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Eingeladener Vortrag
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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.
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).
The geological storage of carbon dioxide (Carbon Capture and Storage, CCS) in depleted gas reservoirs or in saline aquifers is a widely discussed issue. Carbon dioxide may induce corrosion on the piping steels during compression, transportation and injection. Therefore,
selection of appropriate piping steels is a key factor in order to increase the safety and reliability of the CCS technology, and to keep the processes cost-effective.
The here described subproject of the COORAL project (German acronym for “C02 purity for capture and storage”) deals with the levels of impurities in the C02 stream that will be acceptable when using specific steels. Material exposure to carbon dioxide (C02) containing
specific amounts of water vapor, oxygen (02) sulfur dioxide (S02), nitrogen dioxide (N02), carbon monoxide (CO) can be a challenge to steels. Within this subproject 13 different Steels are tested for suitability as materials used for compression, transportation and injection Units within the CCS chain.
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 BAM1 - 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 7200 dangerous goods have been published in the BAM-List since 1989.
The ferritic Steel UNS S44400 (X2CrMoTil8-10, 1.4521) was originally developed as alternative for the austenitic grade AISI316L (X2CrNiMo 17-12-2, 1.4404). Due to its characteristic profile this Steel was qualified for applications requiring high strength values at concomitant adequate corrosion resistance. Because of the lack of Nickel this Steel is a cost-efficient alternative to the Ni-containing austenites. No corrosion test results of UNS S44400 under the influence of dangerous goods were published in the BAM-List so far. Only data on the behavior of AISI 316L are listed. Therefore test specimens of this Steel were exposed to selected corrosive substances in order to compare both steels.
Due to the reduced alloy content a reduced corrosion resistance of the Steel UNS S44400 in acidic substances, such as formic acid, acetic acid and sulfuric acid, in comparison to the austenitic CrNiMosteels was expected but not observed. Tests in an alkaline medium showed sufficient resistance.
Within the project COORAL (German acronym for ''C02 purity for capture and storage") studies on pipeline steels exposed to circulating supercritical impure C02 have been carried out. For this purpose, a loop consisting of compressors, flow meter and two autoclaves was constructed. In order to simulate the real conditions in pipelines, impurities such as H20, CO, S02, N02 and 02 were added to the C02 stream before compression. Exposure experiments were carried out with Steel specimens placed in the autoclaves. Carbon Steel L360NB, pure iron X20Cr13, X46Cr13, X2CrMnNiN22-5-2 and alloy 31 have been exposed to circulating (flow rate 4 L/min) supercritical impure C02 for one week at 60 °C and 10 MPa Surface analysis and weight loss experiments in order to determine the corrosion products and the corrosion rates showed that the impurities cause corrosion problems. Slight general corrosion by L360NB and soft iron was observed. The initiation of pitting corrosion was observed at the surfaces of the materials X20Cr13, X46Cr13, X2CrMnNiN22-5-2. No visible signs of corrosion have been observed on alloy 31.
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.
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.
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.
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.
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.
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.
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.
Carbon Capture, Utilization and Storage (CCUS) has been proposed as a promising technology for the mitigation of CO2 emissions into the atmosphere from fossil-fuel-operated power generation plants. As the reliability and cost effectiveness of the pipeline transport network is crucial to the overall operability and resilience of the CCUS system, it is vital to realize the possible corrosion risks of the employed pipeline steels corresponding to the impurity level of the gas source.
Recent studies have shown that even the high alloyed materials might be susceptible to general and/or localized corrosion by the condensates forming from the impurities such as SOx, NOx, CO, O2 and water [1]. Up to now, however, there is no regulation procedure which defines the maximum acceptable level of impurities and the combination of them for each employed pipeline steels. Herein, systematic experiment series were conducted by mixing pure CO2 gas with varying concentration of each impurity and with the varying combination of them. Each time, the mixture was then fed (1 L/min) into the reactor containing 12 specimens for 120-600 h at 5°C (to simulate the sub-level pipeline transport). The resulted condensate was collected and analyzed by ionic chromatography and atomic absorption spectroscopy to determine the chemical composition. In this study, the “worst-case scenario” gas mixture, containing 2.5 % H2O, 1.8 % O2, 1000 ppm NO2, and 220 ppm SO2 as impurities, resulted in the condensate containing H2SO4 0.114 M and HNO3 0.0184 M (pH 2.13). This “original” condensate was then re-produced to carry out exposure tests and electrochemical characterization including corrosion potentials and impedance spectroscopy in CO2 saturated condition for 7-14 days at the same temperature. The corrosion rate was also measured by mass loss method.
We can conclude that, at the initial stage, HNO3 plays the dominant role in Fe dissolution process, while H2SO4 is responsible for the pit initiation followed by pitting corrosion. Future studies will be focused on the combination effect from the impurities and the exposure test under the regularly changing condensate to mimic the real CO2 pipeline system.
Carbon Capture, Utilization and Storage (CCUS) has been proposed as a promising technology for the mitigation of CO2 emissions into the atmosphere from fossil-fuel- operated power generation plants. As the reliability and cost effectiveness of the Pipeline transport network is crucial to the Overall operability and resilience of the CCUS system, it is vital to realize the possible corrosion risks of the employed Pipeline steels corresponding to the impurity Level of the gas source. Recent studies have shown that even the high alloyed materials might be susceptible to General and/or localized corrosion by the condensates forming from the impurities such as SOx, NOx, CO, O2 and water.
Up to now, however, there is no regulation procedure which defines the maximum acceptable level of impurities and the combination of them for each employed pipeline steels. Herein, systematic experiment series were conducted by mixing pure CO2 gas with varying concentration of each impurity and with the varying combination of them. Each time, the mixture was then fed (1 L/min) into the reactor containing 12 specimens for 120-600 h at 5°C (to simulate the sub-level Pipeline transport). The resulted condensate was collected and analyzed by ionic chromatography and atomic Absorption spectroscopy to determine the chemical composition. In this study, the “worstcase scenario” gas mixture, containing 2.5 % H2O, 1.8 % O2, 1000 ppm NO2, and 220 ppm SO2 as impurities, resulted in the condensate containing H2SO4 0.114 M and HNO3 0.0184 M (pH 2.13).
This “original” condensate was then reproduced to carry out exposure tests and electrochemical characterization including corrosion potentials and impedance spectroscopy in CO2 saturated condition for 7-14 days at the same temperature. The corrosion rate was also measured by mass loss method.
We can conclude that, at the initial stage, HNO3 plays the dominant role in Fe dissolution process, while H2SO4 is responsible for the pit initiation followed by pitting corrosion. Future studies will be focused on the combination effect from the impurities and the exposure test under the regularly changing condensate to mimic the real CO2 pipeline system.
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.
Finally it can be summarized that this book fulfills its intention of providing theoretical background and examples for practical applications of coatings used for corrosion protection.
It can be recommended to those being interested in coatings, serving as an overview on aspects which needs to be considered when working with such systems.
Geothermal brine is a complex system containing a wide variety of dissolved salts resulting from the condition s in a geothermal well. These fluids lead to corrosion in pipes and other parts of geothermal system construction and necessitate intense research efforts in finding new suitable materials. Carbon steel is susceptible to corrosion in geothermal brine especially when it is exposed to a high temperature and high-pressure medium, which is considered to be an aggressive environment. An artificial geothermal water, bas ed on a brine composition found in Indonesia, was used to investigate the performance of high alloyed materials. The electrolyte has pH 4 and contains 1,500 mg/l Cl-, 20 mg/l SO4 2-, 15 mg/l HCO3 -, 200 mg/l Ca 2+, 250 mg/l K+, and 600 mg/l Na+. In order to protect the bare material in geothermal application, it is necessary to either use high alloyed material s or coatings. In this research, a coating system consisting of polyaniline and silicon dioxide was investigated regarding its behavior to protect carbon steel. In detail, the effect of SiO2 and polyaniline (PANi) addition was evaluated by exposure and electrochemical tests for 7 days, i.e. electrochemical impedance spectroscopy (EIS) and open circuit potential (OCP ) at room temperature and 150 °C with 1 MPa pressure .
In this work, the focus was set on the corrosion process of condensate as drops on the surface of carbon steels (X52, X70), martensitic steel UNS S41500, and superaustenite UNS N08031 in CO2 atmosphere with impurities at 278 K (to simulate the transportation condition in a buried pipeline). Exposure tests were performed at both normal pressure and high pressure where CO2 is supercritical or in dense phase. The drop, 1 ‑ 10 μL in volume, was prepared by dropping CO2 saturated ultra-pure water onto the surface of steel coupons in a one-liter-autoclave. The CO2 gas stream, simulating the oxyfuel flue gas with varying concentration of impurities (SO2 and O2 ), was then pumped into the autoclave to observe the condensation and corrosion impacts of impurities. Comparable exposure tests were carried out with the same gas mixture and the same volume of water as vapor to observe the drop formation and the corrosion process that follows. The wettability and stability of drops on the surface of steel coupons in CO2 supercritical/dense phase environment was evaluated additionally by contact angle measurement.
The second edition of this textbook on physical electrochemistry, written by two experienced teachers of physical chemistry, corrosion engineering and materials science and engineering, covers the current knowledge which should be transferred to students of these fields.
In 20 chapters the fundamentals of electrochemistry, the most important electrochemical measurement techniques and applications of electrochemistry are covered.
It can be concluded that this study fulfills its intension of “serving as a key textbook in undergraduate courses” dealing with electrochemistry and being “a reference source for graduated students, researchers and engineers” interested in this field. Teachers will find sufficient content for preparing lectures on this topic. Even self‐learning is well supported by the clear structure, presented content and provided sources for further reading.
The composites combining aluminum and silica nanoparticles with the addition of tetramethylammonium hydroxide (Al-SiO2(T)) and butanol (Al-SiO2(B)) as mixing media have been successfully fabricated. Corrosion behavior of Al-SiO2 composites before and after exposure in 1M NaCl solution was examined using potentiodynamic polarization (Tafel curve analysis). The study was also equipped with scanning electron microscopy (SEM), energy dispersive X-ray (EDX), and X-ray diffraction (XRD) investigations. Before exposure, Al-SiO2(T) exhibited the best corrosion resistance. Performance improvement was indicated by Al-SiO2(B) up to 10 times better than Al-SiO2(T) after exposure. The increased SiO2 content did not significantly enhance the corrosion resistance of the composites. The Al-SiO2 composites with 5% SiO2 content showed very high corrosion resistance (as the optimum composition). Furthermore, pitting corrosion was observed in the Al-SiO2 composites, indicated by the formation of corrosion products at grain boundaries. The product was affected by the presence of SiO2 in the Al matrix and the NaCl environment at 90 °C (approach to synthetic geothermal media: Na+, Cl, H+, OH-). Our study revealed the presence of γ-Al2O3, γ-Al(OH)3, and Al(OH)2Cl as the dominant corrosion products.
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.
By exposure and electrochemical tests in the laboratory the Cu-effect on corrosion behavior of carbon steel, high-alloyed steels and Ti-alloy can be assessed.
Critical materials specific properties were determined by static exposure and electrochemical tests in an artificial geothermal water with high salinity and low pH, containing Cu. Conclusions were drawn using characteristic potential values.
It could be shown that significant Cu-deposition and -precipitation only occurred in combination with carbon steel. High-alloyed materials (S31603, S31653, S31700, S31703, S31803 and N08904) prevent the disturbing Cu-agglomeration. Therefore, they are suitable to be chosen for future design of the piping system, either in massive or in cladded form, if formation of crevices with non-metallic materials can be excluded.
From the interactions and pitting corrosion point of view, R50400 seems to be most favorable.
According to the results of the experiments carried out, the following points can be concluded:
1. Exposure tests showed that specimens with the addition of SiO2 particles and polyaniline particles exhibit better corrosion resistance than specimens with the addition of only polyaniline particles or binder only.
2. Open circuit potential measurements showed that in the beginning of the experiments, both coatings had an open circuit potential 100 mV higher than carbon steel. Within one day of immersion, the potential of carbon steel increased significantly, indicating the formation of oxide layer. After extended exposure the carbon steel potential sat between PS1 (which had higher potential) and PS2 (which had a lower potential) and all three were in the range –600 mV to –500 mV vs Ag/AgCl.
3. Both coatings PS-1 and PS-2 were degraded with increasing exposure time, shown by the decrease of absolute impedance value at low frequency range after 2, 4, and 6 days exposure.
4. Potentiodynamic test was performed after 3 hours and 6 days exposure, and it was shown that the coating in the initial stage exhibited more passive behavior than the specimens exposed for 6 days.
Recent studies have shown that even at a very low concentration of impurities (less than 100 ppmv of SO2, NO2, O2 and H2O) the droplet formation and condensation of sulfuric and nitric acids in dense phase CO2 are possible and observable. To reveal the mechanism of droplet corrosion in dense phase CO2 at high pressure and low temperature, further studies on factors that affect wettability and resulting corrosion behaviors of transport pipeline steels are needed. In this study, effects of surface morphology were investigated by varying surface roughness of carbon steel coupons exposed to CO2 stream containing impurities to measure the wettability by contact angle and to observe the condensation as well as possible droplet corrosion that followed. Other considered factors were: pH of the droplet, temperature, droplet volume, and exposure time.
Geothermal energy is one of the most promising energy resources to replace fossil fuel. To extract this energy, hot fluids of various salts and gases are pumped up from a geothermal well having a certain depth and location. Geothermal wells in volcanic regions often contain highly corrosive CO2 and H2S gases that can be corrosive to the geothermal power-plants, which are commonly constructed of different steels, such as carbon steel. This research focuses on the corrosion behaviour of carbon steel exposed to an artificial geothermal fluid containing CO2 gas, using an artificial acidic-saline geothermal brine as found in Sibayak, Indonesia. This medium has a pH of 4 and a chloride content of 1,500 mg/L. Exposure tests were conducted for seven days at 70 °C and 150 °C to simulate the operating temperatures for low and medium enthalpy geothermal sources. Surface morphology and cross-section of the specimens from the above experiments were analysed using scanning electron microscope (SEM) and energy dispersive X-ray (EDX). Electrochemical tests via open circuit potential (OCP) and electrochemical impedance spectroscopy (EIS) were performed to understand the corrosion processes of carbon steel in CO2-containing solution both at 70 °C and 150 °C. Localized corrosion was observed to a greater extent at 70 °C due to the less protectiveness of corrosion product layer compared to that at 150 °C, where FeCO3 has a high corrosion resistance. However, a longer exposure test for 28 days revealed the occurrence of localized corrosion with deeper pits compared to the seven-day exposed carbon steel. In addition, corrosion product transformation was observed after 28 days, indicating that more Ca2+ cations incorporate into the FeCO3 structure.
Electrochemical deposition of polyaniline on carbon steel for corrosion study in geothermal solution
(2019)
Polyaniline has been widely developed for many applications, e.g. sensor, supercapacitor components, electrochromic devices, and anticorrosion pigments. Although the addition of polyaniline pigment in organic coatings has been an alternative for corrosion protection in industrial applications, the protection mechanism is still not fully understood. Herein in this study, as a part of the development of polyaniline/silicon dioxide coating for geothermal application, polyaniline has been deposited electrochemically on carbon steel surface in oxalic acid medium and tested in geothermal solution to understand the contribution of polyaniline to the corrosion protection of a polyaniline-based composite in the geothermal system. To observe the surface/interface reaction between the electrolyte and electrode surface during the electrochemical polymerization, electrochemical impedance spectroscopy (EIS) was applied after each cycle. For corrosion study in the geothermal application, an artificial geothermal solution was used with the composition of 1,500 mg/l Cl⁻, 20 mg/l SO₄²⁻, 15 mg/l HCO₃⁻, 200 mg/l Ca²⁺, 250 mg/l K⁺, and 600 mg/l Na⁺, and pH 4 to simulate a geothermal brine found in Sibayak, Indonesia. An electrochemical measurement was performed by monitoring the open circuit potential over seven days, with the interruption by EIS every 22 hours. The experiments were performed at room temperature and 150 °C (1 MPa) in an oxygen-free environment. Impedance spectra showed a reduction of the total impedance value of approximately 10 times for specimens measured at 150 °C compared to the specimens measured at room temperature, suggesting a less stable layer at high temperature.
This contribution provides current findings regarding materials susceptibility for carbon capture, utilization and storage (CCUS) applications. Basing on results gathered in 2 German long-term projects (COORAL and CLUSTER) suitable materials are introduced as well as dominating impurities of the CO2-stream and corrosion mechanisms. Investigations cover the whole CCUS process chain and provide material recommendations for certain parts.
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.
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.
This contribution provides current findings regarding materials susceptibility for carbon capture, utilization and storage (CCUS) applications. Basing on results gathered in 2 German long-term projects (COORAL and CLUSTER) suitable materials are introduced as well as dominating impurities of the CO2-stream and corrosion mechanisms. Investigations cover the whole CCUS process chain and provide material recommendations for certain parts.
This book introduces to aspects to be considered when dealing with coatings and linings. Philip A. Schweitzer covers and compares a variety of specific coatings and their applications. In 18 chapters he divided the content into two main parts: linings and coatings.
All professionals involved in design and maintenance processes get by this book a compact survey of necessary considerations which needs to be done when applying surface protection measures. The literature references at the end of some chapters support the readers finding additional information about the special topic, mainly written by the author himself. Since this newly issued paperback edition is a 1:1 re‐print of the 2001 hardcover version, neither current publications are referenced, nor revisions were made.
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 in many cases extreme in terms of corrosion due to the chemical composition of hydrothermal fluids and temperatures. Therefore, materials selection based on preliminary material qualification is essential to guarantee a secure and reliable operation of the facilities. During operation of a geothermal research facility in Groß Schönebeck copper and lead effects have been found downhole. Occurring mechanisms and measures to prevent precipitation or scaling needed to be investigated as well as potential influences of such precipitates on corrosion resistance of metallic materials used for equipment.
This contribution deals with the evaluation of the corrosion behavior of carbon steel and corrosion resistant alloys in copper and/or lead containing artificial geothermal water, simulating the conditions in the Northern German Basin.
The behavior of these materials in an artificial geothermal water obtained by electrochemical measurements and exposure tests are presented. While carbon steel exhibits precipitation and deposition, higher alloyed material shows different response to such species and a higher resistance in saline geothermal water.
Basing on these results the suitability of the investigated corrosion resistant alloy is given for use in such conditions, whereas carbon steel creates difficulties due to its susceptibility to Cu- and Pb-precipitation.
This paperback issue of the 2007 hardcover version within the “Corrosion Engineering Handbook” series presents various materials and methods for controlling and protecting against corrosion instead of using expensive alloys to construct a tank or processing vessel.
This book is a very comprehensive collection of the current knowledge about applied linings and coatings. So, it fulfills its intension, “that regardless of what is being built, … information for … whoever is responsible for the selection of material of construction will be found in this book to enable them to avoid unnecessary loss of material through corrosion”, to a very large extent.
This book by Scrivener Publishing contains 14 chapters written by 82 leading scientists, experienced in the field of coatings. They demonstrate mechanisms, usage and manipulation of cutting‐edge coating methods. Each chapter is well structured and ends with a conclusion, highlighting the content. The book is divided into 3 parts: “Materials and Methods”, “Coating Materials Nanotechnology” and “Advanced Coating Technology and Applications”.
Finally, this book provides a comprehensive insight into innovative research in advanced coating materials and state‐of‐the‐art technologies, without being a real textbook. It fulfills its intension of being beneficial both for technicians and scientists.
This book grew out of a course on polymer coatings held by the author at the university. It shall serve as an introduction to the wide field of polymer coatings. It is not intended to cover completely all facts on polymer coatings.
All chapters are well structured. Selected figures and formulas illustrate the content and contribute to a good understandability. At the end of each chapter some hints for further reading are provided.
Finally, the book fulfills its intention to introduce into the topic by providing basics on science and technology of polymer coatings, suitable for chemists in industry, materials scientists, polymer chemists and physical chemists.