Localized corrosion in the oil industry is a dominant area of study that still remains elusive to researchers. Most infrastructure failures in the oil industry result from localized corrosion defects not general corrosion. Most corrosion testing relies on polished surfaces and relatively short tests resulting in detection of small features that may not be representative of field conditions. This paper looks at media blasted surfaces that are imaged at high resolution before and after corrosion testing. This method of corrosion testing shows that the modified surfaces contain populations of features that can be studied in aggregate to evaluate the effectiveness of corrosion inhibitors. This technique maximizes the utility of interferometry as a microscopy technique while also providing a surface that may be more representative of field conditions than a 600 grit polished surface.
Corrosion failures in the oil and gas industry are dominated by localized failures in carbon steel; however, the industry has yet to develop standards for localized corrosion specifically for low alloy carbon steels (CS) such as UNS(1) K03014 (API(2) 5LX65 [X65]) or UNS G10180 (C1018).1 The reasons for the lack of standardization are understandable as they are not trivial. The challenges are as follows: 1) CS pitting is more complex than pitting on stainless steels (SS) and can be impacted by corrosion byproducts and other forms of scales, and 2) surface finish of a test coupon or electrode has a significant impact on the three phases of pitting: initiation, propagation, and termination.
The first challenge of localized corrosion on CS is that the protective films are not as predictable as for the SS metallurgies. The predictability of passive films on SS is illustrated in the ASTM G46 standard.2 The new lessons learned section in the 2021 version of G46 compares the complexities of passive film formation on SS and CS in more detail and cautions against using G46 in CS applications. The scales formed on CS are dependent on the concentration of iron(II) in solution and the speciation of iron(II) involves a complex set of parameters including temperature, acid gases, acid gas concentration, system pressure, brine composition, and many others. System temperature may be the most significant parameter, owing to the fact that iron(II) solubility in brine is highly temperature dependent. Corrosion tests conducted at or below 50°C may not show protective scales on CS while tests run at 90°C may have scales that are as protective as some forms of chemical inhibition.3,4