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Development of new oil and gas fields is likely to involve sour reserves to an increasing degree. Sourproduction often brings about difficulties in terms of asset integrity, related particularly to corrosionmitigation. Employing corrosion resistant alloys implies a considerable escalation in investment costs. On this basis the use of carbon steel and CO2/H2S corrosion inhibition remains a highly desirableoption.
Qualification of corrosion inhibitors for field deployment involves performance testing in the laboratory. Especially for sour service, a common set of test methods and associated protocols or guidelines used across the oil and gas industry, chemical companies and laboratories does, however, not exist. Development and testing of robust methodology were at the core of a Joint Industry Project (JIP) carried out at the Institute for Energy Technology (IFE). This contribution presents a selection of findings related to precorrosion, one of the aspects addressed in the JIP.
A series of benchmark experiments assessing the performance characteristics of various inhibitorchemistries mitigating corrosion of carbon steel under sweet (CO2) and sour (CO2:H2S 1:1) conditions at 25 °C and 60 °C without any precorrosion raised concerns related to uneven attack and risk for developing undesirable experimental artifacts, e.g. localized corrosion. Subsequent study of several precorrosion methods, including natural and electrochemically accelerated (anodic polarization) corrosion either in the absence or presence of H2S provided valuable insight into advantages and shortcomings of each approach.
From a methodology viewpoint the precorrosion approach and the selected conditions make it possible to generate corroding carbon steel surface either free of protective corrosion products, covered by nonprotective FeS, pre-load the test solution with suspended FeS particles etc., which could be useful for tuning the inhibitor tests to various scenarios relevant to sour corrosion.
Many pipelines within water and wastewater treatment plants that were constructed within the last 50 years are nearing the end of their service lives. Owners have invested in condition assessments to help them make the difficult decision to repair or replace these pipelines.
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Coating degradation on Army ground systems represents a significant maintenance cost and effort. The objective of this proposed work is to develop a predictive model for coating degradation and subsequent substrate corrosion on Army ground assets. Provided with a better understanding of the root causes, steps can be taken to reduce corrosion impacts on Army materiel.
Oil and gas production in a CO2 saturated environment is known to lead to corrosion due to dissolved carbonic acid. However, when the conditions are favorable, a protective FeCO3 layer can also form which reduces the material degradation of the underlying steel by up to ten or a hundred times.1 The formation of FeCO3 is possible via the reaction shown in equation 1.