System for providing air flow to a sulfur recovery unit

A system includes a sulfur recovery unit including a thermal reactor having an acid gas inlet and an air inlet. The acid gas inlet is configured to receive a flow of acid gas, and the air inlet is configured to receive an air flow of pressurized air extracted from a gas turbine compressor of a gas turbine engine.

BACKGROUND OF THE INVENTION

The subject matter disclosed herein relates to a system for providing air flow to a sulfur recovery unit.

Fossil fuels, such as coal or petroleum, may be gasified for use in the production of electricity, chemicals, synthetic fuels, or for a variety of other applications. Gasification involves the incomplete combustion of a carbonaceous fuel with limited oxygen at a very high temperature to produce syngas, a fuel containing carbon monoxide and hydrogen, which enables higher efficiency and cleaner emissions than the fuel in its original state.

The gasification process may result in syngas containing undesirable levels of sulfur or other contaminants. A gas cleaning unit may serve to remove a portion of such contaminants prior to combustion of the syngas. For example, the gas cleaning unit may remove sulfur from the syngas in the form of acid gas containing hydrogen sulfide (H2S). The acid gas may be routed to a sulfur recovery unit (SRU) configured to convert the H2S into elemental sulfur. The conversion process may involve reacting the H2S with large quantities of heated and pressurized air within a thermal reactor. Unfortunately, generating the heated and pressurized air flow may utilize large quantities of energy, thereby decreasing the efficiency of the gasification process.

BRIEF DESCRIPTION OF THE INVENTION

In a first embodiment, a system includes a gas turbine compressor configured to provide a flow of pressurized air to a combustor. The system further includes a sulfur recovery unit including a thermal reactor, and an extraction air line extending between the gas turbine compressor and the sulfur recovery unit. The extraction air line routes a portion of the pressurized air from the gas turbine compressor to the thermal reactor.

In a second embodiment, a sulfur recovery unit including a thermal reactor having an acid gas inlet and an air inlet. The acid gas inlet is configured to receive a flow of acid gas, and the air inlet is configured to receive an air flow of pressurized air extracted from a gas turbine compressor of a gas turbine engine.

In a third embodiment, a system includes a gas turbine engine including a gas turbine compressor. The system also includes an air separation unit configured to receive pressurized air extracted from the gas turbine compressor via a conduit extending between the gas turbine compressor and the air separation unit. The system further includes a sulfur recovery unit configured to extract a portion of the pressurized air from the conduit.

DETAILED DESCRIPTION OF THE INVENTION

Embodiments of the present disclosure may increase the efficiency of a gasification process by providing air extracted from a gas turbine compressor to a thermal reactor of a sulfur recovery unit (SRU). Certain SRUs include blowers and a heat exchanger configured to provide the thermal reactor with a flow of heated and pressurized air. Operation of the blowers utilizes electrical energy which decreases the efficiency of the gasification process. Furthermore, the heat exchanger may be configured to transfer heat from a steam source to the air provided by the blowers before the air enters the thermal reactor. As will be appreciated, transferring heat to the blower air decreases the temperature of the steam. Therefore, the steam contains less energy that may be utilized for other operations within a power generation plant, such as driving a steam turbine. Consequently, the efficiency of the gasification and/or power generation processes may be further reduced.

The present embodiments are configured to obviate the steam-to-air heat exchanger, and reduce the number of blowers providing air to the thermal reactor. Specifically, certain power generation plants include a gas turbine engine, including a gas turbine compressor configured to provide a flow of pressurized air to a combustor. In the present embodiments, a portion of the pressurized air is extracted from the gas turbine compressor and is provided to the thermal reactor of the SRU. In this manner, the number of blowers may be reduced as compared to configurations in which air flow is only provided by the blowers. Consequently, the efficiency of the gasification process may be increased due to the reduction in blower power consumption. Furthermore, the reduction in the number of blowers may decrease maintenance costs and reduce the space utilized by the SRU.

In addition, the steam-to-air heat exchanger may be omitted because the air flow provided by the gas turbine compressor has been heated by the compressor process. Consequently, the efficiency of the gasification process may be enhanced because the heated air may obviate the heat exchanger. Specifically, without the steam-to-air heat exchanger, the temperature of the steam may be maintained, thereby increasing the energy content of the steam. As will be appreciated, because the steam may be utilized to drive a steam turbine for energy generation, increasing the energy content of the steam results in greater steam turbine power output. Furthermore, omission of the heat exchanger may decrease maintenance costs and reduce space utilized by the SRU due to the reduction in SRU components.

FIG. 1is a schematic block diagram showing an embodiment of a power generation plant10. The illustrated power generation plant10may be an integrated gasification combined cycle (IGCC) system10that may produce and burn a synthetic gas, i.e., syngas. Elements of the IGCC system10may include a fuel source12, such as a solid feed, that may be utilized as a source of energy for the IGCC system10. The fuel source12may include coal, petroleum coke, biomass, wood-based materials, agricultural wastes, tars, coke oven gas, and asphalt, or other carbon containing items.

The solid fuel of the fuel source12may be passed to a feedstock preparation unit14. The feedstock preparation unit14may, for example, resize or reshaped the fuel source12by chopping, milling, shredding, pulverizing, briquetting, or palletizing the fuel source12to generate feedstock. Additionally, water, or other suitable liquids may be added to the fuel source12in the feedstock preparation unit14to create slurry feedstock. In other embodiments, no liquid is added to the fuel source, thus yielding dry feedstock.

The feedstock prepared by the feedstock preparation unit14may be passed to a gasifier16. The gasifier16may convert the feedstock into syngas, e.g., a combination of carbon monoxide and hydrogen. This conversion may be accomplished by subjecting the feedstock to a controlled amount of any moderator and oxygen at elevated pressures (e.g., from approximately 600 PSIG-1200 PSIG) and temperatures (e.g., approximately 2200° F.-2700° F.), depending on the type of gasifier utilized. The heating of the feedstock during a pyrolysis process may generate a solid (e.g., char) and residue gases (e.g., carbon monoxide, hydrogen, and nitrogen). The char remaining from the feedstock from the pyrolysis process may only weigh up to approximately 30% of the weight of the original feedstock.

The combustion reaction in the gasifier16may include introducing oxygen to the char and residue gases. The char and residue gases may react with the oxygen to form carbon dioxide and carbon monoxide, which provides heat for the subsequent gasification reactions. The temperatures during the combustion process may range from approximately 2200° F. to approximately 2700° F. In addition, steam may be introduced into the gasifier16. The gasifier16utilizes steam and limited oxygen to allow some of the feedstock to be burned to produce carbon monoxide and energy, which may drive a second reaction that converts further feedstock to hydrogen and additional carbon dioxide.

In this way, a resultant gas may be manufactured by the gasifier16. The resultant gas may include approximately 85% of carbon monoxide and hydrogen, as well as CH4, HCl, HF, COS, NH3, HCN, and H2S (based on the sulfur content of the feedstock). This resultant gas may be termed “raw syngas.” The gasifier16may also generate waste, such as a slag18, which may be a wet ash material.

In certain embodiments (e.g., carbon capture cases), the dirty syngas may be passed on to a water-gas shift (WGS) reactor20to obtain a high hydrogen yield. The WGS reactor20may perform a water-gas shift reaction in which carbon monoxide reacts with water, (e.g., steam), to form carbon dioxide and hydrogen. This process may adjust the ratio of hydrogen to carbon monoxide in the raw syngas from approximately 1 to 1 to approximately 3 to 1, based on a desired level of carbon capture, for further gas processing. It should be noted that the WGS reactor20may be a sour WGS reactor, that is, sulfur may be present in the raw syngas fed into the WGS reactor20during the water-gas shift reaction.

A gas cleaning unit22may be utilized to clean the raw syngas. The gas cleaning unit22may scrub the raw syngas to remove the HCl, HF, COS, HCN, and H2S from the raw syngas, which may include the separation of H2S by an acid gas removal process. Elemental sulfur24may by recovered by a sulfur recovery unit26from the H2S. Furthermore, the gas cleaning unit22may separate salts30from the raw syngas via a water treatment unit32, which may utilize water purification techniques to generate usable salts30from the raw syngas. Subsequently, a clean syngas may be generated from the gas cleaning unit22.

A gas processor34may be utilized to remove residual gas components36from the clean syngas, such as ammonia and methane, as well as methanol or other residual chemicals. However, removal of residual gas components36from the clean syngas is optional since the clean syngas may be utilized as a fuel even when containing the residual gas components36(e.g., tail gas). At this point, the clean syngas may include approximately 3%-40% CO, approximately up to 60% H2, and approximately 10%-40% CO2, and may be substantially stripped of H2S. This clean syngas may be directed into a combustor38(e.g., a combustion chamber) of a gas turbine engine40as combustible fuel.

The IGCC system10may include an air separation unit (ASU)28to separate air into component gases using, for example, cryogenic distillation techniques. The ASU28may separate oxygen from the air supplied to it from a main air compressor (MAC)42and may transfer the separated oxygen to the gasifier16. Additionally, the ASU28may direct separated nitrogen to a diluent nitrogen (DGAN) compressor44. The DGAN compressor44may compress the nitrogen received from the ASU28at least to pressure levels equal to those in the combustor38, enabling injection into the combustion chamber. Thus, once the DGAN compressor44has adequately compressed the nitrogen to an adequate level, the DGAN compressor44may direct the compressed nitrogen to the combustor38of the gas turbine engine40.

As described above, the compressed nitrogen may be transferred from the DGAN compressor44to the combustor38of the gas turbine engine40. The gas turbine engine40may include a turbine46, a drive shaft48, and a compressor50, as well as the combustor38. The combustor38may receive fuel, such as the syngas, which may be injected under pressure from fuel nozzles. This fuel may be mixed with compressed air as well as compressed nitrogen from the DGAN compressor44and combusted within the combustor38. This combustion may create hot pressurized exhaust gases.

The combustor38may direct the exhaust gases towards an exhaust outlet of the turbine46. As the exhaust gases from the combustor38pass through the turbine46, the exhaust gases may force turbine blades in the turbine46to rotate the drive shaft48along an axis of the gas turbine engine40. As illustrated, the drive shaft48may be connected to various components of the gas turbine engine40, including the compressor50.

The drive shaft48may connect the turbine46to the compressor50to form a rotor. The compressor50may include blades coupled to the drive shaft48. Thus, rotation of turbine blades in the turbine46may cause the drive shaft48connecting the turbine46to the compressor50to rotate blades within the compressor50. The rotation of blades in the compressor50causes the compressor50to compress air received via an air intake in the compressor50. The compressed air may then be fed to the combustor38and mixed with fuel and compressed nitrogen to allow for higher efficiency combustion. The drive shaft48may also be connected to a load52, which may be a stationary load, such as an electrical generator, for producing electrical power in a power plant. Indeed, the load52may be any suitable device that is powered by the rotational output of the gas turbine engine40.

In the present embodiment, the gas turbine compressor50also provides a flow of air to the ASU28to supplement the MAC42. Specifically, air may be extracted from the last stage of the compressor50and routed to the ASU28via an extraction air line or conduit53. In certain configurations, approximately 5 to 50, 10 to 40, 10 to 35, or about 10 to 30 percent of the total air flow from the gas turbine compressor50may be extracted for use in the ASU28. Furthermore, a portion of the air flow from the compressor50to the ASU28may be routed to the SRU26via a conduit55. In certain embodiments, approximately between 2 to 13, 3 to 12, 4 to 11, or about 5 to 10 mole percent of the air flow through the compressor-to-ASU conduit53may be routed through the conduit55to the SRU26. In alternative configurations, a separate conduit may route the air flow directly from the compressor50to the SRU26.

As discussed in detail below, the SRU26is configured to react acid gas with oxygen in a thermal reactor to form elemental sulfur24. In the present configuration, at least a portion of the oxygen may be provided by the air flow extracted from the gas turbine compressor50. Such a configuration may increase the efficiency of the IGCC system10compared to embodiments in which the oxygen is supplied by blowers. Specifically, because blowers utilize energy to provide an air flow to the thermal reactor, reducing the number of blowers may increase the total energy output of the IGCC system10. Furthermore, air from the blowers may be heated within a steam-to-air heat exchanger prior to entering the thermal reactor. Because the air extracted from the gas turbine compressor50has already been heated by the compressor process, the heat exchanger may be omitted. Consequently, the energy content of the steam may be maintained, thereby further increasing the IGCC system efficiency. Moreover, reducing the number of blowers and/or omitting the heat exchanger may decrease the space utilized by the SRU26and/or reduce maintenance costs.

The IGCC system10also may include a steam turbine engine54and a heat recovery steam generation (HRSG) system56. The steam turbine engine54may drive a second load58, such as an electrical generator for generating electrical power. However, both the first and second loads52and58may be other types of loads capable of being driven by the gas turbine engine40and the steam turbine engine54, respectively. In addition, although the gas turbine engine40and the steam turbine engine54may drive separate loads52and58, as shown in the illustrated embodiment, the gas turbine engine40and the steam turbine engine54may also be utilized in tandem to drive a single load via a single shaft. The specific configuration of the steam turbine engine54, as well as the gas turbine engine40, may be implementation-specific and may include any combination of sections.

Heated exhaust gas from the gas turbine engine40may be directed into the HRSG56and used to heat water and produce steam used to power the steam turbine engine54. Exhaust from the steam turbine engine54may be directed into a condenser60. The condenser60may utilize a cooling tower62to completely condense steam from the steam turbine discharge. In particular, the cooling tower62may provide cool water to the condenser60to aid in condensing the steam directed into the condenser60from the steam turbine engine54. Condensate from the condenser60may, in turn, be directed into the HRSG56. Again, exhaust from the gas turbine engine40may also be directed into the HRSG56to heat the water from the condenser60and produce steam.

As such, in combined cycle systems such as the IGCC system10, hot exhaust may flow from the gas turbine engine40to the HRSG56, where it may be used to generate high-pressure, high-temperature steam. The steam produced by the HRSG56may then be passed through the steam turbine engine54for power generation.

FIG. 2is a block diagram of a first embodiment of the SRU26, as shown inFIG. 1, in which air extracted from the gas turbine compressor50is mixed with air from a blower prior to injection into the thermal reactor. As illustrated, acid gas from the gas cleaning unit22first enters a heat exchanger64. The heat exchanger64is configured to increase a temperature of the acid gas prior to the acid gas flowing into a thermal reactor66and/or a catalytic reactor68. As will be appreciated, increasing the acid gas temperature may facilitate enhanced chemical reactions within the thermal reactor66and/or the catalytic reactor68. In the present embodiment, a portion of the air extracted from the gas turbine compressor50and routed to the SRU26is provided to the heat exchanger64. The heat exchanger64, in turn, transfers heat from the extraction air to the acid gas flowing into the thermal reactor66and/or the catalytic reactor68. For example, air extracted from the gas turbine compressor50may be approximately between 300 to 1200, 400 to 1000, or about 500 to 800 degrees Fahrenheit. Consequently, the heat exchanger64may be configured to transfer a desired quantity of the heat from the extraction air to the acid gas to properly regulate the reactions within the thermal reactor66and/or the catalytic reactor68. Such a configuration may increase efficiency of the IGCC system10compared to embodiments in which steam is utilized to heat the acid gas. Specifically, by heating the acid gas with extraction air instead of steam, the energy content of the steam may be maintained for driving the steam turbine54, thereby increasing the total power output of the system10.

As illustrated, the acid gas flows from the heat exchanger64to an acid gas inlet of the thermal reactor66. In the present embodiment, the thermal reactor66converts the acid gas into elemental sulfur by a Claus process. In the Claus process, hydrogen sulfide (H2S) within the acid gas reacts with oxygen in the thermal reactor66to produce sulfur dioxide (SO2). The SO2then reacts with residual H2S to produce elemental sulfur and water (H2O). In this manner, H2S is removed from the acid gas, and the elemental sulfur is collected. Specifically, exhaust gas from the thermal reactor66, including elemental sulfur and residual H2S and SO2, flows into a condenser70in which the elemental sulfur within the exhaust gas is condensed and routed to the sulfur storage container24. The remaining exhaust gas flows into a reheater72, in which a temperature of the exhaust gas is increased prior to flowing into the catalytic reactor68. In the present embodiment, a portion of the air extracted from the gas turbine compressor50and routed to the SRU26is provided to the reheater72. The reheater72, in turn, transfers heat from the extraction air to the exhaust gas from the thermal reactor66. For example, air extracted from the gas turbine compressor50may be approximately between 300 to 1200, 400 to 1000, or about 500 to 800 degrees Fahrenheit. Consequently, the reheater72may be configured to transfer a desired quantity of the heat from the extraction air to the exhaust gas to properly regulate the reaction within the catalytic reactor68. Such a configuration may increase efficiency of the IGCC compared to embodiments in which steam is utilized to reheat the thermal reactor exhaust gas. Specifically, by heating the exhaust gas with extraction air instead of steam, the energy content of the steam may be maintained for driving the steam turbine54, thereby increasing the total power output of the system10.

As previously discussed, the exhaust gas includes residual H2S and SO2that may be removed by the catalytic reactor68before the gas is returned to the gas cleaning unit22. As will be appreciated, the catalytic reactor68may contain a catalyst, such as aluminum oxide and/or titanium dioxide, configured to induce the residual H2S and SO2to react and produce elemental sulfur and water. Consequently, the quantity of H2S within the acid gas may be substantially reduced by the catalytic reactor68alone, or in combination with the thermal reactor66.

As illustrated, the extraction air flows in parallel to the heat exchanger64and the reheater72. Specifically, a portion of the air extracted from the gas turbine compressor50is split between the reheater72and the heat exchanger64. As will be appreciated, the ratio of reheater air flow to heat exchanger air flow may be particularly selected and/or variable based on desired heat flow to the acid gas and the thermal reactor exhaust gas. Furthermore, after the extraction air has passed through the reheater72and the heat exchanger64, the air is directed back to the conduit55. As will be appreciated, the overall temperature of the air within the conduit55will be reduced due to heat loss from the reheater72and the heat exchanger64.

In the present embodiment, the SRU26includes an expansion device, such as the illustrated expansion valve74. The expansion valve74is configured to decrease the pressure of the air provided by the gas turbine compressor50. For example, air upstream of the expansion valve74may be approximately between 100 to 600, 125 to 500, 150 to 400, or about 175 to 300 psi. The expansion valve74is configured to reduce the pressure of the airflow to a pressure suitable for use in the thermal reactor66. For example, in certain configurations, the pressure of the airflow may be reduced to approximately between 5 to 200, 10 to 150, 15 to 125, 20 to 100, or about 25 to 75 psi. As will be appreciated, decreasing the pressure of the airflow also decreases the temperature of the airflow. For example, as previously discussed, the air upstream of the expansion valve74may be approximately between 300 to 1200, 400 to 1000, or about 500 to 800 degrees Fahrenheit. The pressure decrease caused by the expansion valve74may induce the air temperature to decrease to approximately between 100 to 1000, 200 to 900, or about 300 to 800 degrees Fahrenheit. However, as discussed in detail below, the temperature of the air flow is sufficient to obviate a separate heat exchanger for increasing the temperature of the air flowing into the thermal reactor66.

In the present embodiment, the air flow from the gas turbine compressor50is mixed with additional oxygen sources before flowing into an air inlet of the thermal reactor66. Specifically, the air flow may be mixed with a supply of oxygen from the ASU28. As previously discussed, the ASU28is configured to separate air into nitrogen and oxygen. A fraction of the oxygen may be routed to the SRU26and mixed with the extraction air downstream from the expansion valve74to increase the oxygen content of the air supplied to the thermal reactor66. Furthermore, additional air may be provided by one or more blowers76. As will be appreciated, the quantity of air supplied to the thermal reactor66may be a function of the quantity of acid gas injected into the thermal reactor66. Specifically, a sufficient quantity of air may be provided to the thermal reactor66to properly react the H2S in the Claus process. For example, during periods when large quantities of acid gas are being injected into the thermal reactor66, additional air may be supplied. The blowers76may be configured to vary an air flow rate to properly supply the thermal reactor66with a sufficient quantity of air to maintain a proper reaction within the thermal reactor66. For example, during startup periods, the air supplied by the gas turbine compressor50may be insufficient to properly react the acid gas within the thermal reactor66. Consequently, air flow from the blowers76may be increased to compensate.

However, during normal operation, providing extraction air to the thermal reactor66may substantially reduce or eliminate air flow from the blowers76, thereby decreasing the energy utilized by the SRU26. As will be appreciated, decreasing air flow to the ASU28by routing a portion of the extraction air to the SRU26may increase the load on the MAC42. However, because the MAC42may be more efficient to operate than the blowers76, the present embodiment may decrease overall energy utilization compared to embodiments that only supply air flow to the thermal reactor66via the blowers76. Furthermore, because a portion of the air flow is provided by air extracted from the gas turbine compressor50, the number of blowers76may be reduced. For example, embodiments that provide air to the thermal reactor66via blowers76alone may utilize 3 to 8, 3 to 6, or about 4 blowers76. The present embodiment may reduce the number of blowers76to two or less. The reduction in number of blowers76may decrease maintenance costs and reduce the space utilized by the SRU26.

As will be appreciated, the temperature of the air provided to the thermal reactor66may be a function of H2S concentration within the acid gas. For example, the acid gas may contain approximately 20% to 50%, 25% to 45%, 30% to 40%, or about 35% H2S. For example, if the H2S concentration is approximately 35%, the temperature of incoming air may be approximately 300 to 450 degrees Fahrenheit to properly react the acid gas and air within the thermal reactor66. Consequently, embodiments that employ blowers76alone may utilize a steam-to-air heat exchanger to increase the temperature of air provided to the thermal reactor66. In contrast, the illustrated embodiment mixes air from the blowers76with the hot pressurized air from the gas turbine compressor50. As will be appreciated, during the mixing process, heat from the extraction air is transferred to the blower air, thereby increasing the temperature of the mixture to a level suitable for use in the thermal reactor66. Consequently, the heat exchanger employed in embodiments that provide air from blowers76alone may be obviated. As a result, the utilized space and maintenance costs associated with the SRU26may be reduced compared to embodiments including the extra heat exchanger. Furthermore, because steam is not utilized to heat the air flow within the heat exchanger, the energy content of the steam may be maintained for driving the steam turbine54, thereby increasing the total power output of the system10. In addition, the temperature of the mixed air flow may be greater than air temperatures provided by the steam-to-air heat exchanger. Consequently, the higher temperatures may facilitate increased flame stability within the thermal reactor66.

FIG. 3is a block diagram of an alternative embodiment of the SRU26in which air extracted from the gas turbine compressor50is utilized to heat air from the blowers76prior to injection into the thermal reactor66. Specifically, the illustrated embodiment includes a second heat exchanger78configured to transfer heat from the extraction air to the air provided by the blowers76. As illustrated, the air extracted from the gas turbine compressor50mixes with additional oxygen downstream from the expansion valve74, and the mixture flows into the thermal reactor66. Air from the blowers76is directed through the heat exchanger78before entering the thermal reactor66. In this configuration, the air from the blowers76does not mix with the extraction air prior to entering the thermal reactor66. Similar to the first embodiment, the extraction air flows in parallel to the heat exchangers64and78, and the reheater72. Specifically, a portion of the air extracted from the gas turbine compressor50is directed to each heat exchanger64and78, and the reheater72via separate flow passages. As illustrated, the air for the heat exchangers64and78, and the reheater72, is extracted upstream of the expansion valve74. After flowing through the heat exchangers64and78, and the reheater72, the air is returned to the conduit55before entering the expansion valve74.

The present configuration may increase efficiency of the IGCC system10compared to embodiments that employ a heat exchanger configured to transfer heat from steam to the air provided by the blowers76. Specifically, without the steam-to-air heat exchanger, the temperature of the steam will not be reduced, thereby increasing the energy content of the steam. As will be appreciated, because the steam may be utilized to drive the steam turbine54, increasing the energy content of the steam results in greater steam turbine power output. Furthermore, as previously discussed, utilizing air extracted from the gas turbine compressor50as an oxygen source within the thermal reactor66substantially reduces or eliminates the load on the blowers76, thereby further increasing efficiency of the IGCC system10.