COMBINED CYCLE NATURAL GAS PROCESSING SYSTEM

Abstract

Combined cycle natural gas processing system that does not discharge carbon dioxide to the atmosphere. The system is provided with an acid gas removal unit that separates carbon dioxide contained in natural gas, and includes a natural gas processing plant that produces liquefied natural gas, and a carbon dioxide cycle. High energy held by a high-temperature and high-pressure carbon dioxide fluid of the carbon dioxide cycle is converted into electrical energy or mechanical energy and supplied to a power consumption device and an energy consumption device provided in the natural gas processing plant. The carbon dioxide fluid extracted from the carbon dioxide cycle and a carbon dioxide separation stream separated by the acid gas removal unit are supplied to a carbon dioxide reception facility capable of receiving carbon dioxide, so that the carbon dioxide generated with production of the liquefied natural gas is not released to the atmosphere.

Claims

1. A combined cycle natural gas processing system comprising: a natural gas processing plant that produces liquefied natural gas from natural gas; and a carbon dioxide cycle power plant that includes a power generation turbine using a carbon dioxide fluid as a driving fluid, and performs power generation using a carbon dioxide cycle that pressurizes and heats the carbon dioxide fluid discharged from the power generation turbine and supplies the carbon dioxide fluid again to the power generation turbine, wherein the natural gas processing plant includes an acid gas removal unit (AGRU) that separates carbon dioxide contained in the natural gas, the carbon dioxide cycle power plant includes: a combustor that is provided on an inlet side of the power generation turbine, mixes the pressurized and heated carbon dioxide fluid with a light hydrocarbon gas containing methane as a main component and a high-purity oxygen gas and combusts the carbon dioxide fluid mixed with the light hydrocarbon gas and the high-purity oxygen gas to generate the carbon dioxide fluid containing high-temperature and high-pressure steam, the light hydrocarbon gas being by-produced when the liquefied natural gas is produced in the natural gas processing plant; a separator that cools the carbon dioxide fluid containing the steam, discharged from the power generation turbine and decompressed, to condense and separate the steam; and an extraction facility that extracts a carbon dioxide fluid exceeding a required circulation amount, determined according to electric power that needs to be obtained by the power generation, out of the carbon dioxide fluid from which moisture has been separated by the separator, and electric power obtained by driving a generator using the power generation turbine is supplied to a power consumption device provided in the natural gas processing plant, the carbon dioxide fluid extracted from the extraction facility and a carbon dioxide separation stream separated by the acid gas removal unit are supplied to a carbon dioxide reception facility capable of receiving carbon dioxide, and the carbon dioxide generated with production of the liquefied natural gas is not released to atmosphere.

2. A combined cycle natural gas processing system comprising: a natural gas processing plant that produces liquefied natural gas from natural gas; and a carbon dioxide cycle power plant that includes a power generation turbine using a carbon dioxide fluid as a driving fluid, and performs power generation using a carbon dioxide cycle that pressurizes and heats the carbon dioxide fluid discharged from the power generation turbine and supplies the carbon dioxide fluid again to the power generation turbine, wherein the natural gas processing plant includes: an acid gas removal unit (AGRU) that separates carbon dioxide contained in the natural gas; a pressurizing unit that pressurizes a carbon dioxide separation stream separated by the acid gas removal unit; and a carbon dioxide supply line that causes the carbon dioxide separation stream pressurized in the pressurizing unit to join the carbon dioxide fluid flowing in the carbon dioxide cycle, the carbon dioxide cycle power plant includes: a combustor that is provided on an inlet side of the power generation turbine, mixes the pressurized and heated carbon dioxide fluid with a light hydrocarbon gas containing methane as a main component and a high-purity oxygen gas and combusts the carbon dioxide fluid mixed with the light hydrocarbon gas and the high-purity oxygen gas to generate the carbon dioxide fluid containing high-temperature and high-pressure steam, the light hydrocarbon gas being by-produced when the liquefied natural gas is produced in the natural gas processing plant; a separator that cools the carbon dioxide fluid containing the steam, discharged from the power generation turbine and decompressed, to condense and separate the steam; and an extraction facility that extracts a carbon dioxide fluid exceeding a required circulation amount, determined according to electric power that needs to be obtained by the power generation, out of the carbon dioxide fluid from which moisture has been separated by the separator, and electric power obtained by driving a generator using the power generation turbine is supplied to a power consumption device provided in the natural gas processing plant, the carbon dioxide fluid extracted from the extraction facility is supplied to a carbon dioxide reception facility capable of receiving carbon dioxide, and the carbon dioxide generated with production of the liquefied natural gas is not released to atmosphere.

3. A combined cycle natural gas processing system comprising: a natural gas processing plant that produces liquefied natural gas from natural gas; and a carbon dioxide cycle plant that includes an energy conversion turbine configured to convert energy held by a driving fluid into mechanical energy using a carbon dioxide fluid as the driving fluid, and obtains the mechanical energy using a carbon dioxide cycle that pressurizes and heats the carbon dioxide fluid discharged from the energy conversion turbine and supplies the carbon dioxide fluid again to the energy conversion turbine, wherein the natural gas processing plant includes an acid gas removal unit (AGRU) that separates carbon dioxide contained in the natural gas, the carbon dioxide cycle plant includes: a combustor that is provided on an inlet side of the energy conversion turbine, mixes the pressurized and heated carbon dioxide fluid with a light hydrocarbon gas containing methane as a main component and a high-purity oxygen gas and combusts the carbon dioxide fluid mixed with the light hydrocarbon gas and the high-purity oxygen gas to generate the carbon dioxide fluid containing high-temperature and high-pressure steam, the light hydrocarbon gas being by-produced when the liquefied natural gas is produced in the natural gas processing plant; a separator that cools the carbon dioxide fluid containing the steam, discharged from the energy conversion turbine and decompressed, to condense and separate the steam; and an extraction facility that extracts a carbon dioxide fluid exceeding a required circulation amount, determined according to the mechanical energy that needs to be obtained by the energy conversion, out of the carbon dioxide fluid from which moisture has been separated by the separator, and the mechanical energy obtained by driving the energy conversion turbine is supplied to a mechanical energy consumption device provided in the natural gas processing plant, the carbon dioxide fluid extracted from the extraction facility and a carbon dioxide separation stream separated by the acid gas removal unit are supplied to a carbon dioxide reception facility capable of receiving carbon dioxide, and the carbon dioxide generated with production of the liquefied natural gas is not released to atmosphere.

4. A combined cycle natural gas processing system comprising: a natural gas processing plant that produces liquefied natural gas from natural gas; and a carbon dioxide cycle plant that includes an energy conversion turbine configured to convert energy held by a driving fluid into mechanical energy using a carbon dioxide fluid as the driving fluid, and recovers energy using a carbon dioxide cycle that pressurizes and heats the carbon dioxide fluid discharged from the energy conversion turbine and supplies the carbon dioxide fluid again to the energy conversion turbine, wherein the natural gas processing plant includes: an acid gas removal unit (AGRU) that separates carbon dioxide contained in the natural gas; a pressurizing unit that pressurizes a carbon dioxide separation stream separated by the acid gas removal unit; and a carbon dioxide supply line that causes the carbon dioxide separation stream pressurized in the pressurizing unit to join the carbon dioxide fluid flowing in the carbon dioxide cycle, the carbon dioxide cycle plant includes: a combustor that is provided on an inlet side of the energy conversion turbine, mixes the pressurized and heated carbon dioxide fluid with a light hydrocarbon gas containing methane as a main component and a high-purity oxygen gas and combusts the carbon dioxide fluid mixed with the light hydrocarbon gas and the high-purity oxygen gas to generate the carbon dioxide fluid containing high-temperature and high-pressure steam, the light hydrocarbon gas being by-produced when the liquefied natural gas is produced in the natural gas processing plant; a separator that cools the carbon dioxide fluid containing the steam, discharged from the energy conversion turbine and decompressed, to condense and separate the steam; and an extraction facility that extracts a carbon dioxide fluid exceeding a required circulation amount, determined according to the mechanical energy that needs to be obtained by the energy conversion, out of the carbon dioxide fluid from which moisture has been separated by the separator, and the mechanical energy obtained by driving the energy conversion turbine is supplied to a mechanical energy consumption device provided in the natural gas processing plant, the carbon dioxide fluid extracted from the extraction facility is supplied to a carbon dioxide reception facility capable of receiving carbon dioxide, and the carbon dioxide generated with production of the liquefied natural gas is not released to atmosphere.

5. The combined cycle natural gas processing system according to claim 3, wherein the mechanical energy consumption device is a rotary device provided in the natural gas processing plant, and the energy conversion turbine is a drive turbine configured to drive the rotary device.

6. The combined cycle natural gas processing system according to claim 5, wherein the carbon dioxide cycle plant further includes a power generation turbine that converts the energy held by the driving fluid into electrical energy, and electric power obtained by driving a generator using the power generation turbine is supplied to a power consumption device provided in the natural gas processing plant.

7. The combined cycle natural gas processing system according to claim 1, wherein the carbon dioxide fluid extracted from the extraction facility is supplied to the carbon dioxide reception facility that is at least one selected from a facility group including a carbon dioxide capture and storage (CCS) facility, an enhanced oil recovery (EOR) facility, a urea synthesis facility, a carbon dioxide mineralization facility, a methanation facility, and a carbon dioxide supply facility for photosynthesis promotion.

8. The combined cycle natural gas processing system according to claim 1, wherein the carbon dioxide separation stream separated by the acid gas removal unit is supplied to a carbon dioxide capture and storage (CCS) facility which is the carbon dioxide reception facility and is configured to pressurize and store the carbon dioxide separation stream, and the carbon dioxide fluid extracted from the extraction facility is supplied to the CCS facility which is the carbon dioxide reception facility, and joins the pressurized carbon dioxide separation stream, and the joined carbon dioxide fluid and the carbon dioxide separation stream are stored together.

9. The combined cycle natural gas processing system according to claim 1, wherein the natural gas processing plant includes an air separation unit (ASU) configured to separate air into an oxygen gas and a nitrogen gas to produce the oxygen gas to be supplied to the combustor, and the air separation unit includes a nitrogen gas supply line configured to supply the obtained nitrogen gas to at least one nitrogen gas use facility selected from a utility facility, a facility that supplies a purge gas to a seal drum of a flare stack, a facility that supplies a blanket gas to a storage tank, and a facility that supplies a microbubble gas for promoting a separation function in an oil-water separation unit.

10. The combined cycle natural gas processing system according to claim 9, wherein the natural gas processing plant includes a nitrogen gas separation unit that separates a nitrogen gas from the light hydrocarbon gas that is supplied to the combustor and contains the methane as the main component, and the nitrogen gas separated by the nitrogen gas separation unit joins nitrogen in the nitrogen gas supply line and is used in the nitrogen gas use facility.

11. The combined cycle natural gas processing system according to claim 1, further comprising an acid gas combustion facility that combusts an acid gas which is separated from the carbon dioxide separation stream and contains a sulfur compound, wherein the carbon dioxide cycle is provided with a carbon dioxide fluid heating unit that heats the carbon dioxide fluid using combustion exhaust heat of the acid gas in the acid gas combustion facility.

12. The combined cycle natural gas processing system according to claim 1, wherein the natural gas processing plant includes a light hydrocarbon gas supply line configured to supply a boil-off gas, vaporized in a storage tank storing the liquefied natural gas (LNG), as the light hydrocarbon gas to the combustor.

13. The combined cycle natural gas processing system according to claim 12, wherein the natural gas processing plant includes: a main cryogenic heat exchanger that liquefies and subcools the natural gas to obtain the LNG; an end flash unit that decompresses the LNG sent from the main cryogenic heat exchanger to a pressure of the storage tank and separates an end flash gas generated by the decompressing from the liquefied natural gas; an auxiliary supply line that causes a light hydrocarbon gas obtained by vaporizing the LNG in the end flash unit to join the light hydrocarbon gas supply line; and a control unit that executes control to increase a temperature of the LNG at an outlet of the main cryogenic heat exchanger in order to increase an evaporation amount of the LNG in the end flash unit in a case where a supply flow rate of the light hydrocarbon gas supplied from the light hydrocarbon gas supply line to the combustor is less than a target supply flow rate necessary for maintaining the required circulation amount of the carbon dioxide fluid even when an entire amount of the boil-off gas that is suppliable from the storage tank is supplied to the light hydrocarbon gas supply line.

14. The combined cycle natural gas processing system according to claim 12, wherein the natural gas processing LNG plant includes: a main cryogenic heat exchanger that liquefies and subcools the natural gas to obtain the LNG; an auxiliary supply line that extracts a part of the natural gas before being liquefied, which is supplied to the main cryogenic heat exchanger, from an inlet side of the main cryogenic heat exchanger to join the light hydrocarbon gas supply line as the light hydrocarbon gas; and a control unit that executes control to increase an extraction amount of the natural gas from the inlet side of the main cryogenic heat exchanger in a case where a supply flow rate of the light hydrocarbon gas supplied from the light hydrocarbon gas supply line to the combustor is less than a target supply flow rate necessary for maintaining the required circulation amount of the carbon dioxide fluid even if an entire amount of the boil-off gas that is suppliable from the storage tank is supplied to the light hydrocarbon gas supply line.

15. The combined cycle natural gas processing system according to claim 1, wherein the power consumption device includes a drive motor of a compressor that executes compression of a refrigerant to compress, cool, and liquefy the refrigerant again after the refrigerant used in the natural gas processing plant for cooling the natural gas is vaporized by heat exchange with the natural gas.

16. The combined cycle natural gas processing system according to claim 1, wherein the carbon dioxide cycle includes a heat exchange unit that heats a heating medium by heat exchange between the carbon dioxide fluid at a high temperature flowing in the carbon dioxide cycle and the heating medium flowing between the carbon dioxide cycle and the natural gas processing plant, and the heating medium heated by the heat exchange unit raises a temperature of a fluid to be heated, which flows through a device requiring a heat source provided in the natural gas processing plant, in a heating unit, and then, is supplied again to the heat exchange unit in a state of being lowered in temperature.

17. The combined cycle natural gas processing system according to claim 16, wherein the acid gas removal unit includes: an absorption column which absorbs an acid gas containing the carbon dioxide contained in the natural gas using a gas absorbing liquid; a regeneration column which regenerates the gas absorbing liquid; and a reboiler which raises a temperature of the gas absorbing liquid in the regeneration column and desorb the absorbed acid gas, and the heating unit is a reboiler, and the fluid to be heated is the gas absorbing liquid in the regeneration column.

18. The combined cycle natural gas processing system according to claim 4, wherein the mechanical energy consumption device is a rotary device provided in the natural gas processing plant, and the energy conversion turbine is a drive turbine configured to drive the rotary device.

19. The combined cycle natural gas processing system according to claim 18, wherein the carbon dioxide cycle plant further includes a power generation turbine that converts the energy held by the driving fluid into electrical energy, and electric power obtained by driving a generator using the power generation turbine is supplied to a power consumption device provided in the natural gas processing plant.

20. The combined cycle natural gas processing system according to claim 2, wherein the carbon dioxide fluid extracted from the extraction facility is supplied to the carbon dioxide reception facility that is at least one selected from a facility group including a carbon dioxide capture and storage (CCS) facility, an enhanced oil recovery (EOR) facility, a urea synthesis facility, a carbon dioxide mineralization facility, a methanation facility, and a carbon dioxide supply facility for photosynthesis promotion.

21. The combined cycle natural gas processing system according to claim 3, wherein the carbon dioxide fluid extracted from the extraction facility is supplied to the carbon dioxide reception facility that is at least one selected from a facility group including a carbon dioxide capture and storage (CCS) facility, an enhanced oil recovery (EOR) facility, a urea synthesis facility, a carbon dioxide mineralization facility, a methanation facility, and a carbon dioxide supply facility for photosynthesis promotion.

22. The combined cycle natural gas processing system according to claim 4, wherein the carbon dioxide fluid extracted from the extraction facility is supplied to the carbon dioxide reception facility that is at least one selected from a facility group including a carbon dioxide capture and storage (CCS) facility, an enhanced oil recovery (EOR) facility, a urea synthesis facility, a carbon dioxide mineralization facility, a methanation facility, and a carbon dioxide supply facility for photosynthesis promotion.

23. The combined cycle natural gas processing system according to claim 3, wherein the carbon dioxide separation stream separated by the acid gas removal unit is supplied to a carbon dioxide capture and storage (CCS) facility which is the carbon dioxide reception facility and is configured to pressurize and store the carbon dioxide separation stream, and the carbon dioxide fluid extracted from the extraction facility is supplied to the CCS facility which is the carbon dioxide reception facility, and joins the pressurized carbon dioxide separation stream, and the joined carbon dioxide fluid and the carbon dioxide separation stream are stored together.

24. The combined cycle natural gas processing system according to claim 2, wherein the power consumption device includes a drive motor of a compressor that executes compression of a refrigerant to compress, cool, and liquefy the refrigerant again after the refrigerant used in the natural gas processing plant for cooling the natural gas is vaporized by heat exchange with the natural gas.

Description

BRIEF DESCRIPTION OF DRAWINGS

[0031] FIG. 1 is a configuration diagram illustrating an example of a combined cycle natural gas processing system according to an embodiment.

[0032] FIG. 2 is a configuration diagram illustrating another example of the combined cycle natural gas processing system.

[0033] FIG. 3 is a configuration diagram illustrating an example of a supply control mechanism of a light hydrocarbon gas for a CO.sub.2 cycle power plant.

[0034] FIG. 4 is a configuration diagram illustrating another example of the supply control mechanism of the light hydrocarbon gas.

[0035] FIG. 5 is a configuration example of a combined cycle natural gas processing system that performs both mechanical energy supply and electrical energy supply from a CO.sub.2 cycle to a device provided in an LNG plant.

[0036] FIG. 6 is a configuration example of a combined cycle natural gas processing system that performs thermal energy supply from a CO.sub.2 cycle to a device provided in an LNG plant.

[0037] FIG. 7 is a configuration example of a combined cycle natural gas processing system that performs thermal energy supply from a device provided in an LNG plant to a CO.sub.2 cycle.

DESCRIPTION OF EMBODIMENTS

[0038] FIG. 1 is a configuration diagram of a combined cycle natural gas processing system 1 according to a first embodiment. The combined cycle natural gas processing system 1 of the present example includes: an LNG plant (natural gas processing plant) 3 that produces liquefied natural gas (LNG) from natural gas (NG); a supercritical (SC)-CO.sub.2 cycle power plant (carbon dioxide cycle power plant) 2 that performs cycle power generation using carbon dioxide (CO.sub.2) in a supercritical state.

[0039] In the example illustrated in FIG. 1, the combined cycle natural gas processing system 1 includes facilities for a pretreatment system that removes an impurity and a heavy component contained in NG, and a facility that liquefies and subcools the pretreated NG.

[0040] As the facilities for the pretreatment system, an acid gas removal unit (AGRU) 31 that separates acid gases such as CO.sub.2 and hydrogen sulfide (H.sub.2S) contained in NG, a dehydration unit 32 that removes moisture contained in NG, and a heavy component separation unit 33 that removes heavy hydrocarbons heavier than methane contained in NG are provided FIG. 1. In addition, the LNG plant 3 may include a gas-liquid separation unit that removes a liquid component contained in NG received from a wellhead, a mercury removal unit that removes mercury in NG, and the like as the facilities for the pretreatment system.

[0041] The AGRU 31 removes the acid gases, such as CO.sub.2 and H.sub.2S, which are likely to solidify in LNG during liquefaction. As a method for removing the acid gases, it is possible to apply a method using a gas absorbing liquid containing an amine compound or a method using a gas separation membrane that allows permeation of the acid gases in NG.

[0042] The acid gases separated from NG by the AGRU 31 are separated into CO.sub.2 containing a trace of light hydrocarbons and the other acid gases containing a sulfur compound such as H.sub.2S by an extraction operation or the like using a gas absorbing liquid of an amine compound in a separation unit 311. The acid gases from which CO.sub.2 containing a trace of light hydrocarbons has been separated is combusted in an acid gas combustion facility 37 to be detoxified, subjected to a treatment for removing air pollutants as necessary, and then, released to the atmosphere. When a sulfur concentration in the acid gases is high, sulfur is recovered and then combusted in the combustion facility 37.

[0043] In addition, a CO.sub.2 gas separated from the other acid gases in the separation unit 311 is sent to a CCS facility 4, which will be described later, as a CO.sub.2 separation stream (carbon dioxide separation stream).

[0044] The dehydration unit 32 removes a trace of moisture contained in the NG. For example, the dehydration unit 32 is filled with an adsorbent such as a molecular sieve or a silica gel, and includes: a plurality of adsorption columns in which an NG moisture removal operation and a regeneration operation of the adsorbent having adsorbed moisture are alternately switched; and a device such as a heater that heats a regeneration gas (for example, NG after moisture removal) of the adsorbent supplied to the adsorption columns where the regeneration operation is being performed.

[0045] NG containing moisture after being used for regeneration of the adsorbent is pressurized using a regeneration gas compressor 321 and returned to an inlet side of the AGRU 31, or is used as a fuel gas for a heater and the like provided in the combined cycle natural gas processing system 1.

[0046] The NG from which impurities such as the acid gases and moisture have been removed is subjected to a treatment of removing a heavy component heavier than methane in the heavy component separation unit 33. The heavy component separation unit 33 includes a cooler that cools the NG to liquefy the heavy component, a distillation column (demethanizer) that performs distillation and separation between a light gas (methane gas) containing methane as a main component and the liquefied heavy component, and the like. In addition, the heavy component separated from the methane gas by the demethanizer is distilled and separated into ethane, propane, butane, and a heavy condensate using a plurality of rectification columns.

[0047] The cooler that liquefies the heavy component may use the methane gas sent from the demethanizer as a self-refrigerant or may use a pre-cooling medium such as propane (FIG. 1 illustrates the former case). In a case where NG is cooled using the pre-cooling medium, a pre-cooling medium cycle is provided in which the pre-cooling medium is vaporized by heat exchange with the NG, then, a gas thereof is compressed, cooled, and liquefied again, and supplied to the cooler.

[0048] The methane gas from which the heavy component has been separated is pressurized by the separation unit 311 including a compressor as necessary, and then, cooled by a liquefying unit 341 to be liquefied, thereby producing LNG. The liquefying unit 341 includes, for example, a main cryogenic heat exchanger (MCHE) that cools, liquefies, and subcools NG with a liquefaction refrigerant that is a mixed refrigerant containing a plurality of types of refrigerant raw materials such as nitrogen, methane, ethane, and propane.

[0049] In addition, the liquefying unit 341 is provided together with a liquefaction refrigerant cycle 342 for compressing, cooling, and re-liquefying a gas of the liquefaction refrigerant vaporized by heat exchange with the methane gas, and supplying the resultant to the MCHE.

[0050] The LNG produced in the liquefying unit 341 is decompressed to a pressure equal to or lower than a reception pressure on an LNG tank (storage tank) 36 side in an end flash unit 35, and then, sent to the LNG tank 36 by an LNG pump 351. From the LNG tank 36, LNG is shipped to the LNG carrier 5 using a shipping pump 362, and the LNG loaded on the LNG carrier 5 is transported to a demand site.

[0051] The LNG plant 3 having the schematic configuration described above includes dynamic devices such as a compressor that compresses the above-described various refrigerants, a compressor (for example, a compressor of the regeneration gas compressor 321 or an NG pressurizing unit 331, a compressor 361 of a BOG to be described later, or a compressor 352 of an end flash gas) that pressurizes NG or the like, and pumps (for example, the LNG pump 351 and the shipping pump 362) for transfer of LNG. These dynamic devices consume energy to pressurize and transport various fluids, and the combined cycle natural gas processing system 1 of the present example is configured to operate these dynamic devices (power consumption devices) using a drive motor driven by electric power generated in the SC-CO.sub.2 cycle power plant 2.

[0052] The SC-CO.sub.2 cycle power plant 2 is a known power plant that generates power by driving a power generation turbine 23 using CO.sub.2 in the supercritical state as a driving fluid. In the example illustrated in FIG. 1, the SC-CO.sub.2 cycle power plant 2 includes a CO.sub.2 cycle for pressurizing and heating CO.sub.2 that has been used for driving of the power generation turbine 23 and supplying the CO.sub.2 again to the power generation turbine 23.

[0053] Hereinafter, a configuration example of the CO.sub.2 cycle will be described with reference to FIG. 1.

[0054] The power generation turbine 23 of the CO.sub.2 cycle is provided with a combustor 22, which combusts a light hydrocarbon gas to supply CO.sub.2, on an inlet side. The combustor 22 replenishes CO.sub.2 to the CO.sub.2 cycle by mixing and combusting an oxygen (O.sub.2) gas and light hydrocarbon gas in a flow of SC-CO.sub.2. In addition, steam is also generated by the combustion of the light hydrocarbon gas in the combustor 22.

[0055] In the combined cycle natural gas processing system 1 of the present example, a light hydrocarbon gas mainly containing a methane gas generated (by-produced) in the process of producing and storing LNG in the LNG plant 3 is used as the light hydrocarbon gas to be combusted in the combustor 22. In the following description, the light hydrocarbon (HC) gas containing methane as the main component is also simply referred to as an HC gas.

[0056] More specifically, the boil-off gas (BOG) generated by vaporization of a part of LNG in the LNG tank 36, the end flash gas generated when the pressure of LNG is adjusted in the end flash unit 35, and the like are used. These HC gases are separated from a nitrogen (N.sub.2) gas by a nitrogen gas separation unit 39, then pressurized by an HC gas supply unit 391 including a compressor, and supplied to the SC-CO.sub.2 cycle power plant 2 through an HC gas supply line 301. Note that reference signs 352 and 361 denote the compressors that supply the end flash gas and the BOG to the nitrogen gas separation unit 39, respectively. As described above, both the BOG and the end flash gas are supplied to the SC-CO.sub.2 cycle power plant 2 as the HC gas that is the methane gas with high purity from which the N.sub.2 gas has been removed.

[0057] An HC gas pressurizing unit 211 that pressurizes the HC gas is provided on the inlet side of the combustor 22, and the HC gas supplied through the HC gas supply line 301 is pressurized to a supply pressure for the CO.sub.2 cycle, and then, introduced into the combustor 22.

[0058] Note that a configuration example of a supply control mechanism configured to supply a required amount of the HC gas for the CO.sub.2 cycle will be described in detail with reference to FIGS. 3 and 4.

[0059] In addition, the HC gas is combusted in the combustor 22 using, for example, a high-purity O.sub.2 gas having a concentration equal to or higher than 99.8%. Thus, the LNG plant 3 is provided with an air separation unit (ASU) 38 configured to separate air into an O.sub.2 gas and a N.sub.2 gas to produce the oxygen gas to be supplied to the combustor 22.

[0060] The O.sub.2 gas produced in the ASU 38 is supplied to the SC-CO.sub.2 cycle power plant 2 through an O.sub.2 gas supply line 302. An oxygen gas pressurizing unit 212 that pressurizes the O.sub.2 gas is provided on the inlet side of the combustor 22, and the O.sub.2 gas supplied through the O.sub.2 gas supply line 302 is pressurized to the supply pressure for the CO.sub.2 cycle, and then, introduced into the combustor 22.

[0061] Note that a part of the O.sub.2 gas produced by the ASU 38 is supplied to the above-described acid gas combustion facility 37 and used for the combustion of the acid gas.

[0062] In the ASU 38 described above, the N.sub.2 gas is produced together with the O.sub.2 gas. This N.sub.2 gas is supplied to at least one N.sub.2 gas use facility selected from a utility facility that supplies the N.sub.2 gas as necessary in the combined cycle natural gas processing system 1, a facility that supplies a purge gas into a seal drum of a flare stack for combusting a surplus gas, a facility that supplies a blanket gas to a gas phase side in the LNG tank 36 to prevent formation of a flammable air-fuel mixture, and a facility that is used an oil-water separation unit, which performs oil-water separation of oil-containing wastewater discharged from a device in the combined cycle natural gas processing system 1, and supplies a microbubble gas into the wastewater to promote the oil-water separation function. The N.sub.2 gas is supplied to these N.sub.2 gas use facilities through a N.sub.2 gas supply line 305. In addition, the N.sub.2 gas may be used as a part of the refrigerant for liquefying and subcooling the methane gas.

[0063] In addition, the BOG and the end flash gas supplied to the combustor 22 as the HC gases are subjected to the N.sub.2 gas separation in the nitrogen gas separation unit 39 as described above. The N.sub.2 gas separated from the HC gases by the nitrogen gas separation unit 39 also merges with the nitrogen of the above-described N.sub.2 gas supply line 305 and is used in each of the N.sub.2 gas use facilities or is used as a part of the refrigerant for liquefying and subcooling the methane gas.

[0064] Returning to the description of the configuration of the CO.sub.2 cycle, the SC-CO.sub.2 replenished with CO.sub.2 in the combustor 22 is supplied to the power generation turbine 23, and power generation is performed by driving the power generation turbine 23 to which a generator 231 is connected. Electric power obtained by the power generation is supplied to each power consumption device in the LNG plant 3 and the SC-CO.sub.2 cycle power plant 2 including the compressor that compresses the refrigerant to be used for the production of LNG.

[0065] The CO.sub.2 gas discharged from the power generation turbine 23 and decompressed is subjected to heat exchange with CO.sub.2 before being supplied to the combustor 22 in a heat exchanger 241, and then, further cooled in a cooler 242. Through these cooling operations, the steam generated by combustion of the HC gas is condensed, and moisture is separated in a gas-liquid separator 243.

[0066] The CO.sub.2 gas from which the moisture has been separated is compressed by a compressor 251 and further cooled by a cooler 252 to become liquid CO.sub.2 and flow into a drum 261.

[0067] The liquid CO.sub.2 in the drum 261 is pressurized by a pressurizing pump 262, further heated to be in a state of SC-CO.sub.2, and supplied again to combustor 22. In the CO.sub.2 cycle of the present example, as means for heating CO.sub.2, a CO.sub.2 fluid heating unit 27 that uses exhaust heat obtained by combusting the acid gas in the above-described acid gas combustion facility 37 provided on the SC-CO.sub.2 cycle power plant 2 side, the heat exchanger 241 that performs heat exchange with the CO.sub.2 gas discharged from the power generation turbine 23, and the above-described combustor 22 that uses the combustion heat of the HC gas are provided.

[0068] Although simplified in FIG. 1, the heating of the CO.sub.2 gas using the CO.sub.2 fluid heating unit 27 will be briefly described. For example, the acid gas combustion facility 37 includes a heat exchange unit (not illustrated) capable of heating a heating medium such as hot oil, hot water, or steam by the combustion heat of the HC gas. The high-temperature heating medium heated in the acid gas combustion facility 37 is sent to the CO.sub.2 fluid heating unit 27. The CO.sub.2 fluid heating unit 27 heats the CO.sub.2 gas using the high-temperature heating medium. The heating medium of which the temperature has decreased due to the heat exchange with the CO.sub.2 gas in the CO.sub.2 fluid heating unit 27 is supplied again to the heat exchange unit of the acid gas combustion facility 37.

[0069] In FIG. 1, the CO.sub.2 fluid heating unit 27 is installed on the upstream side of the heat exchanger 241, but the CO.sub.2 fluid heating unit 27 may be incorporated in the heat exchanger 241. Since a position of the CO.sub.2 fluid heating unit 27 is determined by a heat level obtained in the acid gas combustion facility 37, the position is not limited.

[0070] Returning to the description of the CO.sub.2 cycle, the power generation is performed in the SC-CO.sub.2 cycle power plant 2 by circulating a CO.sub.2 fluid (CO.sub.2 gas, liquid CO.sub.2, or SC-CO.sub.2) in the CO.sub.2 cycle to drive the power generation turbine 23. Thus, the combustion gas containing CO.sub.2 is not released to the atmosphere as compared with a power plant using a gas turbine generator that drives a turbine by combusting a fuel gas or a steam turbine generator that drives a turbine by steam generated by combusting fuel. In addition, a high-purity and high-pressure CO.sub.2 fluid can be obtained from the CO.sub.2 cycle.

[0071] In this regard, the SC-CO.sub.2 cycle power plant 2 of the present example is configured to be capable of extracting a part of the CO.sub.2 fluid circulating in the CO.sub.2 cycle toward a CO.sub.2 reception facility configured for storage, fixation, utilization, and the like of CO.sub.2. In the present example, a liquid CO.sub.2 extraction line 201 for extracting the liquid CO.sub.2 before being heated by the CO.sub.2 fluid heating unit 27 from a position on an outlet side of the pressurizing pump 262 provided in the CO.sub.2 cycle is provided. The liquid CO.sub.2 extraction line 201 corresponds to a CO.sub.2 fluid extraction facility in the present example.

[0072] The pressure of the liquid CO.sub.2 extracted through the liquid CO.sub.2 extraction line 201 can be exemplified by a value within a range of 8 to 30 MPa. In addition, a flow rate of the liquid CO.sub.2 extracted through the liquid CO.sub.2 extraction line 201 is adjusted so as to maintain a state in which a circulation amount (required circulation amount) of the CO.sub.2 fluid, required for the generator 231 to generate power, circulates through the CO.sub.2 cycle with a preset output. That is, the CO.sub.2 fluid exceeding the required circulation amount is extracted through the liquid CO.sub.2 extraction line 201.

[0073] The liquid CO.sub.2 extracted by the liquid CO.sub.2 extraction line 201 is supplied to at least one carbon dioxide reception facility (CO.sub.2 reception facility) selected from a facility group including a carbon dioxide capture and storage (CCS) facility that stores CO.sub.2 in an underground aquifer 6, an enhanced oil recovery facility (EOR) facility that increases oil production by injecting CO.sub.2 into an oil field by pressure, a urea synthesis facility that causes CO.sub.2 to react with ammonia (NH 3) to synthesize urea, a carbon dioxide mineralization facility that causes CO.sub.2 to react with calcium or magnesium to be fixed, a methanation facility in which methane (CH 4) is produced using CO.sub.2 as a raw material, and a carbon dioxide supply facility for photosynthesis promotion configured to increase a crop production amount.

[0074] Here, the CCS facility may be configured to store CO.sub.2 in a deep salt water layer of the sea floor. In addition, in a case where CO.sub.2 is supplied to the EOR and the CCS in parallel, components of the EOR facility and the CCS facility may be shared.

[0075] Note that the extraction of CO.sub.2 in a liquid state is not an essential requirement, and the CO.sub.2 gas may be supplied according to the CO.sub.2 reception specification on the CO.sub.2 reception facility side. For example, a CO.sub.2 gas extraction line as an extraction facility may be connected to a position on an outlet side of the gas-liquid separator 243 provided in the CO.sub.2 cycle. Since the pressure of CO.sub.2 in the CO.sub.2 cycle is higher than the atmospheric pressure, high-purity and high-pressure CO.sub.2 can be supplied even when the CO.sub.2 gas before being compressed by the compressor 251 is extracted.

[0076] Further, in the combined cycle natural gas processing system 1, the CO.sub.2 gas separated from the NG in the AGRU 31 of the LNG plant 3 may also be supplied to at least one CO.sub.2 reception facility selected from the above-described facility group together with the liquid CO.sub.2 extracted from the CO.sub.2 cycle.

[0077] For example, an example in which the CO.sub.2 gas sent from the separation unit 311 at the subsequent stage of the AGRU 31 is pressurized by the CO.sub.2 gas pressurizing unit 312 and sent to the CCS facility 4 through the CO.sub.2 gas extraction line 303 is illustrated in the combined cycle natural gas processing system 1 illustrated in FIG. 1. The CO.sub.2 gas flowing through the CO.sub.2 gas extraction line 303 corresponds to a carbon dioxide separation stream of the present embodiment.

[0078] In the CCS facility 4, the received CO.sub.2 gas is compressed by a CO.sub.2 compressor 41 (in this case, the compressor 41 may be shared with the CO.sub.2 gas pressurizing unit 312 or omitted), and condensed moisture is separated by the CO.sub.2 dehydration unit 42. Subsequently, the CO.sub.2 gas is compressed again by a CO.sub.2 compressor 43 and then cooled by a cooler 44, thereby obtaining high purity and high pressure liquid CO.sub.2. The CO.sub.2 liquefied in the CCS facility 4 is separated into gas and liquid by a gas-liquid separator 45, and is sent to the underground aquifer 6 by a CO.sub.2 pump 46.

[0079] On the other hand, the liquid CO.sub.2 extracted from the SC-CO.sub.2 cycle power plant 2 through the liquid CO.sub.2 extraction line 201 described above is separated from moisture, and has a sufficiently high pressure. Thus, this liquid CO.sub.2 joins the liquid CO.sub.2 discharged from the SC-CO.sub.2 cycle power plant 2 side on the outlet side of the CO.sub.2 pump 46 in the CCS facility 4 and can be directly stored in the underground aquifer 6 as in the example illustrated in FIG. 1. As a result, the amount of CO.sub.2 processing in the CCS facility 4 can be reduced, and facility cost of the CCS facility 4 can be reduced.

[0080] Even when being supplied to another CO.sub.2 reception facility other than the CCS facility 4, the CO.sub.2 gas discharged from the LNG plant 3 (AGRU 31) is subjected to pressurization, moisture removal, and liquefaction according to the reception specification of each CO.sub.2 reception facility. Then, this CO.sub.2 gas is supplied to each CO.sub.2 reception facility together with the CO.sub.2 fluid (CO.sub.2 gas or liquid CO.sub.2) extracted from the SC-CO.sub.2 cycle power plant 2.

[0081] Next, a configuration example of a combined cycle natural gas processing system 1a according to a second embodiment will be described with reference to FIG. 2. Note that the same constituent elements as those of the combined cycle natural gas processing system 1 described with reference to FIG. 1 are denoted by the same reference signs as those illustrated in FIG. 1 in FIGS. 2 to 6 to be described hereinafter.

[0082] The combined cycle natural gas processing system 1a of FIG. 2 has a configuration in which a CO.sub.2 gas, separated from NG by the AGRU 31, is pressurized by the CO.sub.2 gas pressurizing unit 312 via a CO.sub.2 gas supply line 304, and then, is supplied to the CO.sub.2 cycle of the SC-CO.sub.2 cycle power plant 2. In this regard, the configuration is different from that of the combined cycle natural gas processing system 1 illustrated in FIG. 1 in which the CO.sub.2 gas separated by the AGRU 31 is supplied to the CCS facility 4 without passing through the CO.sub.2 cycle. The CO.sub.2 gas flowing through the CO.sub.2 gas supply line 304 corresponds to a carbon dioxide separation stream of the present embodiment.

[0083] In the example illustrated in FIG. 2, the CO.sub.2 gas pressurized by the CO.sub.2 gas pressurizing unit 312 joins a CO.sub.2 fluid (CO.sub.2 gas at this position) circulating in the CO.sub.2 cycle at the position between an outlet side of the power generation turbine 23 and the cooler 242, for example, between the heat exchanger 241 and the cooler 242.

[0084] The joined CO.sub.2 gas is subjected to moisture separation, pressurization, liquefaction, and heating together with the other CO.sub.2 fluid, and forms SC-CO.sub.2 to drive the generator 231.

[0085] Here, as compared with a case where CO.sub.2 is supplied using only the combustor 22 capable of supplying high-temperature CO.sub.2 by combustion of an HC gas, the supply of a relatively low-temperature CO.sub.2 gas from another position as described above also becomes a factor of lowering the thermal efficiency of the CO.sub.2 cycle. On the other hand, it is not necessary to provide the CCS facility 4 described with reference to FIG. 1, the facility investment at the time of construction can be suppressed.

[0086] The combined cycle natural gas processing systems 1 and 1a according to the respective embodiments described above have the following effects. The LNG plant 3 that produces LNG is provided together with the SC-CO.sub.2 cycle power plant 2 that performs power generation using the CO.sub.2 cycle. This LNG plant 3 combusts the HC gas (light hydrocarbon gas containing methane as the main component), by-produced in the LNG plant 3, with the high-purity O.sub.2 gas (of which the concentration is equal to or higher than 99.8%) obtained by the air separation using the ASU 38, and supplies the obtained CO.sub.2 having high energy to the CO.sub.2 cycle. Then, the power generation is performed in the CO.sub.2 cycle. As a result, the high energy at high pressure and high temperature obtained by combusting the HC gas by-produced in the LNG plant 3 can be effectively utilized. In addition, the low-energy CO.sub.2 consumed in the CO.sub.2 cycle is still supplied to various CO.sub.2 reception facilities in the high-purity state, and thus, the release of CO.sub.2 to the atmosphere accompanying the combustion of the HC gas is not performed.

[0087] In addition, CO.sub.2 separated from NG in the AGRU 31 of the LNG plant 3 is not released to the atmosphere either by being supplied to the CO.sub.2 reception facilities directly with the above-described CO.sub.2 fluid or after once joining the CO.sub.2 fluid circulating in the CO.sub.2 cycle.

[0088] Next, a configuration example of a control system that supplies the HC gas to the CO.sub.2 cycle 20 will be described with reference to FIGS. 3 and 4.

[0089] In FIGS. 3 and 4, the description of each device in the CO.sub.2 cycle 20 of the SC-CO.sub.2 cycle power plant 2 is omitted, and a comprehensive description is given. In addition, a comprehensive description is also given regarding the AGRU 31, the pretreatment unit 30 including the dehydration unit 32 and its ancillary devices, the heavy component separation unit 33, and the NG pressurizing unit 331 of the LNG plant 3. In addition, the description of the ASU 38 is omitted.

[0090] A generation amount of a BOG supplied to the SC-CO.sub.2 cycle power plant 2 as an HC gas greatly increases or decreases depending on the outside temperature, the presence or absence of shipment to the LNG carrier 5, and the like. In addition, the end flash unit 35 is the device provided for pressure adjustment of LNG as described above, and is not normally configured to prioritize securing of a supply amount of the HC gas with respect to the CO.sub.2 cycle 20.

[0091] In this regard, a combined cycle natural gas processing system 1b illustrated in FIG. 3 is configured to remove impurities and heavy components and replenish NG before being liquefied as the HC gas when the supply amount is insufficient only with the BOG and an end flash gas with respect to the demand for the HC gas in the CO.sub.2 cycle 20.

[0092] In the example illustrated in FIG. 3, a flow rate of each gas supplied toward the CO.sub.2 cycle 20 is controlled using a combustor supply gas control unit 101. At this time, a supply amount of an O.sub.2 gas is adjusted by a supply control valve 102 provided in the O.sub.2 gas supply line 302.

[0093] On the other hand, a flowmeter 106 is provided in the HC gas supply line 301 that supplies the HC gas toward the CO.sub.2 cycle 20, and an extraction amount of NG is controlled such that a flow rate of the HC gas detected by the flowmeter 106 approaches a target value. In the present example, the target value of the flow rate of the HC gas is set by the combustor supply gas control unit 101. In addition, the extraction amount of NG is controlled by adjusting an opening degree of an extraction control valve 104, provided in an auxiliary supply line 304a, by an HC gas supply control unit 103a. The auxiliary supply line 304a is connected to an inlet side of the MCHE in order to extract a part of NG before being liquefied that is supplied to the MCHE provided in the liquefying unit 341.

[0094] With this configuration, when the generation amount of the BOG and the extraction amount of the end flash gas are small and the flow rate of the flowmeter 106 is insufficient with respect to the target value, control is performed to increase the opening degree of the extraction control valve 104 to increase the extraction amount of NG. On the other hand, when the generation amount of the BOG and the extraction amount of the end flash gas are sufficient and the flow rate of the flowmeter 106 exceeds the target value, control is performed to reduce the opening degree of the extraction control valve 104 to decrease the extraction amount of NG.

[0095] Next, as another embodiment of the supply control mechanism of the HC gas, a combined cycle natural gas processing system 1c illustrated in FIG. 4 is configured to increase or decrease an extraction amount of an end flash gas. Specifically, control of the extraction amount of NG is executed by an HC gas supply control unit 103b. In this case, a piping line from which the end flash gas is extracted corresponds to an auxiliary supply line 304b.

[0096] Note that a plurality of the CO.sub.2 gas pressurizing units 312 may be arranged in parallel on an outlet side of the end flash unit 35 as illustrated in FIG. 4 in order to secure sufficient air supply capacity of the end flash gas in this configuration.

[0097] A control operation of the configuration illustrated in FIG. 4 will be described. When a generation amount of a BOG is small and a flow rate of the flowmeter 106 is insufficient with respect to a target value, an LNG temperature control unit 105, which is provided on an outlet side of the liquefying unit 341 and includes a temperature detection unit that detects the temperature of LNG, performs control to increase the temperature of LNG at the outlet of the liquefying unit 341. As a result, a generation amount of the end flash gas (evaporation amount of LNG) in the end flash unit 35 increases.

[0098] On the other hand, when the generation amount of the BOG is sufficient and the flow rate of the flowmeter 106 exceeds the target value, the temperature of LNG at the outlet of the liquefying unit 341 is lowered to decrease the generation amount of the end flash gas.

[0099] Here, a type of energy, which is supplied to an energy consumption device provided in the LNG plant 3 using the CO.sub.2 cycle, is not limited to the electrical energy generated by the generator 231. The high energy (high-temperature and high-pressure combustion energy) of CO.sub.2 flowing in the CO.sub.2 cycle may be converted into mechanical energy and supplied.

[0100] FIG. 5 schematically illustrates an example of an energy consumption device that receives supply of electrical energy or mechanical energy from the SC-CO.sub.2 cycle power plant (carbon dioxide cycle plant) 2 in a frame illustrating the LNG plant 3 of a combined cycle natural gas processing system 1d.

[0101] The SC-CO.sub.2 cycle power plant 2 illustrated in FIG. 5 supplies electric power to a motor that drives a pump 72 for liquid transportation flowing in the LNG plant 3, and a drive motor of an air cooled heat exchanger (ACHE) 73 that cools fluid. In FIG. 5, a reference sign 232 indicates an electrical room including a device for performing voltage control and power transmission control of the electric power generated by the generator 231. The ACHE 73 may be provided at the top of a pipe rack, or may be provided near the ground while holding the ACHE 73 by a dedicated frame. The motor of the pump 72 and the ACHE 73 correspond to power consumption devices of the present example. In addition to these, an electric heater can be exemplified as the power consumption device to which the electric power is supplied from the SC-CO.sub.2 cycle power plant 2.

[0102] Further, the SC-CO.sub.2 cycle power plant 2 illustrated in FIG. 5 is configured to extract SC-CO.sub.2 in the supercritical state from the outlet side of the combustor 22 and supply the extracted SC-CO.sub.2 to the power machines such as the compressor and the pump in addition to the power supply to the power consumption devices. FIG. 5 illustrates an example in which SC-CO.sub.2 is supplied to a turbine 711 of a turbine type compressor 71 provided in the LNG plant 3. The turbine 711 drives a compressor 712 that compresses a process fluid flowing in the LNG plant 3. The decompressed CO.sub.2 gas after having been used to drive the compressor 712 is returned to an inlet side of the heat exchanger 241 provided in the CO.sub.2 cycle. Examples of the process fluid can include various kinds of refrigerants (a pre-cooling medium for pre-cooling NG, or a liquefaction refrigerant for liquefying or subcooling NG) vaporized by heat exchange, NG (feed gas) supplied to the regeneration gas compressor 321 and the compressor of the NG pressurizing unit 331, and BOG generated in the LNG tank 36.

[0103] In addition, SC-CO.sub.2 extracted from the SC-CO.sub.2 cycle power plant 2 may be supplied to a turbine that drives a pump pressurizing a liquid. As the process fluid in this case, boiler water or the like can be exemplified.

[0104] The compressor 712 and the pump described above correspond to rotary devices of the present example, and the compressor 711 for driving these rotary devices corresponds to an energy conversion turbine of the SC-CO.sub.2 cycle power plant (carbon dioxide cycle plant) 2.

[0105] As described above, the SC-CO.sub.2 cycle power plant 2 illustrated in FIG. 5 is configured to be capable of supplying SC-CO.sub.2 to the power generation turbine 23 and the energy conversion turbine (for example, the turbine 711 in FIG. 5) in parallel and performing both conversion into electrical energy and conversion into mechanical energy. In this example, a required circulation amount for circulating the CO.sub.2 cycle is adjusted so as to maintain a circulation amount that enables the generator 231 to perform the power generation at a preset output and the compressor 711 to perform the conversion into the mechanical energy at a preset output.

[0106] A single (external fuel receiving type) power plant that combusts fuel having stable properties to obtain CO.sub.2 circulating in the CO.sub.2 cycle is normally intended to convert energy of high-temperature and high-pressure SC-CO.sub.2 into electrical energy. Thus, the power generation turbine 23 have a large size is provided, and the entire amount of high-temperature and high-pressure SC-CO.sub.2 obtained in the combustor 22 is supplied to the power generation turbine 23 to generate power. On the other hand, when a part of the high-temperature and high-pressure fluid of SC-CO.sub.2 is directly extracted and used for driving the turbine 711 as in the SC-CO.sub.2 cycle power plant 2 of the present example, the amount of electric power generated by the power generation turbine 23 decreases by such a usage.

[0107] In this regard, the combined cycle natural gas processing system 1d of the present example is provided with the LNG plant 3 and the SC-CO.sub.2 cycle power plant 2 together, which is different from the single power plant intended for power generation. With this configuration, it is possible to more freely provide a supply form contributing to improvement of energy efficiency of the entire combined cycle natural gas processing system 1d to each device in the LNG plant 3 without being limited to only the supply of electrical energy.

[0108] In general, when the energy of high-temperature and high-pressure SC-CO.sub.2 is used, it is most efficient to use the energy in a state of thermal energy by heat exchange or the like (energy efficiency is about 98%). Then, the energy efficiency decreases in the order of the conversion into mechanical energy for driving the turbine (about 40%) and the conversion into electrical energy (about 30%).

[0109] In this regard, since the SC-CO.sub.2 cycle power plant 2 is provided together with the LNG plant 3 in the combined cycle natural gas processing system 1d of the present example, it is possible to select the energy supply form from SC-CO.sub.2 of the high-temperature and high-pressure fluid while considering the function and scale of each energy consumption device and to enhance the energy efficiency of the entire combined cycle natural gas processing system 1d. Thus, the energy efficiency of the entire combined cycle natural gas processing system 1d can be improved as compared with a case where the entire energy is supplied as electrical energy. As described above, it is difficult to derive the idea of selecting the supply/use form of energy in each device to improve the energy efficiency of the entire combined cycle natural gas processing system 1d from the external fuel receiving type power plant installed only for power generation.

[0110] In addition, in a case where the LNG plant 3 is not provided with the SC-CO.sub.2 cycle power plant 2, it is necessary to combust an HC fuel gas in a boiler for generating steam or a gas turbine if the compressor 712 is driven by a steam turbine or the gas turbine. At this time, if CO.sub.2 generated by combustion of the fuel gas is not recovered, the CO.sub.2 is released to the atmosphere.

[0111] In this regard, the SC-CO.sub.2 cycle power plant 2 illustrated in FIG. 5 is configured to drive the turbine 711 by extracting SC-CO.sub.2 from the CO.sub.2 cycle as described above. With this configuration, it is unnecessary to use the boiler and the gas turbine, and it is also unnecessary to use a facility for recovering CO.sub.2 generated in these facilities. As a result, it is possible to configure the combined cycle natural gas processing system 1d that does not release CO.sub.2 to the atmosphere with a relatively simple configuration.

[0112] As described above, it is difficult to drive the configuration of the combined cycle natural gas processing system 1d that avoids not only the comprehensive energy efficiency but also the release of CO.sub.2 to the atmosphere from the external fuel receiving type CO.sub.2 cycle power plant that does not include an energy utilization device other than the power generation facility.

[0113] Further, installing the turbine type compressor 71 that supplies high-temperature and high-pressure SC-CO.sub.2 to the turbine 711 to drive the compressor 712 also has an effect of reducing a footprint (occupied area) of a facility. For example, in the case of a gas turbine compressor that drives the compressor 712 using a gas turbine, it is necessary to provide an air compressor that compresses combustion air.

[0114] In general, the air compressor provided together with the gas turbine compressor is extremely large and has a large footprint. On the other hand, it is unnecessary to provide the air compressor together with the turbine type compressor 71 of the present example using high-temperature and high-pressure SC-CO.sub.2, and there is a possibility that the footprint can be reduced to about as compared with the gas turbine compressor. As a result, it is possible to obtain a significant cost reduction effect in terms of both device cost and site cost.

[0115] Note that it is not essential to provide the power generation turbine 23 and the generator 231 together with the CO.sub.2 cycle plant that supplies SC-CO.sub.2 to the turbine 711 for driving the compressor 712. A carbon dioxide cycle plant including only an energy conversion turbine that supplies mechanical energy to a rotary device may be configured.

[0116] In addition, thermal energy may be supplied from the CO.sub.2 cycle to a device requiring a heat source provided in the LNG plant 3 through a heat exchange unit, in addition to the conversion into mechanical energy and electrical energy. A combined cycle natural gas processing system 1e of FIG. 6 is an example in which a heat exchanger (heat exchange unit) 241a that heats a heating medium (hot oil, hot water, or steam) is provided in the SC-CO.sub.2 cycle power plant 2 in addition to heating of CO.sub.2 before being supplied to the combustor 22 by heat exchange with CO.sub.2 discharged from the power generation turbine 23.

[0117] The heating medium heated by the heat exchanger 241a is used for heating of a fluid to be heated by a reboiler 743 which is a heat exchange unit provided in the LNG plant 3, and then, is supplied again to the heat exchanger 241a.

[0118] FIG. 6 illustrates an AGRU 31b configured to absorb and remove an acid gas containing CO.sub.2 from NG using a gas absorbing liquid in an absorption column 741. The AGRU 31b includes a regeneration column 742 configured to heat the gas absorbing liquid to desorb the acid gas and regenerate the gas absorbing liquid. In the present example, the reboiler 743 of the regeneration column 742, which is the device requiring the heat source, is configured as the above-described heat exchange unit, and the high-temperature heating medium is supplied from the above-described heat exchanger 241a to the reboiler 743. The low-temperature heating medium after having been used to raise the temperature of the gas absorbing liquid in the reboiler 743 is supplied again to the heat exchanger 241a in a cooled state.

[0119] In the above example, the gas absorbing liquid in the regeneration column 742 corresponds to the fluid to be heated, and the reboiler 743 corresponds to a heating unit for the fluid to be heated.

[0120] In addition, in the case of adopting a configuration for separating CO.sub.2 from another acid gas using a gas absorbing liquid as in the separation unit 311 described with reference to FIGS. 1 and 2, the reboiler 743 may be provided in a regeneration column provided in the separation unit 311. In this example as well, thermal energy of the high-temperature heating medium supplied from the heat exchanger 241a on the SC-CO.sub.2 cycle power plant 2 side is used for regeneration of the gas absorbing liquid.

[0121] Here, the fluid to be heated to which thermal energy is supplied from the CO.sub.2 cycle is not limited to the gas absorbing liquid for which regeneration is performed. For example, a heavy component which is subjected to distillation and separation in the distillation column and the rectification column of the heavy component separation unit 33 or a regeneration gas used for regeneration of the adsorbent in the dehydration unit 32 may be used as the fluid to be heated. As the heating medium for heating the fluid to be heated, the above-described hot oil, hot water, steam, or the like can be appropriately selected. In this case, various distillation column and rectification column provided in the LNG plant 3 correspond to the device requiring the heat source in the present example, and the reboiler and the heater provided in the distillation column and the rectification column correspond to the heating unit in the present example.

[0122] As described above, the combined cycle natural gas processing system 1e illustrated in FIG. 6 is configured to supply the thermal energy from the SC-CO.sub.2 cycle power plant 2 to the LNG plant 3. However, a direction of transfer of the thermal energy is not limited to this example.

[0123] For example, a combined cycle natural gas processing system if illustrated in FIG. 7 is configured to supply thermal energy from a device provided in the LNG plant 3 to the SC-CO.sub.2 cycle power plant 2.

[0124] In the combined cycle natural gas processing system if illustrated in FIG. 7, the LNG plant 3 includes an oxygen combustion heater 81 that combusts fuel using a high-purity O.sub.2 gas supplied from the ASU 38 to heat a heating medium (hot oil, hot water, or steam). A CO.sub.2 gas generated by combusting the fuel in the oxygen combustion heater 81 is pressurized by a blower 83 and supplied to the CO.sub.2 cycle of the SC-CO.sub.2 cycle power plant 2 through the CO.sub.2 gas supply line 304.

[0125] On the other hand, a part of the high-temperature heating medium heated by the oxygen combustion heater 81 is supplied to each user in the LNG plant 3. In addition, a part of the high-temperature heating medium is also supplied to the heat exchanger 241b provided in the CO.sub.2 cycle of the SC-CO.sub.2 cycle power plant 2 by a pump 82. The heat exchanger 241b of the present example heats CO.sub.2 before being supplied to the combustor 22 by heat exchange with the heating medium heated by the oxygen combustion heater 81 in addition to heat exchange with CO.sub.2 discharged from the power generation turbine 23 in the CO.sub.2 cycle.

[0126] The low-temperature heating medium after having been used to heat CO.sub.2 in the heat exchanger 241b is returned to the oxygen combustion heater 81 and heated. In addition, the low-temperature heating medium returned from each user in the LNG plant 3 joins a flow path for returning the heating medium from the heat exchanger 241b to the oxygen combustion heater 81, is returned to the oxygen combustion heater 81, and is heated.

[0127] As described above, when the high thermal energy obtained in a fuel combustion facility such as the oxygen combustion heater 81 is excessive on the LNG plant 3 side, the excessive thermal energy can be supplied to the SC-CO.sub.2 cycle power plant 2 side through the heat exchanger 241b. As a result, a combustion amount of an HC gas combusted in the combustor 22 can be reduced as compared with a case where the thermal energy is not supplied.

[0128] In addition, the CO.sub.2 fluid heating unit 27 illustrated in FIGS. 1 and 2 also corresponds to an example of the configuration in which the thermal energy excessive on the LNG plant 3 side is supplied to the SC-CO.sub.2 cycle power plant 2 side.

[0129] The combined cycle natural gas processing system 1e described with reference to FIG. 6 is configured to supply the thermal energy from the SC-CO.sub.2 cycle power plant 2 side to the LNG plant 3 side. In addition to this example, it is also possible to adopt the configuration in which the thermal energy is also supplied from the LNG plant 3 side to the SC-CO.sub.2 cycle power plant 2 side as in the combined cycle natural gas processing system if illustrated in FIG. 7. For example, the heat exchanger 241 may have both functions of a function of supplying heat to the LNG plant 3 and a function of receiving heat from the LNG plant 3 according to the balance of the thermal energy.

[0130] As described above, in the configuration in which the LNG plant 3 and the SC-CO.sub.2 cycle power plant 2 are provided together, the thermal energy can be supplied from one side of the LNG plant 3 and the SC-CO.sub.2 cycle power plant 2 to the other side according to the balance of the thermal energy. In addition, the SC-CO.sub.2 cycle power plant 2 can supply the thermal energy from the LNG plant 3 while supplying the thermal energy to the LNG plant 3. As described above, the heat exchange can be performed simultaneously and bidirectionally between the LNG plant 3 and the SC-CO.sub.2 cycle power plant 2 in the configuration in which the LNG plant 3 and the SC-CO.sub.2 cycle power plant 2 are provided together, so that a synergy effect can be obtained.

[0131] Here, examples of the combined cycle natural gas processing system 1 (FIG. 1) of a type in which the CO.sub.2 gas generated in the LNG plant 3 is directly supplied to the CCS facility 4 and the combined cycle natural gas processing system 1a (FIG. 2) of a type in which the CO.sub.2 gas generated in the LNG plant 3 is supplied to the SC-CO.sub.2 cycle power plant 2 have been described in FIGS. 1 and 2.

[0132] Among these, an application example of a technology for performing energy transfer between the SC-CO.sub.2 cycle power plant 2 and the LNG plant 3 with respect to the combined cycle natural gas processing system 1a of the type of FIG. 2 is illustrated in the combined cycle natural gas processing systems 1d to 1f according to the respective embodiments illustrated in FIGS. 5 to 7. However, the respective technologies described with reference to FIGS. 5 to 7 are not limited to the examples illustrated in these drawings, and may be applied to the combined cycle natural gas processing system 1 of the type described with reference to FIG. 1.

[0133] As described above, the combined cycle natural gas processing systems 1 and 1a to 1f of the present application include the SC-CO.sub.2 cycle power plant that supplies the high-temperature and high-pressure SC-CO.sub.2 to the power generation turbine 23 or the SC-CO.sub.2 cycle plant that drives the compressor 712 or the like using the high-temperature and high-pressure SC-CO.sub.2 to perform the conversion into mechanical energy (hereinafter, these are also collectively referred to as the SC-CO.sub.2 plant 2). In these combined cycle natural gas processing systems 1 and 1a to 1f, the electrical energy, mechanical energy and/or thermal energy generated by using the high-temperature and high-pressure SC-CO.sub.2 are used in the LNG plant 3. Then, CO.sub.2 discharged from the SC-CO.sub.2 plant 2 and the LNG plant 3 is supplied to the CO.sub.2 reception facility. As a result, zero emission is achieved in the entire facility required for the production of LNG.

[0134] Specifically, first, the HC gas containing methane as the main component, which is by-produced in the adjacent LNG plant 3, is supplied to the SC-CO.sub.2 plant 2. Then, the high energy of CO.sub.2 obtained by combusting the HC gas under the high temperature and high pressure together with the high-purity O.sub.2 gas (of which the concentration is equal to or higher than 99.8%) obtained by air separation by the ASU 38 is supplied as the electrical energy, mechanical energy, and/or thermal energy. As a result, the thermal energy obtained by the combustion of the HC gas by-produced in the LNG plant 3 is effectively utilized.

[0135] Second, the high energy generated in the SC-CO.sub.2 plant is converted into various energy forms as the electrical energy, mechanical energy, or thermal energy, and is used in the LNG plant 3 provided together with the SC-CO.sub.2 plant. This reduces CO.sub.2 generated when the hydrocarbon fuel is independently combusted in the LNG plant 3 in order to obtain required energy.

[0136] Third, the CO.sub.2 in the process removed from NG and the CO.sub.2 constantly extracted from the SC-CO.sub.2 plant 2 are isolated in the ground by the CO.sub.2 reception facility and are not released to the atmosphere. Through the above-described integration between facilities, a combined facility that does not discharge the CO.sub.2 in the LNG production process including not only the CO.sub.2 directly generated during the LNG production but also the CO.sub.2 generated as the by-product along with energy supply is constructed.

[0137] That is, the combined cycle natural gas processing systems 1 and 1a to 1f of the present examples can produce LNG without depending on renewable energy having unstable power supply capacity or external power that is likely to discharge CO.sub.2 during power generation, and thus, a zero-emission fuel can be achieved. In addition, in a case where carbon dioxide in an exhaust gas discharged from an air-combustion type combustion apparatus is absorbed using a chemical absorbing liquid (so-called Post Combustion), a recovery rate of carbon dioxide remains about 90%. However, the combined cycle natural gas processing systems 1 and 1a to 1f of the present examples can recover the carbon dioxide generated in the present system at a level close to 100%.

[0138] In this regard, external fuel receiving type power generation facilities in Patent Literatures 2 and 3 described above do not focus on CO.sub.2 generated in a facility to which energy is supplied and a facility which produces a fuel for power generation. Thus, even if an external fuel receiving type power plant itself includes the CO.sub.2 reception facility, when the facility to which the energy is supplied and the facility which produces the fuel for power generation includes hydrocarbon fuel combustion facilities, CO.sub.2 generated in these combustion facilities is released to the atmosphere. As described above, when the CO.sub.2 reception facility is provided for the external fuel receiving type power generation facility, it is difficult to achieve the zero emission in the entire facility including the facility to which the energy is supplied and the facility which produces the fuel for power generation. As described above, the combined cycle natural gas processing systems 1 and 1a to 1f of the present application do not perform simple and one-sided energy supply as in the conventional external fuel receiving type power generation facilities, but achieves the comprehensive zero emission in combination with the LNG plant 3.

[0139] In the combined cycle natural gas processing systems 1 and 1a to 1f according to the respective embodiments described above, the LNG plant 3 is not limited to one having a configuration provided on the ground. For example, the above-described embodiments can also be applied to a floating LNG (FLNG) plant in which the LNG plant 3 is disposed on a floating surface on the water. In this case, all the combined cycle natural gas processing systems 1 and 1a to 1f including the SC-CO.sub.2 cycle power plant 2 may be disposed on the floating surface.

[0140] In addition, the SC-CO.sub.2 cycle power plant 2 is not limited to the configuration in which the power generation turbine 23 is driven using SC-CO.sub.2 to generate power. For example, a case of adopting the SC-CO.sub.2 cycle power plant 2 configured to drive the power generation turbine 23 using a CO.sub.2 gas or a liquid CO.sub.2 to generate power is not excluded.

[0141] In addition, when excessive power is generated even if the power generated in the SC-CO.sub.2 cycle power plant 2 is supplied to the LNG plant 3 and the power consumption device in the SC-CO.sub.2 cycle power plant 2, the power may be supplied to a region outside the combined cycle natural gas processing systems 1 and 1a to 1f.

[0142] In addition, the term by-produced is a concept including both a case where the generation amount of the HC gas is not controlled in the process of producing and storing LNG and a case where the generation amount of the HC gas is controlled in consideration of excess or deficiency of fuel although not specifically described in the above embodiments.

REFERENCE SIGNS LIST

[0143] 1, 1a, 1b, 1c, 1e, 1f processing system [0144] 101 combined cycle natural gas [0145] 101 combustor supply gas control unit [0146] 102 supply control valve [0147] 103a HC gas supply control unit [0148] 103b HC gas gas supply control unit [0149] 104 extraction control valve [0150] 105 LNG temperature control unit [0151] 106 flowmeter [0152] 2 SC-CO.sub.2 cycle power plant [0153] 20 CO.sub.2 cycle [0154] 201 liquid CO.sub.2 extraction line [0155] 211 HC gas pressurizing unit [0156] 212 oxygen gas pressurizing unit [0157] 22 combustor [0158] 23 power generation turbine [0159] 231 generator [0160] 232 electrical room [0161] 241, 241a, 241b heat exchanger [0162] 242 cooler [0163] 243 gas-liquid separator [0164] 251 compressor [0165] 252 cooler [0166] 261 drum [0167] 262 pressurizing pump [0168] 27 CO.sub.2 fluid heating unit [0169] 3 LNG plant [0170] 30 pretreatment unit [0171] 301 HC gas supply line [0172] 302 O.sub.2 gas supply line [0173] 303 CO.sub.2 gas extraction line [0174] 304 CO.sub.2 gas supply line [0175] 304a, 304b auxiliary supply line [0176] 305 N.sub.2 gas gas supply line [0177] 31, 31b AGRU [0178] 311 separation unit [0179] 312 CO.sub.2 gas pressurizing unit [0180] 32 dehydration unit [0181] 321 regeneration gas compressor [0182] 33 heavy component separation unit [0183] 331 NG pressurizing unit [0184] 341 liquefying unit [0185] 342 liquefaction refrigerant cycle [0186] 35 end flash unit [0187] 351 LNG pump [0188] 352 compressor [0189] 36 LNG tank [0190] 361 compressor [0191] 362 shipping pump [0192] 37 acid gas combustion facility [0193] 39 nitrogen gas separation unit [0194] 391 HC gas supply unit [0195] 4 CCS facility [0196] 41 CO.sub.2 compressor [0197] 42 CO.sub.2 dehydration unit [0198] 43 CO.sub.2 compressor [0199] 44 cooler [0200] 45 gas-liquid separator [0201] 46 CO.sub.2 pump [0202] 5 LNG carrier [0203] 6 aquifer [0204] 71 turbine type compressor [0205] 711 turbine [0206] 712 compressor [0207] 72 pump [0208] 741 absorption column [0209] 742 regeneration column [0210] 743 reboiler [0211] 81 oxygen combustion heater [0212] 82 pump [0213] 83 blower