Abstract:
Methods and systems for handling sour carbon dioxide (CO 2 ) streams are provided. In one aspect, a method for sequestering an emissions-heavy gas includes removing at least a portion of an acid gas from a rich solvent in an acid gas stripper to create the emissions-heavy gas, and channeling the emissions-heavy gas to a storage system.

Description:
BACKGROUND OF THE INVENTION 
       [0001]    This invention relates generally to gasification systems and, more particularly, to systems and methods for capturing a rich carbon dioxide (CO 2 ) stream produced by gasification systems. 
         [0002]    At least some known gasification systems, such as those used in power plants, are integrated with at least one power-producing turbine system, thereby forming an integrated gasification combined-cycle (IGCC) power generation system. For example, at least some known gasification systems convert a mixture of fuel, air or oxygen (O 2 ), steam, and/or carbon dioxide (CO 2 ) into a synthetic gas, or “syngas.” The syngas is channeled to the combustor of a gas turbine engine, which powers a generator that supplies electrical power to a power grid. Exhaust from at least some known gas turbine engines is supplied to a heat recovery steam generator that generates steam for driving a steam turbine. Power generated by the steam turbine also drives an electrical generator that provides electrical power to the power grid. 
         [0003]    At least some known gasification systems associated with IGCC systems initially produce a “raw” syngas fuel includes carbon monoxide (CO), hydrogen (H 2 ), hydrogen sulfide (H 2 S), and/or carbon dioxide (CO 2 ). Hydrogen sulfide is commonly referred to as an acid gas. Acid gases are generally removed from the raw syngas fuel to produce a “clean” syngas fuel used for combustion within the gas turbine engines. At least some known acid gas removal is performed with an acid gas removal subsystem that includes at least one main absorber that removes a majority of the H 2 S. 
         [0004]    At least some known gasification systems also include at least one sulfur recovery unit (SRU) that recovers sulfur from the acid gas. Tail gas produced by the SRU is compressed and/or recycled to a gasification reactor using a tail gas unit (TGU). However, such a sulfur recovery system, including the SRU and TGU, represents a significant portion of the capital cost of an IGCC system. Moreover, when an IGCC power plant incorporates pre-combustion CO 2  separation and purification systems, a significant additional capital cost is incurred. 
       BRIEF DESCRIPTION OF THE INVENTION 
       [0005]    In one aspect, a method for sequestering an emissions-heavy gas includes removing at least a portion of an acid gas from a rich solvent in an acid gas stripper to create the emissions-heavy gas, and channeling the emissions-heavy gas to a storage system. 
         [0006]    In another aspect, a method for removing carbon dioxide (CO 2 ) from gases produced by a power system is provided. The method includes removing at least a portion of an acid gas from a rich solvent in an acid gas stripper to create a CO 2  stream, pressurizing at least a portion of the CO 2  stream, and channeling the pressurized CO 2  stream to one of a saline aquifer and an enhanced oil recovery field. 
         [0007]    In another aspect, a gas treatment system for use with a power system is provided. The gas treatment system includes an acid gas stripper configured to remove at least a portion of an acid gas from a rich solvent to create a CO 2  stream. The gas treatment system also includes a compressor coupled in flow communication downstream from the acid gas stripper, wherein the compressor is configured to pressurize the CO 2  stream. The gas treatment system also includes a carbon dioxide (CO 2 ) sequestration system coupled in flow communication downstream from the compressor, wherein the compressor is further configured to channel at least a portion of the pressurized CO 2  stream to the CO 2  sequestration system. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0008]      FIG. 1  is a schematic diagram of an exemplary integrated gasification combined-cycle (IGCC) power system; 
           [0009]      FIG. 2  is a schematic of an exemplary acid gas removal subsystem that can be used with the IGCC power generation system shown in  FIG. 1 ; and 
           [0010]      FIG. 3  is a schematic of an alternative acid gas removal subsystem that can be used with the IGCC power generation system shown in  FIG. 1 . 
       
    
    
     DETAILED DESCRIPTION OF THE INVENTION 
       [0011]    As used herein, the term “lean” is used to describe a solvent that is substantially emissions free, and the term “rich” is used to describe a solvent containing emissions. Similarly, the term “emissions-heavy” is used to describe a gas that contains emissions. 
         [0012]      FIG. 1  is a schematic diagram of an exemplary integrated gasification combined-cycle (IGCC) power generation system  100 , such as those used in power plants. In the exemplary embodiment, IGCC system includes a gas turbine engine  110 . Turbine  114  is rotatably coupled to a first electrical generator  118  via a first rotor  120 . Turbine  114  is coupled in flow communication with at least one fuel source and at least one air source (both described in more detail below) and is configured to receive the fuel and air from the fuel source and the air source, respectively. Turbine  114  produces rotational energy that is transmitted to generator  118  via rotor  120 , wherein generator  118  converts the rotational energy to electrical energy for transmission to at least one load, including, but not limited to, an electrical power grid (not shown). 
         [0013]    IGCC system  100  also includes a steam turbine engine  130 . In the exemplary embodiment, engine  130  includes a steam turbine  132  that is rotatably coupled to a second electrical generator  134  via a second rotor  136 . 
         [0014]    IGCC system  100  also includes a steam generation system  140 . In the exemplary embodiment, system  140  includes at least one heat recovery steam generator (HRSG)  142  that is coupled in flow communication with at least one heat transfer apparatus  144  via at least one heated boiler feedwater conduit  146 . HRSG  142  receives boiler feedwater (not shown) from apparatus  144  via conduit  146  for heating the boiler feedwater into steam. HRSG  142  also receives exhaust gases (not shown) from turbine  114  via an exhaust gas conduit (not shown) that also heats the boiler feedwater into steam. HRSG  142  is coupled in flow communication with turbine  132  via a steam conduit  150 . Excess gasses and steam are exhausted from HRSG  142  to the atmosphere via stack gas conduit  152 . 
         [0015]    Steam conduit  150  channels steam from HRSG  142  to turbine  132 . Turbine  132  receives the steam from HRSG  142  and converts the thermal energy in the steam to rotational energy. The rotational energy is transmitted to generator  134  via rotor  136 , wherein generator  134  converts the rotational energy to electrical energy for transmission to at least one load, including, but not limited to, an electrical power grid. 
         [0016]    IGCC system  100  also includes a gasification system  200 . In the exemplary embodiment, system  200  includes at least one air separation unit  202  that is coupled in flow communication with an air source via an air conduit  204 . In the exemplary embodiment, such air sources include, but are not limited to only including, dedicated air compressors and/or compressed air storage units (neither shown). Air separation unit  202  separates air into oxygen (O 2 ), nitrogen (N 2 ) and other components that are released via a vent (not shown). The nitrogen is channeled to gas turbine  114  to facilitate combustion. 
         [0017]    System  200  includes a gasification reactor  208  that is coupled in flow communication with air separation unit  202  to receive the O 2  channeled from unit  202  via a conduit  210 . System  200  also includes a coal grinding and preparation unit  211 . Unit  211  is coupled in flow communication with a coal source and a water source (neither shown) via a coal supply conduit  212  and a water supply conduit  213 , respectively. In an alternative embodiment, the water supply and water supply conduit  213  are not present. Unit  211  may be configured to handle dry or moist feed system and/or to mix coal and water together to form a coal slurry stream (not shown) that is channeled to gasification reactor  208  via a conduit  214 . 
         [0018]    Gasification reactor  208  receives the coal slurry stream and an oxygen stream via conduits  214  and  210 , respectively. Gasification reactor  208  facilitates the production of a hot, raw synthetic gas (syngas) stream. Moreover, gasification reactor  208  also produces a hot slag stream as a by-product of the syngas production. The slag stream is channeled to a slag handling unit  215  via a hot slag conduit  216 . Slag handling unit  215  quenches and breaks up the slag into smaller pieces that form a stream that may be removed and channeled through slag conduit  217 . In an alternative embodiment, unit  215  recovers soot from solids to facilitate improving gasifier efficiency. The recovered soot returns to gasifier  208  through a conduit (not shown) and substantially soot-free slag is disposed through conduit  217 . 
         [0019]    Gasification reactor  208  is coupled in flow communication with heat transfer apparatus  144  via a hot syngas conduit  218 . Heat transfer apparatus  144  receives the hot, raw syngas stream and transfers at least a portion of its heat to HRSG  142  via conduit  146 . Subsequently, heat transfer apparatus  144  produces a cooled raw syngas stream that is channeled to a scrubber and low temperature gas cooling (LTGC) unit  221  via a syngas conduit  219 . LTGC  221  removes particulate matter entrained within the raw syngas stream and facilitates the removal of the particulate matter via a fly ash conduit  222 . LTGC  221  also provides cooling to the raw syngas stream. 
         [0020]    Gasification system  200  also includes an acid gas removal subsystem  300  that is coupled in flow communication with LTGC  221 . Subsystem  300  receives the cooled raw syngas stream via a raw syngas conduit  220 . Moreover, acid gas removal subsystem  300  facilitates the removal of at least a portion of acid components from the raw syngas stream. In the exemplary embodiment, such acid gas components include, but are not limited to, H 2 S and CO 2 . Acid gas removal subsystem  300  also facilitates the separation of at least some of the acid gas components into other components such as, but not limited to, H 2 S and CO 2 . Acid gas removal subsystem  300  is coupled in flow communication with gasification reactor  208  via conduit  224 . Conduit  224  channels the final integrated gas stream to predetermined portions of gasification reactor  208 . The separation and removal of CO 2  and H 2 S via acid gas removal subsystem  300  produces a clean syngas stream that is channeled to gas turbine  114  via a clean syngas conduit  228 . 
         [0021]    Moreover, in the exemplary embodiment, acid gas removal subsystem  300  is coupled in flow communication with a compressor  400  via a conduit  334 , such that at least a portion of the H 2 S and CO 2  stream is channeled via acid gas removal subsystem  300  to compressor  400 . In one embodiment, compressor  400  is a compression system that includes at least one compression stage. Compressor  400  compresses the H 2 S and CO 2  stream to a predetermined pressure. In one embodiment, compressor  400  compresses the H 2 S and CO 2  stream to a supercritical pressure. In alternative embodiments, compressor  400  compresses the H 2 S and CO 2  stream to different predetermined pressure levels. Compressor  400  channels the compressed H 2 S and CO 2  streams to a sequestration system  500  such as, but not limited to, enhanced oil recovery and/or a saline aquifer. 
         [0022]    During operation, air separation unit  202  receives air via conduit  204 . The air is separated into O 2 , N 2 , and other components that are vented via a vent. The nitrogen is channeled to turbine  114  via conduit  206  and the oxygen is channeled to gasification reactor  208  via conduit  210 . Also, in operation, coal grinding and preparation unit  211  receives coal and water via conduits  212  and  213 , respectively, wherein the resulting coal slurry stream is channeled to gasification reactor  208  via conduit  214 . 
         [0023]    Gasification reactor  208  receives oxygen via conduit  210 , coal via conduit  214 , and the final integrated gas stream from acid gas removal subsystem  300  via conduit  224 . Reactor  208  produces a hot raw syngas stream that is channeled to apparatus  144  via conduit  218 . Any slag by-product formed in reactor  208  is removed via slag handling unit  215  and conduits  216  and  217 . In an alternative embodiment, slag handling unit  215  recovers soot and recycles it to gasifier  208  through a conduit (not shown). Apparatus  144  cools the raw syngas stream to produce a cooled raw syngas stream that is channeled to scrubber and LTGC unit  221  via conduit  219 . Within scrubber and LTGC  221 , particulate matter is removed from the syngas via conduit  222  and the syngas is further cooled. The cooled raw syngas stream is channeled to acid gas removal subsystem  300  wherein acid gas components are substantially removed to form a clean syngas stream that may be channeled to gas turbine  114  via conduit  228 . 
         [0024]    Moreover, during operation, turbine  114  receives nitrogen and clean syngas via conduits  206  and  228 , respectively. Turbine  114  combusts the syngas fuel, produces hot combustion gases, and channels the hot combustion gases to induce rotation of turbine  114 . 
         [0025]    At least a portion of the heat removed from the hot syngas via heat transfer apparatus  144  is channeled to HRSG  142  via conduit  146  wherein the heat facilitates the formation of steam. The steam is channeled to, and causes rotation of, steam turbine  132  via conduit  150 . Turbine  132  rotates second generator  134  via second rotor  136 . 
         [0026]      FIG. 2  is a schematic diagram of an exemplary acid gas removal subsystem  300  that may be used with an IGCC power generation system, such as plant  100  (shown in  FIG. 1 ). Acid gas removal subsystem  300  receives the raw stream via conduit  220 . Also, acid gas removal subsystem  300  channels the clean syngas stream to turbine  114  via conduit  228 . In addition, acid gas removal subsystem  300  channels the integrated gas stream to a gasification reactor, such as gasification reactor  208  (shown in  FIG. 1 ) via conduit  224 . Conduit  220  is coupled in flow communication to at least one high pressure absorber  302 . In the exemplary embodiment, acid gas removal subsystem  300  includes one or more high pressure absorbers  302  that are coupled in flow communication with conduit  220 . Alternatively, acid gas removal subsystem  300  may include any number of high pressure absorbers  302  that facilitates operation of subsystem  300  as described herein. 
         [0027]    In the exemplary embodiment, main absorber  302  uses a solvent to facilitate acid gas removal from the raw syngas stream. The raw syngas stream contacts at least a portion of an acid gas-lean solvent, which removes at least a portion of the selected acid gas components from the raw syngas stream to produce the clean syngas stream. The removed acid gas components are retained within the solvent such that a first acid-gas rich, or simply rich, solvent stream is formed. In the exemplary embodiment, such acid gas components include, but are not limited to only including, H 2 S and CO 2 . Alternatively, any components may be removed that facilitates operation of IGCC system  100  as described herein. 
         [0028]    In the exemplary embodiment, high pressure absorber  302  is coupled in flow communication with a flash drum  308  via first rich solvent stream conduit  306 . Alternatively, high pressure absorber  302  may be coupled in flow communication with any number of flash drums  308  that facilitate the operation of acid gas removal subsystem  300  as described herein. 
         [0029]    Flash drum  308  forms a flash gas and a second rich solvent stream that includes at least some remaining CO 2  and H 2 S gaseous components that were not removed by the flashing mechanism described above. As such, in the exemplary embodiment, flash drum  308  is also coupled in flow communication with at least one acid gas stripper  312  via a second rich solvent conduit  310  that channels at least a portion of the second rich solvent stream to acid gas stripper  312 . Alternatively, a plurality of flash drums  308  may be coupled in flow communication to each other in a series or a parallel configuration, wherein the plurality of flash drums  308  are coupled in flow communication with acid gas stripper  312  via any number of conduits that facilitate the operation of acid gas removal subsystem  300  as described herein. Moreover, in the exemplary embodiment, flash drum  308  is also coupled in flow communication with compressor  400  via conduit  418 . As such, flash drum  308  channels at least a portion of the flash gas to compressor  400 . 
         [0030]    Acid gas stripper  312  receives a rich solvent stream channeled by conduit  310 . Acid gas stripper  312  regenerates the received rich solvent to a lean solvent by substantially reducing the concentration of any acid gas components within the rich solvent, thereby forming a lean solvent stream that is substantially free of CO 2  and H 2 S. Acid gas stripper  312  is coupled in flow communication with a reboiler  314  via a conduit  316 , wherein the lean solvent stream is channeled to reboiler  314 . Reboiler  314  heats the lean solvent and is coupled in flow communication with acid gas stripper  312 . A portion of the heated lean solvent is channeled to acid gas stripper  312  via a conduit  318 , to facilitate a vapor boilup within acid gas stripper  312  such that stripper performance is facilitated to be improved. 
         [0031]    Reboiler  314  is also coupled in flow communication with at least one heat transfer apparatus  304  via pump  320  and conduits  322  and  324 . Pump  320  and conduits  322  and  324  channel the hot lean solvent stream through heat transfer apparatus  304 . Heat transfer apparatus  304  facilitates a transfer of heat from the hot lean solvent stream to the first rich solvent stream. Heat transfer apparatus  304  is coupled in flow communication with high pressure absorber  302  via conduit  364 . Conduit  364  channels a warm lean solvent stream from heat transfer apparatus  304  and facilitates the removal of at least some of the heat within the warm solvent stream to form a cooler, lean solvent stream. 
         [0032]    Acid gas stripper  312  produces a first CO 2 /H 2 S acid gas stream as a function of regenerating the solvent as described above. Acid gas stripper  312  is coupled in flow communication with a phase separator  326  via a conduit  328 . The first CO 2 /H 2 S acid gas stream may contain solvent. Phase separator  326  facilitates removing solvent from the first CO 2 /H 2 S acid gas stream and then returns the solvent back to acid gas stripper  312  via conduit  330 . More specifically, phase separator  326  forms a second CO 2 /H 2 S acid gas stream. Thereafter, the second CO 2 /H 2 S acid gas stream is channeled to compressor  400  via conduit  406 . 
         [0033]    In the exemplary embodiment, condensate from the bottom of gasifier  208  is channeled to an ammonia stripper  404  via conduit  414 . Additionally, condensate from LTGC  221  is channeled to ammonia stripper  404  via conduit  416 . Ammonia stripper  404  forms an ammonia-rich overhead, and channels the overhead to compressor  400  via conduit  406 . 
         [0034]    In one embodiment, compressor  400  is a compression system including at least one compression stage. The second CO 2 /H 2 S acid gas stream, the ammonia-rich overhead stream, and the flash gas are compressed to a predetermined pressure by compressor  400 . In one embodiment, compressor  400  compresses the second CO 2 /H 2 S acid gas stream and ammonia-rich overhead stream are compressed to a supercritical pressure. In alternative embodiment, compressor  400  compresses the second CO 2 /H 2 S acid gas stream and ammonia-rich overhead stream are compressed to a different predetermined pressure. Compressor  400  is also coupled in flow communication with a storage system  500  via a conduit  402 . The compressed streams are channeled to storage system  500 . In the exemplary embodiment, storage system  500  is one of a saline aquifer and an enhanced oil recovery field. Moreover, phase separator  326  is coupled in flow communication with at least one compressor  354  via at least one conduit  350  and at least one blocking valve  352 . Compressor  354  is also coupled in flow communication with conduit  224 . 
         [0035]    In the exemplary embodiment, valve  352  is remotely and automatically operated and are electrically coupled with a control system (not shown). Alternatively, valve  352  may be operated in any manner that facilitates operation of acid gas removal subsystem  300  as described herein. 
         [0036]    During operation, acid gas removal subsystem  300  operates to remove at least a portion of acid components from the raw syngas stream. Such acid gas components include, but are not limited to only including, H 2 S and CO 2 . Subsystem  300  further facilitates the separation of at least some of the acid gas components into components that include, but are not limited to, H 2 S and CO 2 . Specifically, the first CO2/H2S acid gas stream from the acid gas stripper  312  is channeled to phase separator  326  via conduit  328 . Phase separator  326  produces a second CO 2 /H 2 S acid gas stream acid gas stream that has a higher concentration of CO 2  than the first CO 2 /H 2 S acid gas stream. The second CO 2 /H 2 S acid gas stream is channeled to compressor  400  via conduit  406 . An ammonia-rich overhead stream is also channeled to compressor  400  via conduit  406 , from ammonia stripper  404 . Further, a flash gas stream is channeled to compressor  400  via conduit  418 , from flash drum  308 . Compressor  400  compresses the second CO 2 /H 2 S acid gas stream, ammonia-rich overhead stream, and flash gas stream to a predetermined pressure and channels the compressed streams to storage system  500  via conduit  402 . 
         [0037]      FIG. 3  is a schematic diagram of an alternative embodiment of acid gas removal subsystem  300 . In such an embodiment, acid gas removal subsystem  300  includes at least one chemical transition unit, or sulfur removal unit (SRU)  332 , that is coupled in flow communication with phase separator  326  via at least one conduit  334  and at least one inlet block valve  336 . SRU  332  receives a portion of the second CO 2 /H 2 S acid gas stream, and forms sulfur dioxide (SO 2 ) and elemental sulfur (S). Specifically, a portion of the H 2 S within the second CO 2 /H 2 S acid gas stream reacts with O 2  to form SO 2 . The SO 2  also reacts with the remaining H 2 S to form elemental S and H 2 O. Unconverted CO 2 , SO 2 , and N 2  within SRU  332  form an SRU tail gas stream. Any sulfur (S) formed is removed from SRU  332  via a conduit  338 . In the exemplary embodiment, phase separator  326  is also coupled in flow communication with compressor  400  via a conduit  410 . Additionally, flash drum  308  is coupled in flow communication with compressor  400  via conduit  418 . In one embodiment, compressor  400  is a compression system including at least one compression stage. The second CO 2 /H 2 S acid gas stream from phase separator  326  and a flash gas stream from flash drum  308  are compressed to a predetermined pressure by compressor  400 . In one embodiment, compressor  400  compresses the second CO 2 /H 2 S acid gas stream and the flash gas stream to a supercritical pressure. Compressor  400  is also coupled in flow communication with storage system  500  via a conduit  412 . The compressed second CO 2 /H 2 S acid gas stream and flash gas stream are channeled to storage system  500 . In the exemplary embodiment, storage system  500  is one of a saline aquifer and an enhanced oil recovery field. 
         [0038]    Sulfur removal unit  332  is coupled in flow communication with at least one chemical transition unit, or tail gas unit (TGU)  340 , that receives the SRU tail gas stream via a conduit  338 . Tail gas unit  340  also forms H 2 S by hydrogenating the unconverted SO 2  with hydrogen (H 2 ). Carbon dioxide within the second CO 2 /H 2 S acid gas stream and the SRU tail gas stream are substantially chemically unchanged. 
         [0039]    In the alternative embodiment, acid gas removal subsystem  300  also includes at least one compressor  354  coupled in flow communication with TGU  340  via at least one conduit  350  and at least one blocking valve  352 . Compressor  354  is also coupled in flow communication with conduit  224 . 
         [0040]    In the alternative embodiment, valves  336  and  352  are remotely and automatically operated and are electrically coupled with a control system (not shown). Alternatively, valves  336  and  352  may be operated in any manner that facilitates operation of acid gas removal subsystem  300  as described herein. 
         [0041]    During operation, acid gas removal subsystem  300  operates to remove at least a portion of acid components from the raw syngas stream. Such acid gas components include, but are not limited to, H 2 S and CO 2 . Subsystem  300  further facilitates the separation of at least some of the acid gas components into components that include, but are not limited to, H 2 S and CO 2 . Specifically, the first CO 2 /H 2 S acid gas stream from the acid gas stripper  312  is channeled to phase separator  326  via conduit  328 . Phase separator  326  produces a second CO 2 /H 2 S acid gas stream acid gas stream that has a higher concentration of CO 2  than the first CO 2 /H 2 S acid gas stream. A first portion of second CO 2 /H 2 S acid gas stream is channeled to compressor  400  via conduit  410 . Moreover, a flash gas stream is channeled via conduit  418  to compressor  400 , from flash drum  308 . Compressor  400  compresses the portion of the second CO 2 /H 2 S acid gas stream and the flash gas stream to a predetermined pressure and channels the compressed streams to storage system  500  via conduit  402 . A second portion of second CO 2 /H 2 S acid gas stream is channeled from phase separator  326  to SRU  332  via conduit  334  and valve  336 . Sulfur recovery unit  332  removes at least a portion of sulfur from the second CO 2 /H 2 S acid gas stream. Tail gas from SRU  332  is channeled to TGU  340  via conduit  338 . Tail gas unit  340  removes at least a portion of the remaining sulfur from SRU tail gas. TGU tail gas is recycled to gasification system  100  via blower  34  and compressor  354 . 
         [0042]    The above-described systems and methods facilitate eliminating the complexity of gasification plants using CO 2  capture, and by eliminating the need for, in one embodiment, expensive equipment such as sulfur recovery units and tail gas units. Additionally, the systems and methods facilitate creating an alternative low-cost solution for sequestration of rich CO 2 . 
         [0043]    As used herein, an element or step recited in the singular and proceeded with the word “a” or “an” should be understood as not excluding plural said elements or steps, unless such exclusion is explicitly recited. Furthermore, references to “one embodiment” of the present invention are not intended to be interpreted as excluding the existence of additional embodiments that also incorporate the recited features. 
         [0044]    Although the apparatus and methods described herein are described in the context of a CO 2  capture system for an integrated gasification combined-cycle (IGCC) power system, it is understood that the apparatus and methods are not limited to CO 2  capture systems or IGCCs. Likewise, the system components illustrated are not limited to the specific embodiments herein, but rather, components of the system can be utilized independently and separately from other components described herein. 
         [0045]    While the invention has been described in terms of various specific embodiments, those skilled in the art will recognize that the invention can be practiced with modification within the spirit and scope of the claims.