WO2013036273A2

WO2013036273A2 - Integrated underground coal gasification and acid gas removal configurations

Info

Publication number: WO2013036273A2
Application number: PCT/US2011/063802
Authority: WO
Inventors: Michael Wailap CHAN; John Mak; David Kim
Original assignee: Chan Michael Wailap; John Mak; David Kim
Priority date: 2011-09-05
Filing date: 2011-12-07
Publication date: 2013-03-14

Abstract

A syngas treatment plant is configured to remove sulfurous compounds and carbon dioxide from syngas in a configuration having a Redox desulfurization section and a propylene carbonate decarbonization section, wherein H2S is catalytically removed with a chelated solution to elemental sulfur and the reduced solution is re-oxidized by oxygen and the off gases are recycled back to gasification.

Description

Docket No. CHANM05WO

PATENT COOPERATION TREATY

APPLICATION

INTEGRATED UNDERGROUND COAL GASIFICA TIONAND A CID GAS REMOVAL CONFIGURATIONS

INVENTORS:

Michael Wailap Chan

1321 N. Carolan Ave

Burlingame, CA 94010

CITIZENSHIP: USA

John Mak

1321 N. Carolan Ave

Burlingame, CA 94010

CITIZENSHIP: USA

David Kim

1206 Star House

3 Salisbury Road

Kowloon, Hong Kong

CITIZENSHIP: Korea

INTEGRATED UNDERGROUND COAL GASIFICATION AND ACID GAS REMOVAL

CONFIGURATIONS

by Michael Wailap Chan, John Mak and David Kim

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims benefit of priority under 35 U.S.C. § 119(e) to United States provisional patent application number 61/531,054, filed Sept 5, 2011, which is incorporated herein by reference in its entirety for all purposes to the extent that such subject matter is not inconsistent herewith or limiting hereof.

Field of The Invention

The field of the invention is relating to hydrogen and carbon dioxide production from coal gasification, especially underground coal gasification, and configurations and methods in which H2S is removed in a Redox treating unit wherein the Redox solution is regenerated with oxygen and off gases are recycled back to gasification.

Background of The Invention

Coal is a heterogeneous source of energy, with quality (for example, characteristics such as heat, sulfur, and ash content) and heating value varying among different regions and even within individual coal seams. The quality spectrum of surface coal mines varies from the premium-grade bituminous coals, or coking coals, to the low-Btu lignite. Coal demands are generally met by surface mined coals. But as existing coal reserves are being depleted, other coal resources, such as underground coal must be developed. Underground coals are typically of lower quality and are inaccessible since they are typically located over 1 kilometer below the earth surface. The inaccessibility coupled with the lower quality render underground coal mining uneconomical. However, in-situ coal gasification is a viable option as it avoids the high cost of mining and transportation, and the elimination of solid wastes, such as ash and heavy metals, and gaseous emissions.

Underground coal reserves are typically located in remote areas, such as Inner Mongolia, where there is a lack of immediate usage of the gasified products. To be economically viable, underground gasification must be installed together with downstream production facilities, such as ammonia fertilizer plants, fuel oil refineries or power plants.

The other difficulty is that underground coal gasified products typically contain significant amounts of methane and other hydrocarbons and may contain sulfur, mercury and other contaminants. The syngas must be further processed and treated in acid gas removal units before it can be used for chemical or fuel gas production.

There are numerous acid gas removal methods that can be used to treat syngas. For example, a chemical solvent can be used that reacts with acid gas to form a (typically non- covalent) complex with the acid gas. In processes involving a chemical reaction between the acid gas and the solvent, syngas is typically scrubbed with an alkaline salt solution of a weak inorganic acid, for example, described in U.S. Pat. No. 3,563,695, or with alkaline solutions of organic acids or bases as, for example, described in U.S. Pat. No. 2,177,068. While chemical solvents are suitable to remove acid gases to very low levels, they require large heating and cooling duties which increase proportionally with the partial pressure of acid gases. Hence, the chemical solvent processes are generally uneconomical for treating syngas with high partial pressure of C02 (e.g., operating pressure greater than 600 psig).

Alternatively, physical solvent can be used to remove C02 since its acid gas absorption capacity increases with C02 partial pressure, according to Henry's law. The physical absorption of acid gases is further dependent upon the solvent's physical properties, pressures,

temperatures, and feed gas compositions. For example, methanol may be used as a low-boiling organic physical solvent, as exemplified in U.S. Pat. No. 2,863,527. However, such solvent operates at cryogenic temperature (-80°F) necessary to enhance absorption and reduce solvent losses. These processes typically require significantly higher horsepower to operate the refrigeration unit, which has very high capital and operating costs.

Other physical solvents are available that can be operated at ambient or mildly refrigerated temperatures (0°F or lower), including propylene carbonates as described in U.S. Pat. No. 2,926,751 and N-methylpyrrolidone or glycol ethers as described in U.S. Pat. No.

3,505,784. The selection of the physical solvent depends on the application requirements. For example, propylene carbonate is most suitable to remove C02 removal, but it is not H2S selective and cannot meet low H2S specifications (below 4 ppmv). In further known methods, physical solvents with higher H2S absorption capacity include ethers of polyglycols, and specifically dimethoxytetraethylene glycol as shown in U.S. Pat. No. 2,649,166, or N-substituted morpholine as described in U.S. Pat. No. 3,773,896. While use of the H2S selective solvents can be used to meet today's H2S specification, various difficulties still exist. Among other things, solvent circulation can be excessive and the power consumption can be very high. An exemplary known gas treatment configuration that employs a physical solvent is depicted in Prior Art Figure 1, in which coal slurry 1 is fed to gasifier 51 where it reacts with oxygen stream 2 generated from an air separation unit 50. Syngas stream 3, at 600 psig or higher pressure is quenched in a quench unit 52, forming a saturated syngas stream 4. The syngas typically contains about 20% C02 and 30%> H2 (dry basis). The syngas then undergoes the water shifted reaction in unit 53, which consists of a high temperature shift reactor and a low temperature shift reactor. The sour shift catalysts also convert most of the COS in the syngas to H2S. Waste heat from the shift reaction is used to generate steam while the syngas is cooled, forming stream 5. The shifted syngas is treated in H2S removal unit 54 followed by C02 removal unit 58.

A physical solvent is used for both H2S removal and C02 removal, which may include methanol (Rectisol) or DMEPG (Dimethyl ethylene poly-glycol) solvent. In the H2S removal unit, C02 loaded solvent stream 11 from the C02 removal section is used. The C02 loaded solvent is used in order to minimize C02 pickup in the H2S absorber. The unit typically includes an H2S enrichment section for concentrating the H2S content in the acid gas. The enrichment section requires additional solvent circulation and energy consumption. The acid gas stream 7 is required by the Claus sulfur plant to contain at least 25 mole % and preferably 30 mole % and higher H2S. The Claus sulfur plant produces sulfur stream 15 and tail gas stream 8. The tail gas unit 56 produces a H2S enriched stream 16 and a vent gas stream 9. The H2S rich stream is recycled back to the Claus sulfur plant, and the vent gas stream 9, containing about 100 ppmv to 500 ppmv sulfur content, is sent to the incineration unit 57 for destruction prior to venting to atmosphere as stream 10. It should be recognized that the tail gas treating unit solvent cannot effectively remove COS, which is one of the main contributor of sulfur oxides emissions in the acid gas removal units. C02 is removed in a C02 removal unit 58 using lean solvent 12 from the H2S removal section. To minimize energy conservation, a semi-lean solvent circuit is used in the C02 removal unit as the solvent can be partially regenerated by pressure letdown The C02 removal unit produces C02 stream 13 and a treated gas stream 14. Where carbon capture is not required, C02 is vented to the atmosphere. It should be recognized that in such configurations, physical solvent treating is limited by the equilibrium of the acid gases with the solvent. To meet today's stringent sulfur specifications, a very high solvent circulation is required, which tends to co-absorb significant amounts of C02, subsequently diluting the H2S content in the acid gas to the Claus sulfur plant.

Consequently, although many configurations and methods for H2S and C02 removal from syngas are known in the art, all or almost all of them suffer from various disadvantages. Thus, there is still a need to provide methods and configurations for H2S and C02 removal, especially for syngas from underground coal gasification.

Summary of the Invention

The present invention is directed to configurations and methods of treating syngas to remove acid gases, and especially to remove hydrogen sulfide and carbon dioxide from syngas from underground coal gasification. So treated syngas can be used in various manners (e.g., ammonia and fertilizer plants) and the carbon dioxide can be used for urea production or reinjected to the underground coal cavity for sequestration.

Most preferably, contemplated methods and plants are constructed in the following sequence per Figure 1 : underground gasifier 51 , partial oxidation 52, sour shifting and gas cooling 52, mercury removal 54, Redox treating 54, compressor 59 and C02 removal 60.

In particularly contemplated aspects, the air separation unit produces oxygen that is used in at least three different applications: oxidizing and regenerating the Redox chelate solution, controlling underground gasification and partial oxidation of the syngas from underground gasification. Nitrogen from the air separation plant is advantageously used in ammonia synthesis.

In one aspect of the inventive subject matter, a Redox (Reduction Oxidation) unit consists of a scrubbing step that removes H2S using an iron chelate solution to convert H2S to elemental sulfur. The catalytic solution is preferably regenerated by oxidizing with oxygen from the air separation plant. It should be appreciated that oxygen instead of air (of prior arts) provides a high partial pressure oxygen which significantly increases the regeneration reaction rate and produces a leaner solution. Subsequently, the amount of circulation to the treater can be significantly reduced.

In the most preferred configurations, the off-gas from the Redox oxidizer section is recovered and recycled back to underground gasification, thus eliminating the off-gas emissions of prior arts. It should be appreciated that the contemplated Redox unit has completely eliminated the Claus sulfur plant, the tail gas treating unit and the tail gas incinerator.

In the particularly contemplated aspects, the treated gas from the Redox treating unit is compressed in a compressor to at least 600 psig, and processed in a physical solvent unit and most typically, propylene carbonate is used for C02 removal. The solvent is preferably regenerated by pressure letdown and stripping with ambient air. C02 are produced at high pressures for urea production and C02 sequestration.

Where the syngas contains other heavy metal contaminants, such as mercury, it is generally preferred that a contaminant removal unit is used prior to the Redox treating unit such that the hydrogen product can meet specifications without further processing.

In the particularly configured ammonia synthesis plant, nitrogen is supplied from the air separation and mixed with the hydrogen from the C02 removal unit such that the H2 to N2 molar ratio is maintained at the stoichiometric ratio of 3.

In another aspect of the inventive subject matter, a syngas treatment plant will include an air separation unit that produces oxygen for a gasification unit, a partial oxidation unit and a Redox oxidation unit, wherein the gasification unit and partial oxidation are fluidly coupled to produce a syngas that is further shifted to produce more hydrogen. The syngas treating section preferably includes a mercury removal unit, a Redox treating unit and a C02 removal unit, wherein the Redox unit uses an iron chelated solution to selectively remove H2S to produce elemental sulfur and that the solution is regenerated by oxidation with oxygen supplied. In especially preferred aspects, the off gases from the Redox oxidizer is compressed and recycled back to the underground gasification. It is further contemplated that the treated syngas is compressed to a higher pressure and further treated for C02 removal unit using propylene carbonate solvent to produce higher purity hydrogen and C02 for the urea plant and C02 sequestration. Most preferably, the process can be integrated with an ammonia plant by adding stoichiometric nitrogen to the hydrogen as feed gas to the ammonia plant.

Various objects, features, aspects and advantages of the present invention will become apparent from the following detailed description of preferred embodiments of the invention. Brief Description of the Drawing

Figure 1 is an exemplary known configuration diagram of syngas acid gas removal of prior art.

Figure 2 is a configuration diagram of one exemplary H2S removal and C02 removal according to the inventive subject matter..

Figure 3 is an exemplary stream composition according to the inventive subject matter.

Detailed Description

The present invention is directed to plant configurations and methods for treatment of syngas gas comprising H2, C02, CO, H2S, and COS, in which hydrogen sulfide is removed in a first unit, and in which carbon dioxide is removed in a second unit. Contemplated sections include a Redox treating unit for H2S removal using an iron chelated and a physical solution unit for C02 removal, wherein hydrogen is produced and combined with nitrogen forming a stoichiometric feed gas to the ammonia plant.

In the especially configurations and methods of the Redox treating unit, a catalytic solution comprising at least one polyvalent metal (iron) chelated by at least one chelating agent performs oxidation of the H2S to elementary sulfur and concomitant reduction of the polyvalent metal from a higher oxidation level to a lower oxidation level. Subsequently, a syngas depleted in H2S and a reduced chelated solution containing elementary sulfur is produced.

H2S is removed by scrubbing the syngas in a contacting device by ferric and ferrous iron solutions (catalytic solutions), wherein the ferric and ferrous ions are complexed by suitable chelating agents such as polycarboxylic amino-acids. H2S in the syngas reacts with chelated ions according to the reaction equation 1 :

H2S + 2Fe (3+)→ S + 2H (+) + 2Fe (2+)

It should be noted that syngas with pressure at 300 psig or higher can be desulfurized using a Redox treating process, wherein the elemental sulfur can be filtered from the chelated solution in the form of a moist sulfur cake which can be further upgraded to a 99.9% pure molten sulfur product.

The reduced solution is regenerated by oxidizing the chelated ions by oxygen from the air separation plant, according to the reaction equation 2: 2Fe (2+) + 2H (+) + ½ 02→ 2Fe (3+) + H20

It should be appreciated that the use of a Redox unit for H2S removal is particularly advantageous, especially when the syngas contains a low level of H2S.

It should be appreciated that such configurations and methods will provide numerous advantages over prior arts, in terms of lower capital and operating costs. Most notably, a physical solvent designed for H2S and C02 removal, and traditional Claus sulfur plant and tail gas unit are not required.

One exemplary configuration for processing the syngas is depicted in Figure 2. The gas compositions of the major processing units are summarized in Figure 3. Syngas stream 1, typically at 200 to 400 psig and at 400 to 600°F is produced from underground coal gasification 51, using low purity oxygen stream 24 from air separation plant 50 and the recycled off-gas stream 11 from the Redox oxidizer. Typically, low purity oxygen (80% or lower) is sufficient here. The syngas product, stream 1, typically consisting of about 8 mole % CI and heavier hydrocarbons (see Figure 3), is processed in POX (partial oxidation) unit that converts its hydrocarbon contents to hydrogen, forming stream 2.

Stream 2 is processed in the sour shift unit 53. The CO content is shifted to form more hydrogen via the water shift reaction according to the following chemical reaction equation: CO + H20→ H2 + C02. The shift reactors also convert most of the COS to H2S according to the following reaction equation: COS + H20 <→ H2S + C02.

The shifted gas stream 3 are further treated in the mercury and contaminants removal unit 54 (heavy metals, such as Nickel), to typically less than 1 ppmv, or most typically less than 0.1 ppmv. Suitable removal materials may include those comprising carbon materials and/or nonspecific adsorbents (e.g., molecular sieves).

The mercury depleted syngas stream 4 is treated in the Redox treating unit 55 producing a H2S depleted stream 5 and a reduced chelated solution stream 6 containing the sulfur. Solid sulfur stream 9 is filtered out from the solution, and the Redox chelated solution is regenerated in the Redox oxidizer unit 56 by reacting with oxygen stream 23 from the air separation. It should be appreciated the use of pure oxygen (over 80%) is advantageously used to improve the efficiency of chelated solution regeneration. It should be recognized that the regeneration reaction rate for the chelant increases with oxygen partial pressure, which results in an improvement of the solution quality and reduction in solvent circulation. The regenerated solution 7 is pumped by solution pump 57 forming stream 8 and recycled to the Redox treater.

The off-gases from the oxidizer unit stream 10 is compressed by compressor 59 forming stream 11 and recycled back to the underground coal gasification. The sulfur depleted syngas stream 5, combining with recycle gas stream 12, is compressed to 600 psig or higher by compressor 59, forming stream 13 to feed the C02 removal unit 60. The C02 removal unit employs a physical solvent, most typically propylene carbonate, which has a C02 absorption high capacity and can be regenerated by pressure letdown, and by stripping with air stream 24. To minimize H2 losses, the high pressure flash gas stream 12 can be recycled back to the feed gas section for recovery. Typically, the unit is designed with at least two flash stages and hydraulic turbines for power recovery. At least two medium to high pressure stages, streams 13 and stream 14, are generated which reduce the power consumption by C02 compressor 61.

Subsequently, the syngas stream 19 from the C02 removal unit contains over 99% H2 which is mixed with an appropriate amount of nitrogen, stream 20, from the air separation plant forming stream 21 with a H2 to N2 stoichiometric ratio of 3 feeding the ammonia plant.

Thus, specific embodiments and applications of C02 and H2 production from syngas have been disclosed. It should be apparent, however, to those skilled in the art that many more modifications besides those already described are possible without departing from the inventive concepts herein. The inventive subject matter, therefore, is not to be restricted except in the spirit of the appended claims. Moreover, in interpreting both the specification and the claims, all terms should be interpreted in the broadest possible manner consistent with the context. In particular, the terms "comprises" and "comprising" should be interpreted as referring to elements, components, or steps in a non-exclusive manner, indicating that the referenced elements, components, or steps may be present, or utilized, or combined with other elements, components, or steps that are not expressly referenced.

Claims

CLAIMS lat is claimed is:

A plant comprising:

a gasification unit, preferably underground gasification, configured to produce a syngas; wherein a partial oxidation unit is used to further convert the hydrocarbon content in the syngas to produce H2 and CO; and a mercury removal unit to remove mercury and other undesirable contaminants; and

Redox treating unit fluidly coupled to receive syngas, wherein the H2S in the syngas is reduced to elemental sulfur in a chelated solution of a higher oxidation state; and chelated solution of a lower oxidation state is oxidized and regenerated using oxygen; wherein;

off gases are recycled back to the underground coal gasification.

The plant of claim 1 further comprising a C02 removal unit fluidly coupled to the Redox treating unit to receive the desulfurized syngas and is configured to absorb C02 from the desulfurized syngas producing a H2, using a physical solvent, preferably propylene carbonate.

The plant of claim 1 further comprising a sour shift unit that uses a high temperature shift reactor and a low temperature shift reactor to produce hydrogen.

The plant of claim 1 wherein the syngas is treated in a mercury removal bed to remove its mercury content and other contaminants.

The plant of claim 1 wherein 99% pure oxygen from the air separation plant is used to produce hydrogen from syngas, and for regenerating the reduced chelated solution in the Redox unit.

The plant of claim 1 wherein the C02 removal unit further produce high pressure flash gases that is fed to a C02 compressor for urea production and C02 sequestration.

The plant of claim 1 wherein the physical solvent can be regenerated by pressure reduction and stripping with air. The plant of claim 1 wherein hydrogen from the C02 removal unit is combined with nitrogen from the air separation plant in a stoichiometric ratio of 3 and fed to the ammonia synthesis plant

The plant of claim 1 wherein the C02 from the C02 removal unit is used as feedstock to the urea plant.