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Organisationseinheit der BAM
Coupons of X5CrNiCuNb16-4 that may be used as injection pipe with 16% Chromium and 0.05% Carbon (1.4542, AISI 630) were exposed for 3000 h to CO2-saturated saline aquifer water similar to the conditions in the Northern German Basin at ambient pressure and 60 °C. Surface corrosion layers and pits reveal carbonate corrosion products on the surface such as FeCO3 and FeOOH as the main precipitation phases with no dependence on the original surface roughness. Corrosion rates for polished and technical surfaces were below 0.005 mm/year compared to corrosion rates of 0.035 mm/year after shot peening.
Coupons of X5CrNiCuNb16-4 with different surface roughness that may be utilized as injection pipe with 16% Chromium and 0.05% Carbon (1.4542, AISI 630) were exposed for 3000 h to CO2-saturated saline aquifer water simulating the conditions in the Northern German Basin at ambient pressure and 60 °C. Additionally, corrosion fatigue experiments (ambient pressure, technically clean CO2, saline aquifer water of Stuttgart Aquifer) were performed using specimen of X46Cr13 (1.4043, AISI 420C) with regard to the influence of the roughness of technical surfaces on the number of cycles to failure at different stress amplitudes. Specimen of Duplex stainless steel X2CrNiMoN22-3-2 (1.4462) for corrosion fatigue experiments were provided with technical surfaces after machining as well as polished surfaces. Results were obtained at load amplitudes ranging from 175 MPa to 325 MPa in the geothermal brine of the Northern German Basin at 98 °C. The main precipitation phases on the surface as well as within pits reveal carbonates or hydroxides such as siderite (FeCO3) and ferrous hydroxide goethite (FeOOH) independent of the original surface roughness. Corrosion rates for polished and technical surfaces were below 0.005 mm/year compared to corrosion rates of 0.035 mm/year after shot peening. Specimen with technical surfaces tested at high stress amplitudes (>275 MPa) lasted longer (cycles to failure: P50% at Sa 300 MPa=5x105) than specimen with polished surfaces (cycles to failure: P50% at Sa 300 MPa=1.5x105). This behavior is emphasized by the slope coefficient (technical surfaces k = 19.006, polished surfaces k=8.78) meaning earlier failure for polished at high stress amplitude Sa. Although rather low scatter ranges (technical surface: TN=1:1.35, polished surface: TN=1.1.95) indicate no change in failure mechanism it may be assumed that at low stress pitting is the initiating crack growth process whereas at high stress amplitudes the formation of micro cracks is reason for crack propagation and failure.
The appropriate strength of steels used for saline aquifer carbon capture and storage sites (CCS) is usually achieved by applying heat treatments. Thus, heat treatment influences the corrosion resistance for injection pipe steels with 13% chromium and different carbon content: 1.4034/X46Cr13 and 1.4021/X20Cr13 in CO2 saturated saline aquifer water at 60 °C, 1 and 100 bar. X46Cr13 shows better corrosion resistance with respect to corrosion rate, number of pits and maximum intrusion depth. Low corrosion rates are obtained for steels with martensitic microstructures exposed to supercritical CO2 at 100 bar, whereas normalized steels show better corrosion resistance at ambient pressure.
CO2-induced corrosion of casing and tubing steels is a relevant safety issue for compressing emission gasses into deep geological layers (CCS, Carbon Capture and Storage). The influence of CO2 and pressure of the surrounding media on steels is demonstrated in laboratory experiments providing a corrosive environment similar to a geological onshore CCS-site in the Northern German Basin (T = 60 °C, p = 1 - 100 bar, Stuttgart Aquifer, CO2-flow rate of 3 l/h, 7008000 h exposure time). Corrosion kinetics and microstructures were characterized using specimens of heat treated 42CrMo4 (1.7225, casing) and soft annealed X46Cr13 (1.4034, tubing).
In the field of water pipelines, geothermal energy production as well as carbon capture and storage technology (CCS) materials have to provide a high resistance to corrosion and mechanical stress. The combination of cyclic load and corrosive aqueous environment leads to corrosion fatigue of pipes and components (e.g. pumps) and thus inevitably to the reduction of the lifetime of these components. To estimate the reliability of components from adjusted in-situ-laboratory experiments a corrosion chamber was designed and tested with CO2 saturated corrosive aqueous media flowing at a steady rate. Unique feature of this special chamber is its installation directly onto the sample and thus providing flexible usability in almost every testing machine. This allows simultaneous mechanical loading of the sample, operation at temperatures up to 100 °C and exposure to fluid flow of corrosive liquids and gases. The lifetime reduction of AISI 420C (X46Cr13, 1.4034) is demonstrated at T=60 °C, geothermal brine: Stuttgart Aquifer flow rate: 9 l/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 may be identified as failure cause.
The lifetime reduction of cyclically loaded AISI 420C (X46Cr13, 1.4034) constantly exposed to highly corrosive CO2-saturated hot thermal water is demonstrated in in situ-laboratory experiments (60 °C, brine: Stuttgart Aquifer, flowing CO2: 30 L/h). SN plots, micrographic-, phase-, fractographic- and surface analysis were applied to obtain sustainable information on the corrosion and corrosion fatigue behavior. Maximum number of cycles (here 12.5 × 106 cycles to failure) is reached at σa = 173 MPa. Hydroxide and siderite layers were found on pits and crack surfaces. No typical fatigue limit exists and pit corrosion prior to crack initiation may be identified as failure cause.
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.
During carbon dioxide storage technology (carbon capture and storage, CCS) components are exposed to a corrosive environment and mechanical stress, which results in corrosion fatigue and inevitably followed by the a lifetime reduction of these components. In order to gain knowledge upon the corrosion fatigue strength of materials, Samples of high alloyed stainless injection-pipe steels AISI 420 X46Cr13, and X5CrNiCuNb16-4 AISI 630 were tested in a at T=60 °C and ambient pressure in a CO2-saturated synthetic aquifer environment similar to possible geological on-shore CCS-sites in the northern German Basin. Therefore a corrosion chamber applied to a resonant testing machine allowing for “in situ” test conditions was designed and successfully tested. In-situ tension compression experiments were established using a resonant testing machine at a frequency as low as 30 – 40 Hz. In addition technical CO2 was introduced into the closed system at a rate close to 9 L/h to keep stable environmental conditions. Simultaneously electrochemical testing was performed to get information on failure causes and the mechanism of failure during the injection of CO2 into deep geological layers. S-N plots, micrographic analysis, and surface analysis of the fracture surface were applied to obtain sustainable information on the corrosion fatigue behavior of injection pipe steels. Samples used have a surface roughness of Rz = 4, to simulate technically machined surfaces. X46Cr13 reached the maximum number of cycles (12.5 x 106) at a stress amplitude of 173 MPa. X5CrNiCuNb16-4 reached the maximum number of cycles (10 x 106) at a stress amplitude at 150 MPa. The scatter range of X5CrNiCuNb16-4 is very high (1:34); by comparison the scatter range of X46Cr13 is only 1:3.5.