The expansion of Carbon Capture, Utilization, and Storage (CCUS) highlights the growing need for carbon dioxide (CO2) pipeline transportation. While pure CO2 is non-corrosive, impurities such as H2O and NO2 create a corrosive environment that risks pipeline integrity. This study investigates how H2O and NO2 concentrations, along with temperature, influence corrosion under CO2 pipeline conditions. The investigation was performed in an autoclave setup emulating a linear velocity of 0.96 m/s at 100 bar and temperatures of 5 °C and 25 °C, testing X52 and GR70, and a more corrosion-resistant 9Cr alloy. The results indicated that the presence of NO2 elevated the corrosion rate compared to scenarios without. Low H2O concentration led to a corrosion rate of up to five times higher at 5 °C, compared to at 25 °C, in the presence of NO2. Low to moderate corrosion was observed for the carbon steels without NO2 and with 70 ppmv H2O at both temperatures. Reducing the H2O concentration below 70 ppmv and removing NO2, while SO2 and O2 are present, will only result in low to moderate corrosion in the carbon steel CO2 pipeline. The corrosion rate for X52 and GR70 was 0.065 mm/y and 0.016 mm/y higher or 5 and 3 times greater, respectively, at 5 °C compared to 25 °C. The study concludes that H2O should be maintained below 70 ppmv and NO2 should be eliminated to prevent severe corrosion. Emphasizing the importance of CO2 specification compliance and the need for further research into CO2 compositions that align with the specifications.
Large volumes of produced water are being discharged globally as byproducts of oil production. Commercial production chemicals are conventionally needed to avoid problems such as bacterial growth, pipe corrosion, and oil/water separation issues. These chemicals will partition between oil and water phases and may affect both treatment processes and the environmental impact when water is discharged to the ocean after treatment. Capillary zone electrophoresis is used to measure partitioning coefficients of oilfield chemicals when these are dissolved in the water phase and in contact with either octanol or crude oil. The technique is fast and, due to simplicity, could have merits as on-site assessment of the partition coefficient for direct assessment of the fate of chemicals. The method was first qualified by estimating partitioning coefficients of aliphatic carboxylic acids and chemicals with a molecular structure similar to those of some production chemicals. Subsequently, the coefficients were determined for two different commercial corrosion inhibitors and a biocide that are used in the oilfield as production chemicals. The results showed that the chemicals predominantly preferred to remain in the water phase after contact with either octanol or crude oil. The partitioning coefficients log(p) spanned between −0.36 and −1.68 in the case of water/octanol contact and between 2.68 and −1.41 in the case of water/crude oil contact. One of the corrosion inhibitors exhibited a significant difference in the partitioning depending on whether the organic phase was octanol or crude oil. The chemical had a preference for the water phase in the case of the former but a preference for the crude oil phase in the case of the latter. The result demonstrates that it makes it challenging to evaluate the use of partitioning coefficients for oilfield applications.