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In order to provide basic information on corrosion resistance to the designers and users of geothermal plants different metallic materials including duplex and austenitic stainless steels as well as a nickel alloy have been evaluated in artificial geothermal fluids simulating the conditions in some locations with geothermal potential in Germany as well as two sites in Indonesia. By electrochemical and long-term exposure tests at 100 °C and 150 °C the suitability of low alloyed steel UNS G41300, stainless steels UNS S31603 UNS S31803, UNS S32760, super austenitic steel UNS N08031 and nickel based alloy UNS N06059 was investigated in these geothermal fluids, using critical potentials and corrosion rates. In high-saline environments the crevice corrosion turned out to be the determining mechanism. The nickel based alloy shows excellent corrosion resistance against pitting corrosion. Excluding its high cost, it is very good to be used in the construction of geothermal facilities having highly saline brines. Stainless and duplex steels exhibit a limited corrosion resistance concerning pitting and crevice corrosion. Therefore they are not suitable for highly saline brines. The super austenite UNS N08031 showed a temperature depending behavior. In non-saline environments the low-alloyed steel UNS G41300 (beside of the higher alloyed materials) could be employed as a constructional material for the geothermal power plant, as long as a sufficient wall thickness of the material is considered.
To set up recommendations on how to define “reasonable minimum composition thresholds” for CO2 streams to access CO2 pipeline networks, we investigated potential impacts of CO2 streams with different and temporally variable compositions and mass flow rates along the CCS chain. All investigations were based on a generic “CCS cluster scenario” in which CO2 streams captured from a spatial cluster of eleven emitters (seven fossil-fired power plants, two cement plants, one refinery and one steel mill) are collected in a regional pipeline network. The resulting CO2 stream (19.78 Mio t impure CO2 per year) is transported in a trunk line (onshore and offshore) and injected into five generic replicate storage structures (Buntsandstein saline aquifers) offshore. Experimental investigations and modeling of selected impacts revealed beneficial as well as adverse impacts of different impurities and their combinations. Overall, no fundamental technical obstacles for transporting, injecting and storing CO2 streams of the considered variable compositions and mass flow rates were observed. We recommend to define minimum composition thresholds for each specific CCS project through limiting
i) the overall CO2 content,
ii) maximum contents of relevant impurities or elements,
iii) acceptable variability of concentrations of critical impurities, and defining impurity combinations to be avoided.
Within the last years the use of feasible alternative energy sources has risen and is going to replace fossil resources more and more. Nevertheless, service conditions in solar facilities are due to the chemical composition of heat transmission media and temperatures, in many cases, extreme in terms of corrosion. Since the construction of power plants shall be economical with maximum life service, materials selection based on preliminary material qualification is essential to guarantee a secure and reliable operation of those facilities.
The materials selection depends on the operation temperature of a power plant on the chemical composition of the transmission fluid used. In high corrosive environments Ni-based alloys are often used as an all-round solution for the construction of corrosion resistant parts, because of their good corrosion properties. However, there might be limits for their use regarding their corrosion behavior, with which this contribution deals.
By means of electrochemical measurements and exposure tests the suitability of two high alloyed materials X8NiCrSi38-18 and NiCr25FeAlYB in molten nitrate salt (60 % NaNO3/40 % KNO3) was characterized at 600 °C.
Synergistic effects of impurities in the condensate on the corrosion of CO2 transport pipeline
(2017)
For the reliability of transport pipelines the corrosion resistance of the materials used needs to be determined in conditions, which are possible during the transport process. In some situations condensation of components out of the CO2 stream can occur. To study the effect of condensate on transport pipeline steel, a “worst-case scenario” gas mixture, containing 2.5 % H2O, 1.8 % O2, 1000 ppmv NO2, and 220 ppmv SO2, was proposed, fed (1.5 L/min) into a glass reactor containing coupon-shaped specimens for 120 600 h at 278 K (to simulate the underground pipeline transport), and resulted in the condensate containing 0.114 M H2SO4 and 0.0184 M HNO3 (pH 2.13). Basing on this “original” condensate, exposure tests and electrochemical characterization together with pH and conductivity in CO2 saturated condition at the same temperature were carried out. The role of each gas impurity and the combination of them, when the condensate is formed, was studied by investigating the role of individual and varying combination of acidic components in the condensate on the corrosion behaviors of the commercial pipeline-steel (L360NB). It can be concluded that although the condensation of NOx in form of HNO3 causes faster corrosion rate, it is the condensation of SOx or the combination of SOx and NOx that may cause much more severe problems in form of localized and pitting corrosions. Different to the corrosion products formed in CO2 atmosphere without impurities (mainly iron carbonate) the corrosion products resulted from these acidic condensation have no protectability, indicating the need of controlling gas quality during the transportation within the pipeline network.