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In the last years geothermal power has become a reliable and significant energy source. Because service conditions in geothermal facilities from deeply located aquifers are critical in terms of corrosion, materials selection is a very important issue. Preliminary evaluation of the materials suitability represents therefore a valuable strategy to ensure a secure and reliable operation of the facilities. In geothermal applications, the use of high-alloyed materials such as superaustenitic stainless steels, and nickel-based alloys has been considered as a good alternative because of their remarkable corrosion resistance and appropriate mechanical properties. Nevertheless, the corrosion behavior of those metallic materials in geothermal fluids at service conditions has not been determined in many cases. In this work, laboratory tests including electrochemical investigations and exposure tests at 100 °C and 150 °C (1,500 kPa) showed the limits of suitability concerning localized corrosion of three different, corrosion-resistant alloys in the highly saline fluid of the North German Basin.
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.
Corrosion of steel reinforcement in concrete exposed to chloride containing environments is a serious problem in civil engineering practice. Electrochemical methods, e.g., potential mapping, provide information whether the steel reinforcement is still passive or depassivation has been initiated. By applying such techniques no information on the type of corrosion, its extent and distribution of corrosion products is available. Particular the corrosion progress is a significant problem. Especially in the case of macrocell corrosion in reinforced concrete structures, the development at the anode cannot be separated into corrosion damage resulting from macrocell corrosion or self-corrosion. Until now also in laboratory tests it is impossible to collect such information without destroying specimens after electrochemical testing was performed. To overcome this problem it was tried to study the steel surface within the mortar specimens by X-ray tomography (CT). Within the scope of these investigations it could be shown, that X-ray tomography is suitable to make corrosion pits and their development visible which are embedded in a mortar with a cover thickness of about 35 mm. In this publication the time-dependent corrosion damage of reinforced steel is documented by X-ray tomography.
Condensates from the gas stream in simulated CO2 transport pipelines have been identified during the experiments in the laboratory. Because of their acidic origin the corrosion resistance of pipeline steels used for CCS (carbon capture and storage) technology might be limited. Over the last years it has become clear that the amount of water and acid building constituents in the CO2 stream has to be controlled very well. In this work, condensates formed in experiments using gaseous CO2 containing high amounts of water, NO2 and SO2 were analyzed, replicated, and used for extensive electrochemical experiments. These highly acidic condensates were enriched with CO2 and then applied to characteristic steels planned to use in the CCS transport chain. Even high alloy steels are susceptible to localized corrosion under these conditions. The results implicate that condensation of aggressive acid droplets has to be avoided or the locations where condensation takes place have to be controlled extensively.
Within the last years the use of geothermal energy as feasible energy source has risen and is going to replace fossil fuel supply more and more. Nevertheless, Service conditions in geothermal facilities are due to the Chemical composition of hydrothermal fluids and temperatures, in many cases, extreme in terms of corrosion. Since the construction of geothermal 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 ofthose facilities.
The materials selection depends on the location of a power plant respectively on the Chemical composition of the produced aquifer fluid. The duplex Steel is often used as allround solution not only for the construction of geothermal power plants, because of its combination of good mechanical and corrosion properties and its lower costs compared to other highly alloyed materials. But there are limits for the use of the duplex-steel 1.4462 regarding its corrosion behavior, with which this contribution deals.
The limitations of suitability of duplex steel 1.4462 in the geothermal fluids of Molasse Basin and Upper Rhine Graben obtained by means of electrochemical measurements and exposure tests are presented below. While 1.4462 in the artificial Molasse Basin Fluid shows an excellent corrosion resistance against pitting and uniform corrosion it presents low corrosion resistance in the artificial Upper Rhine Graben Fluid due to the difference in salinity. Besides it shows a limited corrosion resistance concerning crevice corrosion.
This study aims to evaluate which of the materials currently available on the market could overcome the Problem of corrosion and withstand highly aggressive conditions in the exploitation of geothermal resources in volcanic environments. Our investigations were triggered by the conditions on Lahendong geothermal field (North Sulawesi, Indonesia): well LHD-23 presents one of the greatest challenges due to its capacity of producing > 20 MWe of energy from a single well and in the same time having very low pH (2-3) and relatively high Chloride (1,500 mg/L) and sulphate (1,600 mg/L) concentration. Three different Steel grades (low-alloyed Steel UNS G41300, stainless Steel UNS S31603 and high-alloyed stainless Steel UNS N08031) were selected, and their corrosion behavior was evaluated by means of short-term electrochemical methods (potentiodynamic polarization) and long-term exposure tests (up to 6 months). The research was carried out in the laboratory under stagnant conditions in the artificial LHD-23 geothermal brine (1,500 mg/L Chlorides, 1,600 mg/L sulphates, pH 2) at 100 °C (100 kPa) and 175 °C (900 kPa), simulating the conditions present at the site.
Since geothermal wells are a feasible energy source to replace fossil fuel supply, many technologies have been developed to take advantage of geothermal energy. Nevertheless, service conditions in geothermal facilities are due to the chemical composition of hydrothermal waters and temperatures, in many cases, extreme in terms of corrosion. Therefore, materials selection based on preliminary material qualification is essential to guarantee a secure and reliable operation of the facilities.
This contribution deals with the evaluation of the corrosion behavior of different steels in flowing low saline, slightly alkaline, artificial geothermal water simulating the conditions in the Molasse-Basin, a location with geothermal potential in Germany.
Test results for steels UNS S31603 and UNS S31803 exposed to this geothermal water obtained by electrochemical measurements and exposure tests are presented. Results obtained in static and flowing water condition show good performance of both alloys with a possible onset of localized corrosion at UNS S31603 in static conditions.
Corrosion resistance of high-alloyed and alternative materials in an artificial geothermal water
(2014)
Many technologies have been developed to take advantage of geothermal energy, which became a feasible energy source to replace fossil fuel supply. Nevertheless, service conditions in geothermal facilities are due to the chemical composition of hydrothermal fluids and involved high temperatures, in many cases, extreme in terms of corrosion. Therefore, materials selection based on preliminary material qualification is essential to guarantee a secure and reliable operation of the facilities.
This contribution deals with the evaluation of the corrosion behavior of two high-alloyed metallic materials and α-Al2O3 in an artificial geothermal fluid simulating the conditions in the Northern German Basin, a location with high geothermal potential. The suitability of the super austenitic stainless steel UNS N08031 and the nickel base alloy UNS N06059 in this geothermal fluid obtained by electrochemical measurements and exposure tests is addressed. As an alternative to the suitable but costly UNS N06059 that showed excellent corrosion resistance against pitting corrosion, ceramic made of α-Al2O3 represents an interesting possibility for selected components to be used in the construction of geothermal facilities
Corrosion resistance of duplex stainless steel (SS) (UNS S32101) and super austenitic SS (UNS NO8031) (Alloy 31) was investigated in crevice conditions in a saline brine. Rubber was used to form a metal/non-metal-crevice confguration. UNS NO8031 did not exhibit any signs of pitting corrosion even by applying potentials much more positive than the corrosion potential.
Corrosion of metallic engineering materials accounts for problems during geothermal operation in the Upper Rhine Graben (URG). Herein, we study the electrochemical behaviour of various metal alloys in an 80 °C simulated geothermal environment by using potentiodynamic polarisation and open-circuit potential measurements. Two different natural geothermal waters from URG geothermal sites were used for the experiments. The measurements reveal spontaneous passivation to be a key process for all alloys. This ennoblement protects more noble alloys from significant corrosion (e.g. titanium gr. 2, alloy 625) and brings less noble alloys to failure, mostly due to pitting corrosion (e.g. 316L).
This paper summarizes the investigation of a serious explosion, which shattered the chemical facility of a chlorine/alkaline plant in Northern Germany in 1981. A pressure tank made from HSB 50 S steel and used as storage of liquid residues from a chlorine liquefaction process violently ruptured and the explosion threw parts of the tank approximately 100 m through the air. The local county government ordered an investigation to determine the root cause of this incident.
The main objective of the investigation was to determine whether a nitrogen overpressure or a chemical reaction of residuals inside the so-called 'Taffy' receiver caused the explosion. A fracture mechanics based analyses evaluated the conditions the material was exposed to during the damage. Metallographic and mechanical tests confirmed that the material specifications were within the values specified by the guidelines but corrosion had reduced the wall thickness considerably.
Analytical calculations to determine the minimum required pressure for the rupture and to cause plastic deformation to the tank confirmed that the failure did not occur due to nitrogen overpressure and therefore, a chemical reaction must have occurred. A detailed chemical analysis confirmed that the explosive disintegration of methylnitrate, which is highly sensitive to heat and impact, and its halogenated derivatives likely caused the incident. Due to the design and operational mode of the plant, impurities could accumulate and form explosive compounds in the Taffy receivers without control.
In Germany the "BAM-List - Requirements for Tanks for the Transport of Dangerous Goods" is the basis for substance-related prototype approvals for tank Containers undertaken by the BAM - Federal Institute for Materials Research and Testing. Compatibility evaluations of selected metallic materials as well as of polymeric gasket and lining materials under the influence of approximately 7000 dangerous goods have been published in the BAM-List since 1989.
The duplex Steel 1.4362 (2304, UNS S32304) was originally developed as substitute for the austenitic grades 1.4404 (316L, UNS S31603) and 1.4571 (316Ti, UNS S31635). Due to its characteristic profile this Steel was qualified for applications requiring high strength values at concomitant adequate corrosion resistance. Because of its lower content of the alloy elements nickel and molybdenum this duplex Steel is a cost-efficient alternative to the molybdenum containing austenite. Only a limited number of corrosion test results of 1.4362 under the influence of dangerous goods published in the BAM-List were available. Therefore test specimens of this Steel were exposed to selected corrosive substances.
Due to the reduced alloy content a reduced corrosion resistance of the duplex Steel 1.4362 in acidic substances, such as formic acid, acetic acid and sulfuric acid, in comparison to the austenitic CrNiMosteels was observed. Tests in the alkaline medium showed a sufficient resistance.
Although the complex changes at the steel-concrete interface due to cathodic polarisation are widely acknowledged to have a beneficial influence concerning the cathodic protection (CP) of steel in concrete, some questions concerning the repassivation of carbon steel in consequence of cathodic polarisation are still not satisfactorily clarified. In the recent literature, some indications are presented that repassivation occurs after a certain time of polarisation. Therefore, the investigations discussed in this paper aim to clarify, to what extent the re-passivation of carbon steel due to cathodic polarisation occurs, and if the ennoblement of OCP is a sufficient indication for repassivation. In a first step, the corrosion state of five nominal equal test specimens was determined by electrochemical impedance spectroscopy (EIS). After determining the initial corrosion state by evaluating the charge transfer resistance and the polarisation resistance, respectively, the specimens were polarised cathodically. Impedance data were recorded before, during and after polarisation. The impedance data were evaluated by equivalent circuit fitting with special attention to charge transfer resistances and the impact of diffusion on the corrosion and polarisation behaviour. The results indicate that the reduction of oxides and oxygen diffusion during cathodic polarisation has strong impact on the systems behaviour and that repassivation effects occur after switching off the polarisation current and during depolarisation, respectively.
The corrosion behaviour of martensitic stainless injection-pipeline steel X46Cr13 exposed to CO2 saturated artificial saline brine with high chloride concentration similar to onshore CCS-site at Ketzin, Germany has been investigated by means of electrochemical technique and microscopic observations at short exposure times (up to 24?h) and by mass loss and metallographic observations at exposure times up to 17520?h. Pitting corrosion kinetics has been characterised and the predictions about the corrosion mechanism are made.
Alloy 59 (NiCr23Mo16Al) with a lot of chromium, molybdenum and nickel possesses excellent resistance not only to reducing but also oxidizing chemicals. Both the Nickel alloy 59 and the superaustenitic steel alloy 31 have already been used as shell materials for tank vehicles or tank containers. Use of these alloys allows the transport of a signifi-cantly more wider variety of chemicals and, especially, waste mixtures than the use of common aus-tenitic steels. Another advantage is the extension of test intervals of for transport tanks. In Germany the 'BAM-List – Requirements for Tanks for the Transport of Dangerous Goods' is the basis for substance-related prototype approvals for tank containers designed for the carriage of dangerous goods issued by the Federal Institute for Materials Research and Testing (BAM). Com-patibility evaluations of selected metallic material groups as well as polymeric gasket and lining materials under the influence of approximately 7000 dangerous goods and water-polluting sub-stances are published in the BAM-List. Alloy 59 belongs to the group of metallic materials in the BAM-List. Due to the large number of dangerous goods in the BAM-List BAM, IKS Dresden and ThyssenKrupp VDM performed a comprehensive corrosion test programme with welded specimens of the nickel alloy 59 and the superaustenitic steels alloy 926 and alloy 31 in the period 2002 - 2010. Especially In particular alloy 59 and alloy 31 were exposed to a large number of corrosive sub-stances such as various mixtures of both nitric acid/sulphuric acid and nitric acid/phosphoric acid at 55 °C. Other corrosive test substances were different organic and inorganic halogenides, peroxyace-tic acid and molten substances. In the case of molten chemicals such as monochloroacetic acid the test temperature was increased to more than 100 °C. The test results presented in this paper are al-ready included in the 10th edition of the BAM-List and, therefore, available to the customer.
In engineering storage sites for Carbon Sequestration the CO2-induced corrosion of injection pipe steels is a relevant safety issue when emission gasses are compressed in deep geological layers. The reliability of the steels suitable for the geological onshore CCS-site (Carbon Capture and Storage) at Ketzin, Germany, is demonstrated in laboratory experiments in equivalent corrosive environment (T = 60 °C, p = 160 bar, aquifer water, CO2-flow rate of 3 L/h, 7008000 h exposure time). Corrosion kinetics and microstructures were characterized using specimens of the heat treated steel 42CrMo4 (1.7225) used for casing, and specimens of the martensitic stainless injection-pipe steel X46Cr13 (1.4034).
CO2 streams captured from power stations or industrial plants may contain impurities that impact the consecutive steps of the CO2 capture and storage (CCS) chain. As the basis for an optimization of CO2 purity over the whole CCS chain, impacts of different impurities were investigated at key steps including studies on (i) corrosion of metallic materials in CO2 streams and brine, (ii) fluid and interfacial properties as a function of pressure, temperature and CO2 stream composition and their implications for CO2 transport, injection and geological storage, (iii) costs of different pipeline design options, (iv) geochemical alterations at typical reservoir conditions and their implications for geomechanical rock properties. Major findings are synthesized for two exemplary single source-single sink CCS chain scenarios involving CO2 stream compositions typical for pre-combustion capture and oxyfuel combustion. Recommendations for material selection for compression, transport and injection were derived for various CO2 stream compositions. To reliably control corrosion, a limitation of water contents to 50 ppmv is recommended for pipeline transportation of all CO2 streams. At geological storage conditions, the presence of either O2, NOx or SO2 only weakly affected fluid-mineral/rock interactions that still impacted geomechanical rock properties.
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.
Experiences from the electrochemical characterization of materials in aqueous solutions are transferred to molten salts, providing a good addition to common exposure tests at temperatures from 450 0C to 600 0C.
By means of electrochemical measurements and exposure tests the suitability of high alloyed materials in molten nitrate salt (60 % NaNO3/40 % KNO3) can be characterized. The method was verified on different Ni-based alloys (UNS N08810, UNS N06600) and Titanium (UNS R50250).
In the literature there are not much data available to describe the corrosion behavior of titanium, nickel alloys and special stainless steels in acids at high temperature, in particular above the boiling point. Therefore, a laboratory testing program was performed with two titanium alloys (UNS R50400 and UNS R53400) to obtain corrosion data in formic acid, acetic acid, phosphoric acid, polyphosphoric acid, p-toluene sulfonic acid and lactic acid at 200 °C. Results were compared to previously published ones obtained on UNS N08031, UNS N06059 and UNS N10665.
From the results it can be concluded that titanium does not always show better corrosion resistance than Ni-based alloys.
UNS N06059 was the best choice for formic and acetic acids at temperatures of 200 °C. Both Ti-alloys are resistant in acetic acid. Some slight differences were observed for formic acid, where UNS R50400 is only resistant up to a 20 % solution and UNS R53400 in concentrated acid too. The phosphoric acid is extremely corrosive and none of the investigated materials was resistant. In the diluted acid (5 %) only UNS R53400 is resistant, whereas in 1 % solution all investigated materials performed satisfactory. UNS N10665 and UNS N06059 showed the best behavior in polyphosphoric acid. In 30 % concentrated p-toluene sulfonic acid at 200 °C all alloys tested were unsuitable. In very diluted acid (0.1 %) both Ti-alloys and the other three alloys behaved well. In lactic acid at 180 °C increased corrosion underneath deposits was detected; the best performance was observed for UNS N06059 and UNS R50400.
The corrosion behavior of carbon Steel and different high-alloyed metals 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.
The suitability of low alloyed Steel UNS G41300, stainless steels UNS S31603 UNS S31803, UNS S32760 and super austenitic Steel UNSN08031 in these geothermal waters, investigated by electrochemical measurements and exposure tests, is limited. The nickel based alloy UNS N06059 shows excellent corrosion resistance against pitting corrosion. Excluding its high cost, it is a very good alternative to be used in the construction of geothermal facilities having highly sahne brines. Stainless and duplex steels exhibit a limited corrosion resistance concerning pitting and crevice corrosion.
Besides the higher alloyed materials, also the low-alloyed Steel UNS G41300 could be employed as a constructional material for the geothermal power plant in non-saline environments with moderate pH, as long as the wall thickness of the material vs. corrosion rate is taken into account.
Among all of the existing electric power generation facilities, corrosion is considered to be the most severe on geothermal power plants. The focus of this research was set to evaluate the suitability of carbon steel API Q125 as a construction material on the geothermal sites Sibayak and Lahendong, Indonesia. The investigations were performed in the artificial geothermal brines under stagnant conditions by means of short-term electrochemical methods (Tafel extrapolation) and long-term exposure tests (up to 6 months). Furthermore, the influence of different parameters on the steels performance (temperature 70 °C, 100 °C and 175 °C, salinity 20 mg/L and 1,500 mg/L chlorides, pH 2 and 4) was assessed as well to ensure a “safer operating window” of a power plant.
The results showed carbon steel API Q125 could be suitable for application in stagnant geothermal brines up to temperatures of 175 °C and a chloride concentration of 1,500 mg/L. Its applicability is limited in highly acidic environments (pH 2).
In the literature there are not much data available to describe the corrosion behavior of titanium, nickel alloys and special stainless steels in acids at high temperature, in particular above the boiling point. Therefore, a laboratory testing program was performed with two titanium alloys (grade 2 - UNS R50400 and grade 12 - UNS R53400) to obtain corrosion data in formic acid, acetic acid, phosphoric acid, polyphosphoric acid, p-toluene sulfonic acid and lactic acid at 200 °C. Results were compared to previously published ones obtained on alloy 31 (UNS N08031), alloy 59 (UNS N06059) and B-2 (UNS N10665).
From the results it can be concluded that titanium does not always Show better corrosion resistance than Ni-based alloys,
Alloy 59 was the best choice for formic and acetic acids at temperatures of 200°C. Both Ti-alloys are resistant in acetic acid. Some slight differences were observed for formic acid, where Ti grade 2 is only resistant up to a 20 % solution and grade 12 in concentrated acid too. The phosphoric acid is extremely corrosive and none of the investigated materials was resistant. In the diluted acid (5 %) only Ti grade 12 is resistant, whereas in 1 % solution all investigated materials withstand. Alloy B-2 and alloy 59 showed the best behavior in polyphosphoric acid. In 30 % concentrated p-toluene sulfonic acid at 200 °C all alloys tested were unsuitable. In very diluted acid (0.1 %) both Ti-alloys and the other three alloys behaved well. In lactic acid at 180 °C increased corrosion underneath deposits was detected; the best performance was observed for alloy 59 and Ti grade 2.
In the last years, geothermal power has become a reliable and significant energy source. Because service conditions in geothermal facilities from deeply located aquifers are usually critical in terms of corrosion, materials selection is a very important issue. Preliminary evaluation of the material's suitability represents therefore a valuable strategy to ensure a secure and reliable operation of the facilities. In geothermal applications, the use of high-alloyed materials such as superaustenitic stainless steels, duplex stainless steels, and nickel-based alloys has been considered as a good alternative because of their remarkable corrosion resistance and appropriate mechanical properties. Nevertheless, the corrosion behavior of those metallic materials in geothermal fluids at service conditions has not been determined in many cases. In this work, laboratory tests including electrochemical investigations and exposure tests at 100 degrees C and 150 degrees C (1,500 kPa) showed the limits of suitability concerning localized corrosion of three different, corrosion-resistant alloys in the highly saline fluid of the North German Basin.
Geothermal sources are found to be the most aggressive natural environments for construction materials in terms of corrosion. This study was focused on investigating the suitability of stainless steel UNS S31603 in volcanic areas of geothermal sites Sibayak and Lahendong (Indonesia). Influence of different factors (temperatures up to 175 °C, chloride content up to 1500 mg/L and pH down to 2) was assessed to determine a 'safe operating window' of a power plant and assure the system integrity. Investigations were performed by means of electrochemical methods and long-term exposure tests.
Many technologies have been developed to take advantage of geothermal energy, which became a feasible energy source to replace fossil fliel supply. Nevertheless, Service conditions in geothermal facilities are due to the Chemical composition of hydrothermal fluids and involved high temperatures, in many cases, extreme in terms of corrosion. Therefore, materials selection based on preliminary material qualification is essential to guarantee a secure and reliable Operation ofthe facilities.
This contribution deals with the evaluation of the corrosion behavior of two high-alloyed metallic materials and a-A1203 in an artificial geothermal fluid simulating the conditions in the Northern German Basin, a location with high geothermal potential. The suitability of the super austenitic stainless Steel, alloy 31, and the nickel base alloy 59 in this geothermal fluid obtained by electrochemical measurements and exposure tests is addressed. As an alternative to the suitable but costly alloy 59 that showed excelient corrosion resistance against pitting corrosion, ceramic made of a-A1203 represents an interesting possibility for selected components to be used in the construction of geothermal facilities.
C02-corrosion on piping steels might cause problems during injection of flue gases for their storage in deep geological aquifer fluids. Therefore, the selection of appropriate piping steels is a key factor to increase safety and reliability of the Carbon Capture and Storage (CCS) technology, and to keep the process cost-efficient.
Within the project COORAL (German acronym for “C02 purity for capture and storage”) corrosion studies on injection piping steels exposed to C02 and artificial brine with high Chloride concentration have been carried out. Corrosion of the injection pipe in C02-rich aquifer fluid may occur within the aquifer brine or when at injection interruptions the aquifer fluid may flow back into the injection pipe. Because of high salinity of aquifer brine and C02-corrosion an appropriate material ranking of injection piping steels should be made.
Corrosion resistance of steels 1.4034, 1.4021, 1.4542, 1.4162 and 1.4562 was investigated in a corrosive environment using electrochemical and metallographic techniques. Electrochemical experiments in order to investigate the surface corrosion kinetics and polarization measurements in order to investigate localized corrosion phenomena have been carried out. Critical pitting potentials and repassivation potentials were determined by polarization curves of investigated materials and compared with measured corrosion potentials. Measured values were used in order to determine the suitability and performance of tested steels in C02-injection conditions.
Aging of passive film formed on UNS N08031 was investigated as a function of passivation time in Green-Death solution at 40°C. The specimen surface was in a stable passive state in the solution.
The passive current density increased with an increase in the passivation potential. Electrochemical Impedance Spectroscopy and Mott–Schottky (M–S) analyses revealed that a more defective n-type
semiconductive passive film formed as the potential increased while the film became stable as the defects in the film decreased at potential lower than 1.0 VSSE. The increase of the applied potential and the polarisation time are likely reasons for the change in passive film stability.
Comparison of the corrosion resistance to dangerous goods of austenitic CrNiMo and duplex steels
(2014)
The “BAM-List - Requirements for Tanks for the Transport of Dangerous Goods” is the basis in Germany for substance-related prototype approvals for tank Containers in Germany. Compatibility evaluations of selected metallic materials and polymeric materials under the influence of approximately 7200 dangerous goods have been published in the BAM-List since 1989. The austenitic CrNi- and CrNiMo-steels - UNS S30403, UNS S31600, UNSS31603 and UNS S31635 - are the materials mostly used worldwide for transport tanks. The duplex Steel UNS S31803 has been put on the BAMList due to the great interest of tank producers and transport Companies. Using UNS S31803 instead of 316L, the weight of the tanks can be reduced, and the list of transportable goods can be extended. The objective of these investigations was to compare the corrosion resistance of duplex Steel UNS S31803 and austenitic Steel UNS S31603. Therefore, test specimens of both steels were exposed to selected corrosive substances, such as formic acid, acetic acid, phosphoric acid, sulfuric acid, nitrating acid, monochloroacetic acid and trichloroacetone at 55 °C (30 °C, 70 °C). The test results have shown that the duplex Steel UNSS31803 is a good alternative to austenitic CrNiMo-steel UNS S31603 for tanks carrying corrosive dangerous goods.
Geothermal energy is an interesting alternative to polluting fossil energy sources. Therefore, in Belgium, two wells have been drilled for a deep geothermal power plant. However, the environment to which the installations are exposed is challenging. The geothermal brine has 165 g/l total dissolved solids (of which 90% are sodium and chlorine) and the production temperature can be up to 130 °C. To assess their suitability to be used in a geothermal power plant, the corrosivity of the artificial brine to three common construction materials was investigated with exposure and electrochemical tests. The metals under consideration are a low-alloyed carbon steel (S235JR), an austenitic stainless steel (UNS S31603) and a duplex stainless steel (UNS S31803). The carbon steel, that was found to corrode uniformly, could be considered as a constructional material if a sufficient wall thickness is chosen. The austenitic stainless steel and the duplex stainless steel demonstrate very low uniform
corrosion rates. They are however susceptible to pitting and crevice corrosion. To guarantee safe operation of the geothermal power plant, the susceptibility of the alloys to stress corrosion cracking should be tested and in situ experiments should be performed.
Geothermal brines often contain high amounts of lead and copper ions that can precipitate as native Cu and Pb as consequence of galvanic corrosion when brines react with carbon steel materials. This contribution evaluates which materials could overcome the problem of galvanic corrosion at geothermal environment.
The behavior of these materials in water containing high chloride concentration (> 100 g/L NaCl) as well as various amounts of dissolved bCl2 and/or CuCl2 was characterized by electrochemical and exposure measurements.
Both methods reveal carbon steel suffers corrosion susceptibility, accompanied by Cu◦ and/or Pb◦ precipitation on the surface. Electrochemical measurements on stainless steels result in significant difference in corrosion and repassivation potentials (Ecorr = -189 mV, Erep = 70 mV), indicating a good corrosion resistance.
The passivation behavior of alloy 31 was investigated as a function of passivation potential in a green-death solution at 40 °C. The alloy 31 surface is in a stable passive state during cyclic potentiodynamic polarization. In potentiostatic polarization of alloy 31, passive current density increases with an increase in the passivation potential. Electrochemical impedance spectroscopy (EIS) and Mott–Schottky (M–S) analysis showed that a more defective n-type semiconductive passive film forms as the potential increases. X-ray photoelectron spectroscopy (XPS) revealed that passive film consists of mainly chromium and minor iron and nickel oxides. The increase of the applied potential is considered to be a reason for the change in passive film stability.
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.
Al2O3 has been widely used as a coating in industrial applications due to its excellent chemical and thermal resistance. Considering high temperatures and aggressive mediums exist in geothermal systems, Al2O3 can be a potential coating candidate to protect steels in geothermal applications. In this study, γ-Al2O3 was used as a coating on martensitic steels by applying AlOOH sol followed by a heat treatment at 600 °C. To evaluate the coating application process, one-, two-, and three-layer coatings were tested in the artificial North German Basin (NGB), containing 166 g/L Cl−, at 150 °C and 1 MPa for 168 h. To reveal the stability of the Al2O3 coating in NGB solution, three-layer coatings were used in exposure tests for 24, 168, 672, and 1296 h, followed by surface and cross-section characterization. SEM images show that the Al2O3 coating was stable up to 1296 h of exposure, where the outer layer mostly transformed into boehmite AlOOH with needle-like crystals dominating the surface. Closer analysis of cross-sections showed that the interface between each layer was affected in long-term exposure tests, which caused local delamination after 168 h of exposure. In separate experiments, electrochemical impedance spectroscopy (EIS) was performed at 150 °C to evaluate the changes of coatings within the first 24 h. Results showed that the most significant decrease in the impedance is within 6 h, which can be associated with the electrolyte penetration through the coating, followed by the formation of AlOOH. Here, results of both short-term EIS measurements (up to 24 h) and long-term exposure tests (up to 1296 h) are discussed.
A global transition towards more sustainable, affordable and reliable energy systems is being stimulated by the Paris Agreement and the United Nation's 2030 Agenda for Sustainable Development. This poses a challenge for the corrosion industry, as building climate‐resilient energy systems and infrastructures brings with it a long‐term direction, so as a result the long‐term behaviour of structural materials (mainly metals and alloys) becomes a major prospect. With this in mind “Corrosion Challenges Towards a Sustainable Society” presents a series of cases showing the importance of corrosion protection of metals and alloys in the development of energy production to further understand the science of corrosion, and bring the need for research and the consequences of corrosion into public and political focus. This includes emphasis on the limitation of greenhouse gas emissions, on the lifetime of infrastructures, implants, cultural heritage artefacts, and a variety of other topics.
Early Stage of Corrosion Formation on Pipeline Steel X70 Under Oxyfuel Atmosphere at Low Temperature
(2020)
The early stage of corrosion formation on X70 pipeline steel under oxyfuel atmosphere was investigated by applying a simulated gas mixture (CO2 containing 6700 ppmv O2, 100 ppmv NO2, 70 ppmv SO2 and 50 ppmv H2O) for 15 h at 278 K and ambient pressure. Short-term tests (6 h) revealed that the corrosion starts as local spots related to grinding marks progressing by time and moisture until a closed layer was formed. Acid droplets (pH 1.5), generated in the gas atmosphere, containing a mixture of H2SO4 and HNO3, were identified as corrosion starters. After 15 h of exposure, corrosion products were mainly X-ray amorphous and only partially crystalline. In-situ energy-dispersive X-ray diffraction (EDXRD) results showed that the crystalline fractions consist primarily of water-bearing iron sulfates. Applying Raman spectroscopy, water-bearing iron nitrates were detected as subordinated phases. Supplementary long-term tests exhibited a significant increase in the crystalline fraction and formation of additional water-bearing iron sulfates. All phases of the corrosion layer were intergrown in a nanocrystalline network. In addition, numerous globular structures have been detected above the corrosion layer, which were identified as hydrated iron sulphate and hematite. As a type of corrosion, shallow pit formation was identified, and the corrosion rate was about 0.1 mma−1. In addition to in-situ EDXRD, SEM/EDS, TEM, Raman spectroscopy and interferometry were used to chemically and microstructurally analyze the corrosion products.
This study focuses on the corrosion mechanism of carbon steel exposed to an artificial geothermal brine influenced by carbon dioxide (CO2) gas. The tested brine simulates a geothermal source in Sibayak, Indonesia, containing 1500 mg/L of Cl-, 20 mg/L of SO4 2-, and 15 mg/L of HCO3-with pH 4. To reveal the temperature effect on the corrosion behavior of carbon steel, exposure and electrochemical tests were carried out at 70 °C and 150 °C. Surface analysis of corroded specimens showed localized corrosion at both temperatures, despite the formation of corrosion products on the surface. After 7 days at 150 °C, SEM images showed the formation of an adherent, dense, and crystalline FeCO3 layer. Whereas at 70 °C, the corrosion products consisted of chukanovite (Fe2(OH)2CO3) and siderite (FeCO3), which are less dense and less protective than that at 150 °C.
Control experiments under Ar-environment were used to investigate the corrosive effect of CO2. Free corrosion potential (Ecorr) and electrochemical impedance spectroscopy (EIS) confirm that at both temperatures, the corrosive effect of CO2 was more significant compared to that measured in the Ar-containing solution. In terms of temperature effect, carbon steel remained active at 70 °C, while at 150 °C, it became passive due to the FeCO3 formation. These results suggest that carbon steel is more susceptible to corrosion at the near ground surface of a geothermal well, whereas at a deeper well with a higher temperature, there is a possible risk of scaling (FeCO3 layer). A longer exposure test at 150 °C with a stagnant solution for 28 days, however, showed the unstable FeCO3 layer and therefore a deeper localized corrosion compared to that of seven-day exposed specimens.
For reliability and safety issues of injection wells, corrosion resistance of materials used needs to be determined. Herein, representative low-cost materials, including carbon steel X70/1.8977 and low alloyed steel 1.7225, were embedded in mortar to mimic the realistic casing-mortar interface. Two types of cement were investigated: (1) Dyckerhoff Variodur commercial Portland cement, representing a highly acidic resistant cement and (2) Wollastonite, which can react with CO2 and become stable under a CO2 stream due to the carbonation process. Exposure tests were performed under 10 MPa and at 333 K in artificial aquifer fluid for up to 20 weeks, revealing crevice corrosion and uniform corrosion instead of expected pitting corrosion. To clarify the role of cement, simulated pore water was made by dispersing cement powder in aquifer fluid and used as a solution to expose steels. Surface analysis, accompanied by element mapping on exposed specimens and their crosssections, was carried out to trace the chloride intrusion and corrosion process that followed.
To study the effects of condensed acid liquid, hereafter referred to as condensate, on the CO2 transport pipeline steels, gas mixtures containing a varying concentration of H2O, O2, NO2, and SO2, were proposed and resulted in the condensate containing H2SO4 and HNO3 with the pH ranging from 0.5 to 2.5. By exposing the pipeline steel to the synthetic condensate with different concentration of acidic components, the corrosion kinetic is significantly changed. Reaction kinetic was studied using electrochemical methods coupled with water analysis and compared with surface analysis (scanning electron microscopy (SEM), energy-dispersive X-ray spectroscopy (EDS), and X-ray diffractometry (XRD)) of corroded coupons. The results showed that, although the condensation of NO2 in the form of HNO3 causes faster general corrosion rate, it is the condensation of SO2 in the form of H2SO4 or the combination of SO2 and NO2 that may cause much more severe problems in the form of localized and pitting corrosions. The resulting corrosion forms were depended on the chemical nature of acids and their concentration at the same investigated pH. The effects of changing CO2 flow rate and renewing condensate on pitting corrosion were further studied.
Interfacial properties related to wettability and corrosion in CO2 transport pipelines are experimentally determined by the sessile and the pendant drop methods. The contact angle of a water drop in a compressed CO2 atmosphere is analyzed on an X70 pipeline carbon steel and compared to that on a martensitic steel S41500 to elucidate the effect of corrosion process on active wetting behaviour. The measurements are performed with liquid CO2 at 278 K and pressures ranging from 5 to 20 MPa. The results show that the contact angle (CA) increases with pressure from 132 ° to 143 ° for S41500 and from 117 ° to 137 ° for X70 and decreases with drop age by 20 ° to 24 ° regardless of the pressure and of the fact that corrosion only occurs on X70, which is confirmed by scanning electron microscopy, element mapping and energy dispersive x-ray spectrometry (EDS) analysis. At higher pressure, the contact angles on both materials converge. Further, related properties like density and interfacial tension were determined. CO2 - saturated water has a higher density than pure water: At 5 MPa saturated water reaches a density of 1017 kg⋅m^(-3) and at 20 MPa 1026 kg⋅m^(-3) compared to pure water with a density of 1002 kg⋅m^(-3) and 1009 kg⋅m^(-3), respectively. In this pressure range the IFT drops from 33 mN⋅m^(-1)at 5 MPa to 23 mN⋅m^(-1) at 20 MPa.
The research focus of this study was set on the corrosion process of condensate as droplets on the surface of carbon steels (X52, X70) martensitic steel UNS S41500, and super austenite UNS N08031 in CO2 atmosphere with impurities at 278 K (to simulate the offshore transportation condition in a buried pipeline). The possibility of dew/droplet formation on the steel surface and wetting behavior of corresponding materials were evaluated by contact angle measurement in dense CO2 at 278 K. To observe the effect of impurities (SO2 and O2) on droplet corrosion process, exposure tests were carried out in the mixed atmosphere with a drop, 1 ‑ 10 µL in volume, of CO2 saturated ultra-pure water on steel surface. Comparable exposure tests were carried out with the same gas mixture and the same volume of water, as vapor, to observe the droplet formation and the corrosion process that follows. Effects of surface roughness on the droplet formation and its corrosion process were further studied and showed no significant role upon long time exposure. The results from droplet experiments were compared to those from the bulk electrolyte for the further recommendation on the quality control of gas stream along with the use of carbon steels as transport pipelines in CCS - Carbon Capture and Storage system.