Patent Application
20240052441
The necessity as well as the duty to reduce global CO2 emissions is influencing the steel industry as one of the main responsible player. The worldwide decarbonisation is pushing the steelmakers towards a transition for a more-sustainable production, based on H2 DRI process.
Hydrogen is the new key factor for CO2 reduction at the present days and in particular for a future decarbonised steel production (green hydrogen).
Today, the main consolidated hydrogen production processes are:
i) Steam Reforming of Natural Gas
This process is the most common and cheapest source of industrial hydrogen.
The natural gas is heated up to 700-1100° C. in the presence of steam and a nickel catalyst. The methane molecules are broken forming carbon monoxide and hydrogen. The carbon monoxide gas passes with steam over iron oxide or other oxides and through a water gas shift reaction further hydrogen is obtained.
Hydrogen produced in this way is economically attractive, but requires fossil fuels, and CO2 capture to avoid emissions.
ii) Electrolysis Unit
Water-based electrolysis units are composed by several cells each one composed by one anode and one cathode submerged into an electrolytic solution and connected to a power source. The electricity dissociates the water inlet flow into hydrogen and oxygen.
Steam-fed electrolysis units instead use steam as input to produce hydrogen and oxygen, based on approximately the same principle as the water-based ones.
Water-fed electrolysis units are expensive from CapEx and OpEx standpoint. Steam-fed electrolysis units are expensive from CapEx and OpEx standpoint; less OpEx expensive than water-fed due to higher efficiency.
The hydrogen production is thus currently associated with high costs so that the main driver is to find new and alternative and sustainable solutions to use hydrogen reducing the associated costs.
The present disclosure aims to find attractive configurations to produce hydrogen in a sustainable and competitive manner, when located in an industrial environment.
The present disclosure discloses a plant and method of producing DRI in a hydrogen direct reduction (DR) plant.
The production of hydrogen (H2) for the hydrogen DR plant is realized through innovative configurations, using gas shift reactor plant and/or steam-fed electrolysis unit for exploiting energy carriers already existing in a complex steel making plant (or more generally industrial site) to produce hydrogen.
Above-mentioned energy carriers are steam and/or CO bearing gas.
According to the disclosure, a method of producing direct reduced iron, DRI, comprises:
The ‘hydrogen DR plant’ may be a DR plant fed with hydrogen as reducing gas, wherein the hydrogen content of the reducing gas is between 85 and 100 vol. %, preferably above 85, or 90 vol. %, e.g. between 90 and 95 vol. %. Such hydrogen DR plant typically includes a shaft furnace and associated recycling gas loop, known as process gas loop, through which furnace top gas is treated (typically cleaned and compressed) and heated to be recycled into the furnace as reducing gas, with the above-mentioned hydrogen content. An optional fuel gas loop (using part of the recycled top gas) can be used for heating purposes in the heater equipment. Hydrogen, provided by the hydrogen stream, generally referred to as make-up hydrogen stream, is added to the process gas loop in amounts sufficient to reach the above-mentioned hydrogen concentration range, in accordance with process requirements. The role of the make-up hydrogen stream is thus to complement the amount of hydrogen in the process loop to reach the desired H2 operating concentration in the reducing gas. The hydrogen make-up stream may typically have a H2 content of 90 to 100 vol. %. The hydrogen DR plant may typically be a MIDREX H2 plant.
The steam may be recovered from any component of the industrial where steam may be available. Alternatively or additionally, steam may be produced through any well-known heat recovery equipment using waste heat sources present in the industrial process that otherwise would represent a heat loss. The heat recovery equipment may typically include a heat exchanger configured to bring into heat exchange relationship the hot gases/waste heat and water to generate steam. The heat recovery equipment may e.g. include a boiler where water is heated by the hot gases/waste heat.
The so-generated steam is supplied to one or more steam-fed electrolysis unit(s) that can convert the steam into hydrogen and oxygen by using electricity as input. Any appropriate electrolysis unit can be used, able to separate oxygen from the water vapour, e.g. a solid oxide electrolyzer cell (SOEC).
The CO-bearing gas represents any available industrial gas with a considerable content in carbon monoxide (e.g. at least 20 v %, or more, in some embodiments 20 to 25 v %, but other gases with higher CO concentrations can be used). In the ironmaking context, the CO-bearing gas may be any metallurgical gas present in the entire plant with a considerable content in carbon monoxide (e.g. BF gas, BOF gas, TGF gas, SAF offgas, etc), preferably with low nitrogen content. By means of equipment based on water gas shift (WGS) technology and CO2 removal, the CO-bearing gas is converted into carbon dioxide CO2 stream, that is separated from the rest, i.e. substantially a hydrogen-rich stream. Various technologies can be used such as the ones used in the art for pre-combustion CO2 capture. In the following, this equipment will be named gas shift reactor plant (GSRP). As is known in the art, the GSRP can include a WGS reactor combined with CO2 capture equipment (e.g. Amine technologies). Alternatively, integrated technologies can be used, where a single reactor is configured to realize the WGS reaction and separate CO2. These technologies are known in the art and need not be further detailed.
Any conventional steam-fed electrolysis unit, any GSRP plant and any heat recovery equipment adapted for generating steam may be used in the context of the disclosure.
In embodiments, the hydrogen DR plant is combined with a natural gas DR plant present in the industrial site.
The natural gas DR plant may typically be a MIDREX NG plant; alternatively it can be substituted by a MIDREX MxCol plant or NG/H2 plant.
The natural gas DR plant classically operates on reformed natural gas to produce DRI from iron ore. It comprises a further shaft furnace and a further process gas loop, the further process gas loop including heater-reformer means to generate a syngas from natural gas (and the recycled process gas). This syngas is used in the further shaft furnace as reducing gas, the typical composition of the reducing gas fed to the furnace being approximately 30-34 vol % CO, 0-4% CO2, 50-55% H2, 2-6% H2O, 1-4% CH4, 0-2% N2.
As will be clear to those skilled in the art, the natural gas DR plant emits a top gas that is hot gases and contains CO. The conventional natural gas DR plant can be synergistically operated with the hydrogen DR plant to reduce the need on hydrogen from external sources. The same can be done for MxCol and NG/H2 plants.
In embodiments, the method includes recovering heat from the natural gas DR plant to generate steam and produce hydrogen in the electrolysis means.
This can be done at several locations in the natural gas DR plant:
Steam can be generated by recovering heat in a same manner (same location) in MxCol and NG/H2 plants, in order produce hydrogen through electrolysis.
The industrial site may generally include an electric arc furnace, EAF, in particular for melting the DRI produced in one of the DR plants or elsewhere. There, heat recovery means may advantageously be arranged to recover heat from hot gasses/waste heat emitted by the EAF to generate steam (fed to the electrolysis unit).
In embodiments, the method includes extracting CO-bearing gas from said natural gas DR plant and feeding said extracted CO-bearing gas to said gas shift reactor means to produce hydrogen. A first stream of CO-bearing gas can be branched off from the process gas loop, preferably downstream of the compressor unit. A second stream of CO-bearing gas can be branched off after the dedusting device.
In embodiments, the method may include recovering heat by means of one or more heat recovery means arranged at one or more locations in the hydrogen DR plant, and feeding the generated steam to the electrolysis means.
Heat recovery means may also be arranged on the process gas loop of the hydrogen DR plant, in particular upstream of the dedusting device, to recover heat from recycled top gas and generate steam fed to the electrolysis means.
Heat recovery means may be arranged to recover heat from hot DRI produced by the hydrogen DR plant, to generate steam fed to the electrolysis means.
In general, heat recovery means may be arranged to recover heat from one or more components within the industrial plant, in particular an EAF, from one or more DRI heat recovery systems (from any DR plant), from any of the DR plants.
According to another aspect, the disclosure relates to a plant comprising:
This plant may generally be configured to implement the above-described method.
According to another aspect, the disclosure relates to a method of operating a hydrogen DR plant, comprising recovering heat by means of heat recovery means arranged at one or more locations in the hydrogen DR plant, and feeding the generated steam to electrolysis means to produce hydrogen that is, in turn, fed, at least in part, to the process gas loop of the hydrogen DR plant.
Heat recovery means may be arranged on the process gas loop of the hydrogen DR plant, in particular upstream of the dedusting device, to recover heat from the recycled top gas and generate steam fed to the electrolysis means.
Heat recovery means may be arranged to recover heat from a DRI heat recovery system of the hydrogen DR plant, to generate steam fed to the electrolysis means.
According to still another aspect, the disclosure relates to a system for implementing the previous method (see also embodiment 4 below).
The present disclosure will now be described, by way of example, with reference to the accompanying drawings, in which
Industrial sites are characterized by steam and CO-bearing gas availability. In this context, the installation of H2 direct reduction plant (e.g. MIDREX® H2) results fully integrated within the existing industrial site, as per the following embodiments.
As will be seen, the present disclosure proposes configurations where a DR plant is fully integrated in an industrial site, in particular metallurgical plant. The disclosure focuses on assisting the hydrogen DR plant to produce H2 by exploiting synergies within these industrial sites.
In the following embodiments, the hydrogen operated DR plants are e.g. of the MIDREX H2™ type.
In some embodiments the hydrogen DR plant is installed on a site with a natural gas operated DR plant, which is e.g. of the MIDREX NG type.
Referring now to
DR plant 10 is generally corresponds to the MIDREX H2 process. As is known, it comprises a vertical shaft 16 with a top inlet 18 and a bottom outlet 20. A charge of iron ore, in lump and/or pelletized form, is loaded into the top of the furnace and is allowed to descend, by gravity, through a reducing gas. The charge remains in the solid state during travel from inlet to outlet. The reducing gas (mainly composed of Hz) is introduced laterally in the shaft furnace—as indicated by arrow 22, at the basis of the reduction section, flowing upwards, through the ore bed. Reduction of the iron oxides occurs in the upper section of the furnace in a Hz-rich reducing atmosphere, at temperatures in the range 850-950° C. The solid product, i.e. the direct reduced iron (DRI) or reduced sponge iron, is discharged after cooling or in a hot state, as indicated CDRI (Cold DRI), HDRI (Hot DRI) and HBI (Hot briquetted iron).
According to the MIDREX H2 process, almost pure hydrogen is used as the reducing gas for DR furnace.
The ideal hydrogen content of the reducing gas is 100%. In practice, the H2 content may vary between 85 and 100 vol. %, with the balance composed by N2, CO, CO2, H2O and CH4. These constituents result from the purity of the H2 make-up, and from eventual addition of natural gas as known in the art.
As will be known to those skilled in the art, MIDREX H2 is similar to the standard MIDREX® natural gas process except that the H2 input gas is generated external to the process. Thus, there is no reforming process to be executed, but only heat transfer, to heat the gas to the required temperature.
Because H2 is converted to H2O and condensed in the top gas scrubber, no CO2 removal system is necessary (unless particularly high NG addition mentioned above).
Referring to the figure, the DR furnace 16 is connect to a top gas recycling loop (or process gas loop) 24, comprising a scrubber 26, compressor unit 28 and heater device 30. The top gas exiting the DR furnace 16 thus flows through the scrubber 26, where dust is removed and water condensed, and further to a compressor device 28. The hydrogen quantity in the process gas loop 24 is adjusted by adding a hydrogen stream referred to as “hydrogen make-up”, depending on the process requirements. The H2 content in the hydrogen make-up stream is preferably 90 to 100%. The hydrogen make-up stream-hydrogen source is indicated at box 32 ‘hydrogen make up’—is injected into the recycling loop 24 between compressor unit 28 and heater device 30. The gas is then heated up to the required temperature range in heater device 30, whereby the reducing gas is ready for introduction into the furnace 16. Heating energy may be provided to the heater device 30 by way of environmentally friendly heat sources such as waste heat, electricity, hydrogen, biomass, and/or natural gas is required as fuel for the heater device.
As will be understood from the present description, most of the hydrogen stream required for the reduction process can be produced on site, arriving at node 32. Optionally, H2 can be added from an external source, although this should normally only represent a minor portion of the hydrogen stream added to the process gas loop.
Steam S1 is recovered from the industrial site 12 where it may be available, or may be produced by means of standard heat recovery equipment. For example, the waste heat is directed to a heat exchanger to produce steam from water (e.g. boiler type steam production).
The produced and/or recovered steam can be used to feed a steam-fed electrolysis unit 3 and produce a hydrogen stream A1 directed to the H2 DR plant.
Another stream of steam S2 recovered from or generated by the industrial plant 12 can feed a water gas shift reactor plant 1 jointly with the CO-bearing gas G1 coming from the gases generated by different processes present in the plant 12.
Gas shift reactor plant, GSRP, 1 is designed to implement the water-gas shift reaction, which describes the reaction of carbon monoxide and water vapor to form carbon dioxide and hydrogen:
CO+H2OCO2+H2
GSRP 1 can be of any appropriate technology. It is thus fed with two streams (steam S2 and CO-bearing gas G1) from the industrial site 12, to produce two main streams comprising on the one hand carbon dioxide and on other hand a hydrogen-rich stream, noted stream A2. It will be appreciated here that GSRP 1 is further configured to separate CO2, which can thus be removed from the process. The GSRP plant 1 can be conventional, based on any appropriate technology.
The hydrogen-rich stream flowing out of GSRP 1 can be optionally passed through a nitrogen removing unit 2 (e.g. using membranes or pressure swing adsorption) for separating N2 from the gaseous flow.
The so-produced hydrogen stream A2 is fed to node 32 where it is mixed with the first stream A1 and possibly with another H2 stream coming from an external source. The thus combined hydrogen stream is introduced into the top gas recycling loop 24.
The CO-bearing gas stream G1 may be compressed upstream of GSRP 1 by a compressor unit 34. A pressure recovery system (turbine) 36 can be arranged downstream of WGS reactor plant 1 to recover energy from the hydrogen A2 flow and generate power to supply compressor 34.
With this integrated solution most of the hydrogen required to the H2 reduction process can be satisfied from the hydrogen self-produced within the integrated plant.
A skilled person of the art will recognize the potential of heat recovery of standard steelmaking plants based on BF-BOF route (i.e. steam produced via heat recovery in sinter coolers, via Coke dry quenching, etc). Similarly those skilled in the art will easily determine the amounts and types of CO-bearing gases available in a standard steelmaking plant based on BF-BOF route (i.e. BF gas, BOF Gas, SAF offgas, etc).
A particularly interesting configuration is the depicted DRI-EAF plant. The conventional practice of DRI-EAF plants is limited on heat recovery; CO-bearing gases are neither commonly available nor profitably exploited.
The present disclosure thus exploits, in one embodiment, waste heat and CO-bearing gas from the EAF to H2 via electrolysis and water gas shift reactions. This permits diminishing the dependence on external H2 sources for operating the DR plant.
It may be noted that the configuration of
As known to those skilled in the art, the Midrex NG plant 40 conventionally includes a shaft furnace 42 and a top gas recycling loop 44 with a top gas scrubber 46, process gas compressor 48, a heat recovery system 50 and a reformer 52. The arrangement of the heat recovery system 50 and a reformer 52 shown in
It will be appreciated that a steel making plant composed of NG Midrex plant 40 and electric arc furnace 12 has different sources of waste heat that can be exploited to produce steam to feed steam-fed electrolysis unit 3 and produce hydrogen indicated as Stream A1 to be used in the MIDREX H2 plant 10.
Steam generation is done by means of heat recovery/steam generation equipment (e.g. boiler type) positioned at one or more of the following locations:
The various steam streams S1 to S5 are combined by means of mixing nodes 56, 56 to form a cumulative stream S6 fed to the electrolysis unit 3, where a hydrogen stream A1 is produced and fed, via node 32 (hydrogen make-up), to the recycling loop 24 of the hydrogen operated DR plant 10.
The total steam produced by all of heat recovery units integrate and decrease the required hydrogen make up from external sources in varying proportions according the sizes of each Midrex plant unit.
As reference considering 1 MTPY NG Midrex, savings of about 60-70% of the total metallurgical hydrogen for 1 MTPY H2 Midrex plants is possible.
Embodiment 3 represents an additional detailed case of embodiment 1, alternative (or cumulative) to embodiment 2.
Here again a hydrogen DR plant 10 is coupled with a NG DR plant 40.
Part of the CO bearing gas generated by the NG reduction process, namely here top gas fuel—stream R2—and/or process gas—stream R1, is taken from the NG recycling loop 44 and directed to the GSRP 1 in order to produce a hydrogen stream Cl for the H2 reduction process. The CO2 stream B1 generated by the GSRP 1 is re-introduced, at least in part, in the NG reduction process in order to meet a predetermined ratio of CO2 in the reforming process.
Hydrogen stream Cl is introduced, optionally combined with hydrogen from another source, into the top gas recycling loop 24 of the hydrogen DR plant 10, upstream of heater 30.
As in
Table 1 below shows typical gas compositions for Top gas fuel (Stream R2) and Process gas (Stream R1).
This last embodiment represents an add-on possibility that can be implemented additionally to previous embodiments.
A steel making plant comprising a H2 Midrex plant and electric arc furnace (EAF) can self-produce part of the hydrogen required by the reduction process in the hydrogen DR plant 10 according the configuration shown in
Streams S7, S8 and S9 (possibly with an additional steam stream from the industrial site network) are combined at mixing node 66, the resulting steam stream S10 is fed to a steam-fed electrolysis unit 3 to produce a hydrogen stream A1.
The heat recovery options (10, 11 and/or 12) and electrolysis unit can be easily integrated in the embodiment of
Benefits
OpEx/CapEx Benefits
Conventional operation of H2 DR plants have today the disadvantage of high OPEX (and CAPEX) related to the hydrogen production or purchase from sources external to the plant.
The present disclosure provides a technically flexible solution since it can bring advantages both for today and for tomorrow, where market conditions will change.
If today steam-fed electrolysis unit could not be totally cost-effective due to the current price of the electricity, it is possible to minimize or turn off its contribution to the process emphasizing the water gas shift technology, that today appears as the most attractive one to produce hydrogen with the lowest Opex in comparison with the industrial hydrogen purchased by the market and the hydrogen production based on electrolysis.
In the next future, the electricity price will decrease. The solution with steam-fed electrolysis will become the most convenient way to produce hydrogen. The flexibility of the present embodiments gives the chance to exploit the two different technologies according to the most convenient market condition.
Therefore, the mentioned innovative plant configurations can reduce the costs associated to the hydrogen utilization both today and tomorrow considering that the self-produced hydrogen can satisfy the process demand in varying proportion according to the process characteristics and to the size of the plant.
Environmental Benefits
The proposed solutions are based on CO-bearing gas and/or steam-fed electrolysis.
In the case of the use of steam-fed electrolysis, the produced hydrogen can be claimed as CO2 free (provided electricity is produced accordingly).
In the case of use of CO-bearing gas, the hydrogen can at least be claimed as CO2 neutral (since no additional CO2 is emitted, nor additional fossil fuel is required—i.e. comparison to steam methane reforming).
| Number | Date | Country | Kind |
|---|---|---|---|
| LU102327 | Dec 2020 | LU | national |
| 21153083.7 | Jan 2021 | EP | regional |
| Filing Document | Filing Date | Country | Kind |
|---|---|---|---|
| PCT/EP2021/086477 | 12/17/2021 | WO |
