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Abstract
In laboratory experiments, corrosion of mild steel specimen in glass cells or autoclaves with a relatively small internal volume (of the order of 1 liter or less), will usually lead to a change in solution chemistry, (i.e., increase in ferrous ion concentration and solution pH) which will affect the corrosion product formation and ultimately the corrosion rate. However, in much larger field systems that are being simulated in the laboratory, such as for example oil and gas mild steel pipelines, the solution chemistry at any specific location does not change significantly over the same time period, since it is governed by the flow coming from further upstream. Therefore, it is very important to be able to maintain a stable solution chemistry in small scale laboratory experiments, in order to get a better simulation of corrosion seen in the field. In this work, a stable solution chemistry system was developed using ion exchange resins. H-form and K-form exchange resins were successfully tested in long term experiments aiming to keep pH and ferrous ion concentration reasonably stable. The results show that pH can be controlled within ±0.02 pH units and ferrous ion concentration within ±3 ppm. The results of electrochemical measurements and surface analysis show that there is a significant difference in both corrosion rate and corrosion product layer formation when a stable solution chemistry system is used.
Introduction
In small scale constant inventory laboratory experiments, CO2 corrosion of mild steel will often lead to a change in aqueous solution chemistry (i.e. increase in ferrous ion concentration and solution pH). As an example, Figure 1 shows the changes in ferrous ion concentration and solution pH during a small scale lab experiment with an API 5L X65 specimen with surface area of 5.4 cm2 in 2 liters of CO2 purged, 1 wt.% NaCl solution at 40 °C and initial pH 4.0. It was found that ferrous ion concentration increased from 0 to 54 ppm during 72 hours. At the same time, the solution pH increased more than 1 pH unit, from pH 4.0 up to pH 5.1.
However, for a field system,¹ such as an oil or gas pipeline, the solution chemistry at a any given location inside the line does not change significantly over time, as there is always fluid flow coming from upstream. It is well known that the increase in pH and ferrous ion concentration will affect the CO2 corrosion rate and the precipitation rate of corrosion products such as iron carbonate. Therefore, it is not trivial to conduct and interpret corrosion results from small scale lab experiments that are meant to simulate field corrosion data.
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