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Many asset owners struggle to identify the root cause of fluctuating corrosion rates due to unreliable inspection data. Facilities worldwide are tasked with monitoring thousands of Condition Monitoring Locations (CMLs) with established NDE techniques such as manual ultrasonic testing and radiography. While these techniques can provide valuable “snapshots” of the condition of particular locations, limitations and inherent errors can compound leading to ill-advised decision making. Manually taken thickness data can vary greatly and result in unwarranted complacency or excessive and costly inspections.
Installed UT sensors can provide better visibility around how, when, and why corrosion is happening in assets and allows people to track and monitor with extremely high precision (.001”). Owner operators can then overlay corrosion rate data with process data to analyze Integrity Operating Windows (IOWs) and help them better understand how to most efficiently and safely operate their assets and either remediate or extend their useful life, thus moving from a time-based maintenance interval to that of a predictive based interval. This paper will cover a real-life example of how an owner operator has used permanent or temporarily installed wireless UT sensors to monitor problematic areas, track remediation tactics, and verify the ramification of operational changes.
Over the past decade, there has been increasing interest in the corrosion behavior of carbon steels in supercritical CO2 conditions. Unlike the case of carbon capture and storage (CCS) where small amounts of water are present, the exploitation of fields with high pressures of CO2 needs to consider the presence of formation water, which presents strong corrosivity. It has been reported that the aqueous corrosion rate of carbon steel at high CO2 pressures (liquid and supercritical CO2) without protective FeCO3 corrosion product layers is very high (>20 mm/y) due to the high concentrations of corrosive species such as H+ and H2CO3.1-5 Steels with low Cr contents (i.e., 1% Cr and 3% Cr) have shown no beneficial effect in terms of reducing the corrosion rate to admissible values.6 Therefore, controlling corrosion in these cases usually involves the use of corrosion resistant alloys (CRAs) or corrosion inhibitors (CI). Adequate protection of carbon steel was achieved by applying CI in high pressure CO2 environments.6
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Left unprotected, metals corrode quickly which over time contributes to the loss of structural integrity and the failure of buildings, bridges, oil & gas platforms, airplanes, cars and many other metal assets, all of which pose a risk to human safety and the surrounding environment. In 2016, the National Association for Corrosion Engineers (NACE) – now known as AMPP – published a landmark study, well-known to those attending this conference, that estimated the direct cost of corrosion to the world economy as $2.5T per year, equivalent to 3.4% of the Gross World Product (1). In the United States, the annual cost of corrosion is estimated at 3.1% of gross domestic product (2), equivalent to $635B (2018). When including indirect costs, such as asset downtime, ship dry-docking and the impact of bridge collapses, the cost of corrosion is estimated at twice that amount.
Seawater injection is commonly utilized for offshore wells to maintain or increase oil production; however, treatment for seawater before injection is always necessary to reduce or remove bacteria, dissolved oxygen, sulfate, and other impurities. Seawater typically has >2000 mg/L sulfate. Without proper sulfate removal, such high levels of sulfate can cause not only barium sulfate, strontium sulfate, and calcium sulfate scales, but also reservoir souring and H2S corrosion in the presence of sulfate reducing bacteria (SRB). Therefore, sulfate removal from seawater is critical before seawater injection into reservoir.