Abstract
Acid gases, such as CO2, H2S, and/or sulfur in oil industry’s production fluids, can be responsible for both general and localized corrosion, acting with different mechanisms, which depend on chemical and physical properties of the produced fluids. Materials selection for handling such fluids is performed by combining experience with suggestions from standards and regulations. A good deal of knowledge is available to predict corrosion rates for CO2-containing hydrocarbons, but the effect of high H2S pressure is less understood, mainly due to the difficulty of performing laboratory tests in such challenging conditions. For instance, the so-called NACE solution to assess SSC (Sulfide Stress Cracking) susceptibility of steels is a water-based solution simulating production fluids in equilibrium with one bar bubbling H2S gas. This solution does not represent environments where high gas pressure is present. Moreover, it does not take into account the corrosive properties of sulfur and its compounds that may deposit in such conditions. Besides, properties of high pressure gases are intermediate between those of a gas and those of a liquid: high pressure gases have superior wetting properties and better penetration in small pores, with respect to liquids. These features could enhance and accelerate damage, and nowadays such conditions are likely to be present in many production fields. This paper is aimed to point out a few challenges in dealing with high pressure gases and to suggest that, for materials selection in sour service, a better correspondence of test conditions with the actual field conditions shall be pursued.
Highlights
Exploitation of fields with high H2S and/or CO2 content is nowadays of growing importance for oil companies
Corrosion resistance of steels and alloys in high and very high H2S pressure shall be investigated in test conditions approaching as close as possible to field conditions
The amount of H2S that can be dissolved in water is limited as a function of temperature
Summary
Exploitation of fields with high H2S and/or CO2 content is nowadays of growing importance for oil companies. The effect on structural metals of high partial pressure of H2S in gas mixtures needs to be further studied. Reinjection wells are, for instance, in contact with dry supercritical fluids, whose corrosion properties are not fully known. Multiphase pipelines too are often transporting fluids containing high pressure sour gas and laboratory tests are critical to material selection assessing crack resistance. Hydrogen sulfide is a weak acid, causing a small decrease in pH of a water solution, and corrodes steels and alloys in neutral solutions, with a generally low uniform corrosion rate. Hydrogen sulfide plays an important role in the stability of corrosion products film, increasing or decreasing its corrosion resistance by interaction with other components, such as CO2. While the mechanisms of carbon steel (CS) corrosion due to CO2 are fairly understood, the effects of H2S presence are not fully understood. H2S corrosion mechanisms proposed in literature [1, 2] do explain experimental data, but their thermodynamics and kinetics details are not known
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