressure affects film formation and thus the localized corrosion when a partially protective film is formed. Corrosion behavior at the top approached that of the bottom when annular flow is maintained.

The theoretical study includes the development of a solution super saturation model and a scaling tendency model, which are good tools for predicting localized corrosion. Localized corrosion occurs when the solution is only slightly above the saturation point and when the scaling tendency is between 0.3 and 3.0.


In the natural gas production industry, mild steel is extensively used for pipeline construction for economical reasons even though it has a relatively poor corrosion resistance. Natural gas does not emerge from the reservoir pure and is always accompanied by various amounts of oil, water, carbon dioxide, hydrogen sulfide or organic acids. These substances combined give rise to a very aggressive environment where the survival of mild steel is not guaranteed.

The multi-phase mixtures of gaseous and liquid hydrocarbons, water, CO2 and H2S moves through gas pipelines in a variety of complicated flow patterns such as annular, mist, slug and stratified flow, depending on the terrain topography and the individual phase flow rates. Flow can accelerate corrosion of mild steel by increasing the mass transfer of corrosive species and/or by damaging the protective films on the steel surface1. In wet-gas pipelines, the typical flow patterns mentioned above enhance the internal corrosion for both the top and the bottom of the pipe.

In the past 30 years, significant progress has been achieved in understanding uniform CO2 corrosion of mild steel2-7. Localized corrosion is still not well understood even though most of the failures in lines are caused by localized attack, which is more difficult to predict or detect than uniform corrosion. In the field of wet gas corrosion research, there are only a handful of studies that relate to field experience, some focusing on corrosion management8 and control 9, others reporting actual case histories10. In most studies the focus was on top-of-line corrosion11,12 where high uniform corrosion and sometimes, localized attack, were associated with rapid condensation of water by external cooling. No studies investigated the nature and magnitude of the attack in wet gas transport in the presence of low condensation rates, typical for well-insulated pipelines.

Previous studies covering localized CO2 corrosion of carbon steels have all been conducted in single-phase water flow13-17. A common underlying theme is that localized attack is always associated with the formation or breakdown of iron carbonate films. The apparatus used in those studies were the rotati

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