Systems for compressing a gas   

BACKGROUND OF THE INVENTION

The subject matter disclosed herein relates to systems for efficiently compressing a gas, such as carbon dioxide (CO2), in a power plant such as an integrated coal gasification combined cycle (IGCC) or a coal-fired conventional power plant.

Power plants, for example IGCC power plants, may produce a carbonous gas such as CO2. In IGCC power plants, a syngas is created by gasifying a carbonaceous fuel such as coal. The syngas may be utilized as fuel for power generation. The syngas may be fed into a combustor of a gas turbine of the IGCC power plant and ignited to power the gas turbine, which may then drive a load such as an electrical generator. One byproduct of such plants may be CO2. Carbon capture and sequestration is very likely to be a key element of any future greenhouse gas legislation, such as CO2 legislation. Thus, power plants may be under provisions to separate the CO2, either pre-combustion or post combustion. The CO2 may be captured, compressed, and sequestered. However, the compression of CO2 requires a considerable amount of energy. Accordingly, there is a need for systems that can reduce power consumption and overall cost in the compression of CO2.

Certain embodiments commensurate in scope with the originally claimed invention are summarized below. These embodiments are not intended to limit the scope of the claimed invention, but rather these embodiments are intended only to provide a brief summary of possible forms of the invention. Indeed, the invention may encompass a variety of forms that may be similar to or different from the embodiments set forth below.

In a first embodiment, a system includes a carbonous gas compression system and a vapor absorption chiller (VAC). The carbonous gas compression system comprises a compressor configured to compress the carbonous gas. The VAC is configured to circulate a coolant through at least one coolant path through the carbonous gas compression system.

In a second embodiment, a system includes a carbonous gas capture system, a carbonous gas compression system, a vapor absorption chiller (VAC), and at least a carbon sequestration system or an enhanced oil recovery (EOR) pipeline. The carbonous gas capture system is configured to extract the carbonous gas. The carbonous gas compression system comprises at least a compressor which is configured to receive the carbonous gas from the carbonous gas capture system and to compress and liquefy the carbonous gas. The VAC is configured to circulate a coolant through at least one coolant path through the carbonous compression system. The carbon sequestration system or the enhanced oil recovery (EOR) pipeline are configured to receive carbonous gas compressed and liquefied by the carbonous gas compression system.

In a third embodiment, a system includes a carbon dioxide (CO2) compression system, a VAC, and a liquid pump. The CO2 compression system comprises at least a compressor configured to compress the CO2. The VAC is configured to circulate a coolant through at least one coolant path through the CO2 compression system. The liquid pump is configured to raise the pressure of the CO2.

BRIEF DESCRIPTION OF THE DRAWINGS

These and other features, aspects, and advantages of the present invention will become better understood when the following detailed description is read with reference to the accompanying drawings in which like characters represent like parts throughout the drawings, wherein:

FIG. 1 depicts a block diagram of an embodiment of an integrated gasification combined cycle (IGCC) power plant, including a gas compression system and a vapor absorption chiller system;

FIG. 2 depicts a block diagram of embodiments of the gas compression system and the vapor absorption chiller system depicted in FIG. 1;

FIG. 3 is a depicts a block diagram of an embodiment of a vapor absorption chiller system; and,

FIG. 4 depicts a block diagram of other embodiments of the gas compression system and the vapor absorption chiller system depicted in FIG. 1.

DETAILED DESCRIPTION

One or more specific embodiments of the present invention will be described below. In an effort to provide a concise description of these embodiments, all features of an actual implementation may not be described in the specification. It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous implementation-specific decisions must be made to achieve the developers\' specific goals, such as compliance with system-related and business-related constraints, which may vary from one implementation to another. Moreover, it should be appreciated that such a development effort might be complex and time consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure.

When introducing elements of various embodiments of the present invention, the articles “a,” “an,” “the,” and “said” are intended to mean that there are one or more of the elements. The terms “comprising,” “including,” and “having” are intended to be inclusive and mean that there may be additional elements other than the listed elements.

The disclosed embodiments include systems for efficiently compressing a carbonous gas (e.g., CO2) produced, for example, by extracting CO2 from syngas in the integrated gasification combined cycle (IGCC) system. The compression of the carbonous gas allows the gas to be stored, for example, in a carbon sequestration system or redirected to an enhanced oil recovery (EOR) pipeline. Power plants such as IGCC power plant described in more detail with respect to FIG. 1 below, may gasify a fuel and provide for the pre-combustion capture of CO2 from the fuel. Additionally, the CO2 may be extracted after the fuel is combusted (i.e., post-combustion extraction), for example, from a flue gas. The CO2 may then be transported, and stored or sequestered, for example, in a supercritical state. The supercritical state of the CO2 refers to CO2 that is in a fluid state while also being above both of its critical pressure and critical temperature. In such a supercritical state, CO2 may behave as a supercritical fluid, expanding to fill a container like a gas but with a density like that of a liquid. Compressors are used to increase the CO2 pressure from near atmospheric pressure to a supercritical phase (i.e., state), in some cases, of upwards of approximately 2215 pounds per square inch absolute (PSIA) at upwards of approximately 100° F. A more efficient system for compressing the carbonous gas is disclosed that is capable of using vapor absorption chiller (VAC) systems to lower the carbonous gas temperatures, resulting in a more efficient and less costly compression of the carbonous gas. Further, liquid compressors (e.g., liquid pumps) may also be used that use significantly less power to operate than gas compressors. Indeed, by combining vapor chiller systems with liquid compressors it may be possible to substantially reduce the amount of energy expended in reaching a supercritical phase of the carbonous gas, thereby increasing efficiency and reducing cost.

With the foregoing in mind, FIG. 1 depicts an embodiment of an IGCC power plant 100 that may produce and burn a synthetic gas, i.e., syngas. Elements of the IGCC power plant 100 may include a fuel source 102, such as a solid feed, that may be utilized as a source of energy for the IGCC power plant 100. The fuel source 102 may 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 source 102 may be passed to a feedstock preparation unit 104. The feedstock preparation unit 104 may, for example, resize or reshape the fuel source 102 by chopping, milling, shredding, pulverizing, briquetting, or palletizing the fuel source 102 to generate feedstock. Additionally, water, or other suitable liquids may be added to the fuel source 102 in the feedstock preparation unit 104 to create slurry feedstock. In certain embodiments, no liquid is added to the fuel source, thus yielding dry feedstock. The feedstock may be conveyed into a gasifier 106 for use in gasification operations.

The gasifier 106 may convert the feedstock into a 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 limited oxygen at elevated pressures (e.g., from approximately 600 pounds per square inch gauge (PSIG)-1200 PSIG) and elevated temperatures (e.g., approximately 2200° F.-2700° F.), depending on the type of feedstock used. 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).

A combustion process may then occur in the gasifier 106. The combustion may 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 gasifier 106. The gasifier 106 utilizes 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 is manufactured by the gasifier 106. This resultant gas may include approximately 85% of carbon monoxide and hydrogen in equal proportions, 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 untreated syngas, since it contains, for example, H2S. The gasifier 106 may also generate waste, such as slag 108, which may be a wet ash material. This slag 108 may be removed from the gasifier 106 and disposed of, for example, as road base or as another building material. To treat the untreated syngas, a gas treatment unit 110 may be utilized. In one embodiment, the gas treatment unit 110 may be a water gas shift reactor. The gas treatment unit 110 may scrub the untreated syngas to remove the HCl, HF, COS, HCN, and H2S from the untreated syngas, which may include separation of sulfur 111 in a sulfur processor 112 by, for example, an acid gas removal process in the sulfur processor 112. Furthermore, the gas treatment unit 110 may separate salts 113 from the untreated syngas via a water treatment unit 114 that may utilize water purification techniques to generate usable salts 113 from the untreated syngas. Subsequently, the gas from the gas treatment unit 110 may include treated syngas, (e.g., the sulfur 111 has been removed from the syngas), with trace amounts of other chemicals, e.g., NH3 (ammonia) and CH4 (methane). A gas processor 115 may be used to remove additional residual gas components 116, such as ammonia and methane, as well as methanol or any residual chemicals from the treated syngas. However, removal of residual gas components from the treated syngas is optional, since the treated syngas may be utilized as a fuel even when containing the residual gas components, e.g., tail gas.

In some embodiments, a carbon capture system 117 may extract and process the carbonous gas (e.g., CO2 that is approximately 60-80 percent, approximately 80-100 percent or approximately 90-100 percent pure by volume) from the syngas (i.e., pre-combustion extraction). Additionally, the carbon capture system 117 may extract and process the carbonous gas after combustion (i.e., post-combustion extraction), for example, by extracting the CO2 from a flue gas. An extracted CO2 may then be transferred into a gas compression system 118. In certain embodiments, the gas compression system 118 may compress, dehydrate, and liquefy the extracted CO2, resulting in a CO2 that is more easily transported and stored. The CO2 may then be redirected into a carbon sequestration system 119, and/or an EOR pipeline 120 for use in, for example, oil recovery activities. Accordingly, emissions of the extracted CO2 into the atmosphere may be reduced or eliminated by redirecting the extracted CO2 for use in such activities.

Gas compression activities may be able to more efficiently compress the extracted CO2 by cooling the compressed CO2 to lower temperatures. Accordingly, a VAC system 122 may operate to transmit water to cool the compression system 118 during operation. The VAC system 122 may also operate to retrieve water made hot through absorption of heat generated by the compression system 118 while compressing. The VAC system 122 may further cycle the water used in conjunction with the compression system 118 through a cooling tower 124 that may act as a water reservoir. By cooling the compression system 118 via the VAC system 122 utilizing the cooling tower 124, the CO2 in the compression system 118 may be compressed more easily, that is, use less energy to compress the CO2, and, thus, the efficiency of the compression system 118 may be increased. Furthermore, the use of the VAC system 122 may be beneficial because of its ability to reuse heat that might otherwise be wasted.

Continuing with the syngas processing, once the CO2 has been captured from the syngas, the treated syngas may be then transmitted to a combustor 125, e.g., a combustion chamber, of a gas turbine engine 126 as combustible fuel. The IGCC power plant 100 may further include an air separation unit (ASU) 128. The ASU 128 may operate to separate air into component gases by, for example, distillation techniques. The ASU 128 may separate oxygen from the air supplied to it from a supplemental air compressor 129, and the ASU 128 may transfer the separated oxygen to the gasifier 106. Additionally the ASU 128 may transmit separated nitrogen to a diluent nitrogen (DGAN) compressor 130.

The DGAN compressor 130 may compress the nitrogen received from the ASU 128 at least to pressure levels equal to those in the combustor 125, so as not to interfere with the proper combustion of the syngas. Thus, once the DGAN compressor 130 has adequately compressed the nitrogen to a proper level, the DGAN compressor 130 may transmit the compressed nitrogen to the combustor 125 of the gas turbine engine 126. The nitrogen may be used as a diluent to facilitate control of emissions, for example.

As described previously, the compressed nitrogen may be transmitted from the DGAN compressor 130 to the combustor 125 of the gas turbine engine 126. The gas turbine engine 126 may include a turbine 132, a drive shaft 133 and a compressor 134, as well as the combustor 125. The combustor 125 may receive fuel, such as 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 compressor 130, and combusted within combustor 125. This combustion may create hot pressurized exhaust gases.

The combustor 125 may direct the exhaust gases towards an exhaust outlet of the turbine 132. As the exhaust gases from the combustor 125 pass through the turbine 132, the exhaust gases force turbine blades in the turbine 132 to rotate the drive shaft 133 along an axis of the gas turbine engine 126. As illustrated, the drive shaft 133 is connected to various components of the gas turbine engine 126, including the compressor 134.

The drive shaft 133 may connect the turbine 132 to the compressor 134 to form a rotor. The compressor 134 may include blades coupled to the drive shaft 133. Thus, rotation of turbine blades in the turbine 132 may cause the drive shaft 133 connecting the turbine 132 to the compressor 134 to rotate blades within the compressor 134. This rotation of blades in the compressor 134 causes the compressor 134 to compress air received via an air intake in the compressor 134. The compressed air may then be fed to the combustor 125 and mixed with fuel and compressed nitrogen to allow for higher efficiency combustion. Drive shaft 133 may also be connected to a load 136, which may be a stationary load, such as an electrical generator for producing electrical power, for example, in a power plant. Indeed, the load 136 may be any suitable device that is powered by the rotational output of the gas turbine engine 126.

The IGCC power plant 100 also may include a steam turbine engine 138 and a heat recovery steam generation (HRSG) system 139. The steam turbine engine 138 may drive a second load 140. The second load 140 may also be an electrical generator for generating electrical power. However, both the first and second loads 136, 140 may be other types of loads capable of being driven by the gas turbine engine 126 and steam turbine engine 138. In addition, although the gas turbine engine 126 and steam turbine engine 138 may drive separate loads 136 and 140, as shown in the illustrated embodiment, the gas turbine engine 126 and steam turbine engine 138 may also be utilized in tandem to drive a single load via a single shaft. The specific configuration of the steam turbine engine 138, as well as the gas turbine engine 126, may be implementation-specific and may include any combination of sections.

The system 100 may also include the HRSG 139. Heated exhaust gas from the gas turbine engine 126 may be transported into the HRSG 139 and used to heat water and produce steam used to power the steam turbine engine 138. Exhaust from, for example, a low-pressure section of the steam turbine engine 138 may be directed into a condenser 142. The condenser 142 may utilize the cooling tower 124 to exchange heated water for chilled water. The cooling tower 124 acts to provide cool water to the condenser 142 to aid in condensing the steam transmitted to the condenser 142 from the steam turbine engine 138. Condensate from the condenser 142 may, in turn, be directed into the HRSG 139. Again, exhaust from the gas turbine engine 126 may also be directed into the HRSG 139 to heat the water from the condenser 142 and produce steam.

In combined cycle power plants such as IGCC power plant 100, hot exhaust may flow from the gas turbine engine 126 and pass to the HRSG 139, where it may be used to generate high-pressure, high-temperature steam. The steam produced by the HRSG 139 may then be passed through the steam turbine engine 138 for power generation. In addition, the produced steam may also be supplied to any other processes where steam may be used, such as to the gasifier 106. The gas turbine engine 126 generation cycle is often referred to as the “topping cycle,” whereas the steam turbine engine 126 generation cycle is often referred to as the “bottoming cycle.” By combining these two cycles as illustrated in FIG. 1, the IGCC power plant 100 may lead to greater efficiencies in both cycles. In particular, exhaust heat from the topping cycle may be captured and used to generate steam for use in the bottoming cycle.

FIG. 2 illustrates the compression system 118 in conjunction with the VAC system 122 of the IGCC system 100. As illustrated, compression system 118 may be a multi-stage compression system 118. That is, the compression system 118 may include a first stage compressor 144, a second stage compressor 146, and a liquid pump 148. The compressors 144 and 146 may operate in conjunction (e.g., in series) with the liquid pump 148 to compress the CO2 received from the CO2 extraction system (e.g., pre-combustion or post-combustion extraction) to a level that facilitates transmission to the CO2 sequestration system 119 and/or EOR pipeline 120. The VAC system 122 is capable of using the chilled water 155 to liquefy the CO2 at intermediate pressures and then use the liquid pump 148 to raise the liquid CO2 to a super critical pressure. Such a method is a more efficient way of liquefying CO2 than, for example, when the chilled water 155 is not used. Because of the irreversibility during compression, the exit temperature of the CO2 after compression increases. To reduce this temperature increase, inter-cooling between the stages of compression and/or the liquid pump may be desirable. Indeed, by using VAC inter-cooling as detailed below, it may be possible to more efficiently compress and liquefy the CO2.

The compression system 118 may include an intermediate chilled water heat exchanger 152, and a final chilled water heat exchanger 154 that may receive a coolant through a chilled temperature coolant path 155. The compression system 118 may also include an intermediate heated water heat exchanger 156, and a final heated water heat exchanger 158 that may receive a coolant through a heated temperature coolant path 159. Collectively, the chilled water heat exchangers 152, 154 and the heated water heat exchangers 156, 158 may be utilized to reduce the temperature of the CO2 flowing through a gas path 163 of the compression system 118. It should be noted that instead of water, other suitable liquids may be utilized in conjunction with the heat exchangers 152, 154, 156, 158 as a coolant. An example of the operation of the heat exchangers 152, 154, 156, 158 in conjunction with the compressors 144, 146 and the liquid pump 148 will be discussed below.

A CO2 flow from, for example, the carbon capture system 117 may be redirected to the first stage compressor 144. The CO2 flow may be at an inlet pressure of approximately 15 PSIA to 40 PSIA and a temperature of between approximately 80° F.-120° F. The first stage compressor 144 may compress the CO2 to a pressure of approximately 200 PSIA-400 PSIA and a temperature of approximately between 400° F. to 600° F. To aid in reducing the temperature of the CO2, so that the second stage compressor 146 may expend less energy in compressing the CO2, the CO2 may pass through the intermediate heated water heat exchanger 156.

The intermediate heated water heat exchanger 156 may receive heated water from a generator 164, e.g. a heat exchanger, of the VAC system 122. The water may be at a temperature of approximately 90° F.-200° F. The heated water may pass through the intermediate heated water heat exchanger 156, through a conduit (e.g., coolant path 159), such as a tube. This coolant path 159 may contact the CO2 as it passes through the intermediate heated water heat exchanger 156, thus reducing the temperature of the CO2 from, for example, approximately 400° F.-600° F., to approximately 100° F.-to 300° F., while increasing the temperature of the heated water to, for example, approximately 150° F.-250° F. Subsequent to passing through the intermediate heated water heat exchanger 156, the CO2 may be passed to the intermediate chilled water heat exchanger 152, so as to come into contact with a conduit (e.g., coolant path 155), containing chilled water. The chilled water may be transmitted from an evaporator 160 of the VAC system 122 via a pump 162 to the final chilled water heat exchanger 154 and then subsequently to the intermediate chilled water heat exchanger 152. The CO2 may contact the conduit carrying the chilled water as it passes through the intermediate chilled water heat exchanger 152, thus reducing the temperature of the CO2, for example, to approximately 60° F.-100° F., while increasing the temperature of the chilled water to approximately 50° F.-80° F.

The CO2 may then pass to the second stage compressor 146. The CO2 entering the second stage compressor 146 may be at a temperature of approximately 60° F.-100° F. and at a pressure of approximately 200 PSIA-400 PSIA. The second stage compressor 146 may compress the CO2 to approximately 550 PSIA-950 PSIA. However, in compressing the CO2, the temperature of the CO2 may also increase from, for example, approximately 60° F.-100° F. to approximately 150° F.-350° F. Again, to aid in reducing the temperature of the CO2 such that it may be condensed or liquefied at a more reduced pressure, and so that the liquid pump 148 may expend less energy for raising the liquid CO2 to supercritical stage, the CO2 may pass through the final heated water heat exchanger 158.

The final heated water heat exchanger 158 may receive heated water from the intermediate heated water heat exchanger 156. The water may be at a temperature of approximately 90° F.-250° F. The heated water may pass through the final heated water heat exchanger 158, through a conduit, such as a tube. This conduit may contact the CO2 as it passes through the final heated water heat exchanger 158, thus reducing the temperature of the CO2 from, for example, approximately 150° F.-350° F. to approximately 100° F.-300° F., while increasing the temperature of the heated water. The heated water may then be transmitted to the generator 164 of the VAC system 122 via a pump 166. Subsequent to passing through the final heated water heat exchanger 158, the CO2 may be passed to the final chilled water heat exchanger 154, so as to come into contact with a conduit containing chilled water. Chilled water may be transmitted from the evaporator 160 of the VAC system 122 via the pump 162 to the final chilled water heat exchanger 154. The chilled water may be, for example, at approximately 20° F.-50° F. The chilled water may pass through the final chilled water heat exchanger 154, through a conduit, such as a tube. The CO2 may contact the conduit carrying the chilled water as it passes through the final chilled water heat exchanger 154, thus reducing the temperature of the CO2 from, for example, approximately 100° F.-300° F. to approximately 25° F.-75° F., while increasing the temperature of the chilled water from approximately 20° F.-50° F. to approximately 40° F.-70° F. Indeed, the temperature of the CO2 in the gas path 163 after the chilled water heat exchanger 154 may be set such that all gaseous CO2 becomes condensed or liquefied.

The liquefied CO2 may then pass to the liquid pump 148. The CO2 entering the liquid pump 148 may be at a temperature of approximately 25° F.-75° F. and at a pressure of approximately 550 PSIA-950 PSIA. The liquid pump 148 may further compress the CO2 to super critical pressure. Accordingly, CO2 exiting the liquid pump 148 may be at a pressure of upwards of approximately 2215 PSIA at a temperature of upwards of approximately 60° F. At this pressure, the compressed CO2 may be introduced into, for example the carbon sequestration system 119 and/or the EOR pipeline 120. The flow of chilled and warm water through the compression system 118 above may be supplied by the VAC system 122, increasing compression and liquefaction efficiency. Accordingly, FIG. 3 illustrates the operation of a VAC system 122.

FIG. 3 illustrates an embodiment of VAC system 122. Heat from, for example, the heat exchangers 156 and 158 of FIG. 2, may operate as waste heat sources to provide hot water or steam that may be used to power the VAC system 122. The use of waste heat is advantageous because heat that may have otherwise have been wasted or cast off is used to aid in compression activities. Accordingly, the VAC system 122 may include an evaporator 160, a generator 164, an absorber 168, and a condenser 170. The evaporator 160 may be kept at low pressure, for example, at a pressure approximately near a vacuum. The low-pressure of the evaporator 160 may cause a refrigerant, such as NH3 (ammonia), to boil at very low temperatures. As illustrated, the evaporator 160 includes a heat exchanger 161 to exchange heat with the compression system 118 via heat exchangers 152 and 154. In particular, heat exchangers 152 and 154 remove heat from the compression system 118, and the heat exchanger 161 adds heat to the evaporator 160. The evaporator 160 may also take heat from the surroundings of the evaporator 160. Because of this heat transfer, the refrigerant may be converted into vapor which may flow into the absorber 168. The absorber 168 may combine the refrigerant vapor with water. In addition, the absorber 168 cools and condenses the refrigerant vapor and water via a heat exchanger 169 that circulates a coolant (e.g., water) with cooling tower 124. The water, rich with refrigerant, may then be pumped via an absorbent pump 172 to the generator 164.

In the generator 164, heat may be transferred to the refrigerant rich liquid by an external heat source, such as hot water or steam from the compression system 118 (e.g., heat exchangers 156 and 158). In particular, the generator 164 has a heat exchanger 165 to receive heat from the heat exchangers 156 and 158 in the compression system 118. The heat from the hot water or steam may boil the refrigerant off from the refrigerant rich liquid. The hot and refrigerant lean liquid then may return back to the absorber 168, where heat may be removed by cooling water flow from cooling tower 124. The refrigerant vapor from the generator 164 may be transmitted to the condenser 170, where the refrigerant vapor may be converted into liquid by exchanging heat with cooling water from the cooling tower 124. In particular, the condenser 170 has a heat exchanger 171 to remove heat via circulation of water with the cooling tower 124. The cooled refrigerant may then returned to the low-pressure evaporator 160, where it takes heat from the water from the compression system 118, thus completing a VAC thermodynamic cycle. The VAC thermodynamic cycle may be able to capture heat from the compression activities and reuse the heat to create a chilling effect to cool the CO2 flow, thus more efficiently compressing the CO2.

FIG. 4 illustrates an embodiment of an N-stage compression system 118 in conjunction with the VAC system 122 of the IGCC system 100. As illustrated, the compression system 118 may be a multi-stage compression system 118. That is, the compression system 118 may include a first stage compressor 144, a final stage compressor 148, and multiple intermediate stages (e.g., 2, 3, 4, 5, 6, 7, 8, 9, 10, or more) each stage including a compressor 146. These compressors 144, 146, 148 may operate in conjunction (e.g., in series) with the liquid pump 148 to compress and liquefy the CO2 received from the carbon capture system 117 to a level that is easily transported and stored. The compression system 118 may include an inlet chilled water heat exchanger 174, a final chilled water heat exchanger 154, and multiple intermediate chilled water heat exchangers 152, for example, one or more per each of the multiple intermediate stages including an intermediate compressor 146. The chilled water heat exchangers 152, 154, 174 may receive a coolant through the chilled temperature coolant path 155. Collectively, the chilled water heat exchangers 152, 154, 174 and the heated water heat exchangers 156, 158 may be utilized to reduce the temperature of the CO2 flowing through the gas path 163 of the compression system 118. The compression system 118 may also include a final heated water heat exchanger 158 and multiple intermediate heated water heat exchangers 156, one or more per each of the multiple intermediate stages including an intermediate compressor 146, as described below. The heated water heat exchangers 152, 154, 174 may receive a coolant through the heated temperature coolant path 159.

Chilled water may be transmitted from the evaporator 160 of the VAC system 122 via the pump 162 to the inlet chilled water heat exchanger 174. The chilled water may pass through the inlet chilled water heat exchanger 174, through a conduit (e.g., coolant path 155), such as a tube. This conduit may contact the CO2 as it passes through the inlet chilled water heat exchanger 174, thus reducing the temperature of the CO2 while increasing the temperature of the chilled water. The CO2 may then pass to the first stage compressor 144. The first stage compressor 144 may compress the CO2. However, in compressing the CO2, the temperature of the CO2 may also increase. To aid in reducing the temperature of the CO2, so that the intermediate compressor 146 may expend less energy in compressing the CO2, the CO2 may pass through the intermediate heated water heat exchanger 156.

The intermediate heated water heat exchanger 156 may receive heated water from the generator 164, e.g. a heat exchanger, of the VAC system 122. The heated water may pass through the intermediate heated water heat exchanger 156, through a conduit, such as a tube. This conduit may contact the CO2 as it passes through the intermediate heated water heat exchanger 156, thus reducing the temperature of the CO2 while increasing the temperature of the heated water. The temperate of the CO2 is reduced because the heated water may be cooler than the CO2. Subsequent to passing through the intermediate heated water heat exchanger 156, the CO2 may be passed to the intermediate chilled water heat exchanger 152, so as to come into contact with a conduit containing chilled water. The CO2 may contact the conduit carrying the chilled water as it passes through the intermediate chilled water heat exchanger 152, thus reducing the temperature of the CO2 while increasing the temperature of the chilled water.

The CO2 may then pass to the intermediate compressor 146. The intermediate compressor 146 may compress the CO2. However, in compressing the CO2, the temperature of the CO2 may also increase. To aid in reducing the temperature of the CO2, so that the next compressor stage may expend less energy in compressing the CO2, the CO2 may pass through a final heated water heat exchanger 158. The final heated water heat exchanger 158 may receive heated water from the intermediate heated water heat exchanger 156. The heated water may pass through the final heated water heat exchanger 158, through a conduit, such as a tube. This conduit may contact the CO2 as it passes through the final heated water heat exchanger 158, thus reducing the temperature of the CO2, while increasing the temperature of the heated water. The heated water may then be transmitted to the generator 164 of the VAC system 122 via a pump 166. Subsequent to passing through the final heated water heat exchanger 158, the CO2 may be passed to the final chilled water heat exchanger 154, so as to come into contact with a conduit containing chilled water. The CO2 may contact the conduit carrying the chilled water as it passes through the final chilled water heat exchanger 154, thus reducing the temperature of the CO2, while increasing the temperature of the chilled water. The CO2 may then pass to the liquid pump 148. The liquid pump 148 may compress the CO2 to super critical state. Consequently, the liquefied CO2 may be more easily transported and stored, through, for example, the use of liquid pumps and liquid conduits.

Collectively, the chilled water heat exchangers 152, 154, 174 and the heated water heat exchangers 156, 158 may be utilized to reduce the temperature of the CO2 flowing through the compression system 118. In this manner, each stage of a N-stage compression system 118 may include corresponding heat exchangers designed to cool the CO2 gas flowing through the various compressors corresponding to a given compression stage.

Technical effects of the invention include the ability to capture and employ waste heat to efficiently compress a carbonous gas, e.g., CO2. Vapor absorption chiller (VAC) systems may be utilized to reclaim heat generated during compression activities. The reclaimed heat may be further utilized to drive a thermodynamic cycle that can result in cooling of the CO2 flow at a reduced pressure such that it becomes liquid, thus allowing for enhanced efficiencies of CO2 compression in reaching the super-critical state. Indeed, by combining vapor chiller systems with liquid compressors it may be possible to substantially reduce the amount of energy expended in reaching a liquid phase of the carbonous gas, increasing efficiency and reducing cost. The liquefied CO2 may be more efficiently transported and stored. Accordingly, more efficient and less costly liquid conduits and liquid pumps may be used to transport the CO2 for storage and use, for example, in oil recovery activities.

This written description uses examples to disclose the invention, including the best mode, and also to enable any person skilled in the art to practice the invention, including making and using any devices or systems and performing any incorporated methods. The patentable scope of the invention is defined by the claims, and may include other examples that occur to those skilled in the art. Such other examples are intended to be within the scope of the claims if they have structural elements that do not differ from the literal language of the claims, or if they include equivalent structural elements with insubstantial differences from the literal languages of the claims.