Managing Internal Corrosion of Mild Steel Pipelines in CO₂‐Enhanced Oil Recovery Multiphase Flow Conditions

Abstract

The “carbon capture, utilization and storage” project has attracted considerable attention in recent years as the demands for reducing CO2 emissions increased. However, the produced fluids during CO2‐enhanced oil recovery (EOR) production are supersaturated with high‐pressure CO2 gas, which leads to serious corrosion damages of the pipelines. To model the corrosive conditions during CO2–EOR production, a self‐designed multiphase flow loop for internal corrosion evaluation was built. The role of flow patterns and emulsification that decisively influencing pipeline corrosion was systematically investigated. It was found that a higher gas‐to‐liquid ratio could be beneficial for reducing pipeline corrosion, which was attributed to a reduction in slug frequency and an enhancement in the stirring effect on the oil–brine mixtures. It was also found that corrosion can be completely inhibited if the transporting liquids were properly controlled under water‐in‐oil emulsion condition. A model considering the transport parameters that ensures the safety of crude‐oil transportation is proposed. It suggests that corrosion control by designing the transport parameters would be a suitable and economic method for tackling the corrosion damages to CO2–EOR pipelines. These ideas have been accepted for guiding the pipeline engineering in the CO2–EOR section of the Shengli oilfield.

Corrosion Control in CO2 Enhanced Oil Recovery From a Perspective of Multiphase Fluids

“…Different from a CO 2 injection well, the fluid in an oil production well is generally a complex mixture of oil, water and gas. In CO 2 -EOR production, the content of CO 2 in gas phase can be as high as 70% in volume (Wang et al, 2015).…”

“…However, corrosion is a big concern in operating a CO 2 -EOR project, as CO 2 becomes corrosive to steel-based facilities when it meets water. For example, in the CO 2 -EOR production section of Shengli oilfield, the presence of a large amount of CO 2 in the production fluids has resulted in an abrupt increase of pipeline leakages within the initial 3 years after the injection of CO 2 into reservoirs (Wang et al, 2015), revealing an averaged corrosion rate of pipeline materials higher than 1.0 mm/y (Zhang J. et al, 2012;. According to the field experience from Chevron, the coated tubes can only service for 50 months in CO 2 -injection well conditions (IEAGHG, 2010).…”

“…Similar damage induced by the presence of high partial pressure of CO 2 has also been reported in other CO 2 -EOR projects (Tzimas et al, 2005;Singh et al, 2010). The corrosion performance of different materials in CO 2 -containing aqueous solutions has been systematically investigated, and some strategies on corrosion control in CCS and CO 2 -EOR production have been suggested based on field experiences (Sim et al, 2014b;Wang et al, 2015). The use of corrosionresistant alloys (CRA) and corrosion inhibitors is regarded as two of the important ways to mitigate corrosion in aggressive CO 2 conditions (IEAGHG, 2010).…”

Process simulation of CO2 capture from CO2‐EOR associated petroleum gas with aqueous MEA and MDEA solvents

“…9,10 In addition, the presence of CO 2 in natural gas will reduce its calorific value, increasing the transportation cost per unit of energy. The natural gas accompanied with CO 2 causes pipeline corrosion during subsequent transportation, and is particularly detrimental.…”

“…The natural gas accompanied with CO 2 causes pipeline corrosion during subsequent transportation, and is particularly detrimental. 9,10 In addition, the presence of CO 2 in natural gas will reduce its calorific value, increasing the transportation cost per unit of energy. 11 At present, four methods are mainly used for CO 2 capture from the associated gas: chemical absorption, variable pressure adsorption, membrane separation, and low temperature fractionation.…”