Electrochemical Behaviour of Low Carbon Steel in Aqueous Solutions

An effective way of assessing corrosion in pipelines before serious consequences occur is to use tools that can predict the future of a pipeline through an understanding of its present state and the mechanisms of corrosion. In this work electrochemical methods such as liner and tafel polarization resistance were used to evaluate corrosion. Most metal corrosion occurs via electrochemical reactions at the interface between the metal and an electrolyte solution and, therefore, since corrosion occurs via electrochemical reactions, electrochemical techniques are ideal for the study of the corrosion processes. This particular study has examined the corrosion that occurred in different grades of low carbon steels with particular aggressive solutions. Corrosion rate measurements were obtained using different aqueous environments such as a plain sodium chloride solution, a sodium chloride and carbon dioxide solution, and a sodium chloride and sulphuric acid solution that also contained a small amount of carbon dioxide. The corrosion morphology was examined using a scanning electron microscopy (SEM) in which the surfaces examined showed general corrosive attack with some shallow pits. The metallurgy of pipelines, vessels, etc in oil and gas- producing systems is usually based on carbon steel. This is because carbon steel has good mechanical properties and is also relatively cost effective. However, carbon steel is strongly susceptible to corrosion attack from the dissolved gases (CO2 and H2S) that are present in the produced fluids. As such, the presence of the two acid gases carbon dioxide CO2 and hydrogen sulphide H2S with partial pressures and condensed water chemistry (1), the corrosivity of the material is generally caused to increase. A quantative understanding of the corrosion rate of steel under these conditions will be a key factor in providing an accurate risk assessment of the attack of pipelines by internal corrosion. Corrosion in gas gathering and transmission pipelines has been reported in the presence of H2S and CO2 in the gas and high chloride concentrations or sulphur/polysulfide sludge from the formation water (2-3). The earliest studies of the combined effects of CO2 and H2S were carried out by Greco and Wright and Sardico, et al. (4) who found that a protective sulphide film formed at concentrations of H2S <1,700 ppm, which corresponds to a gas pressure of <0.1 psi. At higher concentrations, a non-protective sulphide film was reported. In their work It was observed that small concentrations of H2S (0.02 mole or 0.0065 psi) decreased the corrosion rate of steel at 70°C and 80°C in a 1M sodium chloride solution with 10 psi CO2 (5-8). However, it was noticed that pitting occurred in these solutions, possibly caused by selective dissolution of the ferrite phase. At higher H2S concentrations (0.002 psi to 0.0082 psi), considerable scatter in corrosion rate results was observed, with the corrosion rate generally increasing with H2S concentration (4). Certain corrosion phenomena show maximum severity at ambient temperature. In particular, this is true for all the damage mechanisms involving hydrogen cracking: sulphide stress cracking (SSC), stepwise cracking (SWC) and stress oriented hydrogen induced cracking (SOHIC). However, today's problems often concern traces of H2S at partial pressure <1 atm (1). Furthermore, CO2 acts largely via its effect on pH, which readily can be measured or calculated at low temperatures. The objective of the research presented in this paper is to measure the corrosion rate for five types of normal carbon steel in three different aqueous solutions which were (a) plain sodium Chloride (sea water), a second solution of sodium chloride with added carbon dioxide gas, and a third solution of sodium chloride with added sulphuric acid and a small amount of carbon dioxide. This study involved linear polarization resistance (LPR) and analytical techniques scanning electron microscopy (SEM).