ABSTRACT
Corrosion of carbon steel in the presence of H2S is an important topic in the oil and gas industry that has been studied for more than fifty years. Removing this compound results in not only an increase in the corrosion resistance of carbon steel, but also an improvement of environmental, health and safety compliance, thereby increasing production efficiency. Triazines are commonly used as H2S scavengers. However, failures in the form of stress corrosion cracking (SCC) have recently been reported when using certain triazines making it necessary to understand the failure mechanism in order to mitigate/control this detrimental phenomenon. It has been suggested that SCC is governed by corrosion processes and specifically by the transition from a passive (more protective) surface to an active (less protective) surface. This transition is a complicated function of acid gas concentration (CO2 and H2S) and amine adsorption, which are likely different for different systems. Therefore, characterization of the effect of the triazine/H2S reaction processes on the surface properties of steel is an important factor that needs to be explored. In this paper, we seek to understand the effect of triazine on the electrochemical response of a carbon steel surface in a mixed gas system. Cyclic voltammetry was used to qualitatively assess the nature of the carbon steel surface with and without CO2 in the presence of triazine. Changes in surface film properties were also assessed using electrochemical impedance spectroscopy in an attempt to quantify changes in the electronic properties of the surface layer.
INTRODUCTION
Corrosion of carbon steel in the presence of H2S is an important topic in the oil and gas industry that has been studied for more than fifty years. Recently, severe SCC has been observed in shale pipelines1. The exact mechanism has not been identified but several key factors are known. First, cracking is typically observed downstream of the H2S scavenger injection site. It is also known that for the relatively slow flow rates for shale gas pipelines, water hold up is more likely providing an initiation site for corrosion and cracking. Heavers1 suggests that the observed cracking was a form of amine cracking where the amines in the inhibitor increased pH over 8 which led to carbonate cracking. The primary basis for this assessment was that no Mackinawite or other FeS species were observed.
