WO2020035470A1

WO2020035470A1 - Gas cycle and method

Info

Publication number: WO2020035470A1
Application number: PCT/EP2019/071644
Authority: WO
Inventors: Ian Bennett; Pranav PRABHASH
Original assignee: Shell Internationale Research Maatschappij B.V.; Shell Oil Company
Priority date: 2018-08-14
Filing date: 2019-08-13
Publication date: 2020-02-20

Abstract

A system and method are disclosed. The system comprising: an ejector for receiving a gaseous feed stream and a pressurized fluid stream and for providing a mix thereof at an outlet of the ejector; a separator for receiving the mix of the gaseous feed stream and the pressurized fluid stream from the ejector, and having a first separator outlet for providing a first fluid stream and a second separator outlet for providing a second substantially fluidic stream; and a pump for receiving the first fluid stream from the separator, pressurizing the first fluid stream and for providing the pressurized first fluid stream to ejector.

Description

GAS CYCLE AND METHOD

FIELD OF THE INVENTION

The present invention is directed to an improved gas power cycle and an associated method. The cycle and method are for instance suitable for power generation or to compress gases of fluids in an industrial process. The industrial process may, for instance, include a power cycle to generate electricity or to drive equipment, or a process to capture carbon dioxide from flue gas.

BACKGROUND TO THE INVENTION

Global warming, also referred to as climate change, is the observed century- scale rise in the average temperature of the Earth's climate system and its related effects. Many of the observed changes since the l950s are unprecedented in the instrumental temperature record which extends back to the mid- 19th century, and in paleoclimate proxy records covering thousands of years. Possible societal responses to global warming include mitigation by emissions reduction. This adds a powerful argument to the general aim of improving the energy efficiency of equipment to reduce fuel costs and operating expenditure.

At present, the highest cycle thermal efficiency of all thermal engines is achieved by a combined cycle gas and steam turbine plant using natural gas (or other hydrocarbon fuels). Thermal efficiency can typically be about 60% at lower heating value (LHV).

Patent applications RS201400129 ("Configuring of steam- or water-driven mixing ejector in gas-turbine cycle power-plant configuration"; Republic of Serbia, 2lst of March 2014) and RS201601092 ("Recuperated gas-turbine cycle power plant with pressurized water driven mixing ejector"; 2lst of March 2014), both by inventor Stankovi Branko, disclose gas-turbine cycles having increased thermal efficiency. A description of the systems disclosed in both patent applications is also provided in the article "Gas-Turbine-Cycle Power Plant Configurations With Steam- Or Water- Driven Mixing Ejector", IEEE paper 7748780, by the same author, now referred to as Branko Stankovic.

The article by B. Stankovic discloses, for instance, a recuperated gas turbine (GT) cycle power-plant configuration with a pressurized-water driven, or optionally pressurized- water-compressed-air driven, mixing ejector. It consists of an (optional) air compressor for compressing air, a mixing ejector, a separation tank for separation of gas (air) and liquid (water) phases, a water cooler for rejection of heat from the separated liquid phase, a recuperative heat-exchanger (recuperator) for pre combustion heating of the separated humid air by the cycle waste heat, a combustor for a total isobaric combustion of a gaseous (typically natural gas) or a liquid fuel in the stream of separated humid air, a main combustion gas turbine for full expansion of the combusted gas, driving both the said compressor and a load, typically an electric generator, a water pump for pressurizing and recirculation of the separated water back to the said mixing ejector, and an additional water pump for recovery and pressurizing of the water fraction that might be lost in the stream of separated humid air.

US3861151 provides an engine operating system. The system comprises a venturi tube consisting of two closely opposite nozzles, the neighbouring part of such opposing ends of the nozzles being tightly closed so as to form a suction port. These are arranged in a liquid cycle, and an exit of the venturi tube is connected with a gas (or air)-liquid separator. An upper end of the separator is connected to an engine member by way of a heater, while a bottom end of the separator is connected to an inlet of said venturi tube by way of a driving pump. A suction port of the venturi tube is connected through a pipe to open air or to a gas (or air) exit of the engine member.

DE102013020087 provides a system. Herein, a phase separator separates a liquid phase from a gaseous phase of a working medium between a first evaporator and an expander. A suction beam conveying device is connected between the first evaporator and a phase separator or between conveying unit and the first evaporator in a Rankine cycle. A liquid phase region of the phase separator is connected to an input of the suction beam conveying device through secondary circuit line of addition circuit. A second evaporator is arranged between the phase separator and the suction beam conveying device in a secondary circuit. The system also includes a waste heat utilization arrangement.

SUMMARY OF THE INVENTION

The present application aims to provide a system and method having an improved thermal efficiency.

In one aspect, the present invention is directed to a system, comprising: an ejector for receiving a gaseous feed stream and a pressurized liquid working fluid stream and for providing a mixture thereof at an outlet of the ejector;

a separator for receiving the mixture of the gaseous feed stream and the pressurized liquid working fluid stream from the ejector, and having a first separator outlet for providing a liquid working fluid stream and a second separator outlet for providing a second substantially gaseous stream; and

a pump for receiving the liquid working fluid stream from the separator, pressurizing the liquid working fluid stream and for providing the pressurized liquid working fluid stream to the ejector.

A substantially isothermal compression process can be achieved in the ejector. The heat of compression in the ejector can be taken by the water during the compression itself. The Ejector is static machinery, offering increased reliability due to the absence of moving parts and the associated wear.

In an embodiment, the gaseous feed stream and the second substantially gaseous stream comprise gaseous hydrocarbons, and the system further comprises: a combustor for receiving the second substantially gaseous stream from the separator and for combusting said second substantially gaseous stream to provide a combusted gaseous stream;

a gas turbine for receiving the combusted gaseous stream from the combustor for expansion of the combusted gaseous stream, to provide an expanded combusted gaseous stream.

In an embodiment, the system comprises a recuperator arranged between the separator and the combustor for heat exchange between the expanded combusted gaseous stream and the gaseous stream.

The system may comprise a recuperator arranged to receive the expanded combusted gaseous stream from the gas turbine, the recuperator being adapted for heat exchange between the expanded combusted gaseous stream and a cold stream.

In another embodiment, the gaseous feed stream and the gaseous stream comprises flue gas comprising at least carbon dioxide, the system further comprising: a cooler for receiving the second substantially gaseous stream from the separator and for cooling said second substantially gaseous stream; and

a recycle pump for receiving the cooled liquid stream from the cooler and for providing a pressurized cooled liquid stream. In yet another embodiment, the system comprises:

a turbine for providing power and for expanding the flue gas;

a recuperator for receiving the flue gas from the turbine and for heat exchanging the flue gas against the pressurized cooled gaseous stream.

The system may comprise an export outlet connected to the second outlet of the separator for exporting at least part of the second substantially gaseous stream comprising at least carbon dioxide.

According to another aspect, the disclosure provides a method, the method comprising the steps of:

receiving a gaseous feed stream and a pressurized liquid working fluid stream at an inlet of an ejector and providing a pressurized mixture thereof at an outlet of the ejector;

receiving the pressurized mixture in a separator, and providing a first liquid working fluid stream at a first separator outlet and providing a second substantially gaseous stream at a second separator outlet; and

pressurizing the first liquid working fluid stream of the first separator outlet and providing the pressurized liquid working fluid stream to the inlet of the ejector.

In an embodiment,

the gaseous feed stream and the second substantially gaseous stream comprise gaseous hydrocarbons, the method comprising the further steps of:

combusting the second substantially gaseous stream from the second outlet of the separator to provide a combusted gaseous stream;

expanding the combusted gaseous stream in a gas turbine to provide an expanded combusted gaseous stream.

In an embodiment, the method comprises the step of heat exchanging the expanded combusted gaseous stream versus the second substantially gaseous stream.

The method may comprise the steps of:

heat exchanging the expanded combusted gaseous stream and a cold stream.

In yet another embodiment, the gaseous feed stream and the second

substantially gaseous stream comprise flue gas comprising at least carbon dioxide, and the method comprises the further steps of:

receiving the second substantially gaseous stream from the separator and cooling said gaseous stream; and receiving the cooled gaseous stream from the cooler and pressurizing the cooled gaseous stream.

The method may comprise the steps of:

using a turbine for providing power and for providing the flue gas;

receiving the flue gas from the turbine at a recuperator and heat exchanging the flue gas against the pressurized cooled gaseous stream.

The method may comprise the step of exporting at least part of the second substantially gaseous stream comprising at least carbon dioxide.

BRIEF DESCRIPTION OF THE DRAWINGS

The drawing figures depict one or more implementations in accord with the present teachings, by way of example only, not by way of limitation. In the figures, like reference numerals refer to the same or similar elements.

Figure 1 is an illustration of a conventional power cycle;

Figure 2 is an exemplary diagram indicating temperature (vertical axis) versus entropy (horizontal axis) of the conventional power cycle of Figure 1 ;

Figure 3 shows a diagram of a power cycle according to an embodiment of the disclosure;

Figure 4 shows a diagram of a power cycle according to another embodiment;

Figure 5 is an exemplary diagram indicating temperature (vertical axis) versus entropy (horizontal axis) of an embodiment of a power cycle of the present disclosure;

Figure 6 is a diagram of an Allam cycle in accordance with a prior art disclosure; and

Figure 7 is a diagram of a detail of the Allam cycle of Figure 6, including an embodiment of a system according to the present disclosure.

DETAIFED DESCRIPTION OF THE INVENTION

Certain terms used herein are defined as follows:

"Allam cycle" is a general reference to a process cycle as disclosed in the article "Demonstration of the Allam Cycle: An update on the development status of a high efficiency supercritical carbon dioxide power process employing full carbon capture", Energy Procedia 114 (2017) 5948 - 5966, Rodney Allam et al., l3th International Conference on Greenhouse Gas Control Technologies, GHGT-13, 14- 18 November 2016, Fausanne, Switzerland. Depending on the context and selected fuel, the reference may refer to either the version for gaseous fuel (such as natural gas and/or biogas) or solid fuel (such as coal).

LNG refers to liquefied natural gas, which is typically cooled to at least a termperature whereat the gas can be in the liquid phase at about 1 bar pressure; for liquefied methane this temperature is about minus 162 degree C.

Figure 1 shows a conventional setup for a power cycle 10, the power cycle comprising a compressor, a combustor 14, and a turbine. The turbine may drive equipment via shaft 20, such as a generator or another compressor.

The cycle 10 is enabled by circulating a working fluid via the subsequent components of cycle 1. The working fluid enters the compressor at inlet 1 for substantially isentropic compression (see also Fig. 2). The compressed working fluid is provided to the combustor 14 for combustion. The working fluid may be air, to be combusted together with a fuel 18. The combusted working fluid is subsequently provided to the turbine for substantially isentropic expansion. If the working fluid is air, it may be exausted to the environment 4 wherein new air is taken in at inlet 1 of the compressor. Figure 2 shows the corresponding entropy (horizontal axis) versus temperature (vertical axis) diagram.

In Fig. 2, please note that the dotted line between points 4 and 1 indicates the potential for a closed cycle. The latter is contrary to the setup shown in Fig. 1, which is an open cycle wherein there will not be a return from point 4 to the intial state of point 1.

See for instance patent documents US-6141955 and US-7200997 for a more detailed description of state of the art arrangements of cycles including at least one compressor and at least one gas turbine and the specifics and associated

thermodynamics thereof.

Figure 3 shows a schematic diagram of an embodiment of a system for power generation. The system 30 includes a multiphase ejector 32 provided with a first ejector inlet 34 for a gas mixture 36 and a second ejector inlet 38 for a pressurized fluid 40. The gas mixture may typically be air or another oxygen comprising gas mixture. The fluid may be substantially water. The ejector has an outlet 42 for providing a two-phase fluid-gas mixture 44 to a separator 46. The separator 46 has a first separator outlet 48, arranged at or near a lower end of the separator 46, for providing a fluid fraction 50 of the two-phase fluid-gas mixture, and a second separator outlet 52, arranged at or near an upper end of the separator 46, for providing a gas fraction 54 of the two-phase fluid-gas mixture. The fluid fraction 50 is directed to a fluid pump 56. The pump 56 is adapted to pressurize the fluid 50 and provide the pressurized fluid 40. Cooler 58 is arranged in the line to cool the separated fluid 50. This cooler can be situated before or after the pump 56.

In an embodiment (Fig. 3), the second separator outlet 52 is connected to a heat exchanger or recuperator 60 for heating the gas 54. The system comprises a combustor 62 having a first combustor inlet 64 inlet for receiving a gas stream 66 from the recuperator and a second combustor inlet 68 for receiving a fuel 70 and possibly other reactants. A turbine 72 is connected to an outlet of the combustor 62 for receiving flue gas 74 from the combustor. The turbine 72 is, for instance, mechanically connected to axis 20 for driving other equipment, such as a generator (not shown). An outlet 78 of the turbine 72 is connected to the recuperator 60.

Expanded flue gas 76 is directed to the recuperator 60 for heat exchange with the gas stream 54. Cooled flue gas 80 is provided at an outlet of the recuperator.

In another embodiment (Fig. 4), the gas stream 54 is directly provided to the combustor 62. A recuperator 60 is connected to the outlet 78 of the turbine 72.

Expanded flue gas 76 is provided from the turbine outlet 78 to the recuperator for heat exchange with an additional working fluid 82. Warmed working fluid and cooled flue gas 86 are provided at an outlet of the recuperator. This embodiment may be beneficial if the heat exchanger is to extract waste heat for a teriary heat recovery cycle. Such cycle includes, for instance, Organic Rankine Cycles and HRSG.

In a method of operation, air 36 at about atmospheric pressure enters the multiphase ejector 32. The air mixes with very high-pressure water 40 that works as the motive fluid in the ejector 32. As an example, very-high pressure herein means a pressure exceeding 20 to 500 bara. The two-phase water-air mixture 42 leaves the ejector at an intermediate pressure, thereby achieving compression of the air. As an example, intermediate pressure herein means a pressure in the range of, about, 4-100 bara. The water-air mixture 42 is separated in the separator 44. Optionally, the compressed air 54 from the separator 44 passes through the recuperator 60 where it gets heated, to provide heated compressed air 66. The compressed air 54 (Fig. 4) or compressed heated air 66 (Fig. 3) is mixed with fuel 70 in the combustor 62 and ignited to produce flue gas 74. The fuel may be a gaseous or liquid hydrocarbon, such as natural gas. The flue gas 74 comprises a mixture of air and combustion products including C0₂ and H₂0. The turbine 72 extracts energy from the hot flue gas 74 by expansion of the flue gas in the turbine. The residual heat from the expanded exhaust gas 76 leaving the turbine 72 is utilized to heat the compressed air 54 in the recuperator 60.

The high pressure of the motive fluid 40 provides the energy required for compression of the gas 36. The motive pressure, i.e. the pressure of the pressurized fludi stream 40, determines the volume of motive fluid 40 required to achieve compression of a unit volume of gas.

Figure 5 shows an example of a temperature (vertical axis) versus entropy (horizontal axis) diagram for a work cycle using system 30 according to the embodiment of Figs. 3 or 4. The process of energy transfer from the motive fluid (water) 40 to the gas (air) 36 is modelled as an isothermal process. The isothermal efficiency of the ejector 32 is a metric influencing the overall performance and efficiency of the system 30. Isothermal compression of the gas 36 in the ejector 32 is indicated by line 90 (between point 1 and 2) in Fig. 5. In Fig. 5, point 1 indicates the situation at the inlet of the ejector 32, and 2 the situation at the outlet. Depending on the isothermal efficiency of the ejector 32, the compression process will - in practice - cause a small temperature rise 92 of the water-air mixture. The separated water 50 is cooled in the cooler 58 and pumped back into the ejector 32 through the high- pressure water pump 56. This creates a closed loop cycle for the motive fluid 40. For and air working cycle, part of the air moisture from stream 36 is captured,‘tops-up’ the liquid loop and creates a source of water .

The volumetric ratio of motive fluid 40 versus gas 36 and the isothermal efficiency of the ejector 32 are variables that are determined by the physical design of the ejector. An energy balance determines the required flow rate and pressure head capability of the water pump 56.

In Fig. 5, like in Fig. 2, the dotted line between points 4 and 1 indicates the potential for a closed cycle. In an open cycle, the motive fluid will leave the cycle at point 4 without returning to the state of point 1.

Figure 6 shows a diagram of a basic version of the Allam cycle 100 for gaseous fuel. A detailed description of the Allam cycle can be obtained from, for instance,

Gas Turbine World, Vol. 44 No. 6, November - December 2014, pages 14 to 18 (" Gearing up for a new supercritical C02 power cycle system" by Junior Isles). For details of the Allam cycle, such as power, temperature, and pressure ranges, reference is made to this article.

A gaseous fuel 102 is pressurized by compressor 103. The compressor 103 provides pressurized gaseous fuel to be combusted, typically in combustor 104, in the presence of an oxidant flow 106. The oxidant flow may comprise nominally pure oxygen provided by a co-located Air Separation Unit (ASU) 108. The ASU 108 separates air 110, providing oxygen stream 106. The ASU potentially also provides oxygen comprising stream 112.

The exhaust flow 114 exiting the combustor 104 is expanded through a turbine 116 to a reduced pressure and reduced temperature. Inlet pressure of the turbine is typically in the range of 200 bar to 400 bar and the turbine has a pressure ratio between 6 and 12. The turbine typically drives a power generator 117. Expanded exhaust flow 118 output by the turbine 116 enters a recuperating heat exchanger 120.

Exiting the heat exchanger 120, the cooled turbine exhaust flow 140 is cooled further in cooler 142 to near ambient temperature. Heat may be expelled to cooling tower 144. Combustion derived water 146 is separated from the cooled turbine exhaust flow 148 in separator 150, leaving a fluidic C0₂ stream 152. The

predominantly C0₂ fluid stream 152 is then recompressed in compressor 154 to provide compressed fluidic C0₂ stream 156. The compressed stream 156 is cooled in cooler 158 providing liquid (or supercritical) C0₂ stream 160. The liquid (or supercritical) C0₂ stream 160 is pumped to approximately 300 bar pressure by pump 162, providing pressurized cooled C0₂ fluid stream 164.

A first part of the pressurized cooled C0₂ fluid stream 166 is returned to the recuperator 120, which transfers heat from the hot expanded exhaust flow 118 to the high pressure C0₂ recycle stream 166 which acts as diluent quench for the combustion products in the expanded exhaust flow 118. Heated C0₂ recycle stream 124 is recirculated back to the beginning of the cycle, e.g. to the combustor 104 or to cool an inlet of the turbine 116, in a highly recuperative process.

Before entering the heat exchanger 120 or in the heat exchanger 120, the first portion 166 of the recycle C0₂ may be mixed with the oxygen stream 112, rendering oxidant mix stream 124. Within the main process heat exchanger 120, the recycle flows undergo reheating against the hot turbine exhaust 118 before returning to the combustor 104 at temperatures which may exceed 600°C. In order to maintain mass balance within the semi-closed cycle, an export portion 168 of the high purity C0₂ process gas 164 can be exported, for instance after recompression to be provided to a high pressure C0₂ pipeline for sequestration or utilization (carbon capture and storage (CCS) or carbon capture and utilization (CCU)).

For additional details, specific pressure regimes and thermodymics, reference is made to, for instance, the article "Demonstration of the Allam Cycle: An update on the development status of a high efficiency supercritical carbon dioxide power process employing full carbon capture", Energy Procedia 114 (2017) 5948 - 5966. According to the article, "[t]he Allam Cycle takes a novel approach to reducing emissions by employing oxy-combustion and a high-pressure supercritical C0₂ working fluid in a highly recuperated cycle. The C0₂ that must be vented from the process leaves at pipeline pressure and high quality as a result of the operating conditions of the cycle, thereby mitigating the common necessity of an additional capture, clean-up, and compression system. ... The result is a power cycle with major advantages over conventional systems that do not capture C0₂, attaining 59% LHV efficiency (comparable to best- in-class NGCC power plants not capturing C0₂) ..; low capital costs due to the simplicity and high-pressure of the cycle; low ambient cooling requirements, depending on cooling configurations used; and virtually no air emissions, including full C0₂ capture.".

According to the present disclosure, the efficiency of the Allam cycle can be considerably improved by replacing the section enclosed by dotted line VII in Fig. 6 with, for instance, the embodiment of Figure 7.

Figure 7 shows an embodiment of the system 200 of the disclosure, replacing section VII of the Allam cycle shown in Fig. 6. Herein, after leaving the recuperator heat exchanger 120, the turbine exhaust flow 140 is provided to an inlet of a multiphase ejector 170. Also provided to an inlet of the ejector 170 is a pressurized fluid 172. The fluid can comprise water and/or any other fluid suitable for the selected boundary conditions of the cycle. Because C0₂ and water can be corrosive, the option to select an alternative working fluid other than water may be beneficial.

The exhaust gas 140 from the turbine - which comprises a mixture of C0₂ and H₂0 - is compressed in the ejector 170 using the pressurized fluid 172 as motive fluid, providing a pressurized mixture of fluid and gas 174 at an outlet of the ejector 170. The mixture 174 typically comprises water and C0₂. The pressurized mixture 174 is provided (directly) to a separator 176, for separating a water stream 178 from a predominantly C0₂ fluid stream 180. The water stream 178 is typically drained near a lower end of the separator 176. The predominantly C0₂ fluid stream 180 is typically drained near an upper end of the separator.

The water 178 is then cooled in cooler 182, providing cooled water stream 184. The cooled water stream 184 is pressurized by water pump 186 to provide the pressurized water stream 172.

In order to maintain mass balance within the semi-closed cycle, an export portion 190 of the high purity C0₂ process gas 180 can be exported. Export portion 190 can be provided to a high pressure C0₂ pipeline for sequestration or utilization.

In an embodiment, the remaining predominantly C0₂ fluid stream 192 may optionally be cooled in cooler 194, providing cooled C0₂ stream 196. Stream 196 may be pumped to approximately 300 bar pressure by pump 198. Pressurized cooled C0₂ stream 199 is forwarded to the recuperator 120.

The export portion of the high purity predominantly C0₂ fluid stream can be exported for sequestration or utilization. The export portion may relate to, for instance, stream 168 (Fig. 6, after pressurization) or stream 190 (Fig. 7, after separation but before cooling). The net export of C0₂ may be in the order of 5% of the total recycle flow, meaning the majority of the process inventory is recirculated.

The separator 176 and cooler 182 in the embodiment of Figure 7 can be significantly smaller than the separator 150 and the cooler 142 in the conventional Allam cycle shown in Fig. 6. The separator 176 and the cooler 182 may be designed for higher pressure (in the order of about 100 bar or more; compared to about 30 bar for separator 150 and cooler 142 in Fig. 6). This allows a size reduction of separator 176 (in volume).

In operation, the fluid stream 172 drives and pressurizes the gas stream 140, but also removes heat from the gas stream 140 which further improves the compression efficiency. Moreover, since H₂0 is already present in the exhaust gas mixture 140 (as steam), the high pressure cold water 172 acts as a condensing medium.

In a practical embodiment, the flue gas stream 140 is at a pressure in the range of 25 to 30 bara before entering the ejector 170. The water stream 172 is pressurized by pump 186 to a pressure in the range of 100 to 600 bara. The mixture 174 at the outlet of the ejector 170 may be at a pressure in the range of 100 to 120 bara. C0₂ stream 180 may be at a pressure in the range of 90 to 120 bara. C0₂ pump 198 pressurizes the C0₂ stream 196 to a pressure of about or exceeding, for instance, 300 bara.

A substantially isothermal compression process can be achieved in the ejector 170. In an Ejector, the heat of compression can be taken by the water during the compression itself, whereas the C0₂ compressor is limited by the temperature rise. Moreover, an Ejector is static machinery. Compared to the rotating components of a compressor, an ejector offers much higher reliability than a compressor due to the absence of moving parts and the associated wear.

The capital expenditure or upfronts costs of the separator 176 and cooler 182 can be reduced as they are designed for higher pressure and thus can be smaller in size than in the conventional Allam cycle. Also, since the motive fluid 172 is a condensate of the exhaust gas 140, the water 172 is relatively clean, further improving the reliability and efficiency of the ejector 170.

Compared to a conventional industrial gas turbine cycle (as shown, for instance, in Fig. 1) provided with the same recuperator, an ejector based power generation system, based on system 30 of Figs. 4 or 5, can have about 50% more specific work output (measured in kJ/kg) and can be about 9% more efficient. This analysis assumes the same pressure ratio for an air compressor 12 coupled to the gas turbine and the multiphase ejector 32. In a practical embodiment, the isothermal efficiency of the ejector 32 may exceed 60%, or may preferably exceed 80%. The equivalent compression isenetropic efficiency can exceed 100%.

An ejector for the system of the present disclosure may be obtained from Transvac Systems Ltd., Monsal House, 1 Bramble Way, Alfreton, Derbyshire, DE55 4RH, UK. Transvac is an established ejector supplier to industry, and is working on ejectors with the relatively high thermal efficiencies as indicated above.

Serguei Popov is an inventor and entrepreneur who has made high efficiency ejectors. He has historically traded using different company names. For details and dimensions of the ejector, reference is made to patent documents having Mr. Popov as inventor, such as US6312230, US6334758, US6450484 and US6416042. Potential benefits of the system and method of the present disclosure may include one or more of:

- 50% more power compared to an otherwise similar compressor - gas turbine cycle;

- specific work output per unit mass of air flow of the system 30 is significantly higher than conventional gas turbines used for the liquefaction of natural gas (i.e. production of LNG);

- C0₂ emissions are significantly reduced. For instance, the system 30 may reduces emissions to 0.131 tonne CO2 per tonne of LNG produced;

- The system 30 may be a key enabler to achieve ambitious CO2 reduction targets, such as reducing CO2 emissions to a maximum of 0.15 tonne CO2 per tonne of LNG produced (at affordable cost);

- Potential fuel gas reduction by 50% resulting in a NPV of about 300 mln for a single large LNG train deployment;

- can be combined with proven technology, such as industrial scale gas turbines components (as marketed for instance by Siemens , General Electric and Mitsubishi);

- the ejector replaces the compressor and improves reliability by replacing equipment including rotating components (with associated wear and tear) with equipment including only static components.

The core of the present disclosure is the application of a pump and an ejector to compress gas or air isothermally. This combination may be part of a gas turbine (Brayton) power cycle. In additon, heat can be recovered from the turbine exhaust via a recuperator. The combination of these two changes results in a significant increase in thermal efficiency of the sytem. Comparing a contemporary General Electric Frame 7 Gas turbine (commonly used for LNG liquefaction) with the Cycliq Gas Turbine lineup of the present application (see Figs. 3 and 4), the latter can provide a thermal efficiency increase from 33% to 49%. For an LNG plant, this could reduce CO2 emissions by a third and make fuel savings of a third.

There are multiple enhancements to a traditonal gas turbine setup. The highest efficiency option as presently deployed by the power industry is a 'combined- cycle' system which utilises waste heat, from the exhaust of a simple cycle gas turbine, to gererate steam which is expanded via a steam turbine. This arrangment is however significantly more complex than the system 30 proposed in the present application, involving higher capital investment for equipment and construction.

Using any of the embodiments of the present application can provide a significant reduction in capital expenditure, operating expenditure, and/or a reduction in (C0₂) emissions.

Applications for this technology include, but are not limited to:

a) Liquefaction of gases (including LNG);

b) Compression of gases (including gases that include fluids or may have a variable composition);

c) Compression or boosting subsea.

The present disclosure is not limited to the embodiments as described above and in the appended claims. Many modifications are conceivable therein and features of respective embodiments may be combined.

Claims

1. System, comprising:

an ejector for receiving a gaseous feed stream and a pressurized liquid working fluid stream and for providing a mixture thereof at an outlet of the ejector;

a separator for receiving the mixture of the gaseous feed stream and the pressurized liquid working fluid stream from the ejector, the separator having a first separator outlet for providing a liquid working fluid stream and a second separator outlet for providing a second substantially gaseous stream; and

2. The system of claim 1,

the gaseous feed stream and the second substantially gaseous stream comprising gaseous hydrocarbons, and the system further comprising:

a combustor for receiving the second substantially gaseous stream from the separator and for combusting said second substantially gaseous stream to provide a combusted gaseous stream;

3. The system of claim 2, comprising a recuperator arranged between the separator and the combustor for heat exchange between the expanded combusted gaseous stream and the gaseous stream.

4. The system of claim 2, comprising a recuperator arranged to receive the expanded combusted gaseous stream from the gas turbine, the recuperator being adapted for heat exchange between the expanded combusted gaseous stream and a cold stream.

5. The system of claim 1, comprising:

the gaseous feed stream and the second substantially gaseous stream comprising flue gas comprising at least carbon dioxide, and the system further comprising:

a cooler for receiving the second substantially gaseous stream from the separator and for cooling said second substantially gaseous stream; and a recycle pump for receiving the cooled gaseous stream from the cooler and for providing a pressurized cooled liquid stream.

6. The system of claim 5, comprising:

a turbine for extracting power and for expanding the flue gas;

a recuperator for receiving expanded flue gas from the turbine and for heat exchanging the expanded flue gas against the pressurized cooled liquid stream.

7. The system of claim 5 or 6, comprising an export outlet connected to the second outlet of the separator for exporting at least part of the gaseous stream comprising at least carbon dioxide.

8. Method, comprising the steps of:

receiving the pressurized mixture in a separator, and providing a liquid working fluid stream at a first separator outlet and providing a second substantially gaseous stream at a second separator outlet; and

pressurizing the liquid working fluid stream of the first separator outlet and providing the pressurized liquid working fluid stream to the inlet of the ejector.

9. The method of claim 8,

the gaseous feed stream and the second substantially gaseous stream

comprising gaseous hydrocarbons, and the method comprising the further steps of: combusting the second substantially gaseous stream from the second outlet of the separator to provide a combusted gaseous stream;

10. The method of claim 9, comprising the steps of:

heat exchanging the expanded combusted gaseous stream versus the second substantially gaseous stream.

11. The method of claim 9, comprising the steps of:

heat exchanging the expanded combusted gaseous stream and a cold stream.

12. The method of claim 8,

the gaseous feed stream and the second substantially gaseous stream comprising flue gas comprising at least carbon dioxide, and the method comprising the further steps of:

receiving the second substantially gaseous stream from the separator and cooling said second substantially gaseous stream; and

receiving the cooled gaseous stream from the cooler and pressurizing the cooled gaseous stream.

13. The method of claim 12, comprising the steps of:

using a turbine for providing power and for providing the flue gas;

14. The method of claim 12 or 13, comprising the step of exporting at least part of the gaseous stream comprising at least carbon dioxide.