Title:
METHOD FOR THE GASIFICATION OF MOISTURE-CONTAINING HYDROCARBON FEEDSTOCKS
Kind Code:
A1


Abstract:
A method for the gasification of a hydrocarbon feedstock that has a high moisture content to produce useful co-products such as high-value hydrocarbon fuels, pure H2, electricity, and/or ammonia. The method advantageously gasifies the carbon in the feedstock to carbon monoxide (CO) without producing large quantities of carbon dioxide (CO2). Supplemental hydrogen (H2) is co-produced by reacting steam (H2O) generated from the moisture in the hydrocarbon feedstock with a molten metal.



Inventors:
Kindig, James Kelly (Silver City, NM, US)
Styer, Steven R. (Phoenix, AZ, US)
Application Number:
11/746034
Publication Date:
11/08/2007
Filing Date:
05/08/2007
Assignee:
ALCHEMIX CORPORATION (Carefree, AZ, US)
Primary Class:
Other Classes:
48/209, 48/210, 48/197R
International Classes:
C10J3/00; C10J3/57
View Patent Images:
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Primary Examiner:
MERKLING, MATTHEW J
Attorney, Agent or Firm:
Marsh Fischmann & Breyfogle LLP (Lakewood, CO, US)
Claims:
What is claimed is:

1. A method for the gasification of a hydrocarbon feedstock to form a syngas, comprising the steps of: (a) injecting a hydrocarbon feedstock comprising at least about 10 wt. % H2O into a molten metal reactor, the reactor containing a molten metal phase comprising a reactive metal and a slag phase, wherein a portion of the H2O from the feedstock reacts with the reactive metal to reduce the portion of the H2O to H2 and form a reactive metal oxide, and wherein a first portion of carbon from the hydrocarbon feedstock reduces reactive metal oxide contained in the slag phase to the molten metal phase; (b) during the injection of hydrocarbon feedstock, injecting oxygen into said molten metal reactor to oxidize at least a second portion of carbon from said hydrocarbon feedstock to carbon oxides; and (c) recovering a syngas comprising H2 and CO from the reactor, where the recovered syngas comprises not greater than about 15 vol. % CO2.

2. A method as recited in claim 1, wherein the recovered syngas comprises not greater than about 10 vol. % CO2.

3. A method as recited in claim 1, wherein the recovered syngas comprises not greater than about 5 vol. % CO2.

4. A method as recited in claim 1, wherein the hydrocarbon feedstock is selected from the group consisting of pet coke, coal, municipal waste, rubber tires, wood and biomass.

5. A method as recited in claim 1, wherein the hydrocarbon feedstock comprises at least about 25 wt. % H2O.

6. A method as recited in claim 1, further comprising the step of injecting a second hydrocarbon feedstock into said reactor, where the second hydrocarbon feedstock comprises less H2O than said first hydrocarbon feedstock.

7. A method as recited in claim 1, wherein the partial pressure ratio of oxidizing gases to total gases in the reactor as expressed by the fraction: (H2O+CO2)(H2+H2O+CO+CO2) is determined for the hydrocarbon feedstock by minimizing Gibbs' free energy for the reduction reaction employing the hydrocarbon feedstock, and wherein the input rate of a reactant selected from oxygen and hydrocarbon feedstock to the reactor is adjusted to minimize the Gibbs' free energy.

8. A method as recited in claim 1, wherein the hydrocarbon feedstock further comprises sulfur-bearing or chlorine-bearing compounds.

9. A method as recited in claim 8, further comprising the steps of: (i) recovering sulfur-containing compounds from said syngas; (ii) oxidizing said sulfur-containing compounds to form SO2; (iii) contacting said SO2 with H2S or H2; and (iv) extracting elemental sulfur from said contacting step.

10. A method as recited in claim 8, further comprising the steps of: (i) removing chlorine-containing compounds from said syngas by dissolving the chlorine-containing compounds in water; and (ii) removing said chlorine-containing compounds by water purification.

11. A method as recited in claim 1, wherein said reactive metal comprise iron.

12. A method as recited in claim 11, wherein the rate of injection of the hydrocarbon feedstock is maintained such that the iron oxide content in the slag phase does not deviate during the process by more than about 5 weight percent.

13. A method as recited in claim 11, wherein the rate of injection of the hydrocarbon feedstock is maintained such that the iron oxide content in the slag phase is at least about 30 wt. % and is not greater than about 65 wt. %.

Description:

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims priority to U.S. Provisional Patent Application No. 60/746,748 filed May 8, 2006, which is incorporated herein by reference in its entirety as if set forth in full. This application is also related to co-pending U.S. patent application Ser. No. 11/746,013 filed on May 8, 2007 and entitled “Method for the Gasification of Hydrocarbon Feedstocks”, which is also incorporated herein by reference in its entirety.

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention is directed to a method for the gasification of hydrocarbon feedstocks to produce a syngas that is useful for the production of hydrogen, hydrogen-containing materials, electricity or other energy products. The method advantageously produces such high-value products, and can reduce the formation of carbon dioxide (CO2) per unit of energy or commodity produced, as compared to other gasification methods.

2. Description of Related Art

Gasification is a well-known process that converts hydrocarbon materials such as coal, petroleum coke, biomass or similar feedstocks into a syngas comprising carbon monoxide (CO) and hydrogen (H2). During gasification, pyrolysis of the hydrocarbon material releases fuel-bound H2, oxygen, nitrogen and sulfur leaving residual solid carbon char. Some of the carbon char is gasified to CO and H2 with steam (H2O), and some of the carbon is gasified to CO with oxygen.

Table 1 is an illustrative list of major hydrogen-containing materials, naturally-occurring materials and man-made materials, arranged substantially according to their H2 content.

TABLE 1
Hydrogen-ContainingHydrogenRelative
PhaseMaterialContent (mol.%)Value
GasHydrogen100.0High Value
Methane25.1
Ethane20.1
Propane18.3
Ammonia17.8
LiquidJet Fuel14.1
Gasoline14.4
Ethanol13.0
Methanol12.5
Crude OilLow Value
Tar Sands
SolidCoal (Eastern US)4.7
Coal (Western US)6.2
Biomass5.9
Pet Coke3.1
Municipal Waste6.2
Rubber Tires8.7

One goal of the energy industry is to use methods such as gasification to convert relatively low-value hydrocarbon materials to clean, high-value liquid or gaseous hydrocarbons that can be effectively utilized. Each of the high-value products listed in Table 1 can be synthesized from syngas (H2 and CO), except ammonia where N2 replaces the CO. However, for synthesis to occur the ratio of H2 to CO in the syngas (H2:CO) must approximate the volumetric ratio of the H2 and CO in the balanced chemical equation. For example, to make methane (CH4), the volumetric ratio of H2:CO must be about three, because the synthesis equation requires that three moles of H2 be available for each mole of CO:
3H2+CO→CH4+H2O (1)

In conventional gasification, some of the carbon is gasified to CO and H2 with steam (H2O) in a highly endothermic reaction, and some carbon is gasified to CO with O2 in a balancing exothermic reaction:
C+H2O→H2+CO (2)
C+½O2→CO (3)

Conventional gasification produces some H2 from the energy that is released as C is oxidized to CO. However, the H2 produced is only 50 vol. % of the total gas released from the splitting of water (Equation 2) and that H2 is diluted to less than 25 vol. % when considering the additional CO that is produced by the exothermic oxidation of C with O2 that is required for balancing the heat (Equation 3). As a result, the syngas derived from solid hydrocarbons by conventional gasification has a H2:CO ratio that is virtually always less than one, which is too low to be used for manufacturing the high-value hydrogen-containing materials that are needed for commerce.

In order to increase the amount of H2 derived from conventional gasification, some of the CO must be used to reduce H2O and form CO2 as a by-product via the water gas shift reaction, which is conducted in a separate reactor after gasification.
CO+H2O→H2+CO2 (4)

Thus, when conventional gasification is utilized to produce a high H2 syngas or a substantially pure H2 gas stream, over three-fourths of the H2 derives from the conversion of CO to H2 by the water gas shift reaction. This step produces large amounts of CO2, which is commingled with the H2 that is subsequently separated, such as with a pressure-swing adsorption (PSA) unit. The net driving force for producing H2 and associated co-products from solid hydrocarbons is the oxidation of carbon contained within the hydrocarbon to CO2. This oxidation of carbon is stepwise: after pyrolysis isolates H2 (and other gases such as O2, N2 and sulfur) from the carbon, the carbon first is partially oxidized to CO and the CO is then oxidized to CO2. About one-third of the heat produced by the complete oxidation of carbon to CO2 is released in the first oxidation step (C to CO), meaning that the oxidation of the CO to CO2 via the water gas shift reaction produces about two-thirds of the total heat released in completely oxidizing carbon to CO2.

Accordingly, while H2 production by coal gasification is an established commercial technology, it is only economically competitive with steam-methane reformation (SMR) for the production of H2 when natural gas is prohibitively expensive. Most gasification of hydrocarbon materials such as coal is carried out in moving-bed gasifiers, fluidized bed gasifiers or entrained flow gasifiers. Among other factors, such coal gasification plants have a high capital cost and the gasification reactors generally have a low availability, about 75 percent, causing disruptions in the manufacture of syngas. Such a low availability is generally unsatisfactory for downstream manufacturing processes that utilize the syngas (or syngas converted to hydrogen) for oil refining or ammonia production.

Several methods for the gasification of hydrocarbon materials have been suggested that utilize a molten metal to facilitate the reaction. For example, Sumitomo Metal Industries has disclosed a method and apparatus for gasifying hydrocarbon materials utilizing a molten metal reactor. An example of this technology is disclosed in U.S. Pat. No. 4,738,688 by Nakajima et al. As is disclosed in this patent, hydrocarbon material is gasified by blowing the hydrocarbon material onto the top surface of a molten metal bath with a gasifying agent such as oxygen. In this top-blowing process, the hydrocarbon material is decomposed at high temperature points that form above the molten metal. It is disclosed that the resulting gas is rich in CO and H2 and in the proportion of CO2 is rather small. The Sumitomo Metal Industries Technology is also disclosed, for example, in U.S. Pat. No. 4,389,246 by Okamura et al., which discloses that a stirring gas can be injected into the bottom of the molten metal reactor to increase the efficiency of the process.

Another method using a molten metal reactor was developed by Molten Metal Technology, as is illustrated in U.S. Pat. No. 5,395,405 by Nagel et al. In this method, organic waste is gasified by injecting the waste through the top, bottom or sides of the reactor. Gas can also be injected through the bottom of the reactor to create a fountain of molten metal droplets above the surface of the molten metal. U.S. Pat. No. 5,358,697 by Nagel discloses that the molten metal can include two molten metal phases, where the second molten metal phase is immiscible in the first molten metal phase. The use of two metal phases enhances the oxidation of atomic carbon and forms CO2, which is discharged to the atmosphere after scrubbing. U.S. Pat. No. 5,537,940 by Nagel et al. discloses a sequential process wherein organics are injected into a molten metal, such that H2 is formed and removed while carbon dissolves into the molten metal. Thereafter, oxygen is injected into the metal to oxidize the carbon and remove carbon oxides. It is disclosed that the formation of CO is favored when the metal is iron.

Another technology using a molten metal reactor, referred to as the HyMelt Technology, has been disclosed by Malone et al. For example, U.S. Pat. No. 6,110,239 by Malone et al. discloses a process in which a high purity, high pressure H2-rich gas stream and a high purity, high pressure CO-rich gas stream are produced separately and continuously using a molten metal gasifier containing at least 2 zones, to avoid the need to separate the gases in downstream equipment. The method can include introducing a hydrocarbon feed into a molten metal bath beneath the molten metal surface in a feed zone operating at a pressure above 5 atmospheres and decomposing the hydrocarbon feed into H2, which leaves the feed zone as a H2-rich gas, and into carbon, which dissolves in the molten metal. The carbon concentration in the metal is controlled to be at or below the limit of solubility of carbon in the molten metal. A portion of the molten metal is transferred from the feed zone to another molten metal oxidation zone operating at a pressure above 5 atmospheres into which an O2-containing material is introduced beneath the molten metal surface to react with a portion of the carbon to form a CO-rich gas. In this manner, the carbon concentration in the molten metal is controlled so it does not reach the concentration at which the equilibrium oxygen concentration would exceed its solubility limit in the molten metal.

Other methods of carbon gasification using a molten metal bath include that disclosed in U.S. Pat. No. 4,496,369 by Torneman, which discloses a method and apparatus for the gasification of carbon by the injection of carbon, O2 gas and iron oxides beneath the surface of a molten iron metal bath.

Steam reduction is another known method for the manufacture of H2 gas. The steam reduction method utilizes the oxidation of a metal (Me) to strip oxygen from steam, thereby forming hydrogen gas. This reaction is illustrated by Equation 5.
xMe+yH2O MexOy+yH2 (5)

To complete the cycle in a two-step steam reduction process, the metal oxide must be reduced back to the metal using a reductant such as carbon or CO. For example, CO has an oxygen affinity that is similar to the oxygen affinity of H2 and they are equal at about 812° C. At temperatures above about 812° C., CO has a greater affinity for oxygen than does H2, and the CO or carbon will reduce the oxide of Equation 5 back to the metal as indicated by Equations 6 and 7.
MexOy+yCO→xMe+yCO2 (6)
MexOy+yC→xMe+yCO (7)

Generally stated, the function of the metal/metal oxide couple is to transfer oxygen from the steam to the reducing gas (CO) without allowing the H2O/H2 of the hydrogen production step to contact the CO/CO2 of the metal oxide reduction step. Neither the metal nor the metal oxide is consumed by the overall process.

Oxygen partial pressure (pO2) relates to the facility with which the metal may be oxidized (e.g., by steam) and the oxide may be reduced (e.g., by CO). A related mathematical expression is pH2O/pH2, which is proportional to the oxygen partial pressure. Also, an equivalent and inversely related quantity is the hydrogen fraction, expressed as: pH2(pH2+pH2O)(8)

Certain metals react strongly with water, releasing hydrogen. The oxygen partial pressure in equilibrium with these metals and their oxides together is extremely low. Once the oxides are formed, they cannot be effectively reduced back to the metal. Conversely, there is another group of metals that produce insignificant quantities of hydrogen when reacted with water. The oxygen partial pressure in equilibrium with these metals and their oxides together is quite high. The oxides, therefore, can be easily reduced by CO or carbon.

Between the two foregoing groups of metals are other metals characterized by an oxygen affinity that is roughly the same as the oxygen affinity of H2. Included in this intermediate group of metals are, for example: germanium (Ge), iron (Fe), zinc (Zn), tungsten (W), molybdenum (Mo), indium (In), tin (Sn), cobalt (Co) and antimony (Sb). These are elements that readily produce H2 from H2O wherein the resulting oxide can be reduced by carbon and/or CO. That is, these metals have an oxygen affinity such that their equilibrium pH2O/pH2 is low enough to be practical for the production of hydrogen, yet the metal oxide is readily reduced by carbon at normal pyrometallurgical temperatures (e.g., about 1200° C.). These metals are referred to herein as reactive metals, meaning that the metal can be oxidized by steam and the metal oxide can be effectively reduced by carbon or CO.

Iron is a useful reactive metal, and the steam reduction/iron oxidation process was the primary industrial method for manufacturing hydrogen during the 19th and early 20th centuries. At elevated temperatures, iron strips oxygen from water, leaving pure hydrogen.
Fe+H2O→FeO+H2 (9)

Excess water is required to maximize H2 production from a given amount of iron. After the H2 is produced, excess water is condensed leaving an uncontaminated hydrogen gas steam.

An example of this method is disclosed in U.S. Pat. No. 6,663,681 by Kindig et al. In this method, steam is contacted with a molten metal mixture including a first reactive metal such as iron dissolved in a diluent metal such as tin. The reactive metal is oxidized to its metal oxide, forming a hydrogen gas; thereafter, the metal oxide can be reduced back to the metal for further production of hydrogen without substantial movement of the metal or metal oxide to a second reactor.

An extension of this work is reported in U.S. Pat. No. 6,685,754 by Kindig et al. This patent discloses a method for the production of a hydrogen-containing gas composition, such as a synthesis gas including H2 and CO. It is disclosed that the molar ratio of H2:CO in the synthesis gas can be well-controlled to yield a ratio that is adequate for the synthesis of useful products such as methane or methanol. In this method, a molten metal is provided and steam is contacted with the molten metal to react the first portion of the steam with the metal to form hydrogen gas and a metal oxide. The hydrocarbon material is also contacted with the melt in the presence of the steam to react the hydrocarbon material with a second portion of the steam to form CO. A gas stream is extracted from the reactor, where the gas stream can have a molar H2:CO ratio of at least about 1:1. After a period of time, the steam contacting can be terminated and the metal oxide can be contacted with a reductant to reduce the metal oxide back to the molten metal.

SUMMARY OF THE INVENTION

The present invention is directed to a highly stable, highly efficient process for the gasification of a wide range of hydrocarbon feedstocks. As used herein, a hydrocarbon feedstock is any material that comprises carbon and hydrogen, even where the hydrogen is present in relatively low amounts, such as in pet coke. The process can advantageously minimize the production of carbon dioxide (CO2) for the production of a given quantity of chemical product and net energy export.

The method of the present invention can advantageously be carried out continuously in a single reactor for the uninterrupted production of a syngas.

It is also an advantage of the present invention that the solid or liquid hydrocarbons used as the feedstock can be low-value, contaminated hydrocarbons. The method can also have a lower capital cost than conventional gasification.

The syngas stream that can be produced according to the present invention advantageously has a higher CO:CO2 ratio than the syngas stream from conventional gasification. For conventional gasification, a minimum ratio of CO:CO2 must be established to extract H2 from water. Gasification according to the present invention involves oxidation of the metal (iron) as represented by Equation 5 and reduction of the just-formed oxide by carbon as illustrated by Equation 6. Addition of Equations 5 and 6 eliminates the metal and metal oxide and leaves just carbon to reduce the water, the same reaction as for conventional gasification. Therefore, based upon a superficial comparison, the same CO:CO2 ratio should be required in both cases.

However, to create the metallic iron, a source of hydrogen in the present invention, FeO must yield its oxygen to carbon. Because the FeO is in ionic solution with other oxides comprising a slag and because the cations of the other oxides in the slag also exert a binding force on the oxygen, additional energy is required to extricate the oxygen from the mixture of FeO and other oxides. The additional energy required to extricate the oxygen from the solution of mixed oxides arises from combusting additional carbon to increase the ratio of CO:CO2.

Syngas with a high ratio of CO:CO2 contains more energy than syngas with a low ratio of CO:CO2. Therefore, more useful work can be obtained from a given amount of high CO:CO2 syngas per unit of CO2 produced than from a syngas with a lower CO:CO2 ratio. This is a significant advantage of the present invention.

The syngas stream, after heat recovery and purification, is comprised of CO and H2 in a molecular ratio generally reflecting the C:H ratio in the hydrocarbon feedstock that is being reacted, and the CO content is greater than the H2 content. The method of the present invention can also co-produce electricity, nitrogen, sulfur and pozzolanic slag along with the syngas stream. The value of these salable co-products can substantially or completely off-set the cost of H2 production.

The syngas stream and co-produced electricity can be merged in various ways that utilize substantially all of the energy contained therein for subsequent conversion into H2 or H2-containing commodities and/or additional electricity and/or steam. By way of example, the commodities can be selected to include: pure hydrogen; pure hydrogen and electricity and/or steam; ammonia, electricity and/or steam; methane, electricity and/or steam; liquid fuels such as gasoline, diesel and jet fuel, electricity and/or steam; or solely electricity and/or steam. Steam is useful as a source of process heat required by many industries.

More specifically, the syngas stream, N2, electricity and other co-products can be produced by processing a hydrocarbon feedstock, water and air through the following equipment:

    • (1) a molten metal reactor producing a hot crude syngas stream;
    • (2) a gas-purifying train that is designed to recover a purified syngas and heat from the hot crude syngas stream, while rejecting particulate material, water-soluble halogens and sulfurous compounds, and optionally rejecting or recovering H2, to form a refined syngas stream;
    • (3) a steam generator (boiler);
    • (4) an air separation plant to produce substantially pure O2 and N2 from air;
    • (5) equipment for sulfide roasting, such as a fluidized bed;
    • (6) equipment for processing sulfur, such as a Claus plant;
    • (7) equipment for generating electricity;
    • (8) heat recovery equipment, such as where steam is the medium for heat recovery; and
    • (9) gas-compression and other general support equipment.

The energy that is available in the syngas stream can be used in conjunction with one or more of the following chemical conversion processes:

    • 1. catalyzed gas-synthesis loops operating at relatively low temperatures and high pressure;
    • 2. the Fischer-Tropsch process, including modifications thereof;
    • 3. electrical generation, such as by gas-turbine combined cycle;
    • 4. the electrolysis of water; and/or
    • 5. the water gas shift reaction for producing additional pure H2, followed by separation of CO2.
      These chemical conversion processes can be used to produce, for example:
    • 1. Pure hydrogen, such as by combining H2 from gasification with H2 produced either by the electrolysis of water or by water gas shift of some of the CO otherwise dedicated to electricity production;
    • 2. Pure hydrogen and electricity, where additional hydrogen is recovered from the syngas stream and CO is rejected back to the syngas stream for subsequent generation of electricity;
    • 3. Ammonia and electricity, where ammonia can be produced in an ammonia synthesis loop, such as from the syngas stream after purification to pure hydrogen (or conversion of the small amount of CO to methane) and N2;
    • 4. Methane and electricity, where methane can be synthesized in a methanation loop—copious amounts of heat are released by the methanation reaction, and this heat can be converted into useful steam;
    • 5. Liquid fuels and electricity, where the liquid fuels can be produced utilizing the Fischer-Tropsch process; or
    • 6. Electricity, such as by burning the purified syngas stream in a combined cycle gas-fired turbine.

Elemental sulfur and pozzolanic slag are by-products of the process and are salable commodities, further decreasing the net operating cost of the process.

Accordingly, one embodiment of the present invention is directed to a method for the gasification of a hydrocarbon feedstock to form a syngas, The method can include the steps of injecting a hydrocarbon feedstock comprising at least about 10 wt. % H2O into a molten metal reactor, the reactor containing a molten metal phase comprising a reactive metal and a slag phase, wherein a portion of the H2O from the feedstock reacts with the reactive metal to reduce the portion of the H2O to H2 and form a reactive metal oxide, and wherein a first portion of carbon from the hydrocarbon feedstock reduces reactive metal oxide contained in the slag phase to the molten metal phase. During the injection of the hydrocarbon feedstock, oxygen is injected into the molten metal reactor to oxidize at least a second portion of carbon from the hydrocarbon feedstock to carbon oxides. A syngas comprising H2 and CO is recovered from the reactor, where the recovered syngas comprises not greater than about 15 vol. % CO2.

According to one aspect of the method, the recovered syngas comprises not greater than about 10 vol. % CO2, such as not greater than about 5 vol. % CO2. The hydrocarbon feedstock can be selected from the group consisting of pet coke, coal, municipal waste, rubber tires, wood and biomass, and the hydrocarbon feedstock can comprise at least about 25 wt. % H2O.

The method can also include the step of injecting a second hydrocarbon feedstock into the reactor, where the second hydrocarbon feedstock comprises less H2O than said first hydrocarbon feedstock.

According to one aspect, the partial pressure ratio of oxidizing gases to total gases in the reactor as expressed by the fraction: (H2O+CO2)(H2+H2O+CO+CO2)
is determined for the hydrocarbon feedstock by minimizing Gibbs' free energy for the reduction reaction employing the hydrocarbon feedstock, and wherein the input rate of a reactant selected from oxygen and hydrocarbon feedstock to the reactor is adjusted to minimize the Gibbs' free energy.

The hydrocarbon feedstock can also comprise sulfur-bearing or chlorine-bearing compounds. Accordingly, the method can include the steps of recovering sulfur-containing compounds from the syngas, oxidizing the sulfur-containing compounds to form SO2, contacting the SO2 with H2S or H2, and extracting elemental sulfur from the contacting step.

When the feedstock comprises chlorine, the method can include the steps of removing chlorine-containing compounds from the syngas by dissolving the chlorine-containing compounds in water and removing the chlorine-containing compounds by water purification.

According to another aspect, the reactive metal comprises iron and the rate of injection of the hydrocarbon feedstock is maintained such that the iron oxide content in the slag phase does not deviate during the process by more than about 5 weight percent. The rate of injection of the hydrocarbon feedstock can be maintained such that the iron oxide content in the slag phase is at least about 30 wt. % and is not greater than about 65 wt. %.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 schematically illustrates the reactants and the resultant products that can be produced according to an embodiment of the present invention.

FIG. 2 illustrates a binary phase diagram for a tin-iron metal mixture that is useful in accordance with an embodiment of the present invention.

FIG. 3 illustrates a desired temperature operating window that insures slag fluidity for a FeO/CaO/SiO2 slag system with a basicity (CaO:SiO2) of 0.8 according to the present invention.

FIG. 4 illustrates a molten metal reactor that is useful for gasification according to an embodiment of the present invention.

FIG. 5 illustrates a process flow for the continuous production of a syngas according to an embodiment of the present invention.

FIG. 6 illustrates a process flow for the continuous production of syngas according to an embodiment of the present invention.

FIG. 7 illustrates an integrated gasification combined cycle (IGCC) power plant.

DESCRIPTION OF THE INVENTION

An overview of the method of the present invention is illustrated in FIG. 1. The method 100 includes providing reactants to a reactor system 108, where the reactants include at least air 102 and a moist hydrocarbon feedstock 106 that comprises H2O in appreciable quantities.

According to the present invention, the hydrocarbon feedstock 106 can advantageously include relatively low-value hydrocarbons, including those having less than about 10 mol. % H2 and which can also include impurities such as sulfur.

More specifically, the hydrocarbon feedstock according to the present invention can include low-cost, high heating-value carbon sources such as petroleum coke, scrap tires and liquid petroleum residues; medium cost, high heating-value and low-ash, high rank coals that may contain high levels of sulfur; or low-cost, low-heating value materials such as low-rank (sub bituminous) coal, biomass and the organic portion of municipal waste products. Plastics contained in municipal waste can also be a useful feedstock. Further, wood can also be used as a feedstock. Particularly preferred are petroleum coke, other petroleum residues, scrap tires and high-rank low-ash coal. Petroleum coke (also referred to as pet coke) is a black solid that is obtained mainly by cracking and carbonizing residues from the distillation of petroleum oils, especially heavier petroleum oils (tars). It is an advantage of the present invention that the hydrocarbon feedstock can be a low-value hydrocarbon material such as high-sulfur pet coke or low-ash high-rank coal, as the sulfur is readily controlled. Petroleum coke can advantageously have lower ash content than coal and therefore produce less slag.

It is also an advantage of the present invention that the hydrocarbon feedstock 106 can have a relatively high moisture content to provide water to the reactor system 108 and does not require drying before being injected into the molten metal reactor. In this regard, it is preferred that the hydrocarbon feedstock that is input to the reactor system 108 comprise some H2O. Specifically, the hydrocarbon feedstock 106 can comprise at least about 10 wt. % H2O, more preferably at least about 15 wt. % H2O, even more preferably at least about 20 wt. % H2O and even more preferably at least about 25 wt. % H2O. Although the hydrocarbon feedstock includes H2O, the total H2O should preferably not exceed about 50 wt. % of the feedstock and more preferably should not exceed about 40 wt. % of the feedstock. It will be appreciated that many hydrocarbon feedstocks contain such high levels of moisture in their natural state.

A hydrocarbon feedstock having high moisture content can advantageously lead to the formation of H2 due to the reduction of the water in the reactor. For example, Powder River Basin (PRB) coal has a relatively high natural moisture content, such as from about 25 wt. % to about 30 wt. %. Municipal solid waste and wood can also have similarly high moisture content. In one preferred embodiment, the hydrocarbon feedstock that is fed to the reactor has a moisture content such that the moisture contained in the hydrocarbon feedstock oxidizes the metal at substantially the same rate as new metal (Me) is being formed by the reduction of the MexOy in the slag. It is an advantage that such high moisture feedstocks can be utilized with little or no drying, as is typically required in conventional gasification methods. If the moisture content is slightly less than is required to balance the reduction rate, a small amount of additional moisture 104 can be added to the feed, such as by injecting steam. Conversely, if the moisture content is slightly higher than is needed to balance the reduction rate, the addition of a drier hydrocarbon material 105 can reestablish the balance such that the oxidation rate equals reduction rate. Alternatively, the moisture content of the moist hydrocarbon feedstock 106 can be partially dried in a steam drier using excess steam created by the process.

The air 102 input to the process provides a source of O2 and can optionally provide a source of N2, which may be needed for the production of nitrogen-containing end-products such as ammonia.

The method 100 includes providing for the withdrawal from the reactor system 108 of products that can include flue gas 116, electricity 112, elemental sulfur 114, a syngas stream 118, waste water 120 and slag 122. As is discussed in more detail below, the syngas stream can advantageously have a CO:CO2 ratio that is higher than known gasification methods.

Generally, the reactor system 108 generically represented in FIG. 1 includes a molten metal bath reactor that contains a molten metal, or molten metal alloy, and molten slag. A gas train is in gaseous communication with the reactor and is adapted to receive and process the crude syngas stream produced within the reactor. The gas train according to the present invention can be adapted to treat the crude syngas stream to recover the sensible heat, to clean and purify the syngas stream of impurities such as sulfurous compounds, particulates and mercury, and to preclude the formation of noxious compounds such as dioxins and furans, and form a refined syngas stream. The refined syngas stream can optionally be burned in a gas turbine with air, such as at a temperature which virtually precludes formation of nitrogen oxides (NOx). Alternatively, the syngas stream can be burned with oxygen at a low temperature thereby creating a sequesterable flue gas.

The present invention will now be described in greater detail, and with reference to FIGS. 2-7. According to the present invention, some H2 is formed by contacting the moist hydrocarbon feedstock with a molten metal mixture that includes at least a first reactive metal such that at least a portion of the H2O contained in the feedstock is reduced to H2 and the reactive metal is oxidized. The reactive metal can be at least partially dissolved in at least one diluent metal. The diluent metal may also be reactive with the steam, but is, by definition, less reactive with steam than the reactive metal. Thus, the oxygen from the H2O in the feedstock preferentially reacts with the reactive metal to oxidize the reactive metal to its metal oxide and reduce a portion of the steam to form H2.

A hydrocarbon feedstock, which includes at least a portion of the H2O, is injected into the molten metal reactor under conditions of intense mixing, such as by using submerged lances. Under these conditions, the metal oxide is continuously reduced back to the reactive metal by the carbon derived from the hydrocarbon while at the same time the metal is oxidized back to the oxide with moisture (steam) which originated from the moisture accompanying the feedstock. According to one embodiment of the present invention, the oxidation rate of the reactive metal, due to moisture accompanying the hydrocarbon forming steam, equals the rate of reduction of the iron oxide to iron, e.g., the reduction of the iron oxide by carbon derived from the hydrocarbon. This can be accomplished by controlling the total amount of moisture going into the reactor, such as by partially drying the hydrocarbon feedstock or adding some hydrocarbon feedstock with a lower moisture content, or by injecting additional moisture, such as in the form of steam, to the reactor.

The hydrocarbon feedstock is contacted with a molten metal mixture that includes at least a first reactive metal. The reactive metal preferably has an oxygen affinity that is similar to the oxygen affinity of H2 and reacts with the steam to form a metal oxide. For example, the reactive metal can be selected from germanium (Ge), iron (Fe), zinc (Zn), tungsten (W), molybdenum (Mo), indium (In), tin (Sn), cobalt (Co) and antimony (Sb). The molten metal mixture can include one or more reactive metals. The reactive metal preferably should: (1) be soluble in the diluent metal(s); (2) have a very low vapor pressure at the oxidation/reduction temperature(s); and (3) produce one or more oxides when reacted with steam that also has a very low vapor pressure at the oxidation/reduction temperature(s). A particularly preferred reactive metal according to the present invention is iron and according to one embodiment the reactive metal consists essentially of iron.

The reactive metal is preferably at least partially dissolved within a second metal, or mixture of metals, and the metal into which the reactive metal is dissolved is referred to herein as the diluent metal. The diluent metal may also be reactive with steam, in which case it can be selected from the group of reactive metals disclosed hereinabove, provided that the diluent metal is less reactive than the reactive metal. Alternatively, the diluent metal can be selected from the metals wherein the oxygen partial pressure (pO2) in equilibrium with the metal and oxides together is relatively high. These include nickel (Ni), copper (Cu), ruthenium (Ru), rhodium (Rh), palladium (Pd), silver (Ag), cadmium (Cd), rhenium (Re), osmium (Os), iridium (Ir), platinum (Pt), gold (Au), mercury, (Hg), lead (Pb), bismuth (Bi), selenium (Se) and tellurium (Te). More than one diluent metal can be utilized in the molten metal mixture. The diluent metal should not be a metal wherein the oxygen partial pressure in equilibrium with the metal and metal oxide together is extremely low.

Preferably, the diluent metal should: (1) combine with the reactive metal to be liquid in the temperature range of from about 400° C. to about 1400° C.; (2) have a very low vapor pressure over this temperature range; and (3) have the capacity to hold the reactive metal in solution. According to a preferred embodiment of the present invention, the diluent metal is tin and in one embodiment, the diluent metal consists essentially of tin. However, the molten metal mixture can also include additional diluent metals, for example copper and nickel.

A particularly preferred molten metal mixture according to the present invention includes iron as the reactive metal and tin as the diluent metal. Iron has a high solubility in molten tin at elevated temperatures and the melting temperature of the mixture is substantially lower than the melting temperature of pure iron (1538° C.). Although tin is also reactive with steam, it is less reactive than iron. For convenience, the following discussion will refer to iron and tin as the reactive and diluent metals respectively, although the present invention is not limited thereto.

Due to thermodynamics, H2O reduction reactions to form H2 require an excess of H2O above the stoichiometric requirement. The total H2O requirement (the mass ratio of H2O required to H2 produced) for iron is much less than for tin at all temperatures and iron will preferentially oxidize in the molten metal mixture. As a result, increased levels of H2O are utilized with the incoming feedstock, as compared to conventional gasification processes that typically require at least partial drying of the feedstock to remove moisture.

One significant advantage of utilizing a reactive metal dissolved in a diluent metal is that the residence time of the H2O within the reactor is increased with respect to the mass of the reactive metal. That is, a given mass of iron will occupy a first volume as pure iron, but the same mass of iron will be distributed over about twice the volume if the iron is in a 50 weight percent mixture with a diluent metal such as tin.

It is preferred that the metal mixture be maintained at a temperature above the solidus line AC of FIG. 2 (e.g., above 1134° C.), and more preferably above the liquidus line (I-II-III-IV) of FIG. 2. A metal-steam reaction temperature that is too high, however, adds significantly to the operating cost. For the completely molten iron/tin system illustrated in FIG. 2, the melt should be maintained at a temperature above the solidus temperature of about 1134° C., more preferably at a temperature of at least about 1200° C., and even more preferably at a temperature of at least about 1300° C. For the purpose of reasonable economics, the temperature should not be greater than about 1450° C. and more preferably is not greater than about 1400° C. A particularly preferred temperature range for the completely molten tin/iron metal mixture is from about 1300° C. to 1400° C. At 1300° C., about 75 weight percent iron dissolves in tin with sufficient superheat and the mixture stays in the molten state as iron is oxidized. Also, the reaction between H2O and liquid iron dissolved in tin to form hydrogen at 1300° C. is also quite vigorous and the reaction kinetics are excellent. Furthermore, the thermodynamics for the H2O/iron system even at 1200° C. are relatively good, requiring an excess of only about 12.2 tons of H2O to produce each ton of hydrogen (1.37 moles of H2O per mole of hydrogen). The preferred operating temperature will also be influenced by slag conditions, as is discussed below.

When using a reactive metal such as iron in a diluent metal such as tin, it is preferred that that the metal mixture include at least about 3 weight percent iron, more preferably at least about 10 weight percent iron, even more preferably at least about 20 weight percent iron and even more preferably at least about 40 weight percent iron in the molten metal mixture. Further, the amount of iron in the molten metal mixture should preferably not exceed about 85 weight percent and more preferably should not exceed about 65 weight percent. The balance of the metal mixture in a preferred embodiment consists essentially of tin. Accordingly, the amount of tin in the system is preferably not greater than about 97 weight percent, more preferably is not greater than about 90 weight percent, even more preferably is not greater than about 80 weight percent, and even more preferably is not greater than 60 weight percent. The molten metal mixture preferably includes at least about 15 weight percent tin and more preferably at least about 35 weight percent tin.

A method for reacting H2O to form hydrogen using an iron-tin mixture is disclosed in commonly-owned U.S. Pat. Nos. 6,663,681 and 6,685,754, both by Kindig et al. Each of these U.S. patents is incorporated herein by reference in its entirety.

Thus, H2O, the bulk of which can originate from the moisture contained in the hydrocarbon feed, is contacted with the molten metal mixture to generate H2 and to oxidize the reactive metal to a metal oxide. The H2O is contacted with the molten metal mixture in a manner that promotes good mixing and contact with the molten metal mixture. For example, the H2O preferably can be contacted with the molten metal mixture by injection of the hydrocarbon feedstock through submerged lances at velocities in the lance approaching the velocity of sound. Preferred reactor systems in this regard are discussed below.

Control of the composition of the slag that forms over the molten metal is important to the practice of the present invention. In this regard, the concentration of the iron oxide in the molten slag above the metal can range from about 30 weight percent FeO to a preferred maximum concentration of about 65 weight percent FeO, which values are primarily dictated by the temperature of the slag-freeze line. The freeze line for the slag rises steeply at both high and low concentrations of iron oxide, the points where injection of steam is either initiated or terminated. This is illustrated in FIG. 3. The slag composition illustrated in FIG. 3 has a basicity (CaO:SiO2 ratio) of 0.8.

According to the present invention, the optimal slag chemistry (e.g., the FeO content) can be determined for a selected hydrocarbon feedstock, such that the injection of that feedstock into the reactor maintains a substantially constant FeO content in the slag.

A slag layer provides a number of advantages, including preventing the iron from exiting the reactor. The temperature in the reactor should be sufficient to maintain the slag layer that forms over the metal mixture in the molten state over a range of compositions, as illustrated in FIG. 3. Similar to the range of compositions for the molten alloy discussed previously with respect to FIG. 2, there is a range of preferred slag compositions required to ensure adequate slag fluidity and reactivity. FIG. 3 illustrates the preferred operating temperature window (A-B-C-D) superimposed on a graph above the slag freeze line for a FeO/CaO/SiO2 slag as a function of temperature and FeO content. The reactor operating temperature must be above the slag freeze line where the slag is molten. Slag properties can be adjusted—for example fluxes such as SiO2, CaO, MgO, Na2O, K2O and mixtures thereof can be added to the reactor to adjust the properties of the slag. Moreover, sulfur and other anions may be incorporated in the slag to secure satisfactory slag chemistry.

A small amount of CO can also be generated in the gasification reactor from the reaction between liquid carbon (dissolved in the melt) and the H2O that is contacted with the molten metal to form H2. However, the amount of carbon that can be dissolved in molten iron tends toward zero as the iron oxide content of the slag increases and therefore the amount of CO generated in this manner is relatively small.

During production of the syngas, the metal oxide that is generated by the reaction of H2O can advantageously be trapped by dissolution in the slag layer within the reactor. At the preferred temperatures, the iron oxide is molten and is incorporated into the slag, which is lighter than the metal mixture. Therefore, as the dissolved iron is depleted from the molten metal mixture, the molten iron oxide rises through the molten metal and contributes to the slag layer on top of the molten metal. This also enables the metal to sink from the slag layer to the molten metal mixture upon reduction of the metal oxide. This accumulation of iron oxide in the slag may require the addition of one or more fluxes to maintain the slag in the preferred condition with respect to viscosity, reactivity, foaming, and the like.

The gasification method of the present invention includes providing to a reactor a hydrocarbon feedstock preferably with relatively high moisture content, such as un-dried wood or Powder River Basin coal, which can be represented by CyHxOzNaSbAshc.nH2O, and oxygen obtained from an air separation plant. The feed can also include a flux to control slag properties and make-up metals to replace incidental metal losses. Pyrolysis of the moist feedstock releases fuel-bound hydrogen (Hx) as a gas, moisture (nH2O) as steam and carbon (Cy) as a solid; other constituents of the feedstock (Oz, Na, Sb and ash) are also released (i.e., molecular bonds broken) by the pyrolysis. Also, at least a portion of the Cy is oxidized to carbon oxides with oxygen derived from molten iron oxide (FeOx), an endothermic reaction, and at least a second portion of the carbon is oxidized to carbon oxides with oxygen from an air separation plant, an exothermic reaction that at least partially balances the above endothermic reaction. In one embodiment, the molten metal alloy contains tin; and sulfur, if any is contained in the hydrocarbon feedstock, reacts with the tin to form the volatile species SnS and a small concentration of H2S. The ash is also fused and migrates into the slag.

At the same time, a portion of the steam (H2O) is reduced to H2 while a portion of the iron is oxidized to FeOx. The O2 that is introduced burns either iron to FeOx; H2 to H2O; or carbon to mixed carbon oxides to produce additional heat and achieve an energy balance about the reactor.

The molten metal and slag must be contained within a suitable reactor to maintain the desired reaction conditions. Further, the reactants should be provided in a manner conducive to good mixing and high contact surface area. High-temperature reactors suitable for establishing good gas/liquid/solid contact are utilized in the chemical and especially metallurgical industries.

The reactor can be maintained at an elevated pressure if necessary for adequate residence time in the reactor. For example, it may be desirable to maintain an elevated pressure, such as at least about 3 atmospheres (44.1 psi). A slightly elevated pressure in the reactor can be beneficial for minimizing the size overall of the first compression stage. For example, the pressure in the gasification reactor can be about 50 psi and up to about 400 psi. Pressure in the gasification reactor can be achieved, for example, by employing an air separation unit (ASU) that produces liquid (as opposed to gaseous) oxygen. Periodically, however, the gasification reactor must be tapped to remove slag, and tapping under pressure (or releasing pressure before tapping) can be difficult and costly.

One reactor system that can be useful for gasification according to the present invention, referred to as a bath smelter, utilizes lances to inject the steam and other reactants into the molten metal. Examples of reactors utilizing top or side submerged lances to inject reactants are disclosed in U.S. Pat. No. 3,905,807 by Floyd, U.S. Pat. No. 4,251,271 by Floyd, U.S. Pat. No. 5,251,879 by Floyd, U.S. Pat. No. 5,282,881 by Baldock et al., U.S. Pat. No. 5,308,043 by Floyd et al. and U.S. Pat. No. 6,066,771 by Floyd et al. Each of these U.S. patents is incorporated herein by reference in its entirety. Such reactors are capable of injecting reactants (e.g., hydrocarbons and oxygen) into the molten metal at extremely high velocities, approaching Mach 1, thereby promoting good mixing of the reactants.

The major function of the top-submerged lance (TSL) bath smelter is to maximize contact between the solid, liquid and gas phases within the reactor. FIG. 4 schematically illustrates a cross-section of such a reactor. The reactor 500 includes sidewalls 502 that are adapted to contain the molten metal 504 and slag 506. The sidewalls 502 can optionally be cooled, such as by water cooling. A refractory lining 503 is provided to insulate the portion of the reactor containing the molten metal 504 and slag layer 506. At least one top-submerged lance 508 is disposed through the top of the reactor and is adapted to inject reactants such as hydrocarbons and oxygen into the metal 504 or the slag 506 at a high velocity. The top-submerged lance 508 terminates and injects the reactants at or below the surface of the slag layer 506, such as near the interface of the molten metal 504 and the slag layer 506.

The moisture is released as steam when the hydrocarbon feedstock to be gasified is introduced into the reactor 500 containing the molten metal 504 and the slag 506 through a top-submerged lance 508 at a high velocity. The fuel-bound H2 in the hydrocarbon feedstock is released as H2 gas and carbon gasifies by reducing the metal oxide in the slag back to the metal. The oxidation potential within the reactor is controlled at a substantially constant value by introducing a hydrocarbon feedstock to the reactor—the carbon in the feedstock lowers the oxidation potential of the system thereby continuously driving the metal back into the melt, whereas the moisture accompanying the feedstock increases the oxidation potential of the system thereby driving the metal back to its oxide. The result of equal oxidation and reduction rates is that the FeO content of the slag remains substantially unchanged. As is discussed above, the hydrocarbon feedstock can be, for example, coal, petroleum coke, municipal waste, scrap tires, tar sands, low-grade crude oil, wood or similar low-value feedstocks. The particulate solid feedstock or the liquid hydrocarbon feedstock is injected into the reactor at the slag/alloy interface under conditions of intense mixing such as by injecting down a submerged lance 508 and/or 510. For example, a single lance can be used where the lance includes multiple annuli to allow the simultaneous injection of several reactants. An iron-containing hydrocarbon feedstock such as scrap tires can advantageously supply additional iron to the reactor to make up for incidental losses of the iron.

Thus, the hydrocarbon feedstock is subjected to gasification within the reactor 500. That is, the hydrocarbon feedstock is quickly pyrolized to release fuel-bound H2, to release moisture as steam and form carbon. The carbon gasifies while also acting as a reductant for the metal oxide in the slag 506. Therefore, as compared to conventional gasification, a substantial portion of the carbon is oxidized by the metal oxide (FeO) contained in the slag 506.

A heat balance must be achieved around the reactor 500 and little heat is provided by the iron-steam reaction, as it is only mildly exothermic. Since the principal source of H2O is the moisture carried in with the hydrocarbon feedstock that is injected down a lance, heat must be provided to convert that liquid or chemically-bound moisture into steam at the reaction temperature; thus additional heat must typically be supplied to the reactor. In this regard, oxygen can also be injected into the reactor to burn a portion of the hydrocarbon, metal or the H2 and provide the additional heat. For example, substantially pure O2 gas can be injected down a second lance 510. The O2 oxidizes the molten reactive metal, hydrocarbon or H2 in an exothermic reaction and creates the heat necessary to raise the temperature of the incoming moisture associated with the hydrocarbon feedstock to the reactor operating temperature and to sustain the oxidation of the reactive metal by the formed steam. Preferably, a substantially pure oxygen-containing gas is provided and it is typically advantageous to minimize the amount of nitrogen (e.g., from air) injected into the reactor. However, it may be necessary to dilute the O2 gas with a carrier gas to reduce the possibility of burning the lance 510.

A crude syngas containing CO and H2 can be removed through an outlet port 512. In addition, slag 506 can be periodically tapped (removed) through slag outlet port 514.

As is noted above, the slag composition can include a number of compounds, including silica (SiO2), calcium (CaO), alumina (Al2O3) and magnesia (MgO). It has been advantageously found according to the present invention that when other oxides are contained within the slag 506, the iron oxide requires a higher reducing potential for producing iron metal. Therefore, an additional amount of carbon from the hydrocarbon feedstock is necessary and the equilibrium gas composition resulting from the reductive cleaning of the slag advantageously has a high CO:CO2 ratio. This advantageously decreases the amount of CO2 per unit energy that is produced in accordance with the present invention. For example, a CO:CO2 ratio of 4, contains 80 percent CO and 20 percent CO2 (ignoring other gases), whereas a CO:CO2 ratio of 2 contains 66.7 percent CO and 33.3 percent CO2. Combusting either gas produces the same amount of CO2 (100 percent). However, more work is derived from the gas with the higher CO content. Therefore, the higher the CO:CO2 ratio, the greater the amount of work that can be accomplished per unit of CO2 produced. In this regard, it is preferred that the volume ratio of CO:CO2 exiting the reactor 500 (e.g., the raw syngas) is at least about 3, more preferably is at least about 5 and even more preferably is at least about 7.

Controlling the oxidation potential of the reactor contents controls the rate of the reduction reaction and therefore the amount of iron oxide in the slag 506 that reduces to iron and reports to the melt 504. This rate can be maximized by controlling the relative amounts of oxygen gas and carbon from the hydrocarbon feedstock that are injected into the reactor 500. In turn, these relative amounts of oxygen and carbon control the partial pressure ratio of oxidized gases to total gases, as expressed by the fraction: H2O+CO2H2+H2O+CO+CO2.(10)

The preferred value for this ratio can be established through minimization of Gibbs' free energy for the reduction reaction. That is, the method of the present invention is most effective and produces the highest CO:CO2 ratio when the value of the ratio of the oxidizing gases to total gases is determined by the Gibbs' free energy minimization technique for the particular hydrocarbon feedstock being used. Process control can also be based on approaching (targeting) the pre-calculated preferred ratio of oxidized to total gases, which is unique for each different hydrocarbon feedstock and which value when approached insures rapid reduction of iron oxide to iron. That is, CO2 production can be reduced by using the Gibbs' free-energy minimization technique.

A flowsheet illustrating the gasification of a hydrocarbon feedstock and subsequent treatment of the off-gas according to the present invention is illustrated in FIG. 5. The gasification process can employ a reactor 602 that is preferably a bath smelter similar to that described above with respect to FIG. 4. The reactor 602 produces a syngas, which is passed to a purification train 682 to remove contaminants from the syngas.

After the syngas purification train 682, valves 670 control the direction of the syngas stream depending on the desired end products. For example, the syngas stream from reactor 602 can be refined such as by processing through a water gas shift reactor 634 to increase the amount of H2, and/or a pressure swing adsorption (PSA) unit 636 where carbon oxides are separated from H2. The H2, if desired, can then be further compressed for shipment or for storage 650. All or a portion of the syngas stream can be taken to an electricity generating turbine 642 to burn CO and H2 and generate electricity. All or a portion of the syngas can also be sent to hydrocarbon synthesis 690. For hydrocarbon synthesis, some portion of the syngas will likely require conversion to H2 by water gas shift 634 followed by a PSA 636 to isolate H2 from co-mingled CO2.

As is described more fully below, the gas purification train 682 can optionally include multiple units-of-operation for: (a) rapid gas cooling by water quenching; (b) gas cooling and heat recovery by heat exchangers; (c) removal of solid pollutants such as fine particles, for example by filtration; (d) catalytic conversion of carbonyl sulfide (COS) to hydrogen sulfide (H2S); (e) condensation of water vapor and simultaneous removal of soluble halogen acid gases such as HCl and HF; (f) amine scrubbers, solvents or absorbents such as metallic iron or zinc to capture hydrogen sulfide (H2S); and/or (g) other purification unit operations for capturing pollutants originating within the hydrocarbon feedstock, such as activated carbon for capturing volatile species of mercury, a common pollutant emitted by coal-fired electrical generating plants. Additional equipment is discussed in more detail below with respect to FIG. 6.

By way of illustration, the temperature of the syngas stream can be rapidly reduced by water quenching to preclude corrosion issues that arise from high temperatures and high CO concentrations. After quenching to a temperature that precludes corrosion issues, heat can be recovered from the syngas stream utilizing conventional heat exchangers and the recovered heat can be used to raise steam. Fine particulates, such as furnace dust and condensed SnS, can be removed from the syngas stream, and the particulates can be agglomerated and roasted with oxygen. The roasted product (calcine) can be re-injected into the reactor to conserve metal values and the SO2 from the roasting operation can be directed to a Claus plant for recovery of sulfur a salable by-product.

Fine particulates, such as furnace dust, can also be removed from the syngas stream and after agglomeration and roasting, they can be re-injected into the reactor. Any COS that may be present in the syngas stream can be catalyzed to H2S and the H2S can be removed from the syngas stream by amine scrubbing or other processes. The H2S released from the amine regeneration unit operation can be directed to the Claus plant, where it will react with the SO2 derived from roasting furnace dust to form elemental sulfur:
2H2S+SO2→3S+H2O (11)
If insufficient H2S is available to react with the SO2, H2 can be provided to the Claus plant, as needed to meet the reduction requirement for making elemental sulfur.

Slag from the reactor 602 can be tapped (removed), preferably in an amount approximating the amount of ash and flux materials that are added, or in an amount that precludes the rapid build-up in concentration of some compound in the slag, such as vanadium pentoxide, which is frequently present when petroleum coke is utilized.

According to the present invention, burning relatively low-ash carbon feedstocks is preferable to burning high-ash carbon feedstocks. This is because a flux, usually CaO, SiO2 or both must be added in proportion to the amount of ash in the feedstock to control slag properties. Thus, for high-ash carbon, there must be a large slag tap so that an equivalent amount of slag is removed as ash and flux are added. The slag typically contains about 2% tin and about 30% iron, derived from the oxidation of metal alloy, and this can translate into a significant economic loss if not recovered and recycled to the reactor.

However, coal and wood are plentiful and widely distributed and can be used as a hydrocarbon feedstock for producing clean gasoline and diesel fuels, or other products, in accordance with one embodiment of the present invention. The relatively higher ash content of coal and consequently high slag and tin losses, however, is problematic. Aggressive coal cleaning such as froth flotation is a widely practiced approach known for minimizing ash content when using coal. Even with such measures, however, there may be more ash than is economically desirable.

One aspect of the present invention anticipates recovering the residual tin and iron from the tapped slag. The process comprises mixing elemental sulfur, a plant by-product, into the slag just after tapping and while the slag is still hot. Sulfur will react with either elemental tin (Sn) or tin dioxide (SnO2), whichever form is present, to create the volatile tin sulfide, (SnS). If SnO2 is present, SO2 also will be formed. Both reactions are exothermic and the heat derived from the reactions can advantageously off-set thermal losses to the environment.

Immediately after tapping, the slag can be directed into a heated crucible (or converter). Using lances, sulfur, irrespective of its state, can be blown into (through) the hot slag using a gas that is non-oxidizing with respect to sulfur and contains little or no nitrogen. The off-gas from the heated crucible will contain the volatile species, SnS and SO2, which can be directed to the dry bottom quench. Any excess sulfur (above the stoichiometric requirement to react with any Sn and/or SnO2 in the slag) will react with the iron to form iron sulfide.

After recovery of residual tin from the slag, iron may be recovered from the FeOx and FeS, if any, by admitting hydrocarbon and oxygen to the converter. To preclude slag freezing, additional heat may be introduced into the converter, such as by burning natural gas.

Any SnS entering the quench can be captured in a baghouse and recycled after oxidation to SnO2. Any SO2 entering the quench will react with the H2 to form H2S and H2O. The H2S can be captured by an amine scrubber and ultimately processed back to elemental sulfur in a Claus plant. The water can be removed by chilling.

After the “sulfur blow” to recover tin and the addition of hydrocarbon and oxygen to recover the iron, the lances can be removed (retracted) and the slag quenched in a wet-bottom quench. This quickly freezes the slag and controls particle size, minimizing crushing requirements.

One process flow according to the present invention, including the components of a gas purification train can be understood with reference to FIG. 6, which illustrates the co-generation of H2 and electricity according to the present invention.

As illustrated in FIG. 6, reactor 602 generates a syngas stream from a hydrocarbon feedstock as is described above. Steam for input to the gasification reactor 602 largely is provided by evaporation of moisture associated with the hydrocarbon feedstock but can be supplemented by additional steam.

Heat must be supplied to the reactor 602 to raise the temperature of the incoming feedstock to the reaction temperature. According to a preferred embodiment, oxygen (O2) from an air separation plant 614 is supplied to the reactor 602 to provide the oxidant for that heat.

In the reactor 602, O2 can generate heat by: (a) reacting with the metal to form a metal oxide; (b) reacting with hydrogen to form steam; or (c) by reacting with carbon derived from pyrolysis of the hydrocarbon. Both reactions (a) and (b) above decrease the amount of metal available to react with steam to form H2; it therefore it is preferred to provide the reactor with sufficient metal, over and above that required to produce the desired amount of H2, to react with only sufficient O2 to provide the necessary heat.

Simultaneously, a hydrocarbon feed is provided to the reactor 602 to reduce the iron oxide contained in the slag back to iron which re-dissolves into the molten metal. The O2 that is injected into the reactor 602 also generates heat by supporting the partial oxidation of the carbon from the hydrocarbon feedstock to CO in the highly reducing environment of the reactor 602. By controlling the carbon-to-oxygen ratio, which in turn controls the ratio of oxidizing to total gases previously presented, the oxygen present can oxidize the carbon predominately to CO, while at the same time minimizing the formation of CO2. To preclude potential corrosion, a carrier gas (preferably devoid of N2) may be used to dilute the O2 prior to injection into the reactor 602.

Carbon, steam and H2 are all released by pyrolysis of the hydrocarbon feedstock in reactor 602. One portion of the carbon serves as the reductant to render the metal oxides back to the metals and simultaneously generate CO by gasifying the solid carbon. Another portion of the carbon reacts with O2 which, by controlling the oxygen partial pressure, expressed as the ratio of the partial pressures of the oxidizing gases to that of the total gas stream (Equation 10), controls the rate at which the reactive metal oxide is reduced back to the reactive metal. Advantageously, the highly reduced atmosphere that is required to reduce the reactive metal oxide is also high in CO relative to CO2 and high in H2 relative to H2O. A syngas stream comprised of high CO and H2, with lesser amounts of CO2 and trace impurities, results.

A preferred hydrocarbon feedstock is a moisture-containing low-ash hydrocarbon-bearing material high in its percentage of both carbon and hydrogen, and low in its percentage of oxygen and ash. Low ash reduces slag losses, and low oxygen enhances the available (fuel bound) hydrogen. That is, fuels with higher oxygen content such as municipal waste will consume some of the available H2. In this instance, the hydrogen released as elemental hydrogen will be the total hydrogen minus about ⅛ of the oxygen. High carbon and hydrogen values minimize the total amount of fuel required while simultaneously producing a desirable syngas stream.

The moisture-containing hydrocarbon feedstock can also be injected into the reactor 602 using a top-submerged lance or similar device. When so injected, the particulate feedstock can be entrained in a gas such as CO or CO2, and during steady-state operation a portion of the purified and compressed syngas stream can advantageously be recycled and used as a carrier gas. It is also possible, although less desirable, to add the moist hydrocarbon feedstock to the reactor 602 by other means, such as by simply dropping the feedstock into the reactor 602.

Other materials such as fluxes can be injected into the reactor 602, for example to control the properties of the slag such as slag fluidity or tendency to foam. The ash-forming minerals that can be part of the hydrocarbon feedstock contribute to the slag layer within the reactor 602. When coal is used as a hydrocarbon feedstock and there is adequate calcium oxide (CaO) in the slag (either inherent in the feedstock or added as flux), the slag can be tapped from the reactor 602 and sold as a pozzolanic by-product. Additionally, other materials such as tin compounds, cassiterite ore or other materials such as iron compounds or ore may be added to make-up for losses of metal values. According to a particularly preferred embodiment, tin is a diluent metal and cassiterite ore (SnO2) is injected into the reactor to make-up for tin losses.

Thus, in the gasification reactor 602, CO derives from two reactions: (1) the gasification of carbon with FeO (endothermic); and (2) the partial oxidation of carbon (exothermic) to CO. Employing an IGCC 652, this CO can be advantageously used to generate electricity. The advantage is two-fold: (1) the CO to CO2 conversion (the second oxygen atom accepted by the carbon) embodies approximately two-thirds of the energy available from the complete oxidization of carbon; and (2) gas fired turbines, especially when operated as an IGCC 652, comprise a means of generating electricity that is about 66 percent more efficient in converting thermal energy to electric energy than the conventional coal-fired, steam-driven-turbines that currently generate approximately 51 percent of the electrical needs of the United States. As an alternative to generating electricity, additional H2 may be produced by utilizing the approach of conventional gasification, which is the water gas shift reaction 634 followed by isolation of the formed H2 and CO2, usually with a PSA unit 636.

The amount of O2 introduced into reactor 602 is preferably just sufficient to support combustion of enough carbon, hydrogen or iron to supply the heat required for the endothermic conversion of metal oxide to metal. The O2 may have to be introduced as a mixture with a carrier gas to preclude inadvertent oxidation of the injecting lance. Off-gas from the gasification reactor 602 is advantageously in a reduced state.

A crude syngas stream is removed from gasification reactor 602. This crude syngas stream can include H2, un-reacted steam, CO, CO2, H2S, COS, furnace dust, and gaseous tin sulfide (SnS).

The syngas stream also carries substantial heat value. The hot syngas stream can be passed through a quench 608 where liquid water rapidly cools the syngas stream but without substantial loss of recoverable heat. Preferably, the quench 608 is a dry bottom quench wherein a controlled amount of liquid water rapidly cools the syngas stream to a reduced temperature, such as about 900° C. or lower. The rapid cooling is designed to minimize the Boudouard reaction that is favored above 700° C. and which consumes carbon (from the steel of the equipment walls) by reacting with CO2 to form CO. However, the farther the temperature is dropped below about 700° C., the less heat that is available downstream for producing additional electricity. Thus, it is preferred to reduce the syngas stream to a temperature in the range of from about 900° C. to about 700° C.

The use of such a quench 608 to cool the syngas stream can advantageously:

    • 1. Reduce metal “dusting”, i.e., the destruction of the containing ductwork, by rapidly dropping the temperature through the temperature range where the “dusting” reaction occurs (thought to be caused by the Boudouard reaction, wherein carbon contained in the steel plus CO2 yields CO);
    • 2. Minimize the potential for the inadvertent deposition of carbon from the reverse Boudouard reaction;
    • 3. Shift some CO to H2 by the water gas shift reaction thereby increasing the amount of H2. It is believed that this conversion may advantageously be catalyzed by nascent iron oxide dust that can be simultaneously expelled with the reactor gases;
    • 4. Cool the hot gases to more manageable temperatures and volumes without substantial loss of heat; and
    • 5. Condense any gaseous SnS to solid SnS.

The syngas stream can then be passed through waste heat exchanger 610 to further cool the syngas stream and to provide heat for additional steam, thereby conserving heat value. For example, the temperature of the gas stream can be dropped to about 250° C. and the recovered heat used to generate steam.

The syngas stream can also include some contaminants. These can include CO and H2S, both arising from carbon and sulfur dissolved in the metal reacting with the steam, and entrained particulates of frozen slag, metal oxides (e.g., iron oxide) or carbon which are ejected from the molten metal bath and slag. The syngas stream can also include SnS which volatilizes from the molten metal bath and is condensed in the quench 608. The particulate contaminants can be removed from the syngas stream, such as by a filter 616. Alternatively, other means such as electrostatic precipitators or bag houses can be used to separate particulates.

Preferably, the SnS is conveyed to a dryer and pelletizer 628 with the other particulates for agglomeration and the pellets are then treated in a roaster such as a fluidized bed roasting unit 626 to convert the SnS to SnO2 and SO2 through the introduction of O2 from the air separation unit 614. The SnS is preferably roasted in the roasting unit 626 in a manner that the O2 remaining in the roasting gas is minimized, so that little or no O2 is mixed with the gaseous SO2 coming off the roasting unit 626.

The SO2 can then be transferred to a Claus plant 632 where it is combined with H2S from an amine regenerator 630 or, if sufficient H2S is not available for the Claus reaction, H2 exiting the PSA unit 636 can be used as the reductant. The Claus plant 632 produces sulfur which is a salable by-product of the process. The SnO2 can advantageously be recycled to the reactor 602 to reduce tin losses from the system.

After removal of particulate contaminants, if any, the syngas stream can be treated in a catalytic reactor 618 to convert carbonyl sulfide (COS) in the syngas stream to H2S. This reaction is typically carried out at a temperature of about 200° C. with a catalyst. Other means to remove COS, such as physical solvents, can be used. Thereafter, the syngas stream can be cooled in a chiller 620 to condense excess steam and the water can be recovered and recycled to water header 640. The chiller 620 can also advantageously remove soluble chlorine compounds. Chlorine is a common contaminant in many of the types of hydrocarbon feedstock for this process. The chlorine, released during pyrolysis, can react with the hydrogen to form gaseous HCl. The resulting syngas stream is relatively pure, except for trace amounts of H2S.

Considerable heat is released as steam is condensed from the syngas stream by the chiller 620 and this heat can be captured within a hot water header 640 for recycling within the steam system. The Clion concentration in the condensed water is preferably controlled to preclude corrosion problems and assure continued adsorption of the extremely water soluble HCl gas.

The syngas stream can be passed through a compressor 624 to increase the pressure of the syngas stream, preferably to at least about 200 psi, more preferably at least about 400 psi. It then can then be passed through an amine scrubber 622 to remove H2S. The H2S-rich amine solution from the scrubber can be passed to an amine regenerator 630 to regenerate the amine solution which is then passed back to the amine scrubber 622. Other means for removing the H2S, such as physical solvents (e.g., methanol), can also be used.

The H2S can then be combined with SO2 in a Claus plant 632 for the production of elemental sulfur. It may also be desirable to divert a portion of the H2 to the Claus plant 632 since there may not be enough H2S available to stoichiometrically match the SO2 from the roaster 626. The tail gas from the Claus plant 632 may be directed to a quench downstream from the reduction reactor for final gas clean-up (not shown in FIG. 6).

As is noted above, one aspect of the present invention is directed to the recovery of residual tin from the tapped slag. The process comprises mixing elemental sulfur, a process by-product from the Claus reactor 632, into the slag just after tapping and while the slag is still hot. Sulfur will react with either elemental tin (Sn) or tin dioxide (SnO2), whichever form is present, to create volatile tin sulfide (SnS). If SnO2 is present in the slag, SO2 also will be formed. Both reactions are exothermic and the heat derived from the reactions can advantageously off-set thermal losses to the environment.

More specifically, immediately after tapping, the slag can be directed into a heated crucible or converter. Using lances, sulfur, irrespective of its state, can be blown into through the hot slag using a recycle gas that is non-oxidizing with respect to sulfur and contains little or no nitrogen, including process recycle gas. The off-gas will contain the volatile species SnS and SO2 which can be directed to the dry bottom quench 608. Any SnS entering the quench can be captured in a baghouse and recycled after oxidation to SnO2. Any SO2 entering the quench will react with the H2 to form H2S and H2O. The H2S can be captured by the amine scrubber 622 and ultimately processed back to elemental sulfur in the Claus plant 632. The steam can be removed by chiller 620.

Any excess gaseous sulfur, over and above that required to react with tin species, will react with the iron to form iron sulfide. After tin recovery, iron, whether present as FeO or FeS will be recovered by introducing a hydrocarbon and oxygen into the converter.

After the “sulfur blow” and iron reduction, the lances can be removed (retracted) and the slag quenched in a wet-bottom quench. This quickly freezes the slag and controls particle size, minimizing crushing requirements.

After removal of H2S in the amine scrubber 622, the syngas stream can optionally be conveyed to PSA unit 636 to separate carbon oxides from H2.

The gasification method of the present invention can advantageously increase the amount of CO and/or H2 that is produced in the syngas relative to the amount of CO2 simultaneously produced. Table 2 illustrates a comparison of the product syngas from the gasification of an identical quantity of an identical hydrocarbon feedstock for the method of the present invention and the E-Gas process (Conoco-Phillips), an oxygen-blown coal gasification process that is currently regarded as an environmentally friendly commercial gasification process. The data presented in Table 2 represent content of the raw gas stream after removal of contaminants but before any unit operations to adjust the gas ratios, such as PSA or water gas shift.

TABLE 2
E-Gas CompositionPresent Invention
Syngas Component(kmol/cycle)(kmol/cycle)
H22224
CO2735
H2O2510
CO2135

As is illustrated by Table 2, the method of the present invention produces a higher concentration of CO and H2 relative to CO2. The CO:CO2 ratio for the method of the present invention is about 7, whereas for the E-gas process it is about 2.

In the embodiment illustrated in FIG. 6, the syngas can be burned in an IGCC 652 to produce electricity. Some of this electricity can be used to operate different unit operations, such as air separation plant 614 and the various compressors. Excess electricity can be sold into the power grid.

As is illustrated in FIG. 7, the IGCC 652 includes several unit operations. These unit operations include a gas-fired turbine 642 to which air (or oxygen) is fed along with previously compressed syngas to produce electricity via generator 644. The output heat of the gas-fired turbine 642 is utilized to generate steam in a heat exchanger 648, which steam can be input to a steam-turbine generator 646 to generate additional electricity. Any excess steam created in heat-generating units, for example, heat exchanger and superheater 610, chiller 620, Claus plant 632 and fluid bed roaster 626 also can be directed to the steam-turbine 646 to produce additional electricity.

One aspect of the present invention is directed to the production of ammonia using the manufactured low-cost, high-purity hydrogen gas and nitrogen gas from the air separation plant 614 as reactants. One of the important aspects of the method according to the present invention is the in-situ manufacture of large quantities of H2 at a relatively low cost. It is believed that one of the primary hindrances to the methods disclosed in the prior art for the production of ammonia is the need for high volumes of H2 gas and the high cost associated with the H2 gas. According to the present invention, high volumes of hydrogen gas can be economically generated in-situ.

The nitrogen and hydrogen are combined in a H2:N2 molar ratio of about 3:1 in order to maximize the production of ammonia (NH3). In a typical ammonia production method, a gas including hydrogen and nitrogen is compressed to about 200 atmospheres of pressure and passed over an iron catalyst at a temperature of from about 380° C. to about 450° C.

The methods of the present invention can provide numerous advantages as compared to prior art methods. Among these are:

    • reduced CO2 (a greenhouse gas) is produced per unit H2 or energy produced as compared to conventional gasification. CO2 emissions per unit of H2 produced are: conventional gasification about 22 tons CO2 per ton H2; the method of the present invention about 14 tons CO2 per ton H2. Steam methane reformation (SMR) emits 13 tons CO2 per ton H2, however, SMR is not desirable due to the high cost of its feedstock, natural gas.
    • low-value hydrocarbon fuels, inducing high-sulfur hydrocarbons or hydrocarbons containing chlorine, can be utilized.
    • the syngas from the gasification reactor is kept in a highly reducing state.
      Removal and Preclusion of Pollutants

In accordance with the foregoing method, a gas purification train can be used for (1) recovering heat; (2) removing pollutants; and (3) precluding the formation of pollutants from components comprising the syngas stream. Pollutants contained in the feed material which distribute to the gas phase (as opposed to the alloy or slag phase) determine what unit operations are required for removing the pollutants.

By way of example, listed below is a sequence of unit operations (with reference to FIG. 6) designed to remove pollutants that might be expected when utilizing coal as the carbon source for the process of the present invention. Pollutants removed can include fine solid particulates such as furnace dust and SnS, water, chlorine, sulfur and mercury. Pollutants whose formation is advantageously precluded include nitrogen oxides (NOx) and furans and dioxins.

    • 1. Dry bottom quench 608: this unit is designed to rapidly decrease the gas temperature from 1300° C. to 700° C. by injecting liquid water. The purpose of the quench is to preclude a potential metallurgical problem known as dusting, which is the deterioration of the metal that contains the gas and is known to occur at temperatures above about 700° C. in syngas streams with a high concentration of CO.
    • 2. Heat exchanger and steam super heater 610: This unit operation is a conventional heat exchanger and super heater designed to recover the sensible heat of the gases.
    • 3. Metal filter 616: After the gas is cooled, particulates are removed by a candle filter employing a metal filter medium. The fine solids that are recovered are comprised of furnace dust and tin sulfide.
    • 4. Fluid bed roaster 626: In a unit external to the purification train, the particulates collected from metal filter 616 are roasted in a fluid bed roaster in oxygen to form SO2 and SnO2. The SnO2 is returned to the furnace with the dust. The SO2 advances to a Claus plant 632, where the SO2 is combined with H2S, recovered from the amine regeneration system or H2 from the product line to form elemental sulfur.
    • 5. COS to H2S 618: In this unit operation, a catalyst is used to hydrolyze the carbonyl sulfide to hydrogen sulfide and carbon dioxide, and is part of the sulfur removal system. Sulfur is a ubiquitous contaminant of coal and other hydrocarbons.
    • 6. Chiller 620: The chiller is designed to remove steam originating from two sources: (i) steam that was not converted to hydrogen in the gasification reactor; and (ii) water, converted to steam, added to the dry bottom quench. Acid gases such as HCl or HF also will be removed by the chiller due to their high solubility in water. Their removal is related to precluding formation of furans and dioxins.
    • 7. Amine scrubber 622: This standard unit operation is part of the system for removing sulfur, and it operates in conjunction with the amine regeneration unit 630.
    • 8. Activated carbon adsorber (not illustrated): Mercury can be adsorbed by activated charcoal. Mercury can be recovered from the loaded carbon and the charcoal reactivated and reused.
    • 9. Pressure swing adsorption (PSA) system 636: This system is a standard means for disengaging commingled gases and typically is used to separate H2 from CO and CO2 to yield a pure salable stream of H2.

Dioxins are a family of compounds known as polychlorinated dibenzo-dioxins (PCDD), and furans are a family of compounds known as polychlorinated dibenzofurans (PCDF). There are about 210 compounds in these two families, and they have a wide range of environmental, chemical and physical properties. Two methods are postulated for their formation. Both methods are believed to require the presence of all of the following precursor conditions: (1) the presence of solid particles containing carbon structures; (2) the presence of organic or inorganic chlorine; (3) the presence of iron, copper, manganese or zinc ions; (4) an oxidizing atmosphere; and (5) a temperature window of 250° C. to 400° C.

According to the present invention, the formation of dioxins and furans can be substantially precluded because oxygen is absent as the hot syngas stream is cooled through the temperature window of 400° C. to 250° C., and chlorine (Cl) and fluorine (F) are removed before the gases are reheated through that temperature window.

The formation of nitrogen oxides can also be precluded or reduced by reducing the oxidation temperature inside the gas fired turbine. Water or other oxidized gases such as CO2 can be used as a temperature control method.

There are numerous methods for removing elements that are considered pollutants from the syngas stream. In terms of what potential pollutants to remove, the starting point is an analysis of the solid hydrocarbon feed being used and all other materials that enter the process. The method of the present invention advantageously partitions all elements admitted to the process to one of four locations—the slag, the alloy, the reactor dust which includes tin sulfide or the syngas stream.

Slag

Refractory oxides such as SiO2, Al2O3, CaO and MgO report to the slag. Control of slag properties depends upon taking a sufficiently large slag tap to preclude the build-up of potentially detrimental elements. For example, the ash from petroleum coke typically has a high percentage of vanadium, which is expected to report to the slag as vanadium oxide. The vanadium content of the slag can be kept within pre-established limits, preferably less than 20 percent for satisfactory slag properties, by adjusting the amount of flux added and correspondingly, the amount of slag tapped.

Alloy

Some elements that may be associated with the solid hydrocarbon feed, such as oxides of nickel or copper, are expected to be reduced by the carbon and report to the alloy. These elements dilute the alloy but do not render it ineffective. After some time, elements (other than tin and iron) accumulate in the alloy, and the entire alloy may have to be changed out. Value received from the “contaminated” alloy can exceed the cost of a fresh alloy system.

Reactor Dust

This material, extracted from the syngas stream by filtration, is agglomerated and then roasted to produce dry SO2, for sulfur production by the Clauss process, and calcine, for returning iron and tin oxides to the reactor that ejected the dust.

Syngas Streams

Solid hydrocarbons derive from living materials and they are comprised principally of carbon, hydrogen, nitrogen, oxygen, sulfur, chlorine and ash. Ash may be inherent, comprised of inorganic elements commonly associated with the living material, or the ash may be adventitious, washed in from another source. Most ash components are expected to partition to the slag with a few partitioning to the alloy.

The only solid hydrocarbon currently available in North America in sufficient quantity to off-set the use of imported oil is coal. Biomass also could be available in sufficient quantity, but at present there is no biomass collection system in place. Coal (or biomass) can be augmented with pet coke, municipal waste, and rubber tires, either to enhance the quality of the hydrocarbon or to consume waste thereby reducing or eliminating landfills and their associated ills. The major potential contaminants arising from these hydrocarbons are considered below.

From solid hydrocarbon, water and air, the method of the present invention creates both a syngas stream that is highly reducing (low partial pressure of oxygen), hot, dusty and contaminated with chlorine, sulfur compounds and various other elements.

Precluding Corrosion. A high concentration of CO at high temperatures can cause corrosion or “dusting” of the metal ductwork containing the gas. For this reason the 1300° C. high CO syngas from the furnace is rapidly cooled by injecting sufficient liquid water to reduce the temperature to 700° C.

Conserving Heat. This is critical for maintaining good efficiency. Standard heat exchangers are used for this purpose.

Particulate Removal. Devices effective in removing particulates from a syngas stream can include: ESPs (electro-static precipitators), metal filters and (cloth) bag-houses. Metal filters are generally preferred because they can withstand the (relatively high) gas temperature. Two types of (intermingled) particulates are removed; furnace dust and tin sulfide. Tin sulfide along with associated furnace dust is subsequently roasted to recover the tin as tin dioxide, which, along with the furnace dust, recycles to the reactor, and sulfur dioxide which reports to the Claus plant.

Acid Gas Removal. Acid gases include CO2 (as H2CO3); hydrogen sulfide (H2S), hydrogen chloride (HCl), and hydrogen fluoride (HF). Various methods for their removal include:

CO2. Scrubbing with a solvent, such as the RECTISOL process (Lurgi, Frankfurt, Germany), which removes the CO2 from the syngas stream, to be subsequently released (upon regeneration of the solvent) and be compressed-and-sequestered. The RECTISOL process uses cold methanol as a physical solvent and the CO2 (as well as H2S, COS and other sulfur compounds) are removed from the syngas stream. Alternatively, the syngas stream can be burned in pure oxygen yielding a more-or-less pure CO2, again for compression-sequestration. Other methods for removing CO2 exist, including adsorption on activated carbon.

Sulfur. Carbonyl sulfide (COS) is not removed by conventional amines. For this reason it typically is first hydrolyzed into H2S; (COS+H2O→H2S+CO2). This reaction proceeds well in the presence of a catalyst.

Some solvents can remove both H2S and COS. An example is SELEXOL (Union Carbide), a physical solvent made of a dimethyl ether of polyethylene glycol.

Halogen Acids. Halogen acids such as HCl and HF are removed in the method of the present invention due to their extreme solubility in water. In the chiller, a large amount of steam (added as water at the quench) is condensed. Formation of the cloud of condensed water will dissolve and remove the halogen acids from the syngas stream (and also some H2S). If halogen acids are not removed before amine scrubbing, they will react (destructively) with the amine.

NOx The formation of appreciable amounts of NOx can be precluded during combustion of the gas in the gas turbine by the addition of sufficient water to control flame temperature to below the temperature that is required for its formation.

Mercury. Mercury (Hg) is not present in the pet coke. Mercury, however, does exist in coal. Commercial methods for its removal have been developed employing (powdered or granular) activated charcoal for adsorption with regeneration of the activated charcoal achieved by the application of mild heat to the sorbent. Such methods can be employed when mercury is present in the hydrocarbon feed.

Dioxins and Furans. These toxic compounds (collectively about 210 of them) do not exist in the feed; rather, they can form during cooling or heating of the syngas stream as it passes through the temperatures window of 250° C. to 400° C., when all four of the following are present—oxygen, a carbon structure, chlorine and iron (as a catalyst). Absence of any one of these components will preclude formation.

The method of the present invention is advantageously arranged so that O2 is absent as the temperature drops from 400° C. to 250° C. and chlorine is absent as the temperature is raised from 250° C. to 400° C. in the IGCC circuit. The ability to preclude furan and dioxin formation is critical if municipal waste or coal with high chloride content, Illinois coal for example, is used as a feedstock. Municipal waste can be especially high in chlorine content (from PVC, household bleach and other sources).

In summary, there is often more than one means of removing a pollutant from a reducing syngas stream; however, once selected, integration into the gas purification train is required.

In one embodiment of the present invention, CO2 can be removed from the atmosphere and sequestered. This embodiment can potentially create revenue in the form of CO2 credits that are available in several industrialized nations.

According to the present invention, biomass (that otherwise would decompose by oxidation in a landfill) can be converted to syngas and the syngas is converted to methane which in turn is converted to H2 and solid, elemental carbon. The hydrogen is available for further processing, and the carbon is sequestered. Every ton of carbon sequestered is equivalent to excluding 3.7 tons of CO2 from entering the atmosphere. Since oxidizing biomass does not create CO2 emissions (oxidizing biomass simply returns CO2 to the atmosphere that was first removed to create the biomass), sequestering carbon derived from biomass essentially removes CO2 from the atmosphere. Hydrogen thus is produced at no CO2 cost to the environment.

In yet another embodiment of the present invention, applicable to hydrocarbon feedstocks with low to medium sulfur contents (pet coke usually is high in sulfur content), the H2S and COS that appear in the gas stream can be reacted with iron (iron contained in an “iron box”) which can be subsequently roasted along with the SnS recovered by the filter, pelletized and dried. In this case, roasting converts all sulfur in the feedstock into dry SO2. Dry SO2 is especially well suited for the manufacture of sulfuric acid, and is a widely used item of commerce. The iron introduced into the reactor (along with re-cycled tin) comprises make-up iron.

While various embodiments of the present invention have been described in detail, it is apparent that modifications and adaptations of those embodiments will occur to those skilled in the art. However, it is to be expressly understood that such modifications and adaptations are within the spirit and scope of the present invention.