The network of pipelines in the US transports oil and natural gas to and from different states, but they’re prone to damage because of their age and the chemicals they carry. Research shows that corrosion-related costs are up to $8.6 billion per year, involving capital (10%), failures (38%), and operations and maintenance (52%).
Even though there have been changes to the approach of managing and detecting corrosion, pipeline service providers like Mears Corrosion and the Energy Information Administration (EIA) say that it’s important for those working in the industry to understand its different types. Here are some examples:
Also known as sour corrosion, this occurs when metals make contact with hydrogen sulfide (H2S) and moisture. Hydrogen sulfide isn’t a corrosive element in itself, but once it combines with water, it can cause the pipelines to become brittle. It becomes a weak acid and a good source of hydrogen ions, promoting uniform pitting, and stepwise cracking.
Carbon dioxide (CO2) is among the leading corroding elements in oil and gas production facilities. When CO2 combines with water, it promotes an electrochemical reaction that helps form carbonic acid. This is what makes the CO2-gas-turned-fluid acidic. CO2 Corrosion takes place depending on temperature, pH value, and metal characteristics. It has two principal forms – pitting, the removal and rapid penetration of metal in smaller areas, and Mesa attack, a localized form under medium-flow conditions.
This happens when two metallic materials with electrochemical potential made contact with each other, while under exposure to an electrolytic environment. The metal that has the most or least negative potential becomes an anode and then causes corrosion. The anode will start to lose metal ions to balance the electron flow.
These are only some of the most common types of pipeline corrosion. It’s best to know their difference, so it’ll be easier to detect and solve.