CA2983533C - Combined cycle power generation - Google Patents
Combined cycle power generation Download PDFInfo
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- CA2983533C CA2983533C CA2983533A CA2983533A CA2983533C CA 2983533 C CA2983533 C CA 2983533C CA 2983533 A CA2983533 A CA 2983533A CA 2983533 A CA2983533 A CA 2983533A CA 2983533 C CA2983533 C CA 2983533C
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- Prior art keywords
- turbine
- steam
- power generation
- working fluid
- gas
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- Expired - Fee Related
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- 238000010248 power generation Methods 0.000 title claims abstract description 45
- 239000007789 gas Substances 0.000 claims abstract description 37
- 239000012530 fluid Substances 0.000 claims abstract description 33
- 239000003949 liquefied natural gas Substances 0.000 claims abstract description 24
- 238000009835 boiling Methods 0.000 claims abstract description 12
- CURLTUGMZLYLDI-UHFFFAOYSA-N Carbon dioxide Chemical compound O=C=O CURLTUGMZLYLDI-UHFFFAOYSA-N 0.000 claims abstract 6
- 229910002092 carbon dioxide Inorganic materials 0.000 claims abstract 3
- 239000001569 carbon dioxide Substances 0.000 claims abstract 3
- 239000002918 waste heat Substances 0.000 claims description 30
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 claims description 29
- UGFAIRIUMAVXCW-UHFFFAOYSA-N Carbon monoxide Chemical compound [O+]#[C-] UGFAIRIUMAVXCW-UHFFFAOYSA-N 0.000 claims description 24
- 239000003546 flue gas Substances 0.000 claims description 24
- VNWKTOKETHGBQD-UHFFFAOYSA-N methane Chemical compound C VNWKTOKETHGBQD-UHFFFAOYSA-N 0.000 claims description 18
- 238000000034 method Methods 0.000 claims description 11
- 239000003345 natural gas Substances 0.000 claims description 9
- 230000008016 vaporization Effects 0.000 claims description 8
- 230000005611 electricity Effects 0.000 claims description 6
- 239000000446 fuel Substances 0.000 claims description 6
- 238000002347 injection Methods 0.000 claims description 6
- 239000007924 injection Substances 0.000 claims description 6
- 238000011084 recovery Methods 0.000 claims description 4
- 238000010438 heat treatment Methods 0.000 claims description 3
- 238000003303 reheating Methods 0.000 claims 1
- 239000006200 vaporizer Substances 0.000 description 14
- 238000004088 simulation Methods 0.000 description 7
- 230000008901 benefit Effects 0.000 description 6
- 230000007613 environmental effect Effects 0.000 description 2
- 230000004048 modification Effects 0.000 description 2
- 238000012986 modification Methods 0.000 description 2
- 238000005457 optimization Methods 0.000 description 2
- 239000013535 sea water Substances 0.000 description 2
- 230000006978 adaptation Effects 0.000 description 1
- 230000004075 alteration Effects 0.000 description 1
- 238000013459 approach Methods 0.000 description 1
- 239000006227 byproduct Substances 0.000 description 1
- 239000000567 combustion gas Substances 0.000 description 1
- 238000002485 combustion reaction Methods 0.000 description 1
- 238000009833 condensation Methods 0.000 description 1
- 230000005494 condensation Effects 0.000 description 1
- 238000007599 discharging Methods 0.000 description 1
- 238000005516 engineering process Methods 0.000 description 1
- 230000006872 improvement Effects 0.000 description 1
- 230000010354 integration Effects 0.000 description 1
- 239000007788 liquid Substances 0.000 description 1
- 238000004519 manufacturing process Methods 0.000 description 1
- 230000008569 process Effects 0.000 description 1
- 238000012552 review Methods 0.000 description 1
- 238000007711 solidification Methods 0.000 description 1
- 230000008023 solidification Effects 0.000 description 1
- 238000012546 transfer Methods 0.000 description 1
Classifications
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F01—MACHINES OR ENGINES IN GENERAL; ENGINE PLANTS IN GENERAL; STEAM ENGINES
- F01K—STEAM ENGINE PLANTS; STEAM ACCUMULATORS; ENGINE PLANTS NOT OTHERWISE PROVIDED FOR; ENGINES USING SPECIAL WORKING FLUIDS OR CYCLES
- F01K5/00—Plants characterised by use of means for storing steam in an alkali to increase steam pressure, e.g. of Honigmann or Koenemann type
-
- Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
- Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
- Y02E—REDUCTION OF GREENHOUSE GAS [GHG] EMISSIONS, RELATED TO ENERGY GENERATION, TRANSMISSION OR DISTRIBUTION
- Y02E20/00—Combustion technologies with mitigation potential
- Y02E20/16—Combined cycle power plant [CCPP], or combined cycle gas turbine [CCGT]
Landscapes
- Engineering & Computer Science (AREA)
- Chemical & Material Sciences (AREA)
- Combustion & Propulsion (AREA)
- Mechanical Engineering (AREA)
- General Engineering & Computer Science (AREA)
- Engine Equipment That Uses Special Cycles (AREA)
Abstract
A combined cycle power generation system configuration uses a steam- injected gas turbine as a topping cycle and a turbine in a bottoming cycle with liquefied natural gas as a cold sink. The turbine operates with a low boiling point fluid. The low boiling point fluid may, for example, be carbon dioxide.
Description
COMBINED CYCLE POWER GENERATION
FIELD
[0001] The present application relates generally to power generation and, more specifically, to combined cycle power generation.
BACKGROUND
FIELD
[0001] The present application relates generally to power generation and, more specifically, to combined cycle power generation.
BACKGROUND
[0002] It is known to generate electricity by driving a generator with a gas turbine. Furthermore, designers of power generation systems that feature gas turbines typically seek to improve efficiency, reduce capital cost and reduce environmental impact.
BRIEF DESCRIPTION OF THE DRAWINGS
BRIEF DESCRIPTION OF THE DRAWINGS
[0003] Reference will now be made, by way of example, to the accompanying drawings which show example implementations; and in which:
[0004] FIG. 1 schematically illustrates a combined cycle power generation system and a flow within the combined cycle power generation system, embodying aspects of the present application;
[0005] FIG. 2 illustrates a table of assumptions for values that may be used in a simulation of the combined cycle power generation system of FIG. 1;
[0006] FIG. 3 illustrates a table of optimization results from a simulation of the combined cycle power generation system of FIG. 1;
[0007] FIG. 4 illustrates a table of performance parameters for a simulation of the combined cycle power generation system of FIG. 1; and
[0008] FIG. 5 schematically illustrates the combined cycle power generation system of FIG. 1 with an addition and a modification embodying aspects of the present application.
DETAILED DESCRIPTION
DETAILED DESCRIPTION
[0009] In existing technologies that involve utilizing liquefied natural gas to improve power generation, the liquefied natural gas may be used to cool the inlet air to a gas turbine compressor. Alternatively, the liquefied natural gas may be used to cool steam turbine exhaust. Unfortunately, neither approach has more than limited improvement on the power cycle.
[0010] In other proposals, liquefied natural gas may be utilized to improve efficiency in power plants that employ an oxy-fuel combustion gas turbine or a gas turbine that uses another non-conventional working fluid. It seems that practical limitations have been getting in the way of commercialization of these proposals.
[0011] In contrast, in the combined cycle power generation system configuration that is proposed herein, integration of a steam-injected gas turbine as a topping cycle and a turbine in a bottoming cycle with liquefied natural gas as a cold sink can be shown to result in advantages in both cost and efficiency. The combined cycle power generation system configuration may be employed, for example, at a traditional liquefied natural gas receiving terminal. The bottoming cycle may employ a low boiling point working fluid such as 002.
[0012] According to an aspect of the present disclosure, there is provided a combined cycle power generation system. The combined cycle power generation system includes a gas turbine, a waste heat boiler, a condensing turbine and a condenser. The gas turbine receives natural gas fuel and an injection of steam, drives a load drive and generates flue gas. The waste heat boiler includes a heat recovery steam generator and a first heat exchanger configured to: receive the flue gas; condense water from the flue gas while vaporizing a low boiling point working fluid, thereby forming a vaporized working fluid; and heat the water to create the steam. The condensing turbine is driven by the vaporized working fluid, with the vaporized working fluid available at an output port of the first heat exchanger. The condenser is configured to receive liquefied natural gas and condense, while vaporizing the liquefied natural gas, the vaporized working fluid available at the output port of the condensing turbine.
[0013] According to an aspect of the present disclosure, there is provided a method of power generation. The method includes receiving, at a gas turbine, natural gas fuel and an injection of steam, driving, at a gas turbine, a load drive, generating, at the gas turbine, flue gas, condensing water from the flue gas while vaporizing a low boiling point working fluid, thereby forming a vaporized working fluid, heating the water to create the steam, driving a condensing turbine with the vaporized working fluid, with the vaporized working fluid available at an output port of the condensing turbine and condensing, while vaporizing liquefied natural gas, the vaporized working fluid available at the output port of the condensing turbine.
[0014] Other aspects and features of the present disclosure will become apparent to those of ordinary skill in the art upon review of the following description of specific implementations of the disclosure in conjunction with the accompanying figures.
[0015] In overview, a combined cycle power generation system configuration is disclosed in the present application. The combined cycle power generation system configuration uses a steam-injected gas turbine as a topping cycle and a turbine in a bottoming cycle with liquefied natural gas as a cold sink. For the steam-injected gas turbine, a reheat waste heat recovery steam generation scheme is used for higher efficiency. A CO2 Rankine cycle, in one option for the bottoming cycle, decouples a compressor and a turbine and has a pressurized condenser. Liquefied natural gas regasification may cool CO2 to lower than -50 C for higher efficiency.
[0016] FIG. 1 schematically illustrates a combined cycle power generation system 100 and a flow within the combined cycle power generation system 100, embodying aspects of the present application.
[0017] The combined cycle power generation system 100 includes a topping cycle 140, a waste heat boiler 108, a bottoming cycle 150 and a LNG
vaporizer/CO2 condenser 112.
vaporizer/CO2 condenser 112.
[0018] The topping cycle 140 includes a compressor 102, a combustor 103 and a gas turbine 104. The gas turbine 104 is mechanically connected to the compressor 102 and a first electricity generator 130.
[0019] The bottoming cycle 150 includes a CO2 pump 120, a heat exchanger 174, a CO2 turbine 106 and the LNG vaporizer/CO2 condenser 112.
[0020] The vaporizer/condenser 112 is connected to receive liquefied natural gas from a liquefied natural gas pump 118 and is connected to pass vaporized natural gas to a trim heater 114. The vaporizer/condenser 112 is also connected to receive CO2 gas from the waste heat boiler 108 and pass liquefied CO2 to the waste heat boiler 108 via a CO2 pump 120.
[0021] The waste heat boiler 108, which is associated with a CO2 turbine 106, is connected to receive exhaust flue gas from the gas turbine 104. The waste heat boiler 108 is also connected to receive liquefied CO2 from the vaporizer/condenser 112. The waste heat boiler 108 is also connected to provide gaseous CO2 to the turbine 106 and to receive exhaust CO2 from the CO2 turbine 106. The CO2 turbine 106 is mechanically connected to a second electricity generator 132.
[0022] The waste heat boiler 108 is also connected to pass exhaust water to a water treatment system 110 and to receive treated water from the water treatment system 110 via a feedwater pump 116.
[0023] The waste heat boiler 108 is also connected to pass exhaust CO2 to the vaporizer/condenser 112.
[0024] Even further, the waste heat boiler 108 is also connected to pass steam to the combustor 103 of the topping cycle 140.
[0025] The waste heat boiler 108 may include a heat recovery steam generator 172, a first heat exchanger 174 and a second heat exchanger 176.
[0026] FIG. 5 schematically illustrates an adapted combined cycle power generation system 500 and a flow within the adapted combined cycle power generation system 500, embodying further aspects of the present application.
[0027] The combined cycle power generation system 100 is adapted to form the adapted combined cycle power generation system 500 through the addition of a back pressure steam turbine 560 and an adaptation to the waste heat boiler 108 to form an adapted WHB 508.
[0028] In common with the waste heat boiler 108, the adapted WHB 508 receives water from the water treatment system 110 via the feedwater pump 116.
However, rather than passing steam generated from the received water to the combustor 103 of the topping cycle 140, the adapted WHB 508 passes the steam to the back pressure steam turbine 560. Steam at the output of the back pressure steam turbine 560 is received at the adapted WHB 508, from which the steam is reheated and passed to the combustor 103 of the topping cycle 140. The back pressure steam turbine 560 can also be mechanically connected to the second electricity generator 132.
However, rather than passing steam generated from the received water to the combustor 103 of the topping cycle 140, the adapted WHB 508 passes the steam to the back pressure steam turbine 560. Steam at the output of the back pressure steam turbine 560 is received at the adapted WHB 508, from which the steam is reheated and passed to the combustor 103 of the topping cycle 140. The back pressure steam turbine 560 can also be mechanically connected to the second electricity generator 132.
[0029] In operation, in the topping cycle 140, the compressor 102 receives, and compresses, air. The compressor 102 passes the compressed air to the gas turbine combustor 103.
[0030] The gas turbine combustor 103 receives three inputs: the compressed air from the compressor 102; natural gas from the outlet of the trim heater 114;
and steam generated in the waste heat boiler 108.
and steam generated in the waste heat boiler 108.
[0031] The gas turbine combustor 103 heats, using combustion of the natural gas as fuel, the air/steam combination.
[0032] The gas turbine 104 expands the flue gas received from the combustor 103. The result of the expanding is mechanical energy, which is used to drive a load.
Driving the load may take the form of driving the compressor 102 and a rotor of the first generator 130.
Driving the load may take the form of driving the compressor 102 and a rotor of the first generator 130.
[0033] The exhaust gas (flue gas) from the gas turbine 104 is passed to the waste heat boiler 108. Most of the steam in the flue gas may be condensed to exhaust water when cooled, within the waste heat boiler 108, by liquefied 002, the working fluid of the bottoming cycle 150. The waste heat boiler 108 passes the exhaust water (water condensed from the flue gas) to the water treatment system 110 for treatment.
[0034] The waste heat boiler 108 may employ the second heat exchanger 176 to heat (to, say, 50 C) the low-temperature (as low as 15 C) flue gas after steam condensation. A benefit of such heating of the flue gas before discharging the heated flue gas to a stack, is that the heated flue gas has more buoyancy than the low-temperature flue gas.
[0035] Some of the treated water, output from the water treatment system 110, may be pumped, by the feedwater pump 116, to the waste heat boiler 108 where the treated water may be heated into steam. As mentioned hereinbefore, the steam at the output of the waste heat boiler 108 may be received by the combustor 103 of the topping cycle 140. Some of the water output from the water treatment system may be exhausted as a by-product.
[0036] For a Rankine cycle with CO2 as the working fluid, it has previously been determined that the exhaust pressure of the CO2 turbine 106 is preferably higher than the pressure at triple-phase point, to avoid solidification at low temperature. For the purposes of studying the combined cycle power generation system 100, the exhaust pressure of the CO2 turbine 106 may be selected as 5.3 bar, which is slightly higher than the pressure at triple-phase point.
[0037] Consideration of the bottoming cycle 150 may start with the liquefied CO2 output to the CO2 pump 120 from the vaporizer/condenser 112. The liquefied CO2 is pumped, by the CO2 pump 120, to a higher pressure before being passed to the waste heat boiler 108, where the liquefied CO2 may be heated to gas state in the first heat exchanger 174 as steam in the flue gas is condensed, by the heat exchanger, to water. The CO2 gas, at high pressure and temperature enters the CO2 turbine 106. The CO2 turbine 106 expands the CO2 gas. The result of the expanding is mechanical energy, which is used to drive a load. Driving the load may take the form of driving a rotor of the second generator 132. Exhaust CO2 gas may be passed to the waste heat boiler 108, where the exhaust CO2 may be used, as discussed hereinbefore, to heat the low temperature flue gas. The exhaust CO2 gas may be passed, from the waste heat boiler 108, the condenser/vaporizer 112, where the exhaust CO2 gas may be further cooled and condensed in to its liquid state.
[0038] Liquefied natural gas may be pumped to higher pressure by the liquefied natural gas pump 118 before being introduced to the condenser/vaporizer 112.
Within the condenser/vaporizer 112, the liquefied natural gas may be re-gasified in the condenser/vaporizer 112. At the output of the condenser/vaporizer 112, the gaseous natural gas may be further heated in the trim heater 114 to a final temperature before the trim heater 114 supplies the gaseous natural gas to a pipeline and to the combustor 103 of the topping cycle 140.
Within the condenser/vaporizer 112, the liquefied natural gas may be re-gasified in the condenser/vaporizer 112. At the output of the condenser/vaporizer 112, the gaseous natural gas may be further heated in the trim heater 114 to a final temperature before the trim heater 114 supplies the gaseous natural gas to a pipeline and to the combustor 103 of the topping cycle 140.
[0039] FIG. 2 illustrates a table 200 of assumptions for values that may be used in a simulation of the combined cycle power generation system 100 of FIG. 1.
[0040] FIG. 3 illustrates a table 300 of optimization results from a simulation of the combined cycle power generation system 100 of FIG. 1. The table 300 shows values of CO2 flow rate and the inlet parameters of the CO2 turbine 106.
[0041] FIG. 4 illustrates a table 400 of performance parameters for a simulation of the combined cycle power generation system of FIG. 1. The table 400 of performance results shows that the combined cycle power generation system 100 of FIG. 1 may generate 454.2 MW net output and the net efficiency of the combined cycle may reach 65%. The efficiency achieved may be shown to be significantly higher than efficiency of a conventional combined cycle power generation system.
The performance parameters presented are based on simulation of the combined cycle power generation system with a GE 7FA gas turbine.
The performance parameters presented are based on simulation of the combined cycle power generation system with a GE 7FA gas turbine.
[0042] Steam-injected gas turbine used at the topping cycle 140 has advantage in lower specific capital cost (in $/kW). The capital cost of the system may be lower than a conventional combined cycle power generation system.
[0043] In operation of the adapted combined cycle power generation system 500, which is illustrated in FIG. 5, in common with the waste heat boiler 108, the adapted WHB 508 receives water from the water treatment system 110 via the feedwater pump 116. The adapted WHB 508 heats the received water to steam and passes the steam to the back pressure steam turbine 560. Steam at the output of the back pressure steam turbine 560 is received at the adapted WHB 508. The adapted WHB
508 includes at least one component more than the waste heat boiler 108 of FIG. 1.
That at least one component more being a re-heater 578. The steam received from the back pressure steam turbine 560 is heated by the re-heater before being passed to the combustor 103 of the topping cycle 140.
508 includes at least one component more than the waste heat boiler 108 of FIG. 1.
That at least one component more being a re-heater 578. The steam received from the back pressure steam turbine 560 is heated by the re-heater before being passed to the combustor 103 of the topping cycle 140.
[0044] Compared to a conventional combined cycle power generation system at a traditional liquefied natural gas receiving terminal, the new process may be shown to have several advantages. Example advantages include higher efficiency, lower price per kilowatt cost and the potential for water production.
[0045] Since the condenser/vaporizer 112 may gasify the liquefied natural gas using CO2 as a low boiling point working fluid, instead of the often used seawater, there may be an environmental benefit of reducing seawater heat transfer requirements. Notably, the condenser/vaporizer 112 may be considered to be compact and its operation may be considered to be cost effective.
[0046] The above-described implementations of the present application are intended to be examples only. Alterations, modifications and variations may be effected to the particular implementations by those skilled in the art without departing from the scope of the application, which is defined by the claims appended hereto.
Claims (14)
1. A combined cycle power generation system comprising:
a gas turbine that:
receives natural gas fuel and an injection of steam;
drives a load drive; and generates flue gas;
a waste heat boiler including a heat recovery steam generator and a first heat exchanger configured to:
receive the flue gas;
condense water from the flue gas while vaporizing a low boiling point working fluid, thereby forming a vaporized working fluid; and heat the water to create the steam;
a condensing turbine driven by the vaporized working fluid, with the vaporized working fluid available at an output port; and a condenser configured to:
receive liquefied natural gas; and condense, while vaporizing the liquefied natural gas, the vaporized working fluid available at the output port of the condensing turbine.
a gas turbine that:
receives natural gas fuel and an injection of steam;
drives a load drive; and generates flue gas;
a waste heat boiler including a heat recovery steam generator and a first heat exchanger configured to:
receive the flue gas;
condense water from the flue gas while vaporizing a low boiling point working fluid, thereby forming a vaporized working fluid; and heat the water to create the steam;
a condensing turbine driven by the vaporized working fluid, with the vaporized working fluid available at an output port; and a condenser configured to:
receive liquefied natural gas; and condense, while vaporizing the liquefied natural gas, the vaporized working fluid available at the output port of the condensing turbine.
2. The combined cycle power generation system of claim 1 further comprising a steam turbine, wherein the waste heat boiler is configured to produce steam for driving the steam turbine.
3. The combined cycle power generation system of claim 2 wherein the steam turbine emits exhaust steam and the waste heat boiler further includes a re-heater configured to reheat the exhaust steam for injection into the gas turbine.
4. The combined cycle power generation system of claim 1 further comprising a second heat exchanger employing heat from the vaporized working fluid available at the output port of the condensing turbine to reheat the flue gas.
5. The combined cycle power generation system of claim 1 further comprising a pump configured to increase pressure of the low boiling point fluid to higher pressure.
6. The combined cycle power generation system of claim 1 wherein the low boiling point fluid comprises carbon dioxide.
7. The combined cycle power generation system of claim 1 wherein the load drive comprises an electricity generator.
8. A method of power generation comprising:
receiving, at a gas turbine, natural gas fuel and an injection of steam;
driving, at the gas turbine, a load drive;
generating, at the gas turbine, flue gas;
condensing water from the flue gas while vaporizing a low boiling point working fluid, thereby forming a vaporized working fluid;
heating the water to create the steam;
driving a condensing turbine with the vaporized working fluid, with the vaporized working fluid available at an output port of the condensing turbine;
and condensing, while vaporizing liquefied natural gas, the vaporized working fluid available at the output port of the condensing turbine.
receiving, at a gas turbine, natural gas fuel and an injection of steam;
driving, at the gas turbine, a load drive;
generating, at the gas turbine, flue gas;
condensing water from the flue gas while vaporizing a low boiling point working fluid, thereby forming a vaporized working fluid;
heating the water to create the steam;
driving a condensing turbine with the vaporized working fluid, with the vaporized working fluid available at an output port of the condensing turbine;
and condensing, while vaporizing liquefied natural gas, the vaporized working fluid available at the output port of the condensing turbine.
9. The method of claim 8 further comprising driving a steam turbine with the steam.
10. The method of claim 9 wherein the steam turbine emits exhaust steam and the method further comprises reheating the exhaust steam for injection into the gas turbine.
11. The method of claim 8 further comprising employing heat from the vaporized working fluid to reheat the flue gas.
12. The method of claim 8 further comprising increasing pressure of the low boiling point fluid to higher pressure.
13. The method of claim 8 wherein the low boiling point fluid comprises carbon dioxide.
14. The method of claim 8 wherein the load drive comprises an electricity generator.
Applications Claiming Priority (3)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| US201562150046P | 2015-04-20 | 2015-04-20 | |
| US62/150,046 | 2015-04-20 | ||
| PCT/CA2016/050447 WO2016168923A1 (en) | 2015-04-20 | 2016-04-18 | Combined cycle power generation |
Publications (2)
| Publication Number | Publication Date |
|---|---|
| CA2983533A1 CA2983533A1 (en) | 2016-10-27 |
| CA2983533C true CA2983533C (en) | 2018-06-19 |
Family
ID=57142735
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA2983533A Expired - Fee Related CA2983533C (en) | 2015-04-20 | 2016-04-18 | Combined cycle power generation |
Country Status (2)
| Country | Link |
|---|---|
| CA (1) | CA2983533C (en) |
| WO (1) | WO2016168923A1 (en) |
Families Citing this family (1)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| CN111828173B (en) * | 2020-07-14 | 2021-11-19 | 西安交通大学 | Combined cooling, heating and power generation device of micro-miniature gas turbine and working and control method thereof |
Family Cites Families (2)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US20050241311A1 (en) * | 2004-04-16 | 2005-11-03 | Pronske Keith L | Zero emissions closed rankine cycle power system |
| JP6010489B2 (en) * | 2013-03-12 | 2016-10-19 | 三菱日立パワーシステムズ株式会社 | Thermoelectric variable cogeneration system |
-
2016
- 2016-04-18 CA CA2983533A patent/CA2983533C/en not_active Expired - Fee Related
- 2016-04-18 WO PCT/CA2016/050447 patent/WO2016168923A1/en active Application Filing
Also Published As
| Publication number | Publication date |
|---|---|
| CA2983533A1 (en) | 2016-10-27 |
| WO2016168923A1 (en) | 2016-10-27 |
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