October 2022

Special Focus: Plant Safety and Environment

Sustainable steel/chemicals production: Removal of impurities for valorization of steel mill gases

Industry faces significant challenges relating to the transition toward cleaner energy and more sustainable feedstocks.

Industry faces significant challenges relating to the transition toward cleaner energy and more sustainable feedstocks. The key drivers of this transformation are greenhouse gas (GHG) avoidance and the formation of a more circular economy to lower the waste burden on the environment. Both transitions should support the needs of global population growth without affecting the planet's ability to also supply future generations. This is not the first transition that industry has faced, but, where previous industrial transitions were driven by technical developments (technology push), the current transitions are primarily driven by a strong societal pull. This means that the goals are clear, but the (technical) path to achieve these goals is not.

A traditional petrochemical value chain (FIG. 1) takes in carbon from fossil origin (oil or gas) and converts it into a broad variety of products in large assets that have been optimized for cost efficiency and product quality. This typically comes with a significant energy need that is traditionally delivered via combustion of fossil carbon, thus resulting in significant carbon dioxide (CO2) emissions and a post-consumer waste disposal problem. Therefore, the challenge will be to develop technologies and partnerships to deliver circular processes that utilize renewable energy and feedstocks.

FIG. 1. Schematic representation of the carbon value chain for a petrochemical company.
FIG. 1. Schematic representation of the carbon value chain for a petrochemical company.

Today, most of the global steel production is produced using blast furnace technology (FIG. 2). In this route, iron ore is reduced with coke from coal in a blast furnace, followed by the removal of residual-free carbon in the steel by oxygen injection in an oxygen converter. In this process, three major gas streams are co-produced with the target product steel: coke oven gas (COG), blast furnace gas (BFG) and basic oxygen furnace gas (BOFG).

FIG. 2. Schematic representation of a typical blast furnace-based steel mill. Source: ArcelorMittal.
FIG. 2. Schematic representation of a typical blast furnace-based steel mill. Source: ArcelorMittal.

A typical composition of these gases is represented in TABLE 1, which shows that COG primarily contains hydrogen (H2) and light hydrocarbons, whereas the BOFG is carbon monoxide (CO) rich.1 The largest amount of gas produced in a steel mill is BFG, which has a 1:1 ratio of CO and CO2 in a matrix of ~50% nitrogen (N2). This gas is very abundant in steel mills and is typically combusted in a power plant to produce electricity with a very high CO2 footprint.2 To create a greener electricity grid, an alternate use for CO is required. This is where industrial symbiosis (IS) could play an important role. Where companies traditionally optimize their processes and products within their own value chain, IS can take industry to the next level, as it enables the exploration of options to exchange water, waste, energy and material streams in a greater ecosystem by means of system integration and optimization. This not only has economic benefits, but also potentially a positive environmental impact, and can therefore optimize the greater industrial system and contribute to the energy and feedstock transitions.

Of all the steel mill gases, COG has the most significant amounts of impurities—such as ammonia, hydrogen cyanide (HCN), sulfur species [mainly hydrogen sulfide (H2S)], naphthalene, light oil and tar. The light oil is mainly characterized by benzene (80%–85%) and xylene and toluene (15%–20%). The tar is a highly complex blend that is not easy to process.

Today, a significant proportion of products is derived from olefins obtained from the steam cracking of hydrocarbons. However, the petrochemical industry has a long history of using CO (along with H2) in syngas chemistry.

In the past, limited access to oil reserves (such as during World War II) was a primary driver for the utilization of syngas chemistry—which ultimately led to the development of Fischer-Tropsch chemistry as an alternative route to chemicals and fuels. In periods of high oil prices, syngas chemistry has been explored for converting alternate carbon sources like coal, biomass, natural gas and waste plastics. Therefore, many companies have a long tradition in the development of syngas conversion technologies.

Since 2015, Dow Chemical, ArcelorMittal and Tata Steel have been exploring the use of H2-rich COG and CO-rich BFG and/or BOFG as members of an international consortium working on the Carbon2Value project, which explores innovative technology for reducing CO2 emissions across the major energy-intensive steel sector by 30–45%. The consortium’s goal is to use this technology to separate CO2 streams and to valorize CO and potentially CO2 in the future. Based on the knowledge that methanol can be produced commercially from COG1 and ethanol from BOFG and/or BFG,3 these consortium partners have anticipated that other chemical conversions should be possible, as well.4

In parallel, other consortia such as the Carbon2Chem project in Germany are also exploring these options.5 The goal of this project is to avoid CO2 emissions by utilizing CO in syngas conversion chemistry—hence, capturing the carbon in the material value chain. This is seen as a more interesting option than post-combustion CO2 utilization, as CO is more reactive and requires less energy to be converted.

Scope of work

To utilize steel mill gases in the production of chemicals and materials, several challenges have been identified.6,7 First and foremost, the composition of the gas does not meet typical specifications that can be achieved when methane is used to generate syngas via reforming (either partial oxidation, autothermal reforming or steam methane reforming). CO in the BFG is present in diluted form (with CO2 and N2) and contains many impurities. The steel mill gases are saturated with water and contain dust (sulfided iron oxide) and a variety of metals and S and N species. Therefore, the Carbon2Value program focused on three major targets:

  1. Removing impurities to bring the gas on spec for downstream conversion
  2. Improving process and carbon efficiency through the removal of diluents (N2, CO2)
  3. Providing technical demonstration of the concept at scale in a relevant environment.

Here we report the efforts on the removal of CO2 and impurities from the BFG and COG (targets 1 and 2). This work was completed in the framework of an Interreg 2 Seas project (2S01-094) with European Union (EU) co-funding.

After a careful analysis, the research team selected amine scrubbing as the technology to achieve the removal of CO2 and specific impurities in a single process.8 While it is quite common to use the direct reduction of iron to capture CO2 in steel production, to the best of the authors’ knowledge, amine scrubbing is only employed in one BFG steel mill and in a few pilot lines. Limited information about these pilot plants is available; however, challenges on the stability of the applied amine, along with details around the quality of the output gas for downstream processing, have not been reported in the public domain.

For this study, a commercial amine producta was selected. This is a formulated amine for CO2 and H2S removal9 that is expected to deliver better performance than the cheaper alternative monoethanolamine (MEA). A key area of focus was stability, thus making this an important subject of study. Therefore, the joint research program had the following targets:

  1. Assess the feasibility of amine washing with the proprietary solventa to remove CO2 and sulfur impurities from BFG, and from BFG co-fed with COG and COG
  2. Provide a CO-rich product that could be used in a downstream CO conversion unit
  3. Deliver data for full-scale plant design for CO2 capture at steel mills.

Description of the process

To deliver on the research targets, a CO2 capture pilot line was developed. The unit was engineered by Dow and Petrogas and constructed by Petrogas. The pilot unit was completely enclosed within a 40-ft container skid (FIG. 3). The container was designed to be easily transported via truck or ship for testing at different locations.

FIG. 3. Photo of the Carbon2Value CO/CO<sub>2</sub> separation pilot plant installed at the ArcelorMittal steel mill in Ghent, Belgium. The orange pipe contains the BFG that was fed to the unit.
FIG. 3. Photo of the Carbon2Value CO/CO2 separation pilot plant installed at the ArcelorMittal steel mill in Ghent, Belgium. The orange pipe contains the BFG that was fed to the unit.

The steel mill gases were supplied to the pilot unit from tie-ins made on the steel plant’s internal gas header system. The BFG and COG from the pipelines entered the unit at a slight overpressure (TABLE 2). All treated gases and offgases were routed back into the piping network of the steel mill.

The gas from the steel mill first passed through a set of coalescing filters—two installed in parallel for each feed gas—for high-efficiency removal of sub-micron liquid droplets and solids. Mass flowmeters installed downstream of the filters were used to meter in the gases to the compressor suction.

A process sketch of the acid-gas scrubbing process used in the pilot plant is shown in FIG. 4. The mixed gases were compressed in a single-acting, three-stage positive displacement compressor with interstage cooling and liquid condensate removal. The compressor can deliver gas at a maximum discharge pressure of 32 barg. The compressed gases from the compressor were cooled in a plate-and-frame heat exchanger to 40°C (104°F) with chilled ethylene glycol (EG). A flowmeter measured the flow of cooled gas before it entered the absorber.

FIG. 4. Schematic representation of the CO<sub>2</sub> removal process applied in this project.
FIG. 4. Schematic representation of the CO2 removal process applied in this project.

In the absorber, the steel mill gases were contacted with the proprietary solventa to remove the acid gases by chemisorption. The absorber—2.8 m in height and 5 cm in diameter—had a single packed bed loaded with stainless-steel pall rings for enhanced gas-liquid contacting. The column was fitted with a demister pad above the packed bed for de-entrainment. Pressure drop over the packed bed was monitored using a pressure differential cell to identify potential foaming or fouling in the packed bed. The column was also fitted with a resonating fork for foam detection at the top of the column. This was specified by Dow Industrial Solutions based on successful commercial scale applications. The bottom level in the column was measured using a guided wave radar and controlled via an air-actuated level control valve. The treated gas from the top of the absorber was measured using a flowmeter. The inlet flow measurements, along with the inlet and outlet stream compositional analysis, enabled the determination of the acid gas removal efficiency in the absorber.

The treated gas left the absorption column overhead and was routed to downstream consumers at pressure. The solvent left the absorption column through the bottom nozzle. The solvent is fully saturated (i.e., rich in CO2) and is further called “rich solvent.”

The rich solvent left the bottom of the absorber and passed through a particulate filter before being flashed in the horizontal flash vessel. The flash gas was removed from the top of the de-entrainment section of the flash, and the pressure was regulated between 4.5 barg–5.5 barg. The rich solvent from the flash vessel was first routed through an activated carbon filter before entering the top of the stripping column. The activated carbon filter removed foam-causing impurities (e.g., dissolved hydrocarbons, degradation products and a variety of surface-active agents) that had entered or formed in the system. Heat tracing was installed on the transfer line from the flash vessel to preheat the solvent to above 90°C (194°F) before entering the stripper column. Typically, on a commercial unit, preheating the solvent is done by a heat exchanger that recovers heat from the lean solvent after regeneration.

The rich solvent entered the top of the regenerator column and contacted stripped gases and water-amine vapors generated in the reboiler over a single packed bed loaded with stainless-steel pall rings for enhanced gas-liquid contacting. The power input to the electrical reboiler was controlled by maintaining a desired temperature at 120°C (248°F) of the solvent. An overflow weir was installed in the vessel to maintain a constant liquid level to submerge the reboiler and ensure adequate liquid residence time in the reboiler. The overflow from the reboiler was routed into a surge vessel that was located directly below the vessel containing the reboiler.

The overhead vapors from the regenerator column were cooled in a plate-and-frame exchanger to 20°C (68°F) with chilled EG. The condensed liquid was recovered from the acid gases in a knockout vessel that had a demister for high-efficiency de-entrainment. The liquid recovered in the knockout vessel was returned to the top of the regenerator column, using a positive displacement pump.

The lean solvent exited the bottom of the surge vessel and was cooled in a plate heat exchanger to 40°C (104°F) with chilled EG. The cooled solvent was pumped to the absorber. The chilling loop system of a chilled water loop, filled with EG (30 wt%), was cooled to 10°C (50°F) with a chiller unit. The total circulation rate of chilled water was 4 m3/hr, with a total process flow requirement of 0.4 m3/hr.

The unit was fitted with an online gas chromatograph (GC) for gas analysis. Of this setup, three gas streams were analyzed online: the outlet of the compressor, the outlet of the absorber and the outlet of the stripper. The analysis of the liquid amine solvent was done offline in the Dow Industrial Solutions lab in Terneuzen, Netherlands. The process GC system was equipped with five parallel chromatographic trains to separate all major components with a cycle time of 300 sec.

To deliver on the research objectives, the pilot line was operated continuously for specific periods of time in 2018–2021.

Results and discussion

The operational period for the pilot line started with commissioning in 2H 2018. Operations commenced in 2019 and continued in 2020–2021. Over time, the unit availability increased, enabling extended campaigns lasting multiple months at a time. The run length was initially limited by excessive pressure drop over the inlet filters. Improvements to the filter design enabled extended run lengths between filter changes.

The data presented here are mostly from 2020 and comprise two periods:

  • Experiment 1 (Exp. 1), in which the unit was operated for ~800 hr on BFG only (blue data points), BFG + COG mix (purple datapoints) and COG only (red datapoints)
  • Experiment 2 (Exp. 2), in which the unit operated for ~2,500 hr on BFG only.

In total, the unit captured ~2.2 t of CO2 during Exp. 1 and 9.2 t of CO2 during Exp. 2, based on mass balancing with the mass flowmeters and gas composition data from the online GC. In Exp. 1, the cleaned gases from the absorber were routed to a downstream unit of LanzaTech, which utilized the treated gas as a feedstock for ethanol production (not reported here).

The CO2 removal efficiencies during Exp. 1 and Exp. 2 are presented in FIG. 5. The data shows that the targeted CO2 removal efficiency of 90%–95% could be achieved for extended periods of time. During Exp. 1, process conditions were optimized—namely solvent circulation rates and energy input—to reach CO2 removal efficiencies of 95%–100%, albeit at an increased heating duty in the reboiler.

FIG. 5. CO<sub>2</sub> removal efficiencies during Exp. 1 and Exp. 2. In these periods, a total of 2.4 t and 9 t of CO<sub>2</sub> were captured, respectively. Exp. 1 was BFG only (blue data points), BFG + COG (purple data points) and COG only (red data points). Exp. 2 (black data points) was BFG only.
FIG. 5. CO2 removal efficiencies during Exp. 1 and Exp. 2. In these periods, a total of 2.4 t and 9 t of CO2 were captured, respectively. Exp. 1 was BFG only (blue data points), BFG + COG (purple data points) and COG only (red data points). Exp. 2 (black data points) was BFG only.

It was found that performing a detailed energy balance of the system to evaluate energy input per unit mass of CO2 removed was not possible on the pilot unit. Primarily due to the high relative heat losses at this smaller scale at various locations in the process, it was found that the measured number had a high standard deviation from the actual number. Dow Industrial Solutions supports hundreds of commercial CO2 capture units, and it has a proprietary empirical model that predicts the performance of such units. For this small-scale pilot, the heating duty was calculated to be 4.2 GJ/mT of CO2 captured in an idealized configuration. However, the model predicts that this would translate to 2.3 GJ/mT of CO2 captured in a commercial-scale installation. This is well in line with world-class performance for an amine-based CO2 capture unit.12

The impurities present in COG can lead to foaming, fouling and a higher buildup of heat-stable amine salts (HSAS), which can have a significant negative impact on the performance of the system. HSAS are the amine salts of acidic contaminants that do not thermally split and liberate in the regenerator. In the chemical analysis of gas treating amines, they are reported as the weight percent of solution that is amine bound as non-regenerable salt. Naphthalene and tar can condense in the solvent to create fouling material and promote foaming, especially at cold spots. They can also act as a binder if other inorganic particles are present in the system and, thus, aggravate these problems. The acidic species can lead to higher levels of HSAS. Although Dow was aware of these potential problems, for the purpose of this project, a robust pretreatment section (or any other measure in the unit) was not considered to minimize the level of these impurities and their impact, except for the use of a proprietary antifoamb.

FIG. 5 shows that the unit had stable operation during Exp. 1 with BFG only (black and blue data points) and during the run in which BFG was mixed with COG. However, when only COG was processed, unit performance showed a rapid decrease over a period of 1 wk. The red data points show a lower CO2 capture efficiency and a period of unstable operation because of foaming issues in the system. However, the primary cause for this unstable operation was continuous foaming and fouling of the unit due to the presence of naphthalene, tars and oils in the COG that condensed in the absorber. The continued accumulation of these impurities resulted in unit fouling, which was reflected by a high pressure drop across the absorber column and downstream equipment, such as heat exchangers and coolers.

A unit shutdown took place after Exp. 1, and the unit was opened for maintenance. Process forensics indicated significant fouling in several sections of the unit. The nature of the fouling was identified with several analyses, such as elemental analyses of deposits, microscopy of solid residues and GC-mass spectrometry of organic liquids. Based on these results, it was confirmed that aromatic tars from the COG were present in the installation. These are known to cause foaming and fouling in various gas-liquid separation processes when they condense in the colder parts of the unit (e.g., post-compression coolers). Evidence of foaming was also found on the packing that was loaded into the absorber and stripper column.

Additional design features could improve the feedstock purification, such as an upstream pretreatment (washwater column) or other measures in the unit (skimming systems), especially on the high-pressure side of the unit. Furthermore, the preventative use of the proprietary antifoamb would have helped to mitigate the negative impact of the feed gas impurities. However, such improvements were out of scope for this work; therefore, it was decided to discontinue operations with COG. In case COG were utilized as a source of H2 in steel gas valorization, it was anticipated that, with adequate design considerations, the naphthalene, light oil and tar content of such gases could be addressed.

Tar and light oil are not the only contaminants that can impact utilization potential. Steel gases like BFG, BOFG and COG also contain a significant number of contaminants, such as ammonia (NH3), HCN, H2S, carbonyl sulfide (COS) and carbon disulfide, as well as metals such as iron, mercury and arsenic10,11 and traces of O2. These can affect the operations directly or indirectly, and a major objective of this study was to assess that impact as a function of time. During operations, liquid samples were extracted from the amine circulation at a frequent rate. Typically, a 250-ml liquid solvent sample was collected every 72 hr from the unit. These samples were analyzed at Dow’s laboratories.

Analysis results were used to control the amine concentration in the solvent within a target band of 40 wt%–50 wt%. Water—and occasionally amine—was added to the system to replace the water lost from the system.

More interestingly, the chemical composition of the liquid circulation provided an indication of the impact of the treated gas on the composition of the solvent. An extensive list of organic and inorganic species was monitored, along with important parameters such as pH, color, density and acid gas loading. It should be noted that contaminants in the gas can also cause indirect damage, as they can be converted into other more harmful species upon the chemical reactions caused by the basic nature of the solvent, the temperature in the installation and the presence of metals that might catalyze these side reactions.

It was clear from the regular solvent analysis that, despite the relatively poor quality of the BFG (blue and black data points in FIG. 6), the buildup of HSAS was found to be steady, but slow. A somewhat higher rate of formation, although still not critical, was observed when COG was co-fed with the BFG (purple data points) or fed on its own (red data points). The faster growth of the HSAS concentration in these experiments was directly related to the higher concentration of contaminants in the COG. Based on the pilot plant data and operational experience, it was found that untreated COG cannot be fed directly to an amine absorption unit without having a significant impact on the process economics from a capital expenditure perspective (implementation of purification equipment) and an operational expenditure perspective (solvent and energy use). It should be noted that Exp. 2 was terminated because of fouling issues. The upper limit for HSAS was not reached during this experiment.

FIG. 6. Concentration of HSAS as a measure of solvent quality for Exp. 1 (black data points) and  Exp. 2 (blue, purple and red data points) as a function of time.
FIG. 6. Concentration of HSAS as a measure of solvent quality for Exp. 1 (black data points) and Exp. 2 (blue, purple and red data points) as a function of time.

Amine degradation products can be of particular concern when using commodities like primary and secondary amines, such as MEA and diethanolamine (DEA). Examples of associated, problematic degradants include bicine and tris-hydroxyethyl ethylenediamine (THEED), which can result in corrosion of process equipment when not properly managed. Formulated, proprietary aminesc substantially mitigate these risks.

These species could ultimately build up to a concentration that is undesired and should, therefore, be removed from the process.12 However, in this study, the formation and accumulation of both HSAS and amine degradation products were not found to be a cause for operational problems, so the replacement of the amine solvent inventory was not necessary (FIG. 7). This data clearly illustrated the very low reactivity of the proprietary solventa toward the formation of degradation products vs. generic gas treating solvents.

FIG. 7. Buildup of degradation products (i.e., the sum of bicine + THEED + hydroxyethyl ethylene  urea + HEED) during Exp. 1 (black data points) and Exp. 2 (blue, purple and red data points)  as a function of time. Note: Detection limit is ~100 ppmw.
FIG. 7. Buildup of degradation products (i.e., the sum of bicine + THEED + hydroxyethyl ethylene urea + HEED) during Exp. 1 (black data points) and Exp. 2 (blue, purple and red data points) as a function of time. Note: Detection limit is ~100 ppmw.

The primary HSAS encountered in this study was formate (> 80% of the HSAS). The rest of the anions were primarily thiocyanate and acetate. Formate is formed in this system in several different reactions, such as HCN hydrolysis.

For downstream utilization of the CO2 lean gas, the quality of such gas is critical. Therefore, the CO2 content in the treated gas was monitored, along with the H2S, COS and NH3 contents. These components are typically present at concentrations of 1 ppmw–30 ppmw in the feed gas. Amine solvents are also selective toward sulfur species, and it was observed that a high sulfur removal efficiency could be achieved. The CO2 lean gas had a measured H2S concentration between 1 ppm and 2 ppm, and this has the potential to be removed until even lower values under more optimized conditions for H2S capture. Although this is not zero, and it is still an issue for the use of the CO-rich gas to conduct syngas chemistry, the bulk removal of H2S and COS would allow for an affordable deep removal of such species in a guard-bed setup prior to entering the downstream CO conversion unit.6

The downside of the H2S capture by the amine solvent was that it is released with the CO2. Consequently, the H2S is concentrated in the CO2 outlet stream with roughly a factor 4 vs. the input concentration. In essence, this means that the CO2 from treated BFG contains 50 ppm–60 ppm of H2S, and, when treating COG, this could be as much as 250 ppmw of H2S. Further purification of the captured CO2 would need to be considered in case this CO2 is to be processed further via either carbon capture and storage or carbon capture and utilization. In this respect, it is also important to note that traces of amine could be present in the captured CO2. The CO2 from the reboiler was analyzed and was found to contain 1 ppm–2 ppm of the amine, but no NH3 was detected in the CO2.

Summary and outlook

A CO/CO2 separation pilot line was developed and operated with co-funding from the Interreg 2 Seas program. The unit was installed in the heart of the ArcelorMittal steel mill in Ghent, Belgium. This enabled the unit to be fed with real industrial waste gases (e.g., BFG and COG) directly from the major gas lines in the facility.

In the 2019–2021 timeframe, the unit was mainly operated on BFG. It was shown that the inlet filters were effective in removing (acid) condensate and dust from the feed gas. Operation on COG demonstrated that the current filter design did effectively remove the tars present in this gas. Consequently, severe process upsets were observed in the run with COG, mostly due to foaming and fouling caused by the presence of aromatic tars in the amine solvent. Additional measures to clean COG are needed to utilize this gas.

Several thousand hours of operation with BFG demonstrated that the applied proprietary solventa can capture CO2 from BFG at greater than 90% efficiency with minimal degradation. More than 95% efficiency was achieved under optimized conditions. In addition, H2S and COS in the gas were also captured, resulting in a treated gas with H2S and COS in a low ppm range (i.e., 1 ppm–5 ppm). This enabled the use of the CO2 lean gas for CO conversion chemistry, which is typically less tolerable for impurities and requires sub-ppm levels. Although deep removal for chemical conversion is still required, the bulk of the sulfur impurities can be effectively removed using an amine system. A trial with LanzaTech fermentation technology for ethanol production from BFG was conducted successfully. In a follow-up project, for which the CO/CO2 separation pilot line will serve as a feedstock pretreatment, the project partners will explore the subsequent polishing and catalytic conversion of the CO-rich gas.

It was also demonstrated that the relatively poor quality (dust, impurities) of the BFG had limited effect on the long-term quality of the proprietary solventa. Consequently, it was anticipated that an excessive make-up of the amine solvent would not be required, which had a positive impact on the operational costs. As expected, while still not critical for the process, the much poorer quality of the COG showed a higher degradation rate for the solvent. In combination with the observed fouling of the unit when running on this gas, it was decided that amine wash was not a good solution for treatment of COG and/or BFG + COG mixtures without any upstream pretreatment for tar and oil removal to values of less than 100 ppm.

Operations with BFG also confirmed that amine carryover to the CO2 was low and that the energy for solvent regeneration was in line with expectations and on par with typical numbers for this technology (i.e., 2.3 GJ/mT–4.2 GJ/mT CO2 captured). This energy use could be significantly improved when heat integration with the exothermic CO conversion process was implemented.13

The quality of the captured CO2 remains a challenge. As the amine solvent also captured the sulfur species, these will concentrate in the CO2. Consequently, H2S levels of 50 ppm–250 ppm were observed. To be able to send this CO2 for storage and/or utilization, desulfurization of the CO2 must be considered. A suitable technology for this could be Villadsen’s electrochemical desulfurization.14  HP

ACKNOWLEDGMENTS

This project was performed by the Carbon2Value consortium and co-funded by the EU’s Interreg 2 Seas program (Project 2S01-94). The authors kindly acknowledge numerous internal and external contributors to the project, and our external partners at ArcelorMittal Ghent, Petrogas BV, Dow Industrial Solutions, Dow Chemical Lab, Dow Hydrocarbons R&D, LanzaTech, Provinciale Ontwikkelingsmaatschappij Oost-Vlaanderen (POMOV), the University of Lille in France, the Institute for Sustainable Process Technology (ISPT), and Impuls Zeeland (Smart Delta Resources program).

NOTES

a Dow Industrial Solutions’ UCARSOL™ AP 814 solvent
b Dow Industrial Solutions’ UCARSOL™ GT-10 antifoam
c Dow Industrial Solutions’ UCARSOL™ amines

LITERATURE CITED

  1. Schittkowski, J., H. Ruland, D. Laudenschleger, K. Girod, K. Kähler, S. Kaluza, M. Muhler and R. Schlögl, “Methanol synthesis from steel mill exhaust gases: Challenges for the industrial Cu/ZnO/Al2O3 catalyst,” Chemie Ingenieur Technik, 2018.
  2. Kumar, B., G. G. Roy and P. K. Sen, “Comparative exergy analysis between rotary hearth furnace-electric arc furnace and blast furnace-basic oxygen furnace steelmaking routes,” Energy and Climate Change, 2020.
  3. Karlson, B., C. Bellavitis and N. France, “Commercializing LanzaTech, from waste to fuel: An effectuation case,” Journal of Management and Organization, 2021.
  4. Metabolic, “Coresym: CarbOn-monoxide RE-use through industrial SYMbiosis between steel and chemical industries,” December 2017, online: https://www.metabolic.nl/publications/coresym-carbon-monoxide-re-use-through-industrial-symbiosis/
  5. thyssenkrupp, “The Carbon2Chem® project,” online: https://www.thyssenkrupp.com/en/newsroom/content-page-162.html
  6. Keys, A., M. van Hout and B. Daniëls, “Decarbonization options for the Dutch steel industry,” September 2021, online: https://www.pbl.nl/sites/default/files/downloads/pbl-2019-decarbonisation-options-for-the-dutch-steel-industry_3723.pdf
  7.  He, J., D. Laudenschleger, J. Schittkowski, A. Machoke, H. Song, M. Muhler, R. Schlögl and H. Ruland, “Influence of contaminants in steel mill exhaust gases on Cu/ZnO/Al2O3 catalysts applied in methanol synthesis,” Chemie Ingenieur Technik, 2020.
  8. Topsector Energie, “Inventory of large-scale reuse of blast furnace gas,” online: https://projecten.topsectorenergie.nl/projecten/gas-treatment-revasin-24651
  9. Dow Chemical, “UCARSOL™ AP Solvent 814,” online: https://www.dow.com/en-us/pdp.ucarsol-ap-solvent-814.85782z.html#overview
  10. Bannikov, L. P., S. A. Ovchinnikova, V. V. Suprun and S. V. Nesterenko, “Influence of impurities on sulfur removal from coke-oven gas,” Coke & Chemistry,” 2020.
  11. de Oliveira Carneiro, L., S. Fernandes de Vasconcelos, G. Wanderley de Farias Neto, R. Pereira Brito and K. Dantas Brito, “Improving H2S removal in the coke oven gas purification process,” Separation and Purification Technology, 2021.
  12. Baburao, B., S. Bedell, P. Restrepo, D. Schmidt, C. Schubert, B. DeBolt, I. Haji and F. Chopin, “Advanced amine process technology operations and results from demonstration facility at EDF Le Havre,” Energy Procedia, 2014.
  13. Meima, G., A. Malek, C. Biesheuvel, P. Groenendijk, M. Ruitenbeek, T. Davidian and S. Corthals, “Method and system for reducing CO2 emissions from industrial processes,” U.S. Patent No. 10639586B2, 2016.
  14. Villadsen, S. N. B., M. Ahrensberg Kaab, L. Pleth Nielsen, P. Møller and P. Loldrup Fosbøl, “New electroscrubbing process for desulfurization,” Separation and Purification Technology, 2021.

The Authors

Related Articles

From the Archive

Comments

Comments

{{ error }}
{{ comment.comment.Name }} • {{ comment.timeAgo }}
{{ comment.comment.Text }}