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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.
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.
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 .
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.
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.
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.
Since 2016 ISO Technical Committee (TC) 265 is working on standardization the whole CCS-process chain. Around 30 countries are working together to provide international guidelines. As ISO 27913 was the first standard finished within these activities it is already in the stage of first revision.
The objective of ISO 27913 is “to provide specific requirements and recommendations on certain aspects of safe and reliable design, construction and operation of pipelines intended for the large-scale transportation of CO2 that are not already covered in existing pipeline standards such as ISO 13623, ASME B31.8, EN 1594, AS 2885 or other standards. Existing pipeline standards cover many of the issues related to the design and construction of CO2 pipelines; however, there are some CO2 specific issues that are not adequately covered in these standards. The purpose of this document is to cover these issues consistently. Hence, this document is not a standalone standard, but is written to be a supplement to other existing pipeline standards for natural gas or liquids for both onshore and offshore pipelines.”
This contribution shall provide information on the content, the current stage of the revision process, encourage to contribute to this standard and make listeners aware to consider the influence of ISO standard on documents currently in draft.
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 fluids 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.
The corrosion behavior of 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 carbon steel 25CrMo4, stainless steels X2CrNiMo17-12-2, X2CrNiMo-22-5, X2CrNiMoCuWN25-7-4 and super austenitic steel X1CrNiMoCu32-28-7 in these geothermal fluids obtained by electrochemical measurements and exposure tests is limited. The nickel alloy NiCr23Mo16Al shows an 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 saline brines. Stainless and duplex steels exhibit a limited corrosion resistance concerning pitting and crevice corrosion.
Beside of the higher alloyed materials, also the low-alloyed steel 25CrMo4 could be employed as a constructional material for the geothermal power plant in stagnant highly acidic non saline environments, as long as the wall thickness of the material vs. corrosion rate is taken into account.
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.
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 fluids 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 duplex steel S31803 (318LN, X2CrNiMoN22-5-3, 1.4462) conducted by electrochemical measurements and exposure tests in artificial geothermal waters simulating the conditions in different locations with geothermal potential in Germany.
The duplex steel S31803 shows limited suitability for applications in artificial geothermal waters due to its susceptibility to pitting and crevice corrosion.
For low saline geothermal waters it can be considered suitable at moderate temperatures. Slight crevice corrosion susceptibility needs to be considered.
Results are being incorporated into a materials catalogue for geothermal applications which shall provide basic information for designers and users of geothermal facilities.
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.
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.
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.
By means of electrochemical measurements and exposure tests the suitability of two high alloyed materials X8NiCrSi38 18 and NiCr25FeAlYB in molten nitrate salt (60 % NaNO3/40 % KNO3) was characterized at 600 °C.
Specific amounts of oxidizing and reductive impurities as well as some moisture were added to dense phase CO2 to replicate CO2 streams from sources in a CCS pipeline network. Due to the moisture content being only 50 ppmV no visible acid condensation took place. To simulate stress conditions at the inside pipeline surface due to fluid pressure (10 MPa) specimens were preloaded using a load frame. Experiments conducted at 278 K and at 313 K revealed the highest corrosion rate at lower temperature. Corrosive effect of impurities was strongest applying mixed atmosphere, containing oxidizing and reductive components, closely followed by CO2 streams with pure oxidizing character. By far, the lowest corrosion rate (10x lower) resulted from reductive atmosphere. In general, at constant temperature and pressure the CO2 stream composition strongly influences the morphology, thickness and composition of the corrosion products. Applying oxidizing or mixed impurities, iron hydroxides or oxides (e.g. goethite, hematite) occur as dominating corrosion products, capable to incorporate different amounts of sulfur. In contrast, using reductive atmosphere very thin corrosion layers with low crystallinity were developed, and phase identification by XRD was unfeasible. SEM/EDX analysis revealed the formation of Fe-O compounds, most likely attributed to the oxygen partial pressure in the system induced by CO2 (≥0.985 volume fraction) and volatile H2O. In addition to the surface covering corrosion layer, secondary phases had grown locally distributed on top of the layer. These compounds are characteristic for the applied atmosphere and vary in number, shape and chemical composition.
Carbon Capture Utilization and Storage (CCUS) is a promising technology for the 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 pipeline transport network. Due to the absence of certified benchmarks for upper limits, systematic experiments with impurities in the CO2 stream were carried out. For oxidation processes SO2 and NO2 acted as corrosive components, and for reductive atmosphere H2S. Carbon steel L485MB (pipeline), martensitic steel 1.4313 (compression) and austenitic steel 1.4562 (injection) were selected as specimens. Experiments were performed at 0 bar or 100 bar and within a temperature range 278 K ≤ T ≤ 313 K. High-alloyed Cr-Ni steels revealed no corrosion (1.4562, 1.4313), while for carbon steel considerable corrosion was observed. The type and intensity of corrosion was strongly coupled with the applied corrosive species and the level of humidity in the CO2 stream, leading to different compositions of acidic condensates. Applying a reducing atmosphere results in very little corrosion rates, but provokes pitting corrosion. In contrast, oxidizing or mixed settings lead to a clearly increased growth of the corrosion layer, but exhibit shallow uniform corrosion. Exceptional nitric acid results in intergranular corrosion. Investigations on the specimens were carried out by optical microscopy, XRD, SEM/EDX, and AAS/IC.
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.
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.
This work examined the droplet corrosion of CO2 pipeline steels caused by impurities in CO2 supercritical/dense phase at 278 K, simulating the underground transport condition. The wetting properties of carbon steels (X52 and X70) as well as martensitic steel UNS S41500, and superaustenite UNS N08031 were studied by contact angle measurement, revealing reactive wetting behavior of carbon steels. Exposure tests with CO2 saturated water droplet on steel surface showed that the impurities (220 ppmv SO2 and 6700 ppmv O2) diffused into the droplet and then reacted with metal coupons in supercritical/dense phase condition, forming the corrosion product instantly during pumping process. Due to the active wetting behavior, the carbon steels suffered from heavily attack, while negligible corrosion product was observed in cases of martensitic steel UNS S41500 and superaustenite UNS 08031 coupons. Condensation experiments that were carried out on fresh polished coupons in CO2 with 1200 ppmv H2O showed that the formation and aggregation of droplet is dependent on the presence of impurities. Without SO2 and O2, the same concentration of H2O did not cause observable corrosion process after a week of exposure. With 220 ppmv SO2 and 6700 ppmv O2 even low water concentration (5-30 ppmv) still resulted in heterogeneous nucleation and subsequent growth of droplets, leading to corrosive process on carbon steel surface albeit to a lesser extent.
CCUS-Technologie (CO2-Abtrennung; Nutzung und Speicherung, engl. Carbon Dioxide Capture, Utilization and Storage) gilt als eine vielversprechende Methode zur Abschwächung des Beitrags von fossilen Emissionen zur globalen Erwärmung. Dabei wird das in den Verbrennungsprozessen entstandene Treibhausgas aufgefangen, zu verschiedenen Lagerstätten transportiert und langzeitig gespeichert bzw. einer chemischen Nutzung zugeführt.
In bisher veröffentlichten Untersuchungen wurde gezeigt, dass die CO2-Transport-Pipelines in hohem Maße gefährdet sind, wenn sie korrosiven Begleitstoffen des CO2-Stroms, wie SOx, NOx bei einem hohen Wasserdampfanteil ausgesetzt sind. Screening-Tests zeigten, dass bei einer Konzentration von 1000 ppmv H2O die Reaktionen und Kondensation von SO2 und NO2 mit O2 und H2O zu Säuretropfen (pH ~ 0,5) auf der Oberfläche von Metall-Prüfkörper und Gefäß führen. Die Werkstoffe 1.0582, 1.8977, 1.4313 und 1.4562 wurden in CO2-gesättigtem Kondensat mit unterschiedlichem Verhältnis der säurebildenden Komponenten untersucht. Diese Studien zeigten grundsätzlich den Mechanismus sowie die Rolle jedes CO2-Strom-Begleitstoffes auf den Korrosionsprozess. Allerdings spiegeln die bei Auslagerung und elektrochemischen Messungen in der künstlichen CO2-gesättigten Kondensat-Lösung auftretenden Bedingungen nicht im Detail die Realität in der Praxis, wo sich nur Tröpfchen bilden, wider.
Diese Arbeit konzentriert sich auf den Korrosionsprozess von Kondensat in Form von Tröpfchen, auf der Oberfläche von Rohrleitungswerkstoffen unter CO2-Atmosphäre bei 5 °C (Simulation des Transportzustandes). Die Experimente wurden nicht nur für Auslagerungsversuche, sondern auch für elektrochemische Tests mit nur einem Tröpfchen (weniger als 20 µL) konzipiert. Die Auslagerungs-versuche wurden sowohl unter Normaldruck als auch bei hohem Druck (> 70 bar) durchgeführt, wobei das CO2 als dichte – den Tropfen umgebende - Phase vorliegt. Die korrodierten Prüfkörper wurden rasterelektronenmikroskopisch (REM) und mittels Energiedispersiver Röntgenspektroskopie (EDX) analysiert, um nicht nur Korrosionsform, sondern auch die Elementverteilung der Korrosionsprodukte zu zeigen.
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.
Carbon Capture and Storage (CCS) is identified as an excellent technology to reach the target of CO2 reduction. However, the safety issue and cost effectiveness hinder the future of CCS. For the reliability and safety issues of injection wells the corrosion resistance of the materials used needs to be determined.
In this study, representative low cost materials including carbon steel 1.8977 and low alloyed steel 1.7225 were embedded in cement to mimic the realistic casing-cement interface. Electrochemical studies were carried out using these metal-cement specimens in comparison with those made of metal only in CO2 saturated synthetic aquifer fluid, at 333 K, to reveal the effect of cement on the steel performance. The results showed the protective effect of cement on the performance of pipeline metals during polarisation process. However, the corrosion current density was high in all cases, with and without cement, indicating that the corrosion resistance of these materials is low. This conclusion was supported by the surface analysis of the polarized specimens, which revealed both homogenous and pitting corrosions.
Carbon Capture and Storage (CCS) is identified as an excellent technology to reach the target of CO2 reduction. However, the safety issue and cost-effectiveness hinder the future of CCS. For the reliability and safety issues of injection wells, the corrosion resistance of the materials used needs to be determined.
In this study, representative low-cost materials including carbon steel 1.8977 and low alloyed steel 1.7225 were investigated in simulated pore water at 333 K and under CO2 saturation condition to represent the worst-case scenario: CO2 diffusion and aquifer fluid penetration. These simulated pore waters were made from relevant cement powder to mimic the realistic casing-cement interface. Electrochemical studies were carried out using the pore water made of cement powder dissolved in water in comparison with those dissolved in synthetic aquifer fluid, to reveal the effect of cement as well as formation water on the steel performance. Two commercially available types of cement were investigated: Dyckerhoff Variodur® and Wollastonite. Variodur® is a cement containing high performance binder with ultra-fine blast furnace slag which can be used to produce high acid resistance concrete. On the other hand, Wollastonite is an emerging natural material mainly made of CaSiO3 which can be hardened by converting to CaCO3 during CO2 injection.
The results showed the pH-reducing effect of CO2 on the simulated pore water/aquifer (from more than 10 to less than 5) leading to the active corrosion process that happened on both 1.8977 and 1.7225. Electrochemical characterization showed negative free corrosion potential and polarisation curves without passive behaviors. The tested coupons suffered from pitting corrosion, which was confirmed by surface analysis. Interestingly, basing on the pit depth measurements from the tested coupons and the hardness of cement powder, it is suggested that Variodur® performed better than Wollastonite in both aspects. The electrochemical data was compared to that resulted from exposure tests to give a recommendation on material selection for bore-hole construction.
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.
Synergistic effects of impurities in the condensate on the corrosion of CO2 transport pipeline
(2017)
For the reliability of transport pipelines the corrosion resistance of the materials used needs to be determined in conditions, which are possible during the transport process. In some situations condensation of components out of the CO2 stream can occur. To study the effect of condensate on transport pipeline steel, a “worst-case scenario” gas mixture, containing 2.5 % H2O, 1.8 % O2, 1000 ppmv NO2, and 220 ppmv SO2, was proposed, fed (1.5 L/min) into a glass reactor containing coupon-shaped specimens for 120 600 h at 278 K (to simulate the underground pipeline transport), and resulted in the condensate containing 0.114 M H2SO4 and 0.0184 M HNO3 (pH 2.13). Basing on this “original” condensate, exposure tests and electrochemical characterization together with pH and conductivity in CO2 saturated condition at the same temperature were carried out. The role of each gas impurity and the combination of them, when the condensate is formed, was studied by investigating the role of individual and varying combination of acidic components in the condensate on the corrosion behaviors of the commercial pipeline-steel (L360NB). It can be concluded that although the condensation of NOx in form of HNO3 causes faster corrosion rate, it is the condensation of SOx or the combination of SOx and NOx that may cause much more severe problems in form of localized and pitting corrosions. Different to the corrosion products formed in CO2 atmosphere without impurities (mainly iron carbonate) the corrosion products resulted from these acidic condensation have no protectability, indicating the need of controlling gas quality during the transportation within the pipeline network.
The electrochemical behavior of UNS(1) N08031 was investigated as a function of electrode potential in Green-Death(2) solution at 40 °C. The UNS N08031 surface is in a stable passive state during cyclic potentiodynamic polarization without an initiation and/or propagation of localized corrosion. In potentiostatic polarization of UNS N08031 for 3600 s, passive current density increases with an increase in the passivation potential from 0.7 to 1.0 VSSE (silver/silver chloride reference electrode in saturated potassium chloride) 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 mechanism of the defective passive film formation is discussed. The increase of the applied potential is considered to be a reason for the change in passive film stability.
Biodiesel (FAME) from rapeseed is an environmentally friendly alternative to common fossil fuels. It is also suitable to serve as blending component to fuels like heating oil. If the fuel composition is changed, materials compatibility must be guaranteed. Adding polar biodiesel to nonpolar heating oil, changes the blend’s solvency and might cause swelling, extraction and solvation of polymers. The objective of this research was to investigate the compatibility of polymeric materials, which are commonly used for components in middle distillate facilities, along with blends of heating oil and 20 % biodiesel (B20). For this propose, ACM, HNBR, FKM, PE, PA 6, POM, PUR and PVC were exposed to heating oil and B20 for 42 and 84 days at 40 °C. In addition, the polymers HNBR, FKM, PA, POM and PVC were also exposed at 70 °C. Furthermore, the resistance of polymers in eight-year aged B10 at 40 °C was evaluated. Ageing of biodiesel increases acidity which might propagate polymer corrosion. The materials were evaluated as resistant, if the loss in tensile properties (tensile strength and elongation at break) and Shore hardness remained under 15 % compared to the initial unexposed material values. For investigations under compressed conditions, the compression set was determined for specimens of ACM, FKM and HNBR after exposure in heating oil B0 and B20 for 3,7,14, 28, 56 and 90 days at 40 °C according to ISO 815-1. It was found that the resistance in B20 at 40 °C was given for all tested polymers except PUR. In the 8 years aged B10, PUR and POM were not compatible and ACM just conditionally compatible. At 70 °C, FKM and PVC were resistant in B20, whereas HNBR and PA 6 were not compatible. Swelling occurred for the elastomers ACM, HNBR and PUR.
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.
Corrosion Resistance of the Super-Austenitic Stainless Steel UNS S31266 for Geothermal Applications
(2017)
Super-austenitic stainless steels cover grades with high chromium (20 to 27 %), high nickel (18 to 31 %) and high molybdenum (4 to 6 %) contents. Within this family, the 6%Mo high nitrogen grade S31266 was developed to combine the beneficial influence of chromium, tungsten, molybdenum and nitrogen on its mechanical and corrosion properties. Due to 22 % nickel, 24 % chromium and 0.4 % nitrogen additions, this alloy exhibits a very stable microstructure, being less prone to intermetallic phase precipitation than the other highly alloyed super-austenitic stainless steels.
This paper deals with the corrosion resistance of S31266 in artificial geothermal water with moderate salinity and low pH. Long-term static exposures and electrochemical tests were conducted at various temperatures to evaluate the pitting, crevice and stress corrosion cracking resistance of this material.
The results show that S31266 is resistant up to 220 °C. As a consequence, it can be a good candidate material for geothermal applications involving a highly corrosive environment, especially salinity and low pH.
Changes in fuel composition and the introduction of alternative fuels often create problems of corrosion and degradation in materials. The objective of this research was to determine the corrosion behaviour of commercial metallic tank materials (unalloyed steels, austenitic CrNi- and CrNiMo-steels, aluminium and its alloys) in fuels and heating oil with admixtures of biogenic sources, such as gasoline with addition of ethanol (E10, E85), pure biodiesel and heating oil with 10 % biodiesel (B10).
Metallic tank materials were evaluated as resistant in a liquid if the annual corrosion rate due to uniform corrosion did not exceed 0.1 mm/year, and localized corrosion effects in the form of pitting corrosion, stress corrosion cracking and crevice corrosion did not occur.
The corrosion rates of the tank materials after exposure to E10, E85, non-aged and two-year aged pure biodiesel, and non-aged and one-year aged heating oil B10 for four weeks at 50 °C, according to DIN 50905/4, were well below the limit of 0.1 mm/year. For the unalloyed steels, the formation of rust was observed independently of the biofuels amount of ageing. U-bend specimens made of unalloyed steel were not damaged in form of stress corrosion cracking in all test fuels at this test temperature.