Carbon Capture, Transportation, Utilization, and Storage (CCTUS) plays a vital role in mitigating CO2 emissions and combating global warming. The capture process can introduce various impurities, including nitrogen dioxide (NO2), sulfur dioxide (SO2), oxygen (O2), and hydrogen sulfide (H2S), often at parts per million (ppm) levels, which can lead to the formation of acid-rich phases. These phases significantly increase corrosion risks to carbon steel pipelines during the transport and injection of CO2.
Selecting the right tubing and casing materials for CO2 injection and storage is crucial, as corrosive conditions are dictated by near-wellbore factors such as pressure, temperature, brine salinity, pH, and the composition of the injected CO2. Impurities further amplify this risk during shut-ins and after CO2 reinjection; for example, H2S can initiate sulfide stress cracking (SSC), while O2 can increase localized corrosion, and acid formation can lead to high general corrosion rates. Therefore, predicting corrosion behavior in these injection environments is essential for making informed material selections and maintaining asset integrity. OLI has developed a predictive corrosion modeling tool capable of estimating general corrosion rates and propensity to localized corrosion based on the chemistry of CO2 environments.
In this spotlight presentation, Dr. Diana Miller will explore real-world applications, focusing on three different injection fluid compositions. She will demonstrate how OLI software predicts the phase behavior of CO2 injectate and simulates its interaction with formation water, allowing for accurate corrosion rate and propensity to localized corrosion calculations for different materials of construction (13Cr, 15Cr, 17Cr, 22Cr, and 25Cr). Understanding these risks is essential for selecting appropriate corrosion-resistant materials, ensuring well integrity, and maintaining regulatory compliance while optimizing costs.
