Under stratified flow and dewing conditions, internal corrosion can occur at the top of horizontal pipelines where continuous injection of corrosion inhibitors does not have a mitigating effect. This research work presents an experimental study of the influence of the presence of H2S (up to 0.13 bars) and acetic acid (up to 1000 ppm) on the more standard CO2 Top of the Line Corrosion. A comprehensive analysis on the effect of these parameters on the type of corrosion product film formed at the top of the line is performed.
Top of the line corrosion (TLC) was first identified in the sixties'1 and is now a growing concern for the Oil and Gas industry. Many field cases have been published from both onshore and offshore environments 2-7. This type of corrosion occurs in stratified flow when significant temperature gradients exist between the outside environment and the process fluid, thus leading to water condensation on the internal walls of the pipe line. The presence of this condensed water can induce severe general and pitting corrosion problems, typically on the upper part of the pipe (between 9 and 3 o'clock).
Two main sub-categories of TLC can be identified depending on whether the corrosion mechanism is CO2 or H2S dominated. To be fair, the boundaries delimiting what is a sweet or a sour corrosion are not even clear today but are most likely linked to the type of corrosion product film forming at the metal surface.
Top of the line corrosion in sweet conditions has been the focus of intensive research over the past fifteen years and the main corrosion mechanisms involved are now identified, if not well understood. The severity of corrosion attack depends mostly on the condensation rate, the gas temperature, the gas flow rate, the CO2 partial pressure and the presence of organic acid13. Pipe inspections often reveal corrosion over extended areas of the top of the pipeline associated with breakdowns of an otherwise protective FeCO3 layer. Field experience in this domain is also growing and a lot of research work has been already published8-12.
In sour conditions, the mechanism governing top of the line corrosion seems largely different from in sweet conditions. Several pipe failures have been attributed to sour TLC1,5-7 although the real controlling parameters was often unclear. Limited research work has been published on sour TLC 14 -16 , leading often more to interrogation than real answers. Although no firm conclusion can be made at this stage, some important characteristics of sour TLC have been proposed17:
Sour TLC does not seem to be as serious and as common as sweet,
The condensation rate may not be the main controlling parameter as it is in sweet TLC,
The severity of the attack seems to depend on the type and protectiveness of the iron sulfide film formed at the condensed water/steel interface,
Gas temperature consequently, could be a key factor as it directly affects the phase identity and characteristics of the formed iron sulfide.