ABSTRACT

Hydrogen sulfide (H2S) corrosion of mild steel is a serious concern in the oil and gas industry. However, H2S corrosion mechanisms, specifically at high partial pressures of H2S (pH2S), have not been extensively studied because of experimental difficulties and associated safety issues. The current study was conducted under well-controlled conditions at pH2S of 0.05 and 0.096 MPa. The pH range used was from pH 3.0 to pH 5.0, at temperatures of 30 and 80°C, and with rotating cylinder speeds of 100 rpm and 1000 rpm. Short-term exposures, lasting between 1.0 and 1.5 hours, were used to avoid formation of any protective iron sulfide layers. The experimental results were compared with a recent mechanistic model of sour corrosion developed by Zheng, et al. (2014). This model was based on corrosion experiments conducted at low pH2S (0.0001 - 10 kPa) and is applicable only to conditions where protective iron sulfide layers do not form. The validity of the model at higher pH2S was examined, as it was uncertain if the mechanisms identified at lower pH2S were still valid. The comparison with the experimental results obtained in the present study indicated a good agreement between the model and the measurements. This confirmed that the physico-chemical processes underlying H2S corrosion in the absence of protective iron sulfides are very similar across a wide range of H2S aqueous concentrations. It also demonstrated that the mechanistic corrosion model was reasonable when extrapolating from low to high pH2S.

INTRODUCTION

The role of hydrogen sulfide (H2S) on aqueous mild steel corrosion has been one of the concerns of corrosion researchers since 1940 1-13. Ewing14 and Sardisco, et al., 15 were among the first scholars to initiate controlled H2S corrosion experimentation which was later continued by other researchers 13,16-20. The focus of much of the H2S related studies in the past was on iron sulfide formation and the resulting effect on corrosion3,21-23. The vast majority of the available research results come from experiments conducted at lower H2S partial pressures (pH2S < 10-2 MPa). Over the past few decades, a significant number of new oil and gas fields are sour, ranging from a few ppm up to 15-20 mol% H2S (e.g., the Kashagan Field24). This indicated a growing need for better understanding of H2S corrosion mechanisms and more effective prediction tools, particularly at higher pH2S.

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