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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.
The collaborative project “Impacts of impurities in CO2 streams captured from different emitters in a regional cluster on transport, injection and storage (CLUSTER)” aimed to set up recommendations on how to define “reasonable minimum composition thresholds” that CO2 streams should meet when accessing CO2 transport pipeline networks. Within CLUSTER, we investigated potential impacts of CO2 streams with different and temporally variable compositions and mass flow rates along the whole CCS chain. Investigations included, amongst others, impacts on:
• corrosion of pipeline steel,
• pipeline network design and related transport costs,
• alteration of well bore cements,
• pressure development and rock integrity,
• geochemical reactions, and
• petrophysical and geomechanical rock properties.
All investigations are based on a generic CCS chain scenario. In this scenario, CO2 streams are captured from a spatial cluster of eleven emitters and collected in a regional pipeline network. Emitters comprise seven fossil fuel-fired power plants equipped with different capture technologies, two cement plants, one refinery and one integrated iron and steel plant. In total, 19.78 Mio t CO2 (including impurities) are captured in the emitter cluster annually. The combined CO2 stream is transported in a trunk line with a length of 400 km (100 km of these offshore) and is injected into five generic storage structures. The storage reservoirs are saline aquifers of the Buntsandstein.
The investigations revealed beneficial and deteriorating impacts of different impurities and combinations thereof. Overall, no fundamental technical obstacles for transporting, injecting and storing CO2 streams of the modelled variable compositions and mass flow rates were observed. Based on the results, the CLUSTER project team recommends not to define “minimum composition thresholds” for CO2 streams as strict threshold values for each individual impurity in the stream. Instead, CO2 stream compositions and variabilities for specific CCS projects should be constrained with regard to a set of parameters including i) the overall CO2 content, ii) maximum contents of relevant impurities or elements, iii) acceptable variability of CO2 stream composition, and iv) impurity combinations to be avoided.
The collaborative project “Impacts of impurities in CO2 streams captured from different emitters in a regional cluster on transport, injection and storage (CLUSTER)” aimed to set up recommendations on how to define “reasonable minimum composition thresholds” that CO2 streams should meet when accessing CO2 transport pipeline networks. Within CLUSTER, we investigated potential impacts of CO2 streams with different and temporally variable compositions and mass flow rates along the whole CCS chain. Investigations included, amongst others, impacts on: Corrosion of pipeline steel, pipeline network design and related transport costs, alteration of well bore cements, pressure development and rock integrity, geochemical reactions, and petrophysical and geomechanical rock properties.
All investigations are based on a generic CCS chain scenario. In this scenario, CO2 streams are captured from a spatial cluster of eleven emitters and collected in a regional pipeline network. Emitters comprise seven fossil fuel-fired power plants equipped with different capture technologies, two cement plants, one refinery and one integrated iron and steel plant. In total, 19.78 Mio t CO2 (including impurities) are captured in the emitter cluster annually. The combined CO2 stream is transported in a trunk line with a length of 400 km (100 km of these offshore) and is injected into five generic storage structures. The storage reservoirs are saline aquifers of the Buntsandstein.
The investigations revealed beneficial and deteriorating impacts of different impurities and combinations thereof. Overall, no fundamental technical obstacles for transporting, injecting and storing CO2 streams of the modelled variable compositions and mass flow rates were observed. Based on the results, the CLUSTER project team recommends not to define “minimum composition thresholds” for CO2 streams as strict threshold values for each individual impurity in the stream. Instead, CO2 stream compositions and variabilities for specific CCS projects should be constrained with regard to a set of parameters including i) the overall CO2 content, ii) maximum contents of relevant impurities or elements, iii) acceptable variability of CO2 stream composition, and iv) impurity combinations to be avoided.
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.
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.
Carbon Capture Utilization and Storage (CCUS) is a promising technology to reach the target for reduction of CO2 emissions, e.g. from fossil-fuel operated power plants or cement mills. Crucial points for a sustainable and future-proof CCUS procedure are reliability and cost efficiency of the whole process chain, including separation of CO2 from the source, compression of CO2, its subsequent transportation to the injection site and injection into geological formations, e.g. aquifers.
Most components that are in contact with CO2-stream consist of steel. Depending on the operating conditions (e.g. temperature, pressure, and CO2-stream composition) specific suitable steels should be used. The compressed CO2-stream is likely to contain process specific impurities; small amounts of SO2 and NO2 in combination with oxygen and water are most harmful.
One approach, as currently preferred by pipeline operators, is to clean the CO2-stream to such levels, acceptable for carbon steel, commonly used as pipeline material. Another consideration would be, to use more corrosion resistant alloys for CO2-streams with higher amounts of impurities.
Due to the absence of certified benchmarks for upper limits, systematic experiments with impurities in the CO2-stream were carried out reflecting mainly transport and injection conditions.
Within the COORAL project (German acronym for “CO2 purity for capture and storage”) levels of impurities in the CO2-stream, being acceptable when using specific steels, were evaluated. Material exposure to dense or multiphase carbon dioxide (CO2) containing specific amounts of water vapor, oxygen (O2) sulfur dioxide (SO2), nitrogen dioxide (NO2), carbon monoxide (CO) can be a challenge to steels. In some situations, condensation of impurities and reaction products from the CO2 stream can occur.
CO2 saturated brine is supposed to rise in the well when the injection process is interrupted. The material selection shall ensure that neither CO2 nor brine or a combination of both will leak out of the inner tubing.
This COORAL-work was extended by a follow-up project, called CLUSTER. Here the additional influence of impurities was investigated when merging CO2 streams from different sources, combined within a “so-called” cluster.
Results are summarized within the following table regarding suitability for different parts of the process chain.
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.
Study of Polyaniline/Silicon Dioxide based Coating on Carbon Steel in Artificial Geothermal Brine
(2021)
Geothermal brines are corrosive in nature because of their salt contents and high temperatures. Therefore, they pose a major challenge to geothermal power-plants, which are mostly built of low alloyed steels, e.g., carbon steel. Carbon steel is susceptible to uniform and localized corrosion when exposed to geothermal brines having acidic-saline properties. To overcome this limitation, geothermal power plants should be built by either high alloyed materials or by integrating protection systems on carbon steel, such as coatings and inhibitors. We studied a coating system containing polyaniline/silicon dioxide basing on locally available resources that provides protection against corrosion of carbon steel and enhance the thermal resistance in geothermal environments. Here, exposure and electrochemical tests of coated carbon steels were performed in an artificial geothermal brine. The solution had a pH of 4, with the composition of 1,500 mg/L of chlorides, which is based on the chemical analysis of geothermal brine found in Sibayak, Indonesia. All exposure tests were conducted using autoclaves at 150 °C with a total pressure of 1 MPa, which was performed for up to six months to evaluate the durability of the coating system. Post-experimental analyses were performed by assessing the surface of specimens using optical and electron microscopes. On the other hand, electrochemical tests were performed for seven days at 25 °C and 150 °C to investigate the kinetics of electrochemical reactions by measuring open circuit potential and electrochemical impedance spectra. Experimental results showed the corrosion resistance of PANI/SiO2 composite coatings, where polyaniline and SiO2 play their roles as stabilizers.
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.
Al2O3 coatings are often used as protective layers on steels against electrochemical and high-temperature corrosion because they are chemically inert and stable at elevated temperatures. This study presents preliminary work on the possibilities of using Al2O3 sol-gel coatings for corrosion protection of martensitic stainless steels in geothermal environments. Al2O3 sol-gel coatings were applied on UNS S42000, which is known to be susceptible to uniform and localized corrosion. The coated steel specimens were then tested in two types of artificial geothermal water, which simulate the geothermal fluids found in Sibayak (SBY), Indonesia, and North German Basin (NGB), Germany, respectively. SBY has pH 4 and 1.5 g/L of chloride ions, whereas NGB has a pH of 6 and 166 g/L of chloride ions. All experiments were carried out in autoclaves at 150 °C and 1 MPa under the deaerated condition. Evaluations were performed by investigating the surface profiles of both uncoated and coated steels before and after the corrosion test using a Laser Scanning Microscope (LSM) and Scanning Electron Microscope (SEM). Finally, Electrochemical Impedance Spectroscopy (EIS) was performed to compare the corrosion resistance of Al2O3 coated steels in SBY and NGB solutions. It was observed from the corrosion test that Al2O3 coatings are more suitable for use in the geothermal water with a higher pH.
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 .
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.
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.
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.
Integrated Coating System for Corrosion Protection of Carbon Steel in Artificial Geothermal Brine
(2022)
Corrosive geothermal brines are a major challenge to geothermal power-plants. For cost reasons, plant designers prefer to use carbon and low alloyed steels, which are susceptible to uniform and localized corrosion when exposed to geothermal brines having acidic and saline properties. To solve such problem, coatings or inhibitors would be a protective solution as an alternative to the use of high alloyed materials.
This study investigated a coating system consisting of polyaniline/silicon dioxide based on resources locally available in Indonesia. Protection against corrosion of carbon steel was shown by long-term (28 day) exposure and electrochemical tests of coated carbon steels, performed in an artificial acidic and saline geothermal brine, comparable to the conditions encountered at a site in Indonesia.
Therefore, an integrated coating system is proposed for corrosion protection, combining the electrochemical functionality of polyaniline and the physical advantages of silica.
Influence of Precipitating Brine Components on Materials Selection for Geothermal Applications
(2021)
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.
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.
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).
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.
To reveal the corrosion resistance of casing steel/mortar interface in CO2 injection condition, sandwich samples were prepared and exposed up to 20 weeks in aquifer fluid under 10 MPa and 60 °C. Cross section analysis revealed the crevice corrosion as main mechanism instead of pitting corrosion, which would be expected to happen in the extremely high Chloride concentration. Detailed analysis using EDS line scan shown the slow diffusion of Chloride, suggesting why pitting did not happen after 20 weeks. To mimic the passivated steel surface, the steel coupon was passivated in simulated pore solution having pH 13.5 for 42 days. The passivated coupon was further exposed to NGB solution for 28 days. Electrochemical characterization was performed along the exposure processes to reveal the change in impedance, indicating the corrosion resistance of steel casing/mortar interface.
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.
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.
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 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.
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.
Corrosive geothermal brines are a major challenge to geothermal power-plants. For cost reasons, plant designers favorize low alloyed steels, e.g., carbon steel, which are susceptible to uniform and localized corrosion when exposed to geothermal brines having acidic and saline properties. To solve such problem, coatings or inhibitors would be a protective solution as an alternative to the use of high alloyed materials.
This study investigated a coating system consisting of polyaniline/silicon dioxide basing on locally available resources. Protection against corrosion of carbon steel is shown by long-term exposure and electrochemical tests of coated carbon steels, performed in an artificial acidic and saline geothermal brine, comparable to real conditions at a site in Indonesia.
Therefore, an integrated coating system is presented for corrosion protection, combining the electro-chemical functionality of polyaniline and the physical advantages of silica.