Patent Application
20090133535
The invention is directed to a process to prepare elemental iron by contacting an iron ore feed with a reducing gas comprising synthesis gas, wherein the reducing gas is prepared by a partial oxidation process.
Direct reduction of iron (DRI) generates metallic iron in a solid form by removing oxygen from the iron ore by using a reduction gas that can be provided from the synthesis gas obtained by gasification of carbonaceous feedstock. Industrially applied DRI processes include MIDREX, HyL and FINMET, as described in “Development of Reduction Process for the Steel Production” by M. Gojic and S. Kozuh, Kem. Ind. 55 (1) 1-10 (2006).
EP-A-0916739 describes a process wherein the reducing gas for the DRI process is obtained by gasification of a coal slurry. The reducing gas fed to the DRI includes a recycle gas stream that has exited the DRI, and wherein acid gases have been removed from the recycle gas stream.
U.S. Pat. No. 5,871,560 describes a process wherein synthesis gas is mixed with an off-gas produced in a DRI process to be used as a reduction gas and wherein H2S is fed to the reducing gas.
U.S. Pat. No. 2,740,706, as filed in 1951, describes a process for reducing metal oxides by contacting with a reducing gas. In its examples the reducing gas is prepared by partial oxidation of natural gas in admixture with carbon dioxide to obtain a reducing gas having two to three times as much volume of carbon monoxide for each volume of hydrogen. The reason, according to this publication, to add carbon dioxide to the natural gas is to achieve such high contents of carbon monoxide. Coal is mentioned as a possible feedstock instead of natural gas. In this process sulphur is removed from the reducing gas by contacting the gas with sponge iron.
The so-called entrained-flow gasification process for coal as described in “Gasification” by C. Higman and M. van der Burgt, 2003, Elsevier Science, Chapter 5.3, pages 109-128 was developed after 1970 (see page 5 of this reference).
It would be an advancement in the art to provide a process that has a higher efficiency than the above-described processes.
The above is achieved by the following process. Process to prepare elemental iron by contacting an iron ore feed with a reducing gas to obtain iron and an off-gas, wherein the reducing gas is prepared by performing the following steps
(a) partially oxidizing a mixture comprising a sulphur containing solid carbonaceous fuel and gaseous CO2 as carrier medium with oxygen, by supplying an oxygen containing gas and the solid carbonaceous fuel to a burner, thereby obtaining a gas comprising H2, CO, CO2 and H2S;
(b) removing CO2 and H2S from the gas obtained in step (a) to obtain the reducing gas comprising H2 and CO and a first stream comprising CO2 and H2S;
(c) reducing the content of H2S in the first stream comprising CO2 and H2S obtained in step (b) in a liquid redox type process and
(d) recycling at least part of the CO2 obtained in step (c) to step (a).
Applicants found that by recycling part of the CO2 to step (a) a more efficient process is obtained. A further advantage of the present invention is that, for a given amount of carbonaceous fuel to be partially oxidised in the gasification reactor, a smaller reactor volume can be used, resulting in lower equipment expenses, as compared to a situation wherein no CO2 is present in step (a). A further advantage is that the removal of CO2 and H2S is performed in one step, namely step (b), while in the process of U.S. Pat. No. 2,740,706 this removal takes place in two steps. The separation of H2S from the first stream comprising CO2 and H2S by means of a liquid redox process is much more efficient than removing H2S from the entire effluent of step (a) as in the process of U.S. Pat. No. 2,740,706.
In the DRI process an iron ore feed is contacted with the reducing gas comprising H2 and CO to obtain elemental iron and an off-gas. Exemplary DRI processes are those mentioned earlier.
In a typical DRI process the iron ore feed is usually in the form of pellets or in the lump form or a combination of the two. The iron ore is supplied to a heated furnace or to a set of reactors through which it descends by gravity at superatmospheric pressure, e.g., 1.5-12 bar. Iron ore feed is reduced in the said furnace or set of reactors by the action of counterflowing reducing gas that has high H2 and CO contents. Process specifics of the DRI processes are described for example in “Kirk-Othmer Encyclopedia of Chemical Technology”, fourth edition, volume 14, John Wiley & Sons, 1985, pages 855-872.
The reducing gas is used to remove oxygen from the iron oxide comprised within the iron ore feed. The reducing process can be illustrated by the following reaction, where H2O and CO2 are obtained as by-products:
Fe2O3+H2→2Fe+3H2O
Fe2O3+CO→2Fe+CO2
Preferably the reducing gas has H2/CO ratio of at least 0.5. It is also preferred that the reducing gas has a “gas quality” of at least 10. The gas quality is defined as a ratio of reductants to oxidants, as demonstrated by the following equation:
Gas quality=(mol % H2+mol % CO)/(mol % H2O+mol % CO2)
Iron obtained from the DRI process is cooled and carbonized by means of the counterflowing gasses in the lower portion of a shaft furnace according to the following reaction:
3Fe+CO+H2→Fe3C+H2O
3Fe+CH4→Fe3C+2H2
By means of this process it is possible to manufacture for example so-called cold DRI products, hot briquetted iron, or hot direct reduction iron.
The off-gas obtained by the DRI process is the spent reducing gas exiting the furnace. The off-gas can be cleaned by scrubbing and CO2 removal and is preferably recycled to be used as the reducing gas. Preferably the off-gas is treated before the re-use as reducing gas to satisfy the requirement for reducing gas as described above.
In step (a) of the process according to the invention a mixture comprising a sulphur containing solid carbonaceous fuel and CO2 with oxygen containing gas is partially oxidized, thereby obtaining a gas comprising H2, CO, CO2 and H2S.
The partial oxidation may be performed by any process known. Preferably the partial oxidation is performed by means of the so-called entrained-flow gasification process as described in “Gasification” by C. Higman and M. van der Burgt, 2003, Elsevier Science, Chapter 5.3, pages 109-128. More preferably step (a) is performed in an entrained-flow gasifier process wherein the reaction between the mixture of carbonaceous fuel and CO2 with oxygen containing gas takes place in a gasification reactor provided with one or more burners. In such a process an oxygen containing gas and a solid carbonaceous fuel are supplied to a burner. CO2 is used as carrier medium to transport the fuel to the burner. One or more burners can be provided in the gasification reactor. The burner can be a single burner directed downward at the top of a vertically elongated reactor. Preferably the gasification reactor will have substantially horizontal firing burners in diametrically opposing positions. The burner is preferably a co-annular burner with a passage for an oxygen containing gas and a passage for the fuel and the carrier gas. Partial oxidation of the carbonaceous fuel occurs at a relatively high temperature in the range of 1000° C. to 2000° C. and at a pressure in a range of from about 1-70 bar. Preferably the pressure is between 10 and 70 bar, more preferably between 30 and 60 bar. The gas is cooled with either direct quenching with water, direct quenching with the off-gas, direct quenching with the part of the gas obtained in either steps (a) or (b), by indirect heat exchange against evaporating water or combination of such cooling steps. Slag and other molten solids are suitably discharged from the gasification reactor at the lower end of the said reactor.
The term solid carbonaceous fuel may be any carbonaceous fuel in solid form. Examples of solid carbonaceous fuels are coal, coke from coal, petroleum coke, soot, biomass and particulate solids derived from oil shale, tar sands and pitch. Preferably the solid carbonaceous fuel is chosen from the group of coal, petroleum coke, peat and solid biomass. Coal is particularly preferred, and may be of any type and sulphur content, including lignite, sub-bituminous, bituminous and anthracite. Although in many DRI processes natural gas is used as a fuel, coal is an interesting choice for a fuel source because of its abundance. Coal is preferably supplied to the burner in form of fine particulates. The term fine particulates is intended to include at least pulverized particulates having a particle size distribution so that at least about 90% by weight of the material is less than 90 μm and moisture content is typically between 2 and 12% by weight, and preferably less than about 8%, more preferably less than 5% by weight. Preferably coal is supplied in admixture with CO2 as a carrier medium.
Gaseous CO2 containing carrier medium contains preferably at least 80%, more preferably at least 95% CO2. CO2 can be separated from the reducing gas and from the off-gas of the DRI process. It has been found that by using CO2 as obtained in step (c) in step (a), as the carrier medium, a more efficient process is obtained.
Preferably, the CO2 containing carrier gas supplied in step (a) is supplied to the burner at a velocity of less than 20 m/s, preferably from 5 to 15 m/s, more preferably from 7 to 12 m/s. Further it is preferred that the CO2 and the carbonaceous fuel are supplied at a density of from 300 to 600 kg/m3, preferably from 350 to 500 kg/m3, more preferably from 375 to 475 kg/m3.
In a preferred embodiment of the process according to the present invention, the weight ratio of CO2 to the carbonaceous fuel in step (a) is in the range from 0.12-0.49, preferably below 0.40, more preferably below 0.30, even more preferably below 0.20 and most preferably between 0.12-0.20 on a dry basis.
It has been found according to the present invention that using the relatively low weight ratio of CO2 to the carbonaceous fuel in step (a) less oxygen is consumed during gasification.
In a preferred embodiment step a) comprises partially oxidizing a mixture consisting of a sulphur containing solid carbonaceous fuel and CO2 with oxygen containing gas.
The oxygen containing gas comprises substantially pure O2 or air. Preferably it contains at least 90% by volume oxygen, with nitrogen, carbon dioxide and argon being permissible as impurities. Substantially pure oxygen is preferred, such as prepared by an air separation unit (ASU). Steam may be present in the oxygen containing gas as supplied to the burner to act as moderator gas. The ratio between oxygen and steam is preferably from 0 to 0.3 parts by volume of steam per part by volume of oxygen. When the downstream DRI process requires a high CO to H2 ratio it is advantageous to use CO2 instead of steam as a moderator gas. This CO2 is preferably CO2 as obtained in step (c). A mixture of the fuel and oxygen from the oxygen containing stream is then reacted in a reaction zone in the gasification reactor.
The gaseous stream obtained in step (a) comprises mainly H2 and CO, which are the main components of the synthesis gas, and can further comprise other components such as CO2, H2S, HCN and COS. The gaseous stream obtained in step (a) suitably comprises from 1 to 10 mol % CO2, preferably from 4.5 to 7.5 mol % CO2 on a dry basis when performing the process according to the present invention.
The gaseous stream obtained in step (a) is preferably subjected to a dry solids removal and wet scrubbing.
The dry solids removal unit may be of any type, including the cyclone type. The dry solid material is discharged from the dry solids removal unit to be further processed prior to disposal.
In order to remove the particulate matter, for example soot particles, the gaseous stream obtained in step (a) is contacted with a scrubbing liquid in a soot scrubber. The gaseous stream exiting the gasifier is generally at elevated temperature and at elevated pressure. To avoid additional cooling and/or depressurising steps, the scrubbing step in the soot scrubber is preferably performed at elevated temperature and/or at elevated pressure. Preferably, the temperature at which the reducing gas is contacted with scrubbing liquid is in the range of from 120 to 160° C., more preferably from 130 to 150° C. Preferably, the pressure at which the gaseous stream obtained in step (a) is contacted with scrubbing liquid is in the range of from 20 to 80 bara, more preferably from 20 to 60 bara.
The process further comprises step (b) of removing CO2 and H2S from the gas obtained in step (a) thereby obtaining the reducing gas comprising H2 and CO and a first stream comprising CO2 and H2S.
Removing CO2 and H2S is performed in a, hereafter referred to, CO2 recovery system. The CO2 recovery system is preferably a combined CO2/H2S removal system. Preferably CO2/H2S removal is performed by absorption using so-called physical and/or chemical solvent process. The CO2 recovery is performed on the gaseous stream obtained in step (a). The off-gas of the DRI contacting process is suitably also subjected to the same or a different CO2 recovery system to obtain a recycle reducing gas comprising CO and H2 and a second stream comprising CO2 and possibly H2S. In case the CO2 recovery system is the same, the second stream and the first stream are the same and will be referred to as the first stream.
It is preferred to remove at least 80 vol %, preferably at least 90 vol %, more preferably at least 95 vol % and at most 99.5 vol %, of the CO2 present in the gaseous stream obtained in step (a).
Absorption processes are characterized by washing the synthesis gas with a liquid solvent, which selectively removes the acid components (mainly CO2 and H2S) from the gas. The laden solvent is regenerated, releasing the acid components and recirculated to the absorber. The washing or absorption process takes place in a column, which is usually fitted with for example packing or trays. On an industrial scale there are chiefly two categories of absorbent solvents, depending on the mechanism to absorb the acidic components: chemical solvents and physical solvents. Reference is made to the absorption process as described in chapters 8.2.1 and 8.2.2 of “Gasification” (already referred to), page 298-309, and Perry, Chemical Engineerings' Handbook, Chapter 14, Gas Absorption.
Chemical solvents which have proved to be industrially useful are primary, secondary and/or tertiary alkanolamines. The most frequently used amines are derived from ethanolamine, especially monoethanol amine (MEA), diethanolamine (DEA), triethanolamine (TEA), diisopropanolamine (DIPA) and methyldiethanolamine (MDEA).
Physical solvents which have proved to be industrially suitable are cyclo-tetramethylenesulfone and its derivatives, aliphatic acid amides, N-methylpyrrolidone, N-alkylated pyrrolidones and the corresponding piperidones, methanol, ethanol and mixtures of dialkylethers of polyethylene glycols.
A well-known commercial process uses an aqueous mixture of a chemical solvent, especially DIPA and/or MDEA, and a physical solvent, especially cyclotetramethylene-sulfone also referred to as sulfolane. Such systems show good absorption capacity and good selectivity against moderate investment costs and operational costs. They perform very well at high pressures, especially between 20 and 90 bara.
Preferably the solvent comprises one or more compounds selected from the group of N-methylpyrrolidone (NMP), dimethyl ether of polyethylene glycol (DMPEG), methanol or an amine such as di-isopropanol amine (DIPA) or mixtures of amines with sulfolane. More preferably, the solvent comprises an amine and sulfolane.
Preferably step (b) comprises one or more further removal systems that may be guard or scrubbing units, either as back-up or support to the CO2/H2S removal system. These further removal systems are aimed at removing HCN and COS or other contaminants such as NH3, H2S, metals, carbonyls, hydrides or other trace contaminants which may be comprised in the gas obtained in step (a).
Preferably step (b) is performed by at least two steps wherein in a first step the gas obtained in step (a) is contacted with the HCN/COS hydrolysis catalyst to convert HCN to NH3 and COS to H2S, followed by removal of water and ammonia from the gas by cooling and/or scrubbing, and in a second step the gas obtained in said first step is contacted with a suitable solvent, which is selective for absorbing CO2 and H2S as described above.
The process of contacting the gas obtained in step (a) with the HCN/COS hydrolysis catalyst to convert HCN to NH3 and COS to H2S takes place by catalytic hydrolysis in the hydrolysis unit. Examples of a suitable hydrolysis step are disclosed in WO-A-04105922. The hydrolysis zone can be a gas/solid contactor, preferably a fixed bed reactor. Catalysts for the hydrolysis of HCN and COS are known to those skilled in the art and include for example TiO2-based catalysts or catalysts based on alumina and/or chromium-oxide. Preferred catalysts are TiO2-based catalysts.
The process further comprises step (c) of reducing the content of H2S in the first stream comprising CO2 and H2S obtained in step (b). Preferably the CO2 as obtained in step (c) has a sulphur content lower than 10 ppmv, more preferably between 5 and 10 ppmv. Step (c) is performed by means of a liquid redox type process. More preferably step (c) is performed by liquid redox type process by contacting the stream of CO2 and H2S obtained in step (b) with an aqueous reactant solution comprising iron (III) chelate of an organic acid or complex reactant system to produce elemental sulphur which is recovered as a by-product of the present process either prior to or subsequent to regeneration of the reactant, as described in for example “Gas Purification” by A. Kohl and R. Nielsen, Gulf Publishing Company, fifth edition, pages 670-840, and more specifically pages 803-840.
The reduction of H2S content in step (c) can also be performed on a mixture of the first and second stream comprising CO2 and H2S.
The process according to the invention further includes step (d) wherein at least part of the CO2 obtained in step (c) is recycled to step (a). The CO2 that is recycled to step (a) is isolated from the first and optional second stream comprising CO2 and H2S.
The reducing gas obtained in step (b) is directed to an expander wherein the pressure of the reducing gas is reduced and power is generated. The reducing gas is then heated in a gas heater before entering the furnace of the DRI process where it is contacted with iron ore feed to produce iron and the off-gas.
The off-gas of the DRI contacting process can be subjected to the CO2 recovery as described above, thereby obtaining a recycle reducing gas comprising CO and H2 and a second stream comprising CO2 and H2S. The recycle reducing gas comprising CO and H2 can be recycled to the furnace of the DRI process. The CO2 from the first and second streams comprising CO2 and H2S is preferably used in step (a) as a carrier medium to carry the coal to the burner. Excess CO2 is preferably stored in subsurface reservoirs or more preferably a part of the CO2 as obtained in step (c) is used for one of the processes comprising enhanced oil recovery, CO2 sequestration or coal bed methane extraction. A part of the CO2 can be injected into the subterranean zone to obtain a desired pressure in said subterranean zone such to enhance the recovery of a hydrocarbon containing stream as produced from said subterranean zone. A part of the reducing gas obtained in step (c) is preferably used as a fuel in a gas turbine to generate power.
In the process scheme of
| Number | Date | Country | Kind |
|---|---|---|---|
| 07121142.9 | Nov 2007 | EP | regional |
This patent application claims the benefit of European patent application No. 07121142.9, filed Nov. 20, 2007 and U.S. Provisional Application 60/991,162, filed Nov. 29, 2007, both of which are incorporated herein by reference.
| Number | Date | Country | |
|---|---|---|---|
| 60991162 | Nov 2007 | US |
