KR102539433B1 - Floating Marine Structure with Hydrogen Storage Tank - Google Patents

Abstract

The present invention relates to an offshore floating structure equipped with a hydrogen storage tank capable of efficiently storing hydrogen in an offshore floating structure and easily supplying the stored hydrogen from the offshore floating structure to other ships by utilizing an existing hydrogen infrastructure.
An offshore floating structure equipped with a hydrogen storage tank according to the present invention includes a liquefied gas storage tank for storing liquefied gas; A liquid hydrogen storage tank for storing liquid hydrogen; Onshore hydrogen infrastructure with a network of compressed hydrogen pipelines; A hydrogen liquefaction line connecting the liquid hydrogen storage tank and onshore hydrogen infrastructure; And cold heat recovery for cooling the compressed hydrogen gas with the cold heat of the liquefied gas by exchanging heat between the liquefied gas stored in the liquefied gas storage tank and the compressed hydrogen gas transferred from the hydrogen infrastructure to the liquid hydrogen storage tank through the hydrogen liquefaction line. Including, the compressed hydrogen supplied from the land is cooled by the cold heat of the liquefied hydrogen to store the hydrogen in a liquid state, and the liquid hydrogen stored in the liquid hydrogen storage tank is supplied to the liquid hydrogen carrier.

Description

Floating Marine Structure with Hydrogen Storage Tank}

The present invention relates to an offshore floating structure equipped with a hydrogen storage tank capable of efficiently storing hydrogen in an offshore floating structure and easily supplying the stored hydrogen from the offshore floating structure to other ships by utilizing an existing hydrogen infrastructure.

Worldwide, ship emission regulations are being strengthened. For example, the International Maritime Organization (IMO) recently agreed and announced that greenhouse gas (GHG) in ship exhaust would be reduced by about 50% compared to 2008 by 2050. According to Lloyd's Register (LR), if the IMO regulates the agreement, the share of zero-emission fuels and technologies for ships is expected to soar.

In addition, the Marine Environment Protection Committee (MEPC) under the IMO will hold additional consultations on how to reduce greenhouse gas emissions from ships, and an initial strategy will also be adopted.

Accordingly, all ships currently in operation must stop using existing fossil fuels and switch to zero-emission fuels such as hydrogen, electric batteries, and bioenergy. Must be able to sail.

As a zero-emission fuel, hydrogen is in the limelight. Hydrogen is clean and limitless, and is a future clean energy with three times the energy amount of gasoline by weight. When hydrogen is used as a fuel, it is attracting attention because there is no emission of pollutants.

In preparation for an increase in the share of hydrogen as a fuel, it is necessary to develop a technology for stably storing and transporting hydrogen. Methods for storing hydrogen in large quantities include a method of liquefying hydrogen and storing it in a liquid state and a method of compressing gaseous hydrogen and storing it in a compressed hydrogen form.

Japanese Unexamined Patent Publication No. 2003-028567 (2003.01.29.)

To store hydrogen in a liquid state, it must be cooled from room temperature to about -253°C, the boiling point of hydrogen. In addition, in order to store hydrogen in the form of compressed hydrogen gas, it is necessary to compress hydrogen to an ultra-high pressure of about 200 bar to 1,000 bar at atmospheric pressure.

However, with the current technology, in order to store and transport hydrogen in a liquid state or compressed hydrogen gas form, a large amount of energy is consumed to cool the hydrogen to a cryogenic temperature or to compress the hydrogen to an ultra-high pressure. In addition, it is necessary to build infrastructure for liquefying or compressing hydrogen, but there is also a problem of difficulty in selecting a site for infrastructure construction or cost burden.

On the other hand, as international interest in preventing marine air pollution increases, as a representative green-ship, a ship using liquefied natural gas (LNG) as fuel (LFS; Liquefied Gas Fueled Ship) has been developed, and the demand for LNG is also rapidly increasing.

LNG is usually transported by an LNG carrier, and an offshore floating structure is used that receives and stores LNG from an LNG carrier in a floating state, regasifies it, and supplies the regasified natural gas to an onshore terminal.

Typically, an LNG floating storage and regasification unit (FSRU) with an LNG storage tank and an LNG regasification facility, a power generation system installed with an LNG storage tank and an LNG regasification facility, and natural gas, using natural gas as a fuel There is an LNG Floating, Storage, Power Plant (FSPP) that can supply the generated electricity to the land.

In LNG FRSU or LNG FSPP, seawater is used as a heat source for vaporizing LNG, and the cold heat of LNG recovered while vaporizing LNG is discarded into the sea.

Therefore, the present invention is to improve the above-mentioned problems, and efficiently utilizes the existing infrastructure to provide an offshore floating structure equipped with a hydrogen storage tank, which can reduce the energy required to liquefy or compress hydrogen and store it. want to provide

According to one aspect of the present invention for achieving the above object, a liquefied gas storage tank for storing liquefied gas; A liquid hydrogen storage tank for storing liquid hydrogen; Onshore hydrogen infrastructure with a network of compressed hydrogen pipelines; A hydrogen liquefaction line connecting the liquid hydrogen storage tank and onshore hydrogen infrastructure; And cold heat recovery for cooling the compressed hydrogen gas with the cold heat of the liquefied gas by exchanging heat between the liquefied gas stored in the liquefied gas storage tank and the compressed hydrogen gas transferred from the hydrogen infrastructure to the liquid hydrogen storage tank through the hydrogen liquefaction line. A hydrogen storage tank that cools the compressed hydrogen supplied from the onshore hydrogen infrastructure with the cold heat of the liquid hydrogen to store the hydrogen in a liquid state and supplies the liquid hydrogen stored in the liquid hydrogen storage tank to the liquid hydrogen carrier. An offshore floating structure provided with is provided.

Preferably, a liquefied gas regasification facility for vaporizing the liquefied gas stored in the liquefied gas storage tank and supplying the regasified gas to a natural gas consumer; and a hydrogen storage facility for liquefying or further compressing the hydrogen supplied from the onshore hydrogen infrastructure.

Preferably, the liquefied gas regasification facility includes: a liquefied gas vaporizer for vaporizing the preheated liquefied gas while cooling the compressed hydrogen in the cold heat recovery device; and a BOG compressor for compressing the boil-off gas generated in the liquefied gas storage tank and supplying it to the natural gas consumer, wherein the temperature of the regasification gas supplied from the regasification facility to the natural gas consumer is controlled by the natural gas consumer. It may further include a trim heater that adjusts to a required temperature.

Preferably, the hydrogen storage facility includes a hydrogen cooler for cooling compressed hydrogen pre-cooled in the cold heat recovery device using a refrigerant; and a pressure reducing valve for expanding compressed hydrogen cooled in the hydrogen cooler to a storage pressure of the liquid hydrogen storage tank, and liquid hydrogen liquefied while passing through the pressure reducing valve may be stored in the liquid hydrogen storage tank.

Preferably, the hydrogen storage facility includes a hydrogen BOG heat exchanger that cools the compressed hydrogen by exchanging heat between hydrogen boil-off gas generated in the liquid hydrogen storage tank and compressed hydrogen supplied from the cold heat recovery device to the hydrogen cooler. Further, the hydrogen boil-off gas heated while cooling the compressed hydrogen in the hydrogen BOG heat exchanger can be supplied to a hydrogen gas demand place.

Preferably, the hydrogen storage facility includes a hydrogen compressor for further compressing compressed hydrogen supplied from the onshore hydrogen infrastructure; an intermediate cooler for cooling the ultra-high pressure hydrogen compressed in the hydrogen compressor; and an ultra-high pressure hydrogen storage tank for storing the cooled ultra-high pressure hydrogen, and supplying the ultra-high pressure hydrogen to a hydrogen gas demand place.

Preferably, the hydrogen storage facility includes a liquid hydrogen high-pressure pump for compressing the liquid hydrogen stored in the liquid hydrogen storage tank; a hydrogen vaporizer for vaporizing the liquid hydrogen compressed by the liquid hydrogen high-pressure pump; and an ultra-high pressure hydrogen buffer tank for storing the hydrogen gas vaporized in the hydrogen vaporizer, and supplying the vaporized hydrogen gas to a hydrogen gas demand place.

An offshore floating structure equipped with a hydrogen storage tank according to the present invention stores hydrogen by utilizing the existing hydrogen infrastructure and an offshore floating structure for liquefied gas, and recovers the cold heat discarded from the offshore floating structure for liquefied gas to generate hydrogen. Energy and cost required for storage can be reduced.

In addition, the size of the piping and equipment required to liquefy the hydrogen can be reduced.

In addition, by using hydrogen as a fuel for the low-pressure gas engine of the offshore floating structure to generate electricity, it is possible to comply with ship exhaust gas environmental regulations, such as reducing methane slip of the low-pressure gas engine in generating electricity.

In addition, by actively utilizing existing infrastructure, it is possible to minimize the need to build additional infrastructure for commercialization of hydrogen fuel.

1 is a configuration diagram schematically showing an offshore floating structure equipped with a hydrogen storage tank according to a first embodiment of the present invention.
2 is a schematic configuration diagram of an offshore floating structure equipped with a hydrogen storage tank according to a second embodiment of the present invention.
FIG. 3 is a block diagram schematically illustrating a connection relationship between an offshore floating structure equipped with a hydrogen storage tank and various ships and onshore infrastructure according to embodiments of the present invention.

In order to fully understand the operational advantages of the present invention and the objects achieved by the practice of the present invention, reference should be made to the accompanying drawings illustrating preferred embodiments of the present invention and the contents described in the accompanying drawings.

Hereinafter, the configuration and operation of a preferred embodiment of the present invention will be described in detail with reference to the accompanying drawings. In adding reference numerals to the components of each drawing, it should be noted that the same components are marked with the same numerals as much as possible, even if they are displayed on different drawings.

In one embodiment of the present invention described later, the offshore floating structure can store liquefied gas while floating on the sea, vaporize the stored liquefied gas, and supply it to a regasified gas demander such as a land terminal, for example, It may be an offshore floating structure that does not have propulsion capability but floats on the sea, such as an LNG Floating Storage Regasification Unit (FSRU) or an LNG Floating Storage Power Plant (FSPP).

In addition, liquefied gas, for example, LNG (Liquefied Natural Gas), LEG (Liquefied Ethane Gas), LPG (Liquefied Petroleum Gas), liquefied ethylene gas, liquefied propylene gas, etc. It may be a liquefied petrochemical gas. However, in the embodiment to be described later, it will be described as an example in which LNG, which is a representative liquefied gas, is applied.

1 is a block diagram schematically illustrating an offshore floating structure equipped with a hydrogen storage tank according to a first embodiment of the present invention, and FIG. 2 is an offshore floating structure equipped with a hydrogen storage tank according to a second embodiment of the present invention. 3 is a configuration diagram briefly showing a structure, and FIG. 3 is a configuration diagram briefly showing the connection relationship between an offshore floating structure equipped with a hydrogen storage tank according to an embodiment of the present invention and various ships and land infrastructures. am. Hereinafter, an offshore floating structure equipped with a hydrogen storage tank according to an embodiment of the present invention will be described with reference to FIGS. 1 to 3 .

First, with reference to FIG. 1, an offshore floating structure equipped with a hydrogen storage tank according to a first embodiment of the present invention will be described.

An offshore floating structure equipped with a hydrogen storage tank according to a first embodiment of the present invention includes an LNG storage tank 100 for storing LNG; An LNG regasification facility that regasifies the LNG stored in the LNG storage tank 100 and supplies it to NG users; and a hydrogen storage facility that receives hydrogen from the onshore hydrogen infrastructure 200, stores the hydrogen in a liquid or gaseous state, and supplies the stored hydrogen to hydrogen demanders (LH ₂ Carrier, H ₂ Users, etc.).

Although only one LNG storage tank 100 is shown in the drawing, one or more LNG storage tanks 100 may be installed. In addition, the LNG storage tank 100 may be insulated so that cryogenic LNG maintains a liquid state. However, even if the LNG storage tank 100 is insulated, heat intrusion from the outside cannot be completely blocked, so that LNG is naturally vaporized in the LNG storage tank 100 to generate boil-off gas (BOG). When BOG is continuously generated, the internal pressure of the LNG storage tank 100 eventually rises, and the LNG storage tank 100 automatically discharges BOG when the internal pressure of the LNG storage tank 100 exceeds the set value. A safety valve (not shown) may be installed to adjust the internal pressure of (100).

In addition, an LNG pump 110 may be installed in the LNG storage tank 100 to pressurize the LNG stored in the LNG storage tank 100 and supply it to the regasification facility.

As shown in FIG. 1 , one or more LNG pumps 110 may be installed, and at least one having the same capacity may be installed for redundancy. Alternatively, at least one installed with different capacities may be a stripping pump capable of pressurizing and discharging LNG even when the water level of the LNG storage tank 100 is lowered.

The regasification facility of the present embodiment includes a cold heat recovery device 120 that recovers cold heat of LNG by heat exchange between LNG and hydrogen; LNG vaporizer 130 for re-vaporizing LNG by exchanging heat between LNG and a heating medium; and a regasified gas buffer tank 140 for temporarily storing the regasified natural gas. It may include; a trim heater 150 for adjusting the temperature of the regasification gas to be supplied to the natural gas consumer to a temperature required by the natural gas consumer.

In the cold heat recovery device 120 of this embodiment, hydrogen gas transported to the liquid hydrogen storage tank 260 described later and LNG transported to the LNG vaporizer 130 by the LNG pump 110 heat-exchange, and hydrogen gas is produced by the heat exchange. is cooled and LNG is heated.

The heating duty of the LNG vaporizer 130 for vaporizing LNG can be reduced by recovering the cold heat of LNG to be supplied to the natural gas demand side in the cold heat recovery device 120 and cooling the hydrogen gas to be stored in the liquid hydrogen storage tank 260. In addition, the cooling duty of the hydrogen cooler 240 for liquefying hydrogen to be stored can be reduced.

Two or more cold heat recovery devices 120 of this embodiment may be installed in series as shown in FIG. this can be carried out. At this time, LNG and hydrogen may exchange heat in a countercurrent flow.

The LNG vaporizer 130 cools hydrogen while passing through the cold heat recovery device 120 to vaporize the heated LNG. Seawater may be used as a heat source for vaporizing LNG in the LNG vaporizer 130, but is not limited thereto. In the present embodiment, when seawater is used as a heat source for vaporizing LNG, the LNG transferred through the LNG pump 110 exchanges heat with seawater without the cold heat recovery device 120 utilizing the cold heat of the LNG before vaporizing the LNG. Since the temperature of the cooled seawater discharged to the sea after heat exchange is higher than in the case of cooling, the cryogenic seawater discharged by cooling the cryogenic LNG destroys the ecosystem of the surrounding sea where the offshore floating structure is floating. of environmental problems can be improved. The regasified gas (NG) vaporized in the LNG vaporizer 130 is supplied to the regasified gas buffer tank 140 .

The regasification gas buffer tank 140 temporarily stores the regasification gas vaporized in the LNG vaporizer 130, stabilizes the regasification gas before supplying the regasification gas to a natural gas demand place, and serves to control the flow rate. can

In addition, according to the present embodiment, not only the regasified gas obtained by regasifying the LNG stored in the LNG storage tank 100, but also the boil-off gas generated in the LNG storage tank 100 can be supplied to NG users. .

Therefore, the regasification facility of this embodiment may further include a BOG compressor 160 for compressing the boil-off gas generated in the LNG storage tank 100 as a means for supplying the boil-off gas to a natural gas demand place. The BOG compressor 160 may compress boil-off gas and supply it to the regasification gas buffer tank 140, and the boil-off gas may be supplied to a natural gas demand place together with the regasification gas stored in the regasification gas buffer tank 140. . That is, the regasification gas in this embodiment may be a concept including compressed BOG.

In addition, a regasification gas line (GL) connecting the regasification gas buffer tank 140 and the natural gas demand place and providing a flow path through which the regasification gas discharged from the regasification gas buffer tank 140 is transported to the natural gas demand place. is connected from the top of the regasification gas buffer tank 140.

A mist removal device may be installed in the regasification gas buffer tank 140 to separate and remove liquid components such as mist and droplets included in the regasification gas discharged from the regasification gas buffer tank 140 . The regasification gas from the regasification gas buffer tank 140 is discharged after passing through the mist eliminator, and is supplied to a natural gas demand place along the regasification gas line GL.

The regasification facility of this embodiment further includes a trim heater 150 that heats or cools the temperature of the regasification gas supplied from the regasification gas buffer tank 140 to the natural gas consumer to a temperature required by the natural gas consumer. can include

The regasification gas supplied from the regasification gas buffer tank 140 to the natural gas consumer may be supplied after being adjusted to a temperature required by the natural gas consumer in the trim heater 150 . When the temperature of the regasification gas discharged from the regasification gas buffer tank 140 is the temperature required by the natural gas consumer, the trim heater 150 may not be operated, or among the regasification gas supplied to the natural gas consumer Some or all of them may be supplied by bypassing the trim heater 150 .

In the regasification gas line GL, between the trim heater 150 and the natural gas consumer, a flow control valve (without reference numerals) equipped with a flow meter for measuring the flow rate of the regasification gas supplied from the regasification facility to the natural gas consumer. grant); can be installed.

The natural gas demand place may be on board, such as a low-pressure gas engine, or off-board, such as a high-pressure natural gas terminal on land. When there are multiple consumers of natural gas, the regasification gas lines (GL) may be branched into several after the flow control valve and connected to each of the consumers of natural gas, and each branch line may be opened or closed depending on whether or not demand is generated by each consumer. A controlled on-off valve (not referenced) may be installed.

The hydrogen storage facility of this embodiment may receive hydrogen from the hydrogen infrastructure 200 installed on land, liquefy and store it, or compress and store it, and supply the stored hydrogen to a hydrogen demand place.

A hydrogen pipeline network capable of transporting hydrogen gas of about 100 bar is formed in Europe and the United States, such as France, Belgium, and the Netherlands, and about 50 hydrogen stations are in operation. Hydrogen pipe networks have been installed and operated in Korea, the UK, Germany, and Canada. In particular, Europe and the United States, where hydrogen infrastructure is well established, such as hydrogen pipe networks, are designated as ECA (Emission Control Areas), and ECA has stricter ship exhaust gas regulations, such as Tier Ⅲ regulations, than other regions.

In general, the hydrogen pipe network is formed of a high-pressure hydrogen pipe network through which hydrogen compressed at high pressure is transported so that the hydrogen can be easily transported even over long distances. For example, onshore hydrogen infrastructure supplies hydrogen compressed to about 100 bar to hydrogen demanders.

On the other hand, hydrogen is an abundant element in the air and is considered as an ideal alternative fuel. However, at present, hydrogen infrastructure such as hydrogen production, distribution, supply, and storage is insufficient, and the cost required to build infrastructure to meet a wide range of demand is also high, so the economic feasibility is evaluated as low.

In connection with the offshore floating structure equipped with the hydrogen storage tank of this embodiment, it will be possible to receive and store hydrogen at a minimum cost, as well as supply the stored hydrogen to hydrogen demanders such as hydrogen carriers.

The offshore floating structure equipped with the hydrogen storage tank of the present embodiment can be operated in a floating state in the sea near where the onshore hydrogen infrastructure 200, such as a pipeline network supplying compressed hydrogen gas, is built.

In particular, a DFDE (Dual Fuel Diesel Electric) engine may be installed as a power generation engine in the offshore floating structure of this embodiment. The DFDE engine uses a 4-stroke cycle and is mainly used for power generation. In addition, the DFDE engine adopts an otto cycle in which low-pressure natural gas of about 6.5 bar is injected into the combustion air inlet and compressed while the piston rises.

The low-pressure gas engine following the Otto cycle, such as the DFDE, has lower efficiency than the high-pressure gas engine following the diesel cycle, such as the ME-GI engine, but the combustion temperature of the fuel is not high, so the amount of nitrogen oxides (NO _x ) generated due to high heat Since this is small, there is an advantage in that it satisfies IMO Tier III, the currently in effect nitrogen oxide regulation, without additionally installing a separate nitrogen oxide treatment system such as SCR or EGR.

However, since the low-pressure gas engine using the Otto cycle injects fuel into the middle of the cylinder, unlike the high-pressure gas engine, there is a disadvantage in that a methane slip phenomenon in which gas leaks before fuel explosion occurs. The amount of methane slip in the low-pressure gas engine is about 2 g/kWh, which is about 10 times more than the amount of methane slip (about 0.2 g/kWh) generated in the high-pressure gas engine. As methane slip, that is, unburned methane (CH ₄ ) is discharged as exhaust gas, it becomes a factor in rapidly increasing the Global Warming Potential (GWP) of low-pressure gas engine exhaust gas.

According to this embodiment, as will be described later, since hydrogen can be stored using a hydrogen storage facility and can be used as a fuel, it can be provided as an eco-friendly ship.

For example, Hydrogen-enriched Compressed Natural Gas (HCNG) fuel is a clean alternative fuel and has the advantages of both natural gas fuel and hydrogen fuel. By adding hydrogen, the burning velocity and poor combustion stability of natural gas fuel can be improved. Natural gas fuel has received a lot of attention as an alternative fuel because of its low emission of pollutants such as particulate matters and hydrocarbons. HCNG fuel has value as a clean fuel that exceeds the benefits of natural gas in that it increases engine efficiency and power and reduces pollutant emissions through improved engine control.

The hydrogen storage facility of this embodiment is connected to the onshore hydrogen infrastructure 200, and provides a flow path so that the compressed hydrogen supplied from the onshore hydrogen infrastructure 200 is supplied to the cold heat recovery device 120. A hydrogen liquefaction line (HL); includes

In addition, the hydrogen storage facility of this embodiment may further include a temporary storage tank 210 for temporarily storing compressed hydrogen gas supplied from the onshore hydrogen infrastructure 200. Hydrogen gas is transferred from the onshore hydrogen infrastructure 200 to the offshore floating structure of the present embodiment along the hydrogen liquefaction line HL, and is stored in the temporary storage tank 210.

The hydrogen gas stored in the temporary storage tank 210 is transferred to the cold heat recovery device 120 along the hydrogen liquefaction line HL, and is cooled by heat exchange with LNG to be vaporized in the cold heat recovery device 120.

The temporary storage tank 210 may serve to stabilize the flow of hydrogen gas transported from the onshore hydrogen infrastructure 200 to the offshore floating structure and to control the flow rate of hydrogen gas to be supplied to the cold heat recovery device 120 .

In addition, the hydrogen liquefaction line (HL) connecting the onshore hydrogen infrastructure 200 and the temporary storage tank 210 and the hydrogen liquefaction line (HL) connecting the temporary storage tank 210 and the cold heat recovery device 120 contain hydrogen. An on/off valve (no reference numeral) that opens and closes according to whether or not gas is being transported and a flow control valve (no reference numeral 1) for adjusting the flow rate of hydrogen gas transferred by controlling the amount of opening may be installed.

The hydrogen storage facility of the present embodiment includes a hydrogen cooler 240 that cools and liquefies hydrogen cooled by the cold heat of LNG in the cold heat recovery device 120 by heat exchange with a refrigerant; A pressure reducing valve 250 for reducing the liquefied liquid hydrogen while passing through the hydrogen cooler 240; and a liquid hydrogen storage tank 260 for storing liquid hydrogen.

A hydrogen buffer tank 230 may be installed between the cold heat recovery device 120 and the hydrogen cooler 240 to temporarily store the cooled hydrogen cooled in the cold heat recovery device 120 . The cooled hydrogen cooled in the cold heat recovery device 120 is supplied to the hydrogen buffer tank 230 through a hydrogen liquefaction line HL connecting the hydrogen outlet of the cold heat recovery device 120 and the hydrogen buffer tank 230, The cooled hydrogen stored in the hydrogen buffer tank 230 is supplied to the hydrogen cooler 240 through a hydrogen liquefaction line HL connecting the hydrogen buffer tank 230 and the hydrogen cooler 240.

The hydrogen buffer tank 230 may play a role of stabilizing the flow of hydrogen supplied from the cold heat recovery device 120 to the hydrogen cooler 240 and adjusting the flow rate of hydrogen to be supplied to the hydrogen cooler 240 .

In addition, a flow path is provided so that the hydrogen cooled in the cold heat recovery device 120, branched from the hydrogen liquefaction line HL connecting the cold heat recovery device 120 and the hydrogen buffer tank 230, is recycled to the cold heat recovery device 120. A hydrogen branch line (HL1a, HL1b) to do; may be connected.

The control unit (not shown) transfers some or all of the cooled hydrogen transferred from the cold heat recovery device 120 to the hydrogen buffer tank 230 according to the temperature of the hydrogen cooled through the cold heat recovery device 120 through the hydrogen branch line HL1a. , HL1b) to control the hydrogen to be recycled to the cold heat recovery device 120, thereby controlling the temperature of the cooled hydrogen.

Alternatively, the temperature of LNG to be vaporized may be controlled using the hydrogen branch lines HL1a and HL1b.

As described above, when two cold heat recovery devices 120 are installed in series, the hydrogen branch lines HL1a and HL1b are connected to the first cold heat recovery device 120a so that the cooled hydrogen is recycled to the first cold heat recovery device 120a. and a branch line HL1a connected to the hydrogen inlet of the second cold heat recovery device 120b to recirculate the cooled hydrogen to the second cold heat recovery device 120b.

On the other hand, it is branched from the LNG line (LL) connecting the LNG storage tank 100 and the cold heat recovery device 120, and the cold heat recovery device 120 and the LNG vaporizer 130, and heats while passing through the cold heat recovery device 120. An LNG branch line providing a flow path to recirculate the recovered LNG to the cold heat recovery device 120 or directly supply LNG from the LNG storage tank 100 to the LNG vaporizer 130 bypassing the cold heat recovery device 120. (LL1a, LL1b); may be used to adjust the temperature of cooling hydrogen or the temperature of LNG supplied to the LNG vaporizer 130.

The control unit may measure the temperature of the cooling hydrogen or the temperature of the LNG supplied to the LNG vaporizer 130 and adjust the flow rate of the LNG branched into the LNG branch lines LL1a and LL1b based on the measured value. Alternatively, it may be adjusted according to whether or not the hydrogen is cooled. That is, when there is no need to cool the hydrogen, the LNG may be controlled to be supplied to the LNG vaporizer 130 without preheating by bypassing the cold heat recovery device 120 along the LNG branch lines LL1a and LL1b.

The hydrogen cooler 240 of this embodiment can liquefy all of the hydrogen pre-cooled in the cold heat recovery device 120 . Although not shown in the drawings, a refrigerant circulating in a refrigerant cycle may be utilized as cooling heat for liquefying hydrogen in the hydrogen cooler 240 . As in the present embodiment, hydrogen is pre-cooled by heat exchange with LNG in the cold heat recovery device 120, and then liquefied by heat exchange with the refrigerant in the hydrogen cooler 240, thereby reducing the cooling duty in the hydrogen cooler 240. . In particular, since the temperature of the hydrogen introduced into the hydrogen cooler 240 is relatively low, the energy consumption of the refrigerant compressor in the refrigerant cycle is significantly reduced compared to supplying hydrogen to the hydrogen cooler 240 without pre-cooling.

In addition, the hydrogen storage facility of the present embodiment includes a hydrogen BOG line (HBL) providing a flow path so that hydrogen BOG generated by natural vaporization of liquid hydrogen in the liquid hydrogen storage tank 260 is discharged to a hydrogen demand place; And it is connected to the hydrogen BOG line (HBL) and the hydrogen liquefaction line (HL), and the cooling hydrogen supplied from the cold heat recovery device 120 to the hydrogen buffer tank 230 is heat exchanged with the hydrogen BOG to further cool the hydrogen with the cold heat of the hydrogen BOG. A hydrogen BOG heat exchanger 220 for cooling; further includes.

The hydrogen BOG discharged from the liquid hydrogen storage tank 260 is the temperature of the liquid hydrogen stored in the liquid hydrogen storage tank 260, that is, about -250 ° C, and the hydrogen consumer (H ₂ Users) hydrogen at a higher temperature than this Therefore, according to this embodiment, the hydrogen BOG heat exchanger 220 can be used to recover the cold heat of the hydrogen BOG and cool the hydrogen to be liquefied with the cold heat of the hydrogen BOG.

Hydrogen provided by the onshore hydrogen infrastructure 200 is generally standardized to be supplied at a pressure of about 100 bar. That is, about 100 bar of hydrogen is transferred from the onshore hydrogen infrastructure 200 to the offshore floating structure. While exchanging heat with LNG at about -160 ° C in the cold heat recovery device 120 of the present embodiment and exchanging heat with hydrogen BOG in the hydrogen BOG heat exchanger 220, hydrogen to be liquefied can be cooled to about -156 ° C, and the hydrogen cooler In 240, hydrogen to be liquefied by heat exchange with the refrigerant may be cooled to about -251 °C.

Liquid hydrogen that is liquefied while passing through the hydrogen cooler 240 is about 100 bar, -251 ° C, and can be maintained at about 1 bar in the liquid hydrogen storage tank 260.

That is, the pressure reducing valve 250 of the present embodiment can reduce or expand the high-pressure hydrogen transported from the hydrogen demander 200 on land to the storage pressure of the liquid hydrogen storage tank 260.

The pressure reducing valve 250 of this embodiment may be a Joule-Thomson valve, and while passing through the Joule-Thomson valve, the pressure and temperature of the liquid hydrogen are lowered to about 1 bar and about -253 ° C, and the liquid hydrogen storage tank 260 Saved.

Unlike natural gas, hydrogen gas has a reversal temperature of the Joule-Thomson effect of about -80 ° C or lower, which is lower than room temperature. will rise Therefore, the temperature of the hydrogen gas before being introduced into the pressure reducing valve 250 must be equal to or less than the inversion temperature of hydrogen, and the hydrogen cooler 240 may cool the hydrogen to the inversion temperature or less.

1 shows only one pressure reducing valve 250. However, by installing a plurality of pressure reducing valves 250 in series, the hydrogen expansion (pressure reduction) process can be performed in multiple steps. That is, by installing a plurality of hydrogen coolers 240 and pressure reducing valves 250, depending on the temperature of liquid hydrogen to be stored in the liquid hydrogen storage tank 260 and the temperature of hydrogen introduced into the pressure reducing valve 250, the hydrogen cooler ( 240) and the pressure-reducing valve 250 are sequentially repeated in multiple steps to reach the liquid hydrogen supplied to the liquid hydrogen storage tank 260 to the target temperature and target pressure.

The liquid hydrogen storage tank 260 of this embodiment stores liquefied and temperature-controlled liquid hydrogen while passing through the cold heat recovery device 120, the hydrogen BOG line 220, the hydrogen cooler 240 and the pressure reducing valve 250 do.

Although only one liquid hydrogen storage tank 260 is shown in FIG. 1, a plurality of liquid hydrogen storage tanks 260 may be installed, and may be insulated so that cryogenic liquid hydrogen maintains a liquid state. In addition, even if the liquid hydrogen storage tank 260 is insulated, boil-off gas may be generated by heat intrusion from the outside, and the boil-off gas generated in the liquid hydrogen storage tank 260 is the above-described hydrogen BOG line (HBL) Through this, gaseous hydrogen can be supplied to the demand place. The demand for gaseous hydrogen may be on board, such as a low-pressure gas engine, or outside a ship, such as a Comp. H ₂ Carrier.

In addition, the liquid hydrogen storage tank 260 may be manufactured to withstand up to a certain level that the internal pressure of the liquid hydrogen storage tank 260 rises as boil-off gas is generated, and the liquid hydrogen storage tank 260 has an internal pressure When this set value is exceeded, the safety valve is automatically opened and the hydrogen boil-off gas is controlled to be discharged from the liquid hydrogen storage tank 260 so that the internal pressure is maintained below the set value.

The liquid hydrogen stored in the liquid hydrogen storage tank 260 may be supplied to liquid hydrogen consumers (LH ₂ Users). The liquid hydrogen demand place may be in a ship, such as a low-pressure gas engine, or may be outboard, such as a liquid hydrogen carrier (LH ₂ Carrier).

In addition, the hydrogen storage facility of this embodiment includes a hydrogen compressor 270 that further compresses hydrogen transported from the land hydrogen infrastructure 200 to an offshore floating structure to an ultra-high pressure; and an ultra-high pressure hydrogen storage tank 280 for storing the ultra-high pressure hydrogen further compressed by the hydrogen compressor 270.

The hydrogen compressor 270 further compresses the hydrogen transferred from the onshore hydrogen infrastructure 200 to a pressure suitable for storing the hydrogen in the ultra-high pressure hydrogen storage tank 280.

For example, the hydrogen compressor 270 may further compress hydrogen transported at a pressure of about 100 bar from the onshore hydrogen infrastructure 200 to an ultra-high pressure of about 200 bar to 1,000 bar, or 300 bar to 700 bar.

As shown in FIG. 1, an intermediate cooler 271 may be installed at the rear end of the hydrogen compressor 270 to cool the ultra-high pressure hydrogen whose temperature has increased while being compressed to ultra-high pressure through the hydrogen compressor 270.

The ultra-high pressure hydrogen storage tank 280 stores ultra-high pressure hydrogen compressed to ultra-high pressure in the hydrogen compressor 270 and then cooled in the intermediate cooler 271. In addition, the ultra-high pressure hydrogen stored in the ultra-high pressure hydrogen storage tank 280 may be supplied to a source of ultra-high pressure hydrogen such as an ultra-high pressure hydrogen carrier.

Although not specifically shown in the drawings, the ultra-high pressure hydrogen storage tank 280 may be a pressure tank for storing ultra-high pressure hydrogen. In addition, although only one ultra-high pressure hydrogen storage tank 280 is shown in FIG. 1, it is not limited thereto, and a plurality of ultra-high pressure hydrogen storage tanks 280 may be installed. Although the pressure of the compressed hydrogen stored in the ultra-high pressure hydrogen storage tank 280 is not particularly limited, the ultra-high pressure hydrogen storage tank 280 of the present embodiment may be used as a commercially available compressed hydrogen tank for land. For example, the ultra-high pressure hydrogen stored in the ultra-high pressure hydrogen storage tank 280 may be about 200 bar to 1,000 bar, or about 300 bar to 700 bar.

The hydrogen compressor 270 may directly compress hydrogen transported from the onshore hydrogen infrastructure 200 or may receive and compress hydrogen transported from the onshore hydrogen infrastructure 200 and stored in the temporary storage tank 210 .

The hydrogen transferred from the onshore hydrogen infrastructure 200 is stored in the temporary storage tank 210, and the flow rate of hydrogen to be liquefied and stored in the liquid hydrogen storage tank 260 in a liquid state, and the ultra-high pressure hydrogen storage tank in a gaseous state after being compressed ( 280) may be distributed and supplied to the hydrogen liquefaction line (HL) and the hydrogen compression line (CL), respectively.

For example, among the flow rate of hydrogen transported from the onshore hydrogen infrastructure 200, the above-described hydrogen liquefaction device, that is, the cold heat recovery device 120, the hydrogen BOG heat exchanger 220, the hydrogen cooler 240, etc. An amount of hydrogen exceeding the amount that can be liquefied may be compressed and stored in the ultra-high pressure hydrogen storage tank 280, and the rest may be liquefied and stored in the liquid hydrogen storage tank 260.

Alternatively, when maintenance of the hydrogen liquefaction device is performed or when LNG is not vaporized, all hydrogen transferred from the onshore hydrogen infrastructure 200 may be compressed and stored in the ultra-high pressure hydrogen storage tank 280.

As described above, according to the present embodiment, hydrogen gas is transferred from the existing onshore hydrogen infrastructure 200 and liquefied with cold heat of LNG, and LNG provides cold heat to hydrogen to be liquefied, preheats it, and then vaporizes it, which is necessary to store hydrogen. Energy and cost can be saved, and the size of piping and equipment required to liquefy hydrogen can be reduced.

Next, with reference to FIG. 2, an offshore floating structure equipped with a hydrogen storage tank according to a second embodiment of the present invention will be described. The second embodiment of the present invention, as a modified example of the above-described first embodiment, does not compress and store the compressed hydrogen gas transferred from the onshore hydrogen infrastructure 200 in a gaseous state, and liquefies all the transferred hydrogen, It is different from the first embodiment in that some or all of the liquid hydrogen is compressed and vaporized. Therefore, hereinafter, differences from the first embodiment will be mainly described, and detailed descriptions of the remaining configurations and operations thereof will be omitted, and even if the descriptions are omitted, the same can be applied.

An offshore floating structure equipped with a hydrogen storage tank according to this embodiment, as shown in FIG. 2, includes an LNG storage tank 100; LNG vaporizer 130; a regasification gas buffer tank 140; BOG compressor 160; and a trim heater 150 to vaporize the LNG stored in the LNG storage tank 100 and supply it to a natural gas consumer.

In addition, the offshore floating structure equipped with a hydrogen storage tank according to the present embodiment liquefies the high-pressure gaseous hydrogen transferred from the onshore hydrogen infrastructure 200 and stores it in a liquid state, or further compresses it, including a hydrogen storage facility. It can be stored in an ultra-high pressure gaseous state.

The hydrogen storage facility of this embodiment includes a temporary storage tank 210; Cold heat recovery device 120; hydrogen BOG heat exchanger 220; a hydrogen buffer tank 230; a hydrogen cooler 240; pressure reducing valve 250; and a liquid hydrogen storage tank 260.

According to the present embodiment, gaseous hydrogen transferred from the onshore hydrogen infrastructure 200 is stored in the temporary storage tank 210, supplied to the cold heat recovery device 120 along the hydrogen liquefaction line HL, and the cold heat recovery device In 120, the cold heat of the LNG to be vaporized supplied to the LNG vaporizer 130 is recovered to pre-cool the hydrogen to be liquefied.

The liquid hydrogen liquefied while passing through the cold heat recovery device 120, the hydrogen BOG heat exchanger 220, the hydrogen cooler 240, and the pressure reducing valve 250 is stored in the liquid hydrogen storage tank 260, and the liquid hydrogen storage tank ( 260) may be supplied to liquid hydrogen demanders such as liquid hydrogen carriers.

In addition, according to this embodiment, the liquid hydrogen high pressure pump 310 for further compressing the liquid hydrogen stored in the liquid hydrogen storage tank 260; A hydrogen vaporizer 320 for vaporizing hydrogen compressed at high pressure in the liquid hydrogen high-pressure pump 310; and an ultra-high pressure hydrogen buffer tank 330 for storing vaporized compressed hydrogen.

The liquid hydrogen high-pressure pump 310 compresses the liquid hydrogen stored in the liquid hydrogen storage tank 260 to the storage pressure of the ultra-high pressure hydrogen buffer tank 330 and supplies it to the hydrogen vaporizer 320.

For example, the liquid hydrogen high-pressure pump 310 may compress liquid hydrogen to about 200 bar to 1,000 bar or about 300 bar to 700 bar.

The hydrogen vaporizer 320 vaporizes compressed hydrogen into gaseous hydrogen using the hydrogen high-pressure pump 310 . The high-pressure gaseous hydrogen vaporized in the hydrogen vaporizer 320 is stored in the ultra-high pressure hydrogen buffer tank 330 .

The heat source for vaporizing hydrogen in the hydrogen vaporizer 320 of this embodiment may use seawater.

The ultra-high pressure hydrogen buffer tank 330 stores high-pressure gaseous hydrogen compressed in the liquid hydrogen high-pressure pump 310 and then vaporized in the hydrogen vaporizer 320. In addition, the ultra-high pressure hydrogen stored in the ultra-high pressure hydrogen buffer tank 330 may be supplied to a source of ultra-high pressure hydrogen such as an ultra-high pressure hydrogen carrier.

For example, according to this embodiment, hydrogen supplied from the onshore hydrogen infrastructure 200 is liquefied and stored in the liquid hydrogen storage tank 260, and when demand occurs at a hydrogen gas demand place, the liquid hydrogen storage tank 260 By vaporizing the stored hydrogen and temporarily storing it in the ultra-high pressure hydrogen buffer tank 330, it is possible to supply the hydrogen gas from the liquid hydrogen storage tank 260 to a demand place.

Although not specifically shown in the drawings, the ultra-high pressure hydrogen buffer tank 330 may be a pressure tank for storing ultra-high pressure hydrogen. In addition, although only one ultra-high pressure hydrogen buffer tank 330 is shown in FIG. 2, it is not limited thereto, and a plurality of ultra-high pressure hydrogen buffer tanks 330 may be installed. Although the pressure of the compressed hydrogen stored in the ultra-high pressure hydrogen butter tank 330 is not particularly limited, the ultra-high pressure hydrogen buffer tank 330 of the present embodiment may be used as a commercially available compressed hydrogen tank for land. For example, the ultra-high pressure hydrogen stored in the ultra-high pressure hydrogen buffer tank 330 may be about 200 bar to 1,000 bar, or about 300 bar to 700 bar.

As in the present embodiment, hydrogen transferred from the existing onshore hydrogen infrastructure 200 is pre-cooled with the cold heat of LNG to be vaporized, then the entire amount is liquefied and stored in a liquid state, or the stored liquid hydrogen is compressed and vaporized at high pressure. By storing hydrogen in a compressed gas state, energy and costs required to store hydrogen can be reduced, and the size of piping and equipment required to liquefy hydrogen can be reduced.

In addition, since hydrogen in a compressed gaseous state obtained by compressing and vaporizing hydrogen after liquefying hydrogen is stored, compressed hydrogen in a gaseous state with less energy than compressing hydrogen in a gaseous state by compressing hydrogen in a liquid state. can be saved

As shown in FIG. 3, an offshore floating structure equipped with a hydrogen storage tank according to embodiments of the present invention transports LNG (eg, about 1 bar, -163° C.) from an LNG carrier. It can be supplied and stored in the LNG storage tank 100, and the LNG stored in the LNG storage tank 100 is vaporized by liquefying hydrogen to supply regasified gas, that is, high-pressure natural gas (CNG) to the regasified gas line (GL). Through this, it can be supplied to natural gas demanders such as onshore natural gas infrastructure.

In addition, an offshore floating structure equipped with a hydrogen storage tank according to embodiments of the present invention receives hydrogen (eg, about 100 bar) from the hydrogen infrastructure 200 and liquefies it with the cold heat of LNG to be vaporized. It may be stored in the liquid hydrogen storage tank 260 or compressed and stored in the ultra-high pressure hydrogen storage tank 280, and the liquid hydrogen stored in the liquid hydrogen storage tank 260 may be compressed, vaporized, and stored in a compressed gas state. In addition, the stored liquid hydrogen (eg, about 1 bar, -253 ° C) can be supplied to a liquid hydrogen demand place such as a liquid hydrogen carrier, and the stored compressed gas hydrogen (eg, about 300 bar to 700 bar, room temperature) It can be supplied to gaseous hydrogen demanders such as gaseous hydrogen carriers.

In addition, an offshore floating structure equipped with a hydrogen storage tank according to an embodiment of the present invention includes LNG stored in the LNG storage tank 100, liquid hydrogen stored in the liquid hydrogen storage tank 260, and ultra-high pressure hydrogen storage tank 280. ) Or compressed gas hydrogen stored in the ultra-high pressure hydrogen buffer tank 330 and HCNG, a mixture of LNG and hydrogen, are used as fuel for a low-pressure gas engine (not shown) to produce electricity, so that it can be used at the power demand point on board as well as power on land It can also be supplied to offshore power demand sources such as infrastructure.

As in the above-described embodiments of the present invention, when compressed hydrogen, for example, gaseous hydrogen of about 100 bar is supplied from the onshore hydrogen infrastructure 200 through a high-pressure hydrogen pipeline, and the hydrogen is liquefied and stored, the hydrogen production plant Compared to the case of liquefying gaseous hydrogen of about 1 bar produced in , the energy and cost required for hydrogen liquefaction can be significantly reduced.

In the hydrogen liquefaction process in which hydrogen is compressed, cooled, and then expanded to liquefy, the pressure of hydrogen before expansion is about 20 bar and the pressure of hydrogen after expansion is about 1.3 bar to about 1.3 bar, about -253 ° C. When liquid hydrogen is obtained, Table 1 shows the results of comparative analysis of the energy consumption of the liquefaction process according to one embodiment of the present invention and the existing hydrogen liquefaction process using a process simulation program (HYSYS). However, this is for simple comparison of the energy saving effect of the liquefaction process according to the embodiments of the present invention compared to existing processes, but is not limited to absolute values.

process
division
hydrogen
source
Hydrogen liquefaction process
energy consumption
energy
opponent
ratio supply
( _GH2 ) compression
(External E) Cooling
(LNG) Cooling
(External E) expansion
(LH ₂ ) copy
invent Athletics
hydrogen
infra
(pipeline)
100 bar,
25℃
Unnecessary
100 bar,
-150℃
100 bar,
-251℃
(1.1MW)


1.3 bar, -253.4 ℃

1.1 MW

9% case 1
hydrogen
production
plant
1 bar,
25℃
20 bar,
575.6℃
(5.1MW) not conducted 20 bar,
-251℃
(7.9MW)
13.0 MW
100% case 2 20 bar,
-150℃ 20 bar,
-251℃
(1.2MW)
6.3 MW
48%

(Case 1) First, when gaseous hydrogen of about 1 bar and 25 ° C produced in a hydrogen production plant is compressed to about 20 bar using a compressor, about 5.1 MW of energy is consumed in the compression process. Compression raises the temperature of hydrogen to about 575.6 °C. About 7.9 MW of energy is consumed to cool compressed hydrogen at about 20 bar and 575.6 ° C to -251 ° C using the refrigerant cycle (external cooling heat). When cooling hydrogen at about 20 bar and -251 ° C is expanded to 1.3 bar, the temperature is lowered to about -253.4 ° C, and liquid hydrogen can be obtained. That is, the existing hydrogen liquefaction method using the Case 1 process consumes about 13.0 MW of energy.

(Case 2) Next, when the gas waterway of about 1 bar and 25 ° C produced in the hydrogen production plant is compressed to about 20 bar using a compressor, about 5.1 MW of energy is consumed in the compression process. Compression raises the temperature of hydrogen to about 575.6 °C. Before cooling compressed hydrogen using a refrigerant cycle, if it is pre-cooled using cold heat of LNG, hydrogen can be cooled to about -150°C. After cooling hydrogen to about -150 ° C using LNG, about 1.2 MW of energy is consumed to cool compressed hydrogen at about 20 bar, -150 ° C to -251 ° C using a refrigerant cycle. When cooling hydrogen at about 20 bar and -251 ° C is expanded to 1.3 bar, the temperature is lowered to about -253.4 ° C, and liquid hydrogen can be obtained. That is, the existing hydrogen liquefaction method using the Case 2 process consumes about 6.3 MW of energy.

Finally, according to one embodiment of the present invention, when gaseous hydrogen of about 100 bar and 25 ° C is supplied using the onshore hydrogen infrastructure 200, that is, a high-pressure hydrogen supply pipeline, hydrogen is further compressed. Since there is no need to do so, the energy required for the compression process is not consumed. Gaseous hydrogen at about 100 bar, 25 ° C can be cooled to about -150 ° C by heat exchange with LNG, and about 1.1 MW of energy is consumed to cool hydrogen to about -251 ° C using a refrigerant cycle. This figure, for absolute comparison with Case 1 and Case 2, hydrogen at about 100 bar, -150 ° C. before heat exchange with the refrigerant cycle, after expanding to about 20 bar, hydrogen at about 20 bar, -156.1 ° C. This is the energy consumption when cooling to about -251 ° C using a refrigerant cycle, that is, when compressed gaseous hydrogen is expanded in multiple stages. When cooling hydrogen at about 20 bar and -251 ° C is expanded to 1.3 bar, the temperature is lowered to about -253.4 ° C, and liquid hydrogen can be obtained. That is, the hydrogen liquefaction method according to one embodiment of the present invention consumes about 1.1 MW of energy.

Since the energy consumption of the liquefaction method according to embodiments of the present invention is only about 9% based on the energy consumption of the existing process (Case 1), according to one embodiment of the present invention, compared to the existing process, about Energy savings of 91% can be expected.

It is obvious to those skilled in the art that the present invention is not limited to the above embodiments and can be variously modified or modified without departing from the technical gist of the present invention. it did

100: LNG storage tank
120: cold heat recovery device
130: LNG vaporizer
140: regasification gas buffer tank
150: trim heater
160: BOG compressor
200: onshore hydrogen infrastructure
210: temporary storage tank
220: hydrogen BOG heat exchanger
230: hydrogen buffer tank
240: hydrogen cooler
250: pressure reducing valve
260: liquid hydrogen storage tank
270: hydrogen compressor
280: ultra-high pressure hydrogen storage tank
310: liquid hydrogen high pressure pump
320: hydrogen vaporizer
330: ultra-high pressure hydrogen buffer tank

Claims (7)

A liquefied gas storage tank 100 for storing liquefied gas; A liquid hydrogen storage tank 260 for storing liquid hydrogen;
Onshore hydrogen infrastructure 200 with a compressed hydrogen pipe network installed;
A hydrogen liquefaction line (HL) connecting the liquid hydrogen storage tank and onshore hydrogen infrastructure;
A cold heat recovery device for cooling the compressed hydrogen gas with the cold heat of the liquefied gas by exchanging heat between the liquefied gas stored in the liquefied gas storage tank and the compressed hydrogen gas transferred from the hydrogen infrastructure to the liquid hydrogen storage tank through the hydrogen liquefaction line. (120);
a liquefied gas regasification facility for vaporizing the liquefied gas stored in the liquefied gas storage tank and supplying the regasified gas to a natural gas consumer; and
A hydrogen storage facility for liquefying or further compressing the hydrogen supplied from the onshore hydrogen infrastructure;
The hydrogen storage facility,
a hydrogen cooler 240 that cools compressed hydrogen pre-cooled in the cold heat recovery device using a refrigerant; and
A pressure reducing valve 250 for expanding the compressed hydrogen cooled in the hydrogen cooler to the storage pressure of the liquid hydrogen storage tank; including,
Liquid hydrogen liquefied while passing through the pressure reducing valve is stored in the liquid hydrogen storage tank,
An offshore floating structure equipped with a hydrogen storage tank that cools the compressed hydrogen supplied from the onshore hydrogen infrastructure with the cold heat of the liquid hydrogen to store the hydrogen in a liquid state and supplies the liquid hydrogen stored in the liquid hydrogen storage tank to the liquid hydrogen carrier. . delete The method of claim 1,
The liquefied gas regasification facility,
A liquefied gas vaporizer 130 for vaporizing preheated liquefied gas while cooling the compressed hydrogen in the cold heat recovery device; and
Including; BOG compressor 160 for compressing the boil-off gas generated in the liquefied gas storage tank and supplying it to the natural gas demand place,
An offshore floating structure equipped with a hydrogen storage tank, further comprising: a trim heater 150 for adjusting the temperature of the regasification gas supplied from the regasification facility to a natural gas consumer to a temperature required by the natural gas consumer. delete The method of claim 1,
The hydrogen storage facility,
A hydrogen BOG heat exchanger (220) for cooling the compressed hydrogen by exchanging heat between the hydrogen boil-off gas generated in the liquid hydrogen storage tank and the compressed hydrogen supplied from the cold heat recovery device to the hydrogen cooler (220);
An offshore floating structure equipped with a hydrogen storage tank, wherein the hydrogen boil-off gas heated while cooling the compressed hydrogen in the hydrogen BOG heat exchanger is supplied to a hydrogen gas demand place. The method of claim 1,
The hydrogen storage facility,
a hydrogen compressor 270 further compressing compressed hydrogen supplied from the onshore hydrogen infrastructure;
an intermediate cooler 271 for cooling the ultra-high pressure hydrogen compressed in the hydrogen compressor; and
An ultra-high pressure hydrogen storage tank 280 for storing the cooled ultra-high pressure hydrogen; further comprising,
An offshore floating structure equipped with a hydrogen storage tank for supplying the ultra-high pressure hydrogen to a hydrogen gas demand place. The method of claim 1,
The hydrogen storage facility,
A liquid hydrogen high-pressure pump 310 for compressing the liquid hydrogen stored in the liquid hydrogen storage tank;
a hydrogen vaporizer 320 for vaporizing the liquid hydrogen compressed by the liquid hydrogen high-pressure pump; and
An ultra-high pressure hydrogen buffer tank 330 for storing the hydrogen gas vaporized in the hydrogen vaporizer; further comprising,
An offshore floating structure equipped with a hydrogen storage tank for supplying the vaporized hydrogen gas to a hydrogen gas demand place.

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