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The process chain for Carbon Capture and Sequestration (CCS) includes tubing for injection of CO2 into saline aquifers. The compressed CO2 is likely to contain specific impurities; small concentrations of SO2 and NO2 in combination with oxygen and humidity are most harmful. In addition, CO2 saturated brine is supposed to rise in the well when the injection process is interrupted. The material selection has to ensure that neither CO2 nor brine or a combination of both will leak out of the inner tubing. In this comprehensive paper the investigated materials range from low-alloy steels and 13% Cr steels up to high-alloy materials. Electrochemical tests as well as long term exposure tests were performed in CO2, in brine and combination of both; pressure was up to 100 bar, temperature up to 60 °C. Whereas the CO2 stream itself can be handled using low alloy steels, combinations of CO2 and brine require more resistant materials to control the strong tendency to pitting corrosion. The corrosion behavior of heat-treated steels depends on factors such as microstructure and carbon content. For different sections of the injection tube, appropriate materials should be used to guarantee safety and consider cost effectiveness.
Carbon capture and storage (CCS) includes processing of supercritical carbon dioxide (scCO2). The carbon dioxide (CO2) stemming from flue gases contains acid forming impurities, especially in the case of coal fired power plants. In the present work, the mobility and reactivity of acids in supercritical scCO2 was investigated. The corrosive attack of low alloyed carbon steel (material 1.0484) by water (H2O) alone in scCO2 was negligible. Nitric acid (HNO3) was very mobile and corrosive towards the carbon steel while sulfuric acid did not migrate through the scCO2 to react with the steel surface. Hydrochloric acid in scCO2 was very mobile and reactive towards both carbon steel and high alloyed test equipment. Gravimetric analyses revealed a severe material loss after corrosion in the presence of HNO3. Thickness measurements showed localized material losses.
In corrosive environments such as CCS bore holes or geothermal power plants the materials loaded cyclically are also exposed constantly to the highly corrosive hot thermal water. The lifetime reduction of (X46Cr13, AISI 420C) is demonstrated in in-situ-laboratory experiments (T=60 °C, geothermal brine: Stuttgart Aquifer flow rate: 9 Nl/h, CO2). S-N plots, micrographic-, phase-, fractographic- and surface analysis were applied to obtain sustainable information on the corrosion fatigue behavior. Maximum number of cycles (here 12.5 x 106 cycles to failure) is reached at σa =173 MPa. No typical fatigue strength exists and passive corrosion fatigue is most likely failure cause.
Static immersion tests of potential injection pipe steels 42CrMo4, X20Cr13, X46Cr13, X35CrMo4, and X5CrNiCuNb16-4 at T = 60 °C and ambient pressure, as well as p = 100 bar were performed for 700–8000 h in a CO₂-saturated synthetic aquifer environment similar to CCS sites in the Northern German Basin (NGB). Corrosion rates at 100 bar are generally lower than at ambient pressure. The main corrosion products are FeCO₃ and FeOOH with surface and local corrosion phenomena directly related to the alloy composition and microstructure. The appropriate heat treatment enhances corrosion resistance. The lifetime reduction of X46Cr13, X5CrNiCuNb16-4, and duplex stainless steel X2CrNiMoN22-5-3 in a CCS environment is demonstrated in the in situ corrosion fatigue CF experiments (axial push-pull and rotation bending load, 60 °C, brine: Stuttgart Aquifer and NGB, flowing CO₂: 30 L/h, +/- applied potential). Insulating the test setup is necessary to gain reliable data. S-N plots, micrographic-, phase-, fractographic-, and surface analysis prove that the life expectancy of X2CrNiMoN22-5-3 in the axial cyclic load to failure is clearly related to the surface finish, applied stress amplitude, and stress mode. The horizontal grain attack within corrosion pit cavities, multiple fatigue cracks, and preferable deterioration of austenitic phase mainly cause fatigue failure. The CF life range increases significantly when a protective potential is applied.
In CCS environment (carbon capture and storage) pipes are loaded statically and/or cyclically and at the same time exposed constantly to the highly corrosive hot thermal water. Experimental procedures such as ambient pressure immersions tests, in-situ corrosion fatigue experiments using a flexibly designed corrosion chamber at ambient pressure and a specially designed corrosion chamber at high pressure. Experimental set-ups for push/pull and rotation bending load are introduced. The corrosion behavior and lifetime reduction of high alloyed steels (X46Cr13, 1.4043), (X5CrNiCuNb16-4, 1.4542) and (X2CrNiMoN22-5-3, 1.4462) is demonstrated (T=60 °C, geothermal brine: Stuttgart Aquifer flow rate: 9 l/h, CO₂).
Static immersion tests of potential injection pipe steels 42CrMo4, X20Cr13, X46Cr13, X35CrMo4, and X5CrNiCuNb16-4 at T = 60°C and ambient pressure, as well as p = 100 bar were performed for 700–8000 h in a CO2-saturated synthetic aquifer environment similar to CCS sites in the Northern German Basin (NGB). Corrosion rates at 100 bar are generally lower than at ambient pressure. The main corrosion products are FeCO3 and FeOOH with surface and local corrosion phenomena directly related to the alloy composition and microstructure. The appropriate heat treatment enhances corrosion resistance. The lifetime reduction of X46Cr13, X5CrNiCuNb16-4, and duplex stainless steel X2CrNiMoN22-5-3 in a CCS environment is demonstrated in the in situ corrosion fatigue CF experiments (axial push-pull and rotation bending load, 60°C , brine: Stuttgart Aquifer and NGB, flowing CO2: 30 L/h, +/- applied potential). Insulating the test setup is necessary to gain reliable data. S-N plots, micrographic-, phase-, fractographic-, and surface analysis prove that the life expectancy of X2CrNiMoN22-5-3 in the axial cyclic load to failure is clearly related to the surface finish, applied stress amplitude, and stress mode. The horizontal grain attack within corrosion pit cavities, multiple fatigue cracks, and preferable deterioration of austenitic phase mainly cause fatigue failure. The CF life range increases significantly when a protective potential is applied.
When engineering a Carbon Capture and Storage site (CCS) local corrosion (pitting) of the injection pipe steel may become an issue when emission gasses from oxyfuel power plants are compressed into deep geological layers. This highly corrosive environment arises when the flue gasses, mainly composed of CO2 , are injected into saline aquifer water. Immediately carbonic acid is formed causing corrosive attack of the injection steels. The influence of heat treatment on the local corrosion resistance was demonstrated in laboratory experiments at 60 °C and ambient pressure for three steels X46Cr13 (1.4034), X20Cr13 (1.4021) and X5CrNiCuNb16-4 (1.4543) under a similar liquid corrosive environment as found at a geological onshore CCS-site in the Northern German Bassin.
The CCS technique involves the compression of emission gasses in deep geological layers. To guarantee the safety of the site, C02-corrosion of the injection pipe steels has to be given special attention when engineering CCSsites. To get to know the corrosion behaviour samples of the heat treated Steel 1.72252CrMo4, used for casing, and the stainless injection-pipe Steel 1.4034 X46Cr 13 were kept at T=60 °C and ambient pressure as well as p=100 bar for 700 h - 8000 h in a C02-saturated synthetic aquifer environment similar to possible geological on-shore CCS-sites in the northern German Basin. The isothermal corrosion behaviour obtained by mass gain of the steels in the gas phase, the liquid phase and the intermediate phase gives surface corrosion rates around 0.1 to 0.8 mm/year at ambient pressure and much lower about 0.02 to 0.2 mm/year at 100 bar where the C02 is in its supercritical state. Severe pit corrosion with pit heights around 4.5 mm are only located on the 42CrMo4 Steel. Main phase of the continuous complicated multi-layered carbonate/oxide structure is siderite FeCO} in both types of Steel.
Properties of pipe steels for CCS technology require resistance against the corrosive environment of a potential CCS-site (heat, pressure, salinity of the aquifer, CO2-partial pressure). The influence of austenitizing in heat treatment routines of two different injection pipe steels (1.4034, X46Cr13 and 1.4021, X20Cr13) was evaluated. Steel coupons were austenitized at different temperatures (900 – 1050 °C) for different lengths of time (30–90 min) before quenching and annealing prior to long term corrosion experiments (60°C, 100 bar, artificial brine close to a CCS-site in the Northern German Basin, Germany). In general, fewer pits are found on X46Cr13. Comparing steels with 13% chromium each the higher carbon content of X46Cr13 (0.46% C) results in a lower number of pits compared to X20Cr13 (0.20% C). It is found that neither the carbon content of the steels nor austenitizing temperature has much influence, but local corrosion behaviour is most susceptible towards austenitizing time