EP3184876A1 - Terminal de regazéification de cogénération de gaz naturel liquide - Google Patents

Terminal de regazéification de cogénération de gaz naturel liquide Download PDF

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Publication number
EP3184876A1
EP3184876A1 EP15202622.5A EP15202622A EP3184876A1 EP 3184876 A1 EP3184876 A1 EP 3184876A1 EP 15202622 A EP15202622 A EP 15202622A EP 3184876 A1 EP3184876 A1 EP 3184876A1
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EP
European Patent Office
Prior art keywords
natural gas
gas stream
stream
liquid natural
fuel
Prior art date
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Application number
EP15202622.5A
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German (de)
English (en)
Inventor
Pablo Antonio Vega Perez
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Shell Internationale Research Maatschappij BV
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Shell Internationale Research Maatschappij BV
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Priority to EP15202622.5A priority Critical patent/EP3184876A1/fr
Publication of EP3184876A1 publication Critical patent/EP3184876A1/fr
Withdrawn legal-status Critical Current

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    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F17—STORING OR DISTRIBUTING GASES OR LIQUIDS
    • F17C—VESSELS FOR CONTAINING OR STORING COMPRESSED, LIQUEFIED OR SOLIDIFIED GASES; FIXED-CAPACITY GAS-HOLDERS; FILLING VESSELS WITH, OR DISCHARGING FROM VESSELS, COMPRESSED, LIQUEFIED, OR SOLIDIFIED GASES
    • F17C7/00—Methods or apparatus for discharging liquefied, solidified, or compressed gases from pressure vessels, not covered by another subclass
    • F17C7/02—Discharging liquefied gases
    • F17C7/04—Discharging liquefied gases with change of state, e.g. vaporisation
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F17—STORING OR DISTRIBUTING GASES OR LIQUIDS
    • F17C—VESSELS FOR CONTAINING OR STORING COMPRESSED, LIQUEFIED OR SOLIDIFIED GASES; FIXED-CAPACITY GAS-HOLDERS; FILLING VESSELS WITH, OR DISCHARGING FROM VESSELS, COMPRESSED, LIQUEFIED, OR SOLIDIFIED GASES
    • F17C9/00—Methods or apparatus for discharging liquefied or solidified gases from vessels not under pressure
    • F17C9/02—Methods or apparatus for discharging liquefied or solidified gases from vessels not under pressure with change of state, e.g. vaporisation
    • F17C9/04—Recovery of thermal energy
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F17—STORING OR DISTRIBUTING GASES OR LIQUIDS
    • F17C—VESSELS FOR CONTAINING OR STORING COMPRESSED, LIQUEFIED OR SOLIDIFIED GASES; FIXED-CAPACITY GAS-HOLDERS; FILLING VESSELS WITH, OR DISCHARGING FROM VESSELS, COMPRESSED, LIQUEFIED, OR SOLIDIFIED GASES
    • F17C2221/00—Handled fluid, in particular type of fluid
    • F17C2221/01—Pure fluids
    • F17C2221/013—Carbon dioxide
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F17—STORING OR DISTRIBUTING GASES OR LIQUIDS
    • F17C—VESSELS FOR CONTAINING OR STORING COMPRESSED, LIQUEFIED OR SOLIDIFIED GASES; FIXED-CAPACITY GAS-HOLDERS; FILLING VESSELS WITH, OR DISCHARGING FROM VESSELS, COMPRESSED, LIQUEFIED, OR SOLIDIFIED GASES
    • F17C2221/00—Handled fluid, in particular type of fluid
    • F17C2221/03—Mixtures
    • F17C2221/032—Hydrocarbons
    • F17C2221/033—Methane, e.g. natural gas, CNG, LNG, GNL, GNC, PLNG
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F17—STORING OR DISTRIBUTING GASES OR LIQUIDS
    • F17C—VESSELS FOR CONTAINING OR STORING COMPRESSED, LIQUEFIED OR SOLIDIFIED GASES; FIXED-CAPACITY GAS-HOLDERS; FILLING VESSELS WITH, OR DISCHARGING FROM VESSELS, COMPRESSED, LIQUEFIED, OR SOLIDIFIED GASES
    • F17C2221/00—Handled fluid, in particular type of fluid
    • F17C2221/03—Mixtures
    • F17C2221/038—Refrigerants
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
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    • F17C—VESSELS FOR CONTAINING OR STORING COMPRESSED, LIQUEFIED OR SOLIDIFIED GASES; FIXED-CAPACITY GAS-HOLDERS; FILLING VESSELS WITH, OR DISCHARGING FROM VESSELS, COMPRESSED, LIQUEFIED, OR SOLIDIFIED GASES
    • F17C2223/00—Handled fluid before transfer, i.e. state of fluid when stored in the vessel or before transfer from the vessel
    • F17C2223/01—Handled fluid before transfer, i.e. state of fluid when stored in the vessel or before transfer from the vessel characterised by the phase
    • F17C2223/0146—Two-phase
    • F17C2223/0153—Liquefied gas, e.g. LPG, GPL
    • F17C2223/0161—Liquefied gas, e.g. LPG, GPL cryogenic, e.g. LNG, GNL, PLNG
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    • F17C2223/03—Handled fluid before transfer, i.e. state of fluid when stored in the vessel or before transfer from the vessel characterised by the pressure level
    • F17C2223/033—Small pressure, e.g. for liquefied gas
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    • F17C2223/00—Handled fluid before transfer, i.e. state of fluid when stored in the vessel or before transfer from the vessel
    • F17C2223/03—Handled fluid before transfer, i.e. state of fluid when stored in the vessel or before transfer from the vessel characterised by the pressure level
    • F17C2223/035—High pressure (>10 bar)
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    • F17C2225/00—Handled fluid after transfer, i.e. state of fluid after transfer from the vessel
    • F17C2225/01—Handled fluid after transfer, i.e. state of fluid after transfer from the vessel characterised by the phase
    • F17C2225/0107—Single phase
    • F17C2225/0123—Single phase gaseous, e.g. CNG, GNC
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    • F17C2225/03—Handled fluid after transfer, i.e. state of fluid after transfer from the vessel characterised by the pressure level
    • F17C2225/036—Very high pressure, i.e. above 80 bars
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    • F17C2227/00—Transfer of fluids, i.e. method or means for transferring the fluid; Heat exchange with the fluid
    • F17C2227/01—Propulsion of the fluid
    • F17C2227/0128—Propulsion of the fluid with pumps or compressors
    • F17C2227/0157—Compressors
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    • F17C2227/00—Transfer of fluids, i.e. method or means for transferring the fluid; Heat exchange with the fluid
    • F17C2227/03—Heat exchange with the fluid
    • F17C2227/0302—Heat exchange with the fluid by heating
    • F17C2227/0309—Heat exchange with the fluid by heating using another fluid
    • F17C2227/0323—Heat exchange with the fluid by heating using another fluid in a closed loop
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    • F17C—VESSELS FOR CONTAINING OR STORING COMPRESSED, LIQUEFIED OR SOLIDIFIED GASES; FIXED-CAPACITY GAS-HOLDERS; FILLING VESSELS WITH, OR DISCHARGING FROM VESSELS, COMPRESSED, LIQUEFIED, OR SOLIDIFIED GASES
    • F17C2227/00—Transfer of fluids, i.e. method or means for transferring the fluid; Heat exchange with the fluid
    • F17C2227/03—Heat exchange with the fluid
    • F17C2227/0337—Heat exchange with the fluid by cooling
    • F17C2227/0358—Heat exchange with the fluid by cooling by expansion
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    • F17C2227/00—Transfer of fluids, i.e. method or means for transferring the fluid; Heat exchange with the fluid
    • F17C2227/03—Heat exchange with the fluid
    • F17C2227/0367—Localisation of heat exchange
    • F17C2227/0388—Localisation of heat exchange separate
    • F17C2227/0393—Localisation of heat exchange separate using a vaporiser
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    • F17C—VESSELS FOR CONTAINING OR STORING COMPRESSED, LIQUEFIED OR SOLIDIFIED GASES; FIXED-CAPACITY GAS-HOLDERS; FILLING VESSELS WITH, OR DISCHARGING FROM VESSELS, COMPRESSED, LIQUEFIED, OR SOLIDIFIED GASES
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    • F17C2250/0439—Temperature
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    • F17C—VESSELS FOR CONTAINING OR STORING COMPRESSED, LIQUEFIED OR SOLIDIFIED GASES; FIXED-CAPACITY GAS-HOLDERS; FILLING VESSELS WITH, OR DISCHARGING FROM VESSELS, COMPRESSED, LIQUEFIED, OR SOLIDIFIED GASES
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    • F17C2250/0447—Composition; Humidity
    • F17C2250/0452—Concentration of a product
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    • F17C—VESSELS FOR CONTAINING OR STORING COMPRESSED, LIQUEFIED OR SOLIDIFIED GASES; FIXED-CAPACITY GAS-HOLDERS; FILLING VESSELS WITH, OR DISCHARGING FROM VESSELS, COMPRESSED, LIQUEFIED, OR SOLIDIFIED GASES
    • F17C2250/00—Accessories; Control means; Indicating, measuring or monitoring of parameters
    • F17C2250/06—Controlling or regulating of parameters as output values
    • F17C2250/0605—Parameters
    • F17C2250/0626—Pressure
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    • F17C—VESSELS FOR CONTAINING OR STORING COMPRESSED, LIQUEFIED OR SOLIDIFIED GASES; FIXED-CAPACITY GAS-HOLDERS; FILLING VESSELS WITH, OR DISCHARGING FROM VESSELS, COMPRESSED, LIQUEFIED, OR SOLIDIFIED GASES
    • F17C2250/00—Accessories; Control means; Indicating, measuring or monitoring of parameters
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    • F17C2250/0642—Composition; Humidity
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    • F17C2265/00—Effects achieved by gas storage or gas handling
    • F17C2265/03—Treating the boil-off
    • F17C2265/032—Treating the boil-off by recovery
    • F17C2265/037—Treating the boil-off by recovery with pressurising
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    • F17C—VESSELS FOR CONTAINING OR STORING COMPRESSED, LIQUEFIED OR SOLIDIFIED GASES; FIXED-CAPACITY GAS-HOLDERS; FILLING VESSELS WITH, OR DISCHARGING FROM VESSELS, COMPRESSED, LIQUEFIED, OR SOLIDIFIED GASES
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    • F17C2265/00—Effects achieved by gas storage or gas handling
    • F17C2265/05—Regasification
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    • F17C2265/07—Generating electrical power as side effect
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    • F17C2270/00—Applications
    • F17C2270/01—Applications for fluid transport or storage
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    • F17C2270/01—Applications for fluid transport or storage
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    • F17C2270/0118—Offshore
    • F17C2270/0123—Terminals

Definitions

  • the present invention relates to a regasification terminal and a method for the regasification of a liquid natural gas stream.
  • Natural gas is a useful fuel source. However, it is often produced a relative large distance away from the market. In such cases it may be desirable to liquefy natural gas in an LNG plant at or near the source of. In the form of LNG (liquefied natural gas) storage and transportation over long distances can be done more economically than in gaseous form, because it occupies a smaller volume.
  • LNG liquefied natural gas
  • the term LNG is used in this text to refer to liquid or liquefied natural gas.
  • the LNG may be at or close to atmospheric pressure (atmospheric LNG) or may be at an elevated pressure (pressurized LNG).
  • the temperature of the LNG is typically at the boiling temperature corresponding with the pressure.
  • the LNG may also be at a temperature (substantially) below the boiling temperature and may even be partially solidified.
  • Atmospheric LNG is at a pressure at or close to atmospheric pressure, typically in the range of 1000 - 1250 mbar and is consequently at a temperature close to -162°C.
  • Pressurized LNG (also referred to as cryo compressed LNG (ccLNG)) is at a pressure greater than atmospheric pressure.
  • the pressure of pressurized LNG may be above 2 bar or at least above 5 bar.
  • pressurized LNG may be produced at a pressure of 15 - 17 bar at a temperature of approximately -115°C.
  • the LNG is transported by a suitable LNG carrier vessel to a regasification terminal (also referred to as regasification terminal or import terminal), where it is usually transferred to a LNG storage tank.
  • a regasification terminal also referred to as regasification terminal or import terminal
  • an LNG stream to be regasified is obtained from the LNG storage tank.
  • Boil-off gas obtained from the LNG storage tank is typically recondensed to be combined with the LNG stream to be regasified and the combined stream is then regasified and fed to the gas grid.
  • the gas may be distributed to different consumers, such as residential and commercial consumers, industry as feedstock and gas power plants, which use the gas to generate electricicity.
  • the LNG may be pressurized to a pressure of above 60 bar, e.g. 80 bar, to meet the requirementss of the gas grid.
  • the pressurized liquid natural gas stream is then passed through heat exchangers, also referred to as vaporizers or vaporizer heat exchangers, which vaporize the pressurized liquid natural gas stream by heating against a heating medium, e.g. ambient water or air.
  • heat exchangers also referred to as vaporizers or vaporizer heat exchangers, which vaporize the pressurized liquid natural gas stream by heating against a heating medium, e.g. ambient water or air.
  • vaporizers are open rack vaporizers, submerged combustion vaporisers, intermediate fluid vaporisers, shell and tube vaporisers, ambient air vaporisers.
  • the regasified natural gas product may then be fed to the gas grid.
  • Regasification terminals and methods to regasify LNG are known in the art and are for instance described in patent application publication US2010/0000233 , US2006/0242969 , US2009/0282836 , WO2008012286 , WO2013186271 , WO2013186277 , WO2013186275 and WO11006917 .
  • WO12102849 describes a method and system for regasifying LNG, including providing heat to a LNG regasification process from a power plant. If the heat is not sufficient, additional heat can be provided to the LNG regasification process from a cooling tower operated in a warming tower configuration. This method and system has the disadvantage that a cooling/warming tower is needed in case the heat from the power plant is too much or not sufficient.
  • US6374591 described a process and system in which a LNG supply system fuels a power plant.
  • Gasified LNG in a combustor mixes with air from an air compressor to provide hot combustion gas for a gas turbine.
  • the expanding LNG is used to chill a heat exchange fluid, e.g. water, which heat exchange fluid cools and densifies the intake air for the air compressor.
  • the heat exchange fluid is used in another heat exchange step and is then re-chilled and recycled to cool and densify the intake air.
  • WO06019900 describes to use LNG cold in a plurality of cycles in a combined power plant to increase power output.
  • Plant configurations integrate a combined cycle power plant with a regasification operation in which in a first stage LNG cold provides cooling in an open or closed power cycle. A significant portion of the LNG is vaporized in the first stage.
  • LNG cold provides cooling for a heat transfer medium that is used to provide refrigeration for the cooling water to a steam power turbine and for an air intake chiller of a combustion turbine in the power plant.
  • WO10131979 describes a plant for the combined regasification of refrigerated liquid gas and the production of electric power, where both a unit for re-gasification of liquid gas and a unit for the production of electric power are installed on board a floating terminal comprising tanks for liquid gas.
  • the power producing unit is designed for the generation of electric power by combustion of hydrocarbons, and the heat produced by the power producing unit is used for the re-gasification of the refrigerated liquid gas.
  • the present invention provides a method of operating a gasification terminal, the method comprising:
  • a system for gasifiying a liquid natural gas comprising a gasification terminal and a gas power plant (100), wherein the gasification terminal is arranged to receive a liquid natural gas stream (10) and generate a heated pressurized gasified natural gas stream (12) from the liquid natural gas stream (10) being at a first pressure (P1) and a first temperature (T1), wherein the gas power plant is arranged to receive a fuel stream (101) and generate primary power and a hot flue gas stream (120) from the fuel stream, wherein the system further comprises a heat recovery circuit (200) arranged to transfer heat from the hot flue gas stream (120) to the liquid natural gas stream in the gasification terminal via a heat transfer fluid, wherein the gasification terminal further comprises an expander (22) arranged to receive the heated pressurized gasified natural gas stream (12), discharge further power and a gasified natural gas stream (13) at a send out pressure and a send out temperature, the send out pressure being smaller than the first pressure and the send out temperature
  • the above method and system have the advantage that the liquid natural gas stream is gasified in an energy efficient manner without the need of ambient warming duty and associated hardware. Also, there is no need to discharge a cooled ambient stream to the environment. Furthermore, in addition to regasified natural gas stream, power is generated in an efficient manner.
  • the send out pressure may be more than 10 bar, 20 bar or 30 bar below the first pressure.
  • the send out pressure may be in the range of 70 - 90 bar, e.g. 80 bar.
  • the send out temperature may be more than 10°C or 20°C below the first temperature.
  • the send out temperature may be in the range +20°C - +40°C, e.g. +30°C.
  • the gas power plant may be any kind of device suitable to generate primary power from a fuel stream, e.g. in the form of electricity.
  • the gas power plant may for instance comprise a gas turbine to which the fuel stream is fed to generate the primary power and the hot flue gas stream, the fuel stream being a gaseous fuel stream.
  • the gas power plant may comprise a reciprocating gas engine to which the fuel stream is fed to generate the primary power and the hot flue gas stream.
  • the reciprocating gas engine used is a only-gas engine, which operate with spark-ignition, the fuel stream being a gaseous fuel stream.
  • the power plant comprises a dual fuel reciprocating gas engine with compressed ingnition which runs on a fuel stream comprising a gaseous fuel stream and a liquid fuel stream, such as diesel.
  • a heated pressurized gasified natural gas stream (12) By operating a gas power plant and using the waste heat, a heated pressurized gasified natural gas stream (12) can be obtained having a temperature above the send out temperature. This allows to extract work and thereby generate further power from the heated pressurized gasified natural gas stream (12) in step a4) obtaining a gasified natural gas stream (13) at a send out pressure and send out temperature that is still suitable for exporting to the gas grid.
  • the heated pressurized gasified natural gas stream (12) is at a first pressure (P1) and a first temperature (T1). It will be understood that the pressure of the pressurized liquid natural gas stream 11 as obtained in a2) will in practice be higher than the pressure of the heated pressurized gasified natural gas stream 12 as obtained in a3) due to pressure losses in the one or more vaporizer heat exchangers that may be used in a3) and associated piping. However, as no deliberate pressure reduction measures or devices are included, these pressures will be substantially equal to each other.
  • the pressurized liquid natural gas stream 11 as obtained in a2) may be at a pressure less than 3 bar, or even less then 2 bar above the pressure of the the heated pressurized gasified natural gas stream 12 as obtained in a3). Therefore, in this text both the the pressurized liquid natural gas stream 11 as obtained in a2) and the heated pressurized gasified natural gas stream 12 as obtained in a3) are referred to as being at the first pressure (P1).
  • the gasified natural gas stream (13) preferably meets gas grid specifications, in particular in terms of pressure and temperature.
  • the send out pressure preferably meets the gas grid pressure requirements, e.g. 75 - 85 bar.
  • the send out temperature of the gasified natural gas stream preferably meets the gas grid temperature requirements, e.g. 0 - 30°C.
  • the first pressure selected for step a2) is above the send out pressure, preferably more than 15 or 20 bars above the send out pressure.
  • the heated pressurized regasified natural gas stream obtained in step a3) is substantially the same (i.e. less than 3 or 2 bar lower), but is still at a pressure well above the send out pressure.
  • the heated pressurized regasified natural gas stream obtained in step a3) may be at a temperature above the send out temperature, preferably more than 15°C above the send out temperature (the maximum temperature within the delivery temperature range).
  • the pressurized liquid natural gas stream can efficiently be heated to a temperature above the send out temperature, preferably more than 15°C above the send out temperature to obtain the heated pressurized gasified natural gas stream. From this stream work can be extracted in step a4) thereby obtaining a gasified natural gas stream that (still) meets the gas grid requirements in terms of pressure and temperature.
  • the pressure and the temperature of the gasified natural gas stream are at the send out pressure and the send out temperature respectively at the outlet of the expander. Consequently, no additional processing, in particular no heating, is needed downstream of the expander to reach the intended send out temperature and send out pressure.
  • the gasified natural gas stream is directly passed to the gas grid.
  • the gas power plant (100) may be an open Brayton cycle.
  • the gas power plant (100) may be an Otto or a Diesel cycle.
  • the heat recovery circuit in step c) may be a closed Rankine cycle.
  • the combination of the gas power plant and the heat recovery circuit may be referred to as a combined cycle.
  • Extracting work from the heated pressurized regasified natural gas stream in step a4) may comprise operating an open Rankine cycle.
  • the fuel stream is a natural gas stream directly or indirectly obtained from the one or more liquid natural gas storage tanks.
  • obtaining the fuel stream in step b) comprises obtaining a split stream (14) from the gasified natural gas stream (13) to be, at least partially, comprised in the fuel stream (101).
  • the split stream 14 is thus obtained from the gasified natural gas stream 13 at the send out pressure and the send out temperature.
  • the fuel stream 101 is formed from this split stream only, the fuel stream being a gaseous fuel stream. This has the advantage that no external fuel source is needed.
  • the fuel stream is formed by the split stream and a liquid fuel stream only.
  • obtaining the liquid natural gas stream (10) to be gasified in step a1) is done by obtaining the liquid natural gas stream (10) from one or more pressurized liquid natural gas storage tanks (1) from which no continuous boil-off gas stream is obtained and in which the pressure is allowed to rise above atmospheric pressure.
  • a boil-off gas stream may be obtained incidentally only when needed, i.e. when the pressure exceeds a predetermined safety threshold or during loading to supply a vapour return stream to a carrier. But during operation, no continuous boil-off gas stream is obtained and the pressure in the pressurized liquid natural gas storage tanks (1) is allowed to rise to a level well above 1 bar, for instance to a level of above 5 bar or above 10 bar.
  • obtaining the fuel stream in step b) comprises obtaining a boil off gas stream (33) from the one or more liquid natural gas storage tanks (1) to be, at least partially, comprised in the fuel stream (101).
  • the complete boil off gas stream is comprised in the fuel stream.
  • the fuel stream may consist of the boil off gas stream only without further streams being added.
  • the fuel stream is formed by the boil-off gas stream and a a liquid fuel stream only.
  • the boil off gas stream may be pressurized using a boil-off gas compressor (32) to match the pressure of the split stream (14) at the point where the split stream and the (pressurized) boil off gas stream are combined, to allow combining these two streams and allow efficient combustion in the gas turbine.
  • a boil-off gas compressor (32) to match the pressure of the split stream (14) at the point where the split stream and the (pressurized) boil off gas stream are combined, to allow combining these two streams and allow efficient combustion in the gas turbine.
  • step a2) may be performed efficiently in a single pressurizing stage, where according to the prior art this is done in a dual pressurizing stage to allow the recondensed boil off gas stream to be added in between the two pressurizing stages.
  • additional fuel may be provided to the gas power plant, in particular in case of a dual fuel reciprocating gas engine, in which case a liquid fuel stream is added.
  • the ratio of the gaseous fuel stream and the liquid fuel stream is preferably a predetermined fixed ratio.
  • obtaining the fuel stream in step b) comprises obtaining a boil off gas stream (33) from the one or more liquid natural gas storage tanks (1) to be, at least partially, comprised in the fuel stream (101) and obtaining a split stream (14) from the gasified natural gas stream (13) to be, at least partially, comprised in the fuel stream (101).
  • the fuel stream may consist of the boil off gas stream and the split stream (14) only without further streams being added.
  • the fuel stream is formed by the boil off gas stream, the split stream and a liquid fuel stream only.
  • the flow rate of the boil off gas stream varies in time.
  • the flow rate of the boil off gas stream may vary depending on the ambient temperature, the filling level of the liquid natural gas storage tank(s), and may further depend on whether or not the liquid natural gas storage tank is being filled or not.
  • filling for instance by a LNG carrier
  • the flow rate of the boil off gas stream will typically be relatively high compared to when no filling is taking place (holding mode) or reloading of LNG carriers is taking place.
  • controlling the flow rate of the gaseous fuel stream may comprise controlling the flow rate of the split stream in response to a measured flow rate of the boil off gas stream.
  • controlling the flow rate of the gaseous fuel stream (101) and the flow rate of the liquid natural gas stream (10) in relation to each other comprises executing a control loop comprising:
  • controlling the flow rate of the fuel stream 101 and the flow rate of the liquid natural gas stream 10 is done with respect to each other.
  • the flow rates are controlled in relation to each other in such a way that sufficient heat is transferred by the heat recovery circuit from the hot flue gasses to the liquid natural gas stream to allow regasifying the liquid natural gas stream without the need of additional heating duty and preferably with a relatively high waste heat recovery to reduce waste heat losses.
  • an intended flow rate of the fuel stream and an intended flow rate of the liquid natural gas stream e.g. the composition of the fuel stream, the temperature and/or composition of the liquid natural gas stream, the temperature of an air stream being provided to the gas power plant.
  • Controlling the flow rates in relation to each other may comprise adjusting one or both of the flow rates.
  • controlling the flow rate of the fuel stream (101) and the flow rate of the liquid natural gas stream (10) with respect to each other comprises adjusting one of the flow rates only, preferably adjusting the flow rate of the fuel stream (101) only.
  • Controlling the flow rate of the fuel stream preferably comprises adjusting the flow rate of the split stream. Adjusting the flow rate of the split stream may be done by controlling a valve in the conduit carrying the split stream and/or by controlling a split valve providing the split of the split stream from the from the gasified natural gas stream 13.
  • Controlling the flow rates may comprise
  • the flow rates of the fuel stream and/or the liquid natural gas stream are actively and continuously controlled.
  • the control is preferably automated.
  • Active and continuous control includes constantly or regularly performing one or more measurements and adjusting the flow rate of the fuel stream and/or the liquid natural gas stream when needed based on the obtained measurements.
  • the flow rate of the fuel stream 101 is minimized.
  • the power generated may be maximized or controlled to be at a predetermined level.
  • controlling the fuel stream (101) comprises obtaining a fuel stream pressure indication indicative of the pressure of the fuel stream (101) as passed to the gas power plant (101) and operating a pressure control device to maintain the pressure of the fuel stream within a predetermined operating range based on the fuel stream pressure indication.
  • the pressure control device may be a pump or a pressure reduction valve (15) present in the conduit carrying the split-off stream and/or a pump or pressure reduction valve present in the conduit carrying the boil-off gas stream.
  • the predetermined operating range may be selected such that the pressure of the fuel stream is within the operating range of the gas turbine or gas engine.
  • the pressurized liquid natural gas stream (11) is gasified by only heat exchanging against the heat transfer fluid.
  • the method and system don't comprise deliberate and substantial (direct or indirect) heat exchanging of the pressurized liquid natural gas stream (11) against any other stream, in particular not directly or indirectly heat exchanging against an ambient stream, such as an ambient water or air stream. It will of course be understood that some heating of the (pressurized) liquid natural gas stream 11 and the heated pressurized gasified natural gas stream 12 may occur when flowing through the system (due to ambient heat ingress), however, this is not considered to be deliberate or substantial heat exchanging.
  • the heat transfer fluid only exchanges heat with the hot flue gas stream (120) and the pressurized liquid natural gas stream (11).
  • the heat transfer fluid only receives heat via heat exchanging from the hot flue gas stream (120).
  • Operating the heat recovery circuit in step (c) comprises heating the heat transfer fluid against the hot flue gas stream and does not comprise heat exchanging the heat transfer fluid against any other stream in order to heat the heat transfer fluid, in particular not directly or indirectly heat exchanging against an ambient stream, such as an ambient water or air stream. Further heating/cooling may occur as a result of compression/expansion, but this is not considered heat exchanging.
  • Controlling the flow rates is done in such a manner that the heat transfer fluid is able to transfer sufficient and not too much heat to the pressurized liquid natural gas stream.
  • the heat transfer fluid consists of one or more of the following: CO2, ammonia, propane, ethane, ethylene, fluorocarbons (C x F y ).
  • the heat transfer fluid may substantially consist of CO2.
  • the heat transfer fluid may be essentially pure CO2. It will be understood that the term pure is used to indicate a level of purity that is practically achievable, e.g. a purity of more than 99 mol%.
  • a heat transfer fluid consisting of CO2 is advantageous, as CO2 is non-flammable, non-toxic and non-corrosive. Also, CO2 will cause relatively little corrosion and erosion. Furthermore, as CO2 is naturally present in the atmosphere, unintended release will not directly result in environmental or safety risks.
  • step c) comprises circulating a heat transfer fluid consisting of CO2 through the heat recovery circuit, the heat transfer fluid being in a supercritical state throughout the heat recovery circuit.
  • supercritical is used to refer to a fluid having a temperature and pressure above its critical point. In the supercritical state/region no distinct liquid and gas phases exist and the heat transfer fluid consisting of CO2 is then a supercritical fluid. According to this embodiment, the heat transfer fluid has a temperature and pressure above the critical point throughout the entire heat recovery circuit.
  • CO2 Because of the relatively low critical temperature of CO2 (the critical point of CO2 is found at a low temperature but with high pressure, 31.04°C and 73.82 bara) CO2 offers advantages with respect to the use of steam as heat transer fluid.
  • the heat recovery in supercritical state occurs in a phase transition-free thus eliminating any temperature pinch limitations. Also, the mass density and heat transfer coefficient are substantially higher than those of a vapour phase, allowing for a major size reduction of the heat recovery exchanger. As the supercritical CO2 has a relatively low viscocity, it has relatively good flow properties.
  • the heat recovery circuit in step (c) comprises generating additional power by circulating the heat transfer fluid, e.g. through a closed Rankine cycle or Brayton cycle.
  • the Rankine cycle comprises a waste heat recovery heat exchanger (201), a turbine (203), a vaporizer heat exchanger (21) and a pump (207).
  • the Brayton cycle comprises the same elements, except for pump 207 being a compressor.
  • the heat transfer fluid drives the turbine thereby generating additional power.
  • the turbine can produce additional power more efficiently, consequently allowing a much smaller turbine size than that for an equivalent output power driven by steam.
  • Fig. 1 schematically shows a system according to an embodiment
  • Fig. 2 schematically shows a system according to an alternative embodiment.
  • Fig. 1 schematically shows a liquid natural gas storage tank 1 in fluid communication with a gasification terminal.
  • the one or more liquid natural gas storage tanks 1 may comprise hardware allowing the liquid natural gas storage tanks 1 to be loaded with liquid natural gas, for instance from a carrier vessel (not shown).
  • the gasification terminal comprises a pump 20, a vaporizer heat exchanger 21 and a natural gas expander 22.
  • the pump 20 may be a high pressure pump and although shown as a single pump 20, it may be formed by one or more parallel and/or serial pumps 20.
  • the vaporizer heat exchanger 21 is shown as a single vaporizer heat exchanger 20, but may be formed by one or more parallel and/or serial vaporizer heat exchangers.
  • the natural gas expander 22 is shown as a single natural gas expander 22, but may be formed by one or more parallel and/or serial natural gas expanders 22.
  • An inlet of the pump 20 is in fluid communication with the liquid natural gas storage tank 1 via conduit 10.
  • An outlet of the pump 20 is in fluid communication with an inlet of the vaporizer heat exchanger 21 via conduit 11.
  • An outlet of the vaporizer heat exchanger 21 is in fluid communication with an inlet of the natural gas expander 22 via conduit 12.
  • An outlet of the natural gas expander 22 is in fluid communication with the gas grid 60 via conduit 13.
  • Fig. 1 further schematically shows a gas power plant 100.
  • the gas power plant 100 comprises a compressor 104 and an expander 109, preferably provided on the same shaft 105.
  • the compressor 104 is arranged to receive and compress an air stream 103 and forward the resulting compressed air stream to a fuel burning device 107.
  • the fuel burning device 107 comprises an air inlet to receive the compressed air stream and a fuel inlet to receive a fuel stream 101.
  • the fuel and air are mixed and combusted, thereby generating a combusted gas stream 108 which is forwarded to expander 109.
  • the expander 109 is driven by the combusted gas stream 108.
  • the expander 109 drives compressor 104, generates power, e.g. in the form of electricity via a dynamo.
  • the expander 109 further discharges the combusted gas stream as a hot flue gas stream 120 via a flue gas outlet.
  • the fuel burning device 107 may be any suitable device and is represented schematically in Fig. 1 .
  • Fig. 1 further schematically shows a heat recovery circuit 200 being arranged to transfer heat from the hot flue gas stream 120 to the pressurized liquid natural gas stream 11.
  • the heat recovery circuit 200 as depicted comprises a waste heat recovery heat exchanger 201, a turbine 203, the one or more vaporizer heat exchangers 21 and a pump or compressor 207.
  • An outlet of the waste heat recovery heat exchanger 201 is in fluid communication with an inlet of the turbine 203 via conduit 202
  • an outlet of the turbine 203 is in fluid communication with a heat transfer fluid inlet of the one or more vaporizer heat exchangers 21 via conduit 204
  • a heat transfer fluid outlet of the one or more vaporizer heat exchangers 21 is in fluid communication with an inlet of the pump/compressor 207 via conduit 206
  • an outlet of the pump/compressor 207 is in fluid communication with a heat transfer fluid inlet of the waste heat recovery heat exchanger 201 via conduit 208.
  • the heat recovery circuit 200 comprises a heat transfer fluid that, in use, is cycled through the heat recovery circuit 200.
  • the heat recovery circuit 200 is schematically depicted in Fig.'s 1 and 2 and may comprise additional elements, including knock-out drums, surge drums.
  • the turbine 203 may be formed by different turbines, e.g. a high-pressure and a low-pressure turbine.
  • the waste heat recovery heat exchanger 201 comprises a flue gas inlet being in fluid communication with a flue gas outlet of the expander 109 to receive a hot flue gas stream 120.
  • the waste heat recovery heat exchanger further comprises a flue gas outlet that is in fluid communication with an exhaust stack 121 to discharge of the flue gas stream.
  • the heat recovery circuit 200 as depicted in the Figures comprises an expander 109 from which work is extracted and which is thus used to generate power. Obtaining power from the heat recovery circuit 200 using an expander is optional.
  • Conduit 13 connecting the outlet of the natural gas expander 22 with the gas grid 60 comprises a splitter 17 to split off a split stream 14 from the gasified natural gas stream 13.
  • the splitter 17 preferably is a controllable splitter 17 enabling controlling the flow rate of the split stream 14.
  • a boil-off gas stream is obtained from the one or more liquid natural gas storage tanks 1.
  • Boil-off conduit 31 transfers the boil-off gas stream to an inlet of a boil-off gas compressor 32 to obtain a pressurized boil-off gas stream which is passed to the gas power plant via further boil-off conduit 33.
  • the embodiment schematically depicted shows a fuel stream 101 being fed to the fuel burning device 107, wherein the fuel stream comprises the pressurized boil-off gas stream 33 and the split stream 14.
  • the fuel stream 101 is formed in a different manner.
  • Fig. 2 shows an embodiment in which the fuel stream 101 is formed by the split stream 14, without adding boil-off gas.
  • the system may further comprise a controller C arranged to control the flow rate of the fuel stream 101 and the flow rate of the liquid natural gas stream 10 with respect to each other.
  • the controller may be arranged to actively and continuously control the flow rates of the fuel stream and/or the liquid natural gas stream.
  • the controller may be a computer.
  • the controller may be arranged to control the system such that the flow rate of the fuel stream 101 is minimized for a given liquid natural gas stream 10.
  • the controller may be arranged to maximize or control the power generated to be at a predetermined level.
  • the controller may be arranged to obtain a fuel stream pressure indication indicative of the pressure of the fuel stream 101 as passed to the gas power plant 101 and operate a pressure control device to maintain the pressure of the fuel stream within a predetermined operating range.
  • a liquid natural gas stream 10 is obtained from the one or more liquid natural gas storage tanks 1 (step a1).
  • the liquid natural gas stream 10 may have a temperature between -155°C - -162°C and a pressure in the range of 1 - 5 bar, e.g. 4 bar.
  • the liquid natural gas stream 10 is pressurized by pump 20 (step a2) resulting in a pressurized liquid natural gas stream 11 having a slightly raised temperature, e.g. in the range of -150°C - -160°C and a first pressure being in the range of 80 - 120 bar.
  • the pressurized liquid natural gas stream 11 is heated against the heat transfer fluid to a first temperature T1 being above the send out temperature.
  • the thereby obtained heated pressurized gasified natural gas stream 12 typically has a pressure substantially equal to the first pressure, other than a non-deliberate pressure loss (e.g. 2 or 3 bar) caused by flowing through the vaporizer heat exchanger 21.
  • the heated pressurized gasified natural gas stream 12 has a temperature in the range of +30°C - +60°C, e.g. +50°C.
  • step a4 the heated pressurized gasified natural gas stream 12 is passed through an expander 22 (step a4), thereby obtaining a gasified natural gas stream 13 at the send out pressure and the send out temperature.
  • the send out pressure may be more than 10 bar, 20 bar or 30 bar below the first pressure.
  • the send out pressure may be in the range of 70 - 90 bar, e.g. 80 bar.
  • the send out temperature may be more than 10°C or 20°C below the first temperature.
  • the send out temperature may be in the range +20°C - +40°C, e.g. +30°C.
  • the gas power plant 100 is operated by providing a fuel stream 101 to the gas power plant and obtaining primary power and a hot flue gas stream 120 from the fuel stream.
  • the fuel stream 101 is obtained by obtaining the boil off gas stream 33 from the one or more liquid natural gas storage tanks 1 and obtaining the split stream 14 from the gasified natural gas stream 13 to form the fuel stream 101. No additional streams are added to the fuel stream 101 in the embodiment depicted in Fig. 1 .
  • the fuel stream 101 is obtained by obtaining the split stream 14 from the gasified natural gas stream 13 to form the fuel stream 101. No additional streams are added to the fuel stream 101 in the embodiment depicted in Fig. 2 .
  • the heat recovery circuit 200 is operated by cycling the heat transfer fluid through the heat recovery circuit 200 thereby transferring heat from the hot flue gas stream 120 to the liquid natural gas stream in the vaporizer heat exchanger 21.
  • the heat transfer fluid may consist of CO2 and may be in the supercritical state throughout the heat recovery circuit.
  • Appropriate control schemes may be employed to actively and continuously balance the mass flows of the fuel stream and the liquid natural gas stream, to ensure that sufficient heat is transferred to the vaporizer heat exchanger.
  • liquid natural gas stream 10 is only heated by pumping and pressurizing and by receiving heating duty from the hot flue gas stream 120 via the heat recovery circuit 200. Thus, no other heating sources are present, except for undeliberate heat ingress, such as from the ambient.
  • a system for gasifiying a liquid natural gas comprising a gasification terminal and a gas power plant (100), wherein the gasification terminal is arranged to receive a liquid natural gas stream (10) and generate a heated pressurized gasified natural gas stream (12) from the liquid natural gas stream (10) being at the send out pressure and the send out temperature, wherein the gas power plant is arranged to receive a fuel stream (101) and generate primary power and a hot flue gas stream (120) from the fuel stream, wherein the system further comprises a heat recovery circuit (200) arranged to transfer heat from the hot flue gas stream (120) to the liquid natural gas stream in the gasification terminal via a heat transfer fluid, wherein, in use, the heat recovery circuit comprises a heat transfer fluid consisting of CO2 which is circulated through the heat recovery circuit in a supercritical state.

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CN115596992A (zh) * 2022-09-20 2023-01-13 中国技术进出口集团有限公司（Cn） 一种分布式天然气发电站低能耗的lng气化系统
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CN116201619A (zh) * 2023-02-20 2023-06-02 上海林海生态技术股份有限公司 沼气厂内燃机余热和lng冷能综合利用发电系统及方法
CN117386468A (zh) * 2023-10-06 2024-01-12 惠州深能源丰达电力有限公司 循环电站压气机进气与低压缸排汽的系统与方法
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US11643949B1 (en) * 2021-11-29 2023-05-09 Trane International Inc. Energy generation system for non-traditional combustible fluid source
WO2023094991A1 (fr) * 2021-11-29 2023-06-01 Trane International Inc. Système de génération d'énergie pour une source de fluide combustible non traditionnelle
US12110812B2 (en) 2021-11-29 2024-10-08 Trane International Inc. Energy generation system for non-traditional combustible fluid source
JP2024027276A (ja) * 2022-08-17 2024-03-01 エア・ウォーター株式会社 燃料ガス製造設備
CN115596992A (zh) * 2022-09-20 2023-01-13 中国技术进出口集团有限公司（Cn） 一种分布式天然气发电站低能耗的lng气化系统
CN116201619A (zh) * 2023-02-20 2023-06-02 上海林海生态技术股份有限公司 沼气厂内燃机余热和lng冷能综合利用发电系统及方法
CN116201619B (zh) * 2023-02-20 2025-11-21 上海林海生态技术股份有限公司 沼气厂内燃机余热和lng冷能综合利用发电系统及方法
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