Corrosion degradation of pipeline carbon steels subjected to geothermal plant conditions

Abstract

PurposeThe purpose of this paper is to evaluate the electrochemical behaviour of two carbon steels exposed to acidic geothermal solutions and their resistance to hydrogen induced cracking (HIC), in order to determine the effect of hydrogen damage on the failure process of the steels used for line pipe and casings at a geothermal plant.Design/methodology/approachSamples of two different steels: ASTM A‐53 Grade B (line pipe) and API L‐80 (casing) were immersed for a duration of 96 h in the electrolyte proposed by NACE to evaluate susceptibility to HIC. Samples of the two steels embedded in non‐conducting Bakelite were subjected to potentiodynamic polarisation scans at room temperature using as the electrolyte brines obtained from different wells at the Cerro Prieto geothermal plant. Hardness tests were performed on the samples before and after the HIC tests in order to determine hardness changes induced by hydrogen penetration as field results indicated embrittlement of the steels after four months of service.FindingsThe steels, ASTM A‐53 Grade B and API L‐80 did not exhibit crack sensitivity as no cracks are observed in the tests specimens, though they showed an increase in hardness. The steels exhibited high‐corrosion rates in the brine media at room temperature (3.3 mm/yr), which is expected to increase at higher temperatures.Originality/valueThe work revealed that carbon steels used for line pipes and casings at geothermal plants can exhibit high resistance to HIC, however they corrode at high rates and may show embrittlement. It is suggested that due to the high‐operation temperature, the damage induced by hydrogen resulted in hardness increase but was not sufficient to develop cracks.

Corrosion Behaviour of L80 Steel Grade in Geothermal Power Plants in Switzerland

“…In bicarbonate environments with very low chloride concentrations, low-alloyed carbon steels show noticeable resistance to uniform corrosion [32]. However, environments with high chloride concentrations and low pH (around 6) might lead to uniform attack and to the formation of pits on the steel surface [28][29][30]. Other brines containing non-condensable gases, such as H 2 S, are very aggressive for this type of steels, resulting in significantly high corrosion rates [23,30,31].…”

“…This results in a limited knowledge about properties of deep geothermal fluids (at depths of 4-5 km) [10] and, thus, a lack of expertise in corrosion issues of geothermal installations. Furthermore, literature on corrosion shows that most of the experimental studies are restricted to specific geothermal fields [23,[28][29][30][31][32]. Considering that the fluid chemistry might significantly vary not only between physically separated fields but also between nearby boreholes [33,34], the transfer of technical know-how of existing geothermal power plants abroad to design durable, maintenance-free facilities in Switzerland constitutes a research challenge.…”

Thermal effects on microbial composition and microbiologically induced corrosion and mineral precipitation affecting operation of a geothermal plant in a deep saline aquifer

“…Highly mineralized geothermal fluids with an excess of sulfate tend to scale formation (sulfide, carbonate, silica) in the reservoir, pipelines and topside structures when brine is cooled in the course of fluid production and energy extraction (Skinner et al 1967;Dalas and Koutsoukos 1989;Gallup 2002). Furthermore, chemically and microbially induced corrosion additionally occurs in plant infrastructure and adversely affects plant operations and commercial benefits (Gallup 2009;Valdez et al 2009;Miranda-Herrera et al 2010). Therefore, the detrimental effect of microbes on power plant components has increasingly garnered attention.…”

Laboratory tests simulating corrosion in geothermal power plants: influence of service conditions

“…Furthermore, other components of the power plant that handle the hot brines, such as the pipeline system located on the surface between the wellheads and heat exchangers (Fig. 1), are not exempt of corrosion problems (Karlsdottir 2012;Miranda-Herrera et al 2010). Other types of corrosion, such as crevice corrosion, must be considered when selecting materials for the power plant equipment.…”