At first glance, the need to explore and develop hydrocarbon gas fields which contain high CO2 contents (up to 80 mole %) would call for the use of expensive corrosion resistant alloys. This would have the potential to render project development costs untenable. An alternative approach would be to evaluate the technical feasibility of using carbon steels. Unlike transportation and sequestration of supercritical CO2, where the amount of water is normally negligible or comes from condensation, field development has to consider the presence of formation water. This water has the potential to contain multiple corrosive species. In addition to the action of such species during carbon steel corrosion, evaluations that involve the effect of flow on corrosion rates are required as flow has the possible effects of challenging the protectiveness of the corrosion product films and increasing the mass transfer rates close to the pipe wall. In the present study, flow-sensitive CO2 corrosion has been investigated using a high-pressure high-temperature rotating cylinder electrode (RCE) autoclave and a pipe flow loop system. Corrosion rates are measured via weight loss and by electrochemical methods at various pH's (3 to 5), temperatures (25 to 50C), near critical and supercritical CO2 partial pressures and at equivalent fluid velocities from 0 to 1.5 m/s.
South East Asia has about 182 Tcfg undeveloped hydrocarbon gas reserves. One of the reasons that these reserves have not been fully harnessed is that they reside in high CO2 fields; for example, Natuna D-Alpha field in Indonesia contains about 70 mole percent of CO2 [1]. At the outset, the development of these fields would call for the use of expensive corrosion resistant alloys due to the possibility of high CO2 corrosion. This would potentially render the project development costs untenable. An alternative approach would be to evaluate the technical feasibility of using carbon steels. Unlike transportation and sequestration of supercritical CO2, where the amount of water is normally negligible or comes from condensation [2], field development has to consider the presence of formation water which has the potential of containing multiple corrosive species. For offshore installation, it would be costly to dry the gas stream or to remove the CO2 gas prior to transportation of hydrocarbon gas via pipelines. It is even impractical to remove water and CO2 from the full stream coming from the wells. While the presence of dissolved CO2 and other corrosive species itself renders the environment corrosive to carbon steel, the flowing of the corrosive liquid over the metal surface could possibly enhance the corrosion rate. This is because flow has the possible effects of increasing the corrosion rate by increasing the mass transfer rates of the corrosive species to the pipe wall and challenging the protectiveness of the corrosion product films [3][4]. There have been a lot of studies on the effects of flow on CO2 corrosion of carbon steel [5-8]. However, only few studies have attempted to address the flow effect in high partial pressure CO2, i.e., 10 bar and above.
