KR102473954B1 - Floating Power Plant and Employment Method therefor - Google Patents

Abstract

The present invention is a floating power plant and a method for operating a floating power plant capable of producing hydrogen by utilizing cold heat and waste heat discarded while generating power in a floating power plant, increasing energy efficiency and reducing operating costs. It is about.
A floating power plant according to the present invention includes a gas engine for generating electric power using liquefied gas as fuel; a fuel supply system supplying fuel gas to the gas engine by vaporizing liquefied gas; a waste heat recovery system for producing steam by recovering waste heat generated by combustion of the fuel gas in the gas engine; a hydrogen production system for producing hydrogen using the remaining fuel gas supplied to the gas engine and the steam produced by the waste heat recovery system; and a hydrogen liquefaction system for liquefying the produced hydrogen by using the cold heat of the liquefied gas to be supplied to the fuel supply system.

Description

Floating Power Plant and Operation Method of Floating Power Plant {Floating Power Plant and Employment Method therefor}

The present invention is a floating power plant and a method for operating a floating power plant capable of producing hydrogen by utilizing cold heat and waste heat discarded while generating power in a floating power plant, increasing energy efficiency and reducing operating costs. It is about.

Recently, interest in power generation using natural gas is increasing due to the demand for eco-friendly power production. In particular, interest in gas power generation is increasing in emerging countries where power supply is not smooth.

In general, natural gas is made in the state of liquefied natural gas (LNG; Liquefied Natural Gas), which is liquefied at a cryogenic temperature at a production site, and is then transported over a long distance to a destination by an LNG carrier. LNG is obtained by cooling natural gas to a cryogenic temperature of about -163 ° C. at atmospheric pressure, and its volume is reduced to about 1/600 of that of gaseous natural gas, so it is very suitable for long-distance transportation through sea.

An LNG carrier is for loading and unloading LNG to a place of demand by operating the sea carrying LNG, and for this purpose, it includes an LNG storage tank capable of withstanding cryogenic LNG. Typically, such an LNG carrier unloads LNG in an LNG storage tank in a liquefied state to an onshore terminal, and the unloaded LNG is regasified by an LNG regasification facility installed in the onshore terminal and then supplied to consumers.

As such, power generation plants that generate electricity by burning gas fuel are generally installed mainly on land, especially on the seashore. The coastal area has the advantage of easy supply and demand for these raw materials. However, the cost of foundation construction, such as land purchase, is expensive, and opposition from residents and environmental pollution must be taken into account. In addition, it was difficult to generate large-capacity gas power generation in Southeast Asian countries composed of several islands.

In order to solve these problems, technologies for mounting the power plant on a ship or offshore structure, away from the fixed form on land, are being developed. Ships and offshore structures are advantageous in that they can be placed in a timely manner in a place where raw materials are easily supplied or where power supply is required, while reducing the cost of purchasing land for plant installation and the cost of foundation work.

Accordingly, an LNG storage tank for storing LNG, an LNG regasification facility for regasifying LNG, and a power generation facility capable of generating power using the regasified gas are mounted, and a floating type capable of transmitting power generated on board to land. Development of a power plant (FSPP; Floating, Storage, Power Plant) is required.

A power generation facility of an existing floating power plant has a gas turbine and a generator, drives the gas turbine using regasification gas, and converts the driving force of the gas turbine into electric energy using the generator to produce electric power.

However, the power generation efficiency of the gas turbine is low, and the energy efficiency of the floating power plant is low because the cold heat of LNG and the waste heat generated in the power plant are not effectively utilized and are discarded.

Therefore, the present invention has been made to solve the above-mentioned problems, and the floating power plant, which can improve the process efficiency and energy efficiency of the floating power plant by using the cold heat of liquefied gas and waste heat discharged from power generation facilities. And to provide a method of operating a floating power plant.

According to one aspect of the present invention for achieving the above object, a gas engine for generating electric power using liquefied gas as fuel; a fuel supply system supplying fuel gas to the gas engine by vaporizing liquefied gas; a waste heat recovery system for producing steam by recovering waste heat generated by combustion of the fuel gas in the gas engine; a hydrogen production system for producing hydrogen using the remaining fuel gas supplied to the gas engine and the steam produced by the waste heat recovery system; And a hydrogen liquefaction system for liquefying the produced hydrogen by using the cold heat of the liquefied gas to be supplied to the fuel supply system; including, a floating power plant is provided.

Preferably, the hydrogen liquefaction system includes a first heat exchanger that cools the hydrogen by exchanging heat between the hydrogen and the liquefied gas, and the first heat exchanger and the fuel supply system are connected to the heat exchange in the first heat exchanger. It may be connected to a preheating line for supplying liquefied gas whose temperature has risen by the fuel supply system.

Preferably, the fuel supply system includes a fuel vaporizer for vaporizing the liquefied gas; a fuel compressor for compressing the fuel gas vaporized in the fuel vaporizer to a pressure required by the gas engine; and a fuel heater configured to heat the fuel gas compressed by the fuel compressor to a temperature required by the gas engine, wherein the preheating line is connected from the first heat exchanger to the fuel vaporizer so that the first heat exchanger Liquefied gas whose temperature has risen in may be supplied to the fuel vaporizer.

Preferably, the hydrogen liquefaction system, the second heat exchanger for further cooling the hydrogen cooled by the cooling heat of the liquefied gas in the first heat exchanger; And an expander for cooling some of the hydrogen supplied from the first heat exchanger to the second heat exchanger by expansion, further comprising, in the second heat exchanger, the hydrogen cooled in the first heat exchanger expands in the expander. It can be cooled by the hydrogen refrigerant cooled by.

Preferably, the hydrogen liquefaction system may further include an expansion valve for liquefying at least a portion of the hydrogen cooled by the hydrogen refrigerant in the second heat exchanger.

Preferably, the hydrogen liquefaction system may further include a separator for gas-liquid separation of hydrogen passing through the expansion valve and supplying hydrogen in a liquid state to a liquid hydrogen tank.

Preferably, a hydrogen production line connecting the fuel supply system and the hydrogen production system further includes, wherein the hydrogen production system includes a reformer for producing hydrogen by reforming the fuel gas and the steam, , The hydrogen production line may be connected from a rear end of the fuel compressor to a front end of the reformer, so that fuel gas compressed by the fuel compressor may be supplied to the reformer.

Preferably, a regasification system for regasifying the liquefied gas and supplying the liquefied gas to an onshore gas demand place; further comprising, in the floating power plant, regasification gas, electric power, hydrogen gas and liquid using the liquefied gas. Hydrogen can be produced.

According to another aspect of the present invention for achieving the above object, supplying liquefied gas to the fuel gas of the gas engine; generating electric power by using fuel gas as fuel in the gas engine; and generating steam by recovering waste heat generated by combustion of the fuel gas in the gas engine, and producing hydrogen using the fuel gas and steam as raw materials; And a step of liquefying the produced hydrogen by heat exchange with the liquefied gas to be vaporized; a method of operating a floating power plant including a is provided.

Preferably, the step of supplying the liquefied gas as fuel gas of a gas engine comprises: vaporizing the liquefied gas; and compressing the fuel gas obtained by vaporizing the liquefied gas. In the vaporizing of the liquefied gas, the liquefied gas may include liquefied gas heated while liquefying the hydrogen.

Preferably, the compressed fuel gas may be supplied as a raw material in the step of producing the hydrogen.

Preferably, the step of liquefying the hydrogen by heat exchange with liquefied gas comprises: firstly cooling the hydrogen by heat exchange with liquefied gas; and branching some of the primarily cooled hydrogen to further cool it by expansion, and using the expanded hydrogen as a refrigerant to branch off and secondarily cool the remaining hydrogen. have.

Preferably, further cooling the secondary cooled hydrogen by an expansion valve; and gas-liquid separation of the hydrogen further cooled by the expansion valve; further including, the gas-liquid separated liquid hydrogen is stored, and the separated gas hydrogen may be re-supplied to the step of first cooling the hydrogen.

Preferably, the step of vaporizing the liquefied gas and supplying it to a gas demand place on land; further comprising, in the floating power plant, using the liquefied gas to produce regasified gas, power, hydrogen and liquid hydrogen have.

The floating power plant and the operating method of the floating power plant according to the present invention regasify liquefied gas and supply it to a gas demand place, and use the regasified gas to produce power, and at the same time, waste heat generated while producing power. can be used to produce hydrogen, a clean energy.

By producing hydrogen, which is clean energy, it can contribute to energy purification.

In addition, by using the cold heat of liquefied gas to liquefy and store hydrogen, it is easy to store and supply hydrogen to a hydrogen demand place.

In addition, by using the liquefied gas heated while liquefying hydrogen as a fuel for power generation, it is possible to increase the heat exchange efficiency for supplying the liquefied gas to the power generation facility and lower the required specifications of the heat exchanger, which is advantageous from an economic point of view.

1 is a configuration diagram schematically showing process equipment of a floating power plant according to an embodiment 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 an embodiment of the present invention described later, the liquefied gas may be a liquefied gas that can be transported by liquefying the gas at a low temperature, for example, LNG (Liquefied Natural Gas), LEG (Liquefied Ethane Gas), LPG (Liquefied Gas) Petroleum Gas), liquefied ethylene gas (Liquefied Ethylene Gas), liquefied propylene gas (Liquefied Propylene Gas) and the like. 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.

In addition, in one embodiment of the present invention described later, the floating power plant has an engine capable of using liquefied gas as a fuel for a power generation engine, and can supply power generated by the power generation engine to a gas demand place on land. characterized by

In addition, the floating power plant may be a ship having propulsion capability, and may include offshore structures that do not have propulsion capability but are floating on the sea, such as BMPP (Barge Mounted Power Plant) and FSPP (Floating Storage Power Plnat). can However, in an embodiment to be described later, an example applied to FSPP will be described.

1 is a configuration diagram schematically showing process equipment of a floating power plant according to an embodiment of the present invention. Hereinafter, with reference to FIG. 1, a floating power plant and a floating power plant operating method according to an embodiment of the present invention will be described.

A floating power plant according to an embodiment of the present invention includes a regasification system 100 for regasifying LNG and supplying it to a place of demand on land; A fuel supply system 200 that generates power using LNG; a waste heat recovery system 300 that recovers waste heat discharged from the fuel supply system 200; A hydrogen production system 400 that produces hydrogen using LNG; and a hydrogen liquefaction system 500 for liquefying hydrogen using LNG.

The floating power plant of this embodiment may further include an LNG storage tank (T) for storing LNG. Although only one LNG storage tank (T) is shown in FIG. 1, a plurality of LNG storage tanks (T) may be installed in the floating power plant of this embodiment.

The LNG used in the regasification system 100, the fuel supply system 200, the hydrogen production system 400, and the hydrogen liquefaction system 500 of this embodiment may be stored in the LNG storage tank T.

In this embodiment, an LNG storage tank (T) is installed in a floating power plant, and a regasification system 100, a fuel supply system 200, a hydrogen production system 400, and a hydrogen liquefaction system from the LNG storage tank (T) It will be described as an example in which LNG is transferred to any one or more of (500). However, it is not limited thereto, and the floating power plant according to the present invention is not installed with an LNG storage tank (T), and an external LNG supply source, for example, an LNG storage tank installed on land or another LNG storage tank installed. It will also be possible to receive LNG directly from the ship and use it.

In this embodiment, LNG may be stored at about -163 ° C. at about 1 atm in the LNG storage tank (T). The LNG storage tank T may have an insulating structure so that cryogenic LNG can maintain a liquid state.

Even if the LNG storage tank T is insulated, LNG may be spontaneously vaporized due to heat intrusion from the outside. LNG is naturally vaporized to generate boil-off gas (BOG), and the generation of the boil-off gas increases the internal pressure of the LNG storage tank (T). The LNG storage tank (T) may have a pressure-resistant structure capable of withstanding a certain degree of internal pressure increase.

For example, when the internal pressure of the LNG storage tank (T) rises above a set value, the LNG storage tank (T) opens a safety valve (not shown) to discharge the boil-off gas to the outside of the LNG storage tank (T). It may be by design.

Although not shown in the drawings, the boil-off gas discharged from the LNG storage tank (T) also includes any one or more of the regasification system 100, the fuel supply system 200, the hydrogen production system 400, and the hydrogen liquefaction system 500. can be utilized in

In addition, an LNG supply pump (not shown) may be provided inside the LNG storage tank T to discharge LNG to the outside. The LNG supply pump may be a semi-submersible pump, and one or more may be provided.

The regasification system 100 of this embodiment includes a vaporizer 120 for vaporizing LNG to be supplied to a gas demand place; and a regasification pump 110 for compressing the LNG to be regasified and supplying the compressed LNG to the vaporizer 120 .

In addition, the regasification system 100 of this embodiment, that is, the LNG storage tank T, the regasification pump 110, the vaporizer 120, and the gas demand point are connected by a regasification line GL1; the LNG is It flows along the regasification line GL1, is regasified, and is transported from the LNG storage tank T to a gas demand place. In this embodiment, the gas demander may be a gas demander installed on the shore, such as a power plant.

The regasification pump 110 according to the present embodiment compresses LNG to be regasified and supplied to a gas consumer to a pressure required by the gas consumer or higher than a critical pressure. For example, the pressure of the regasification gas required by the gas consumer may be 30 to 40 barg, 50 to 70 barg, or 100 barg, and the regasification pump 110 may supply LNG at a pressure of 30 to 40 barg or 50 to 40 barg. It can be compressed to 70 barg or 100 barg, or to a slightly higher pressure to account for downstream pressure loss.

In addition, in the present embodiment, by using the regasification pump 110 to compress LNG to be vaporized to a pressure higher than the critical pressure of LNG, heat exchange efficiency in the vaporizer 120 may be increased. That is, LNG compressed by the regasification pump 110 and transferred to the vaporizer 120 may be in a supercritical state.

The vaporizer 120 of the present embodiment vaporizes LNG compressed by the regasification pump 110 to a pressure required by a gas consumer or to a pressure slightly higher than that by heat exchange.

As described above, the high-pressure LNG transferred from the regasification pump 110 to the vaporizer 120 may be in a supercritical state. In this specification, 'evaporation' does not simply mean a phase change from a liquid to a gas phase, but the transfer of heat energy from a heat medium to LNG, that is, the temperature rise of LNG by obtaining heat energy from a heat medium. It is a concept that includes

In addition, according to this embodiment, the vaporizer 120 may be connected to a heat source line ML1 through which a heat medium to vaporize compressed LNG flows. The heat medium supplied to the vaporizer 120 may be seawater, fresh water or glycol water. In this embodiment, it will be described as an example that the heating medium supplied to the vaporizer 120 is seawater.

LNG is vaporized by heat exchange in the vaporizer 120 and seawater is cooled. The heat medium, that is, seawater cooled while vaporizing LNG in the vaporizer 120 is discharged from the vaporizer 120 through the heat source line ML1.

Although not shown in the figure, the seawater cooled by heat exchange in the vaporizer 120 may be directly discharged to the sea, or may be discharged to the sea after undergoing a separate treatment process such as temperature control and purification, and at least some of the vaporizer ( 120) may be recycled.

In addition, a flow control valve (not shown) may be further provided in the heat source line ML1 to open and close the passage and adjust the flow rate of seawater flowing to the vaporizer 120 along the heat source line ML1.

The control unit, not shown, controls the opening and closing of the flow control valve according to the flow rate and temperature of LNG to be vaporized in the vaporizer 120, the temperature of seawater supplied to the vaporizer 120, etc. The flow rate of seawater can be adjusted.

In addition, although not shown in the drawing, the regasification system 100 of the present embodiment further includes a compressor (not shown) for compressing the boil-off gas generated in the LNG storage tank T, so that the boil-off gas is supplied to a gas demand place. It can also be compressed to a required pressure and supplied to a gas consumer. Alternatively, a condenser (not shown) for condensing the boil-off gas may be further provided to re-liquefy the boil-off gas, and then re-vaporize the boil-off gas in the vaporizer 120 and supply the gas to a consumer.

The fuel supply system 200 of this embodiment includes a gas engine 240 that generates power by using fuel gas vaporized from LNG as fuel; A fuel vaporizer 210 for vaporizing LNG to be supplied to the gas engine 240; a fuel compressor 220 for compressing the fuel gas vaporized in the fuel vaporizer 220; and a fuel heater 230 for controlling the temperature of the fuel gas to be supplied to the gas engine 240.

The fuel supply system 200 of the present embodiment, that is, the LNG storage tank T, the fuel vaporizer 210, the fuel compressor 220, the fuel heater 230 and the gas engine 240 includes a fuel supply line GL2; Connected by, LNG flows along the fuel supply line (GL2) and is fueled, and is transferred from the LNG storage tank (T) to the gas engine (240).

A generator (not shown) may be connected to the gas engine 240 to convert driving force of the engine into electrical energy. The generator converts driving power by combustion of fuel gas into electrical energy, and the generated electrical energy is transmitted through a power supply line PL connecting the gas engine 240 and a power demander. In this embodiment, the power demander may be installed on land. In addition, although not shown in the drawings, the power generated by the gas engine 240 may be supplied to a power consumer in the floating power plant of the present embodiment.

The gas engine 240 of this embodiment may be a Dual Fuel Diesel Electric (DFDE) engine. The DFDE engine consists of a 4-stroke, injects low-pressure natural gas of about 3 bar to 8 bar, or about 4 bar to 6.5 bar, or about 6.5 bar into the combustion air inlet, and compresses it while the piston rises. It is a low-pressure gas injection engine that adopts an Otto Cycle. The DFDE engine may be provided as an engine for power generation of a ship.

The fuel vaporizer 210 vaporizes LNG to be supplied as fuel for the gas engine 240 from the LNG storage tank T through heat exchange.

In addition, the fuel vaporizer 210 may be connected to a first steam line SL1 through which a heat medium to vaporize LNG flows. The heating medium supplied to the fuel vaporizer 210 may be steam or glycol water. In this embodiment, the heat medium supplied to the fuel vaporizer 210 will be described as an example of steam. Also, in this embodiment, steam may be produced in a waste heat recovery system 300 to be described later.

LNG is vaporized by heat exchange in the fuel vaporizer 210, steam is cooled, and some of the steam may be condensed. The heat medium cooled while vaporizing LNG in the fuel vaporizer 210, that is, steam is discharged from the fuel vaporizer 210 through the first fresh water recovery line WL1.

Although not shown in the figure, the steam cooled by heat exchange in the fuel vaporizer 210 may be discharged to the outside or may be recycled to the waste heat recovery system 300 to be described later after undergoing a treatment process such as complete condensation.

In addition, a first steam flow control valve (not shown) is further provided in the first steam line SL1 to open and close the passage and adjust the flow rate of steam flowing to the fuel vaporizer 210 along the first steam line SL1. It can be.

The control unit (not shown) controls the opening and closing of the first steam flow control valve according to the flow rate and temperature of LNG to be vaporized in the fuel vaporizer 210, the temperature of the steam supplied to the fuel vaporizer 210, and the like, so that the fuel vaporizer The flow rate of steam supplied to (210) can be adjusted.

Alternatively, the first steam flow control valve may be provided on the first fresh water recovery line WL1.

The gas engine 240 of this embodiment has a limit on the methane number of the fuel gas, and if a fuel gas that does not meet the limit on the methane number is supplied as fuel, a knocking phenomenon may occur, so the methane number of the fuel gas needs to be adjusted.

According to this embodiment, the methane number of the fuel gas supplied to the gas engine 240 may be adjusted by controlling the temperature of the LNG vaporized in the fuel vaporizer 210 by controlling the first steam flow control valve.

For example, if the vaporization temperature of the fuel vaporizer 210 is lowered, the proportion of methane among the components of the vaporized gas increases and the proportion of heavy hydrocarbons such as propane and butane decreases. The methane number of the fuel gas increases.

Conversely, if the vaporization temperature of the fuel vaporizer 210 is increased, heavy hydrocarbons are increased in the vaporized gas components, so the methane number of the fuel gas vaporized in the fuel vaporizer 210 is lowered.

The fuel compressor 220 of this embodiment, the fuel gas vaporized in the fuel vaporizer 210, the pressure required by the gas engine 240, that is, about 3 bar to 8 bar, or about 4 bar to 6.5 bar, or about It can be compressed to 6.5 bar.

Also, the fuel compressor 220 may be a multi-stage compressor composed of a plurality of compressors. For example, the fuel compressor 220 may compress fuel gas to a pressure required by the gas engine 240 in four stages by connecting four compressors in series. An intercooler may be provided at each rear end of the plurality of compressors to cool the fuel gas whose temperature is increased by compression. The number of stages of the fuel compressor 220 is not limited thereto.

The fuel heater 230 of this embodiment can adjust the temperature of the fuel gas compressed in the fuel compressor 220 to meet conditions required by the gas engine 240 . As described above, since the vaporization temperature in the fuel vaporizer 210 is controlled due to the methane number limit of the gas engine 240, the fuel heater 230 adjusts the temperature of the fuel gas whose methane number is adjusted to the gas engine 240. The fuel gas can be heated to meet the fuel conditions of

The fuel heater 230 may be connected to a second steam line SL2 through which a heat medium to heat fuel gas flows. The heating medium supplied to the fuel heater 230 may be steam or glycol water. In the present embodiment, a heat medium supplied to the fuel heater 230 will be described as an example of steam. Also, in this embodiment, steam may be produced in a waste heat recovery system 300 to be described later.

Fuel gas is heated by heat exchange in the fuel heater 230, steam is cooled, and some of the steam may be condensed. The heat medium, that is, steam cooled while heating the fuel gas in the fuel heater 230 is discharged from the fuel heater 230 through the second fresh water recovery line WL2.

Although not shown in the drawing, the steam cooled by heat exchange in the fuel heater 230 may be discharged to the outside or may be recycled to the waste heat recovery system 300 to be described later after undergoing a treatment process such as complete condensation.

In addition, a second steam flow control valve (not shown) is further provided in the second steam line SL2 to open and close the passage and adjust the flow rate of steam flowing to the fuel heater 230 along the second steam line SL2. It can be.

The control unit (not shown) controls the opening and closing of the second steam flow control valve according to the flow rate and temperature of the fuel gas to be heated by the fuel heater 230, the temperature of the steam supplied to the fuel heater 230, etc. The flow rate of steam supplied to the heater 230 may be adjusted.

Alternatively, the first steam flow control valve may be provided on the second fresh water recovery line WL2.

The fuel gas whose temperature is controlled in the fuel heater 230 is supplied as fuel to the gas engine 240 along the fuel supply line GL2.

In addition, although not shown in the drawings, a boil-off gas compressor (not shown) for compressing the boil-off gas discharged from the LNG storage tank T to a pressure required by the gas engine 240 is further provided, so that the gas engine 240 It can also be supplied as fuel. Boiled gas is natural vaporization of LNG, and methane is the main component, so it may not be necessary to adjust the methane number. The boil-off gas compressor may be provided separately for the purpose of compressing the boil-off gas, or the fuel compressor 220 may be utilized.

The gas engine 240 of this embodiment receives fuel gas through the fuel supply line GL2, is driven by burning fuel, and generates combustion gas by burning fuel.

The waste heat recovery system 300 of this embodiment includes an economizer 310 that produces steam using combustion heat of combustion gas discharged from the gas engine 240 .

The gas engine 240 and the economizer 310 are connected by an engine exhaust gas line EL1, and combustion gas is supplied from the gas engine 240 to the economizer 310 along the engine exhaust gas line EL1.

In addition, the economizer 310 includes a fresh water supply line (WL); and a steam supply line (SL); are connected. Fresh water to generate steam by thermal energy of combustion gas is supplied to the economizer 310 along the fresh water supply line WL. In addition, the steam generated by the economizer 310 is discharged along the steam supply line SL and supplied to a steam consumer.

The steam demand point of this embodiment may include the fuel vaporizer 210 and the fuel heater 230 described above, and the first steam line SL1 and the second steam line SL2 branch from the steam supply line SL. It can be.

In addition, the steam demand place may include a hydrogen production system 400 to be described later. The third steam line SL3 connected to the hydrogen production system 400 may be branched off from the steam supply line SL.

A control unit (not shown) may control the flow rate of steam to be supplied to the first steam line SL1 , the second steam line SL2 , and the third steam line SL3 .

The combustion gas whose temperature is lowered while steam is generated by heat exchange with fresh water in the economizer 310 may be discharged into the atmosphere along the engine exhaust gas line EL1.

In addition, the combustion gas may undergo a separate treatment process such as a purification process before being supplied to the economizer 310 or discharged from the economizer 310 into the atmosphere.

The hydrogen production system 400 of this embodiment includes a hydrogen production compressor 410 for compressing natural gas as a raw material for producing hydrogen; A reformer 430 for producing hydrogen by reforming natural gas and steam; and a hydrogen gas tank 460 for storing hydrogen generated by the reforming reaction.

According to this embodiment, as a raw material for producing hydrogen with the hydrogen production system 400, natural gas vaporized from LNG or boil-off gas generated from the LNG storage tank T can be used. In this embodiment, the use of fuel gas vaporized in the fuel supply system 200 as a raw material for hydrogen production will be described as an example.

That is, according to the present embodiment, a hydrogen production line GL4 connected from the fuel supply line GL2 to the compressor 410 for hydrogen production; may be provided. The fuel gas vaporized in the fuel vaporizer 210 and compressed in the fuel compressor 220 may be supplied to the compressor 410 for producing hydrogen along the hydrogen production line GL4 .

As described above, the fuel gas vaporized in the fuel vaporizer 210 is supplied to the compressor 410 for hydrogen production along the hydrogen production line GL4 because the methane number is adjusted due to the methane number limit of the gas engine 240 Natural gas is mainly composed of methane.

Therefore, according to the present embodiment, some or all of the vaporized and compressed fuel gas to be supplied to the gas engine 240, or the gas fuel remaining after being supplied to the gas engine 240, that is, natural gas containing methane as the main component By supplying the gas as a raw material for hydrogen production of the hydrogen production system 400, the efficiency of hydrogen production can be increased.

In addition, by supplying gas fuel primarily compressed at a pressure required by the gas engine 240 to the compressor 410 for hydrogen production, compression energy required for a reforming reaction can be reduced.

The compressor 410 for producing hydrogen according to the present embodiment compresses natural gas to a pressure suitable for a reforming reaction. For example, the compressor 410 for producing hydrogen may compress natural gas to about 30 to 50 bar.

The reformer 430 of this embodiment produces hydrogen by reforming the natural gas compressed in the compressor 410 for hydrogen production and steam.

The hydrogen production system 400 according to the present embodiment is connected to the waste heat recovery system 300 through the third steam line SL3. The third steam line SL3 may branch from the steam supply line SL, be connected from the steam supply line SL to the reformer 430, or join the hydrogen production line GL4 at the front end of the reformer 430. It can be.

Alternatively, although not shown in the drawings, a mixer (not shown) may be further provided so that a mixture of natural gas and steam is introduced into the reformer 430 at the front end of the reformer 430 .

That is, steam supplied to the reformer 430 in this embodiment may be produced by the economizer 310 described above.

In the reformer 430 of this embodiment, hydrogen can be produced by steam reforming, and the following reforming reaction occurs. In addition, the reforming reaction in the reformer 430 may occur under reaction conditions of about 700 to 800° C. and about 30 to 50 bar under a catalyst.

CH ₄ (g) + H ₂ O (g) → CO (g) + 3H ₂ (g)

CH4(g) + 2H ₂ O(g) → CO ₂ (g) + 4H ₂ O(g)

The hydrogen gas generated by the reforming reaction described above in the reformer 430 may be stored in the hydrogen gas tank 460 for storing hydrogen gas.

The hydrogen production system 400 of this embodiment includes a converter 440 that shifts carbon monoxide and water among products generated in the reformer 430 into carbon dioxide and hydrogen; and an absorber 430 for absorbing and removing carbon dioxide from a mixture of carbon dioxide and hydrogen, which is a product of passing through the reformer 430 and the converter 440.

In converter 440, the following reactions occur.

CO(g) + H ₂ O(g) → CO ₂ (g) + H ₂ (g)

In the absorber 430, carbon dioxide is separated from the mixture by a pressure swing adsorption (PSA) method, so that hydrogen can be recovered and purified.

That is, only hydrogen gas separated from the product discharged from the reformer 430 while passing through the converter 440 and the absorber 450 can be supplied to the hydrogen gas tank 460 along the hydrogen line HL2.

The hydrogen gas tank 460 may be provided as a pressure tank.

The hydrogen gas stored in the hydrogen gas tank 460 may be directly supplied to a hydrogen gas demand place through a separate pipe line connected to the hydrogen gas demand place. Alternatively, after being supplied to the hydrogen liquefaction system 500 to be described later and liquefied, it may be stored in a liquid state in a hydrogen liquid tank (not shown). Alternatively, the hydrogen gas tank 460 or the hydrogen liquid tank (not shown) itself may be unloaded and supplied to a hydrogen demand place.

In addition, a preprocessor 420 for removing impurities such as hydrogen sulfide from the compressed natural gas supplied to the reformer 430 may be further provided at a front end of the reformer 430 .

The hydrogen liquefaction system 500 of this embodiment includes, in order to liquefy the hydrogen gas stored in the hydrogen gas tank 460, a first heat exchanger 510 for cooling the hydrogen gas; a second heat exchanger 520 that secondarily cools the hydrogen gas cooled in the first heat exchanger 510; and a separator 540 for gas-liquid separation of hydrogen at least partially liquefied while passing through the first heat exchanger 510 and the second heat exchanger 520.

The first heat exchanger 510 of this embodiment includes a second hydrogen line HL2 through which hydrogen gas flows from the hydrogen gas tank 460 to the first heat exchanger 510; and a preheating line GL3 through which LNG flows from the LNG storage tank T to the first heat exchanger 510 as a refrigerant for cooling the hydrogen gas.

That is, in the first heat exchanger 510 of the present embodiment, hydrogen gas and LNG exchange heat, and the hydrogen gas is cooled and LNG is preheated by the heat exchange.

The preheating line GL3 may be connected from the refrigerant outlet of the first heat exchanger 510 to the fuel supply line GL2. That is, LNG whose temperature has increased by heat exchange in the first heat exchanger 510 is supplied to the fuel supply system 200 through the preheating line GL3.

A point where the preheating line GL3 joins the fuel supply line GL2 may be a front end of the fuel vaporizer 210 . That is, LNG preheated in the first heat exchanger 510 is supplied to the fuel vaporizer 210 . Therefore, according to the present embodiment, as preheated LNG flows into the fuel vaporizer 210, the heating duty required to vaporize the fuel gas to be supplied to the gas engine 240 in the fuel vaporizer 210 can be reduced. have. In addition, requirements for the fuel vaporizer 210 can be lowered, and equipment and maintenance costs can also be reduced.

A hydrogen liquefaction pump 550 pressurizing LNG supplied from the LNG storage tank T to the first heat exchanger 510 may be provided in the preheating line GL3.

The hydrogen gas cooled in the first heat exchanger 510 is supplied to the second heat exchanger 520 along the third hydrogen line HL3.

According to this embodiment, the expander 530 for cooling the hydrogen gas supplied from the first heat exchanger 510 to the second heat exchanger 520 by expansion; may be further included.

Some of the hydrogen gas supplied from the first heat exchanger 510 to the second heat exchanger 520 is supplied from the third hydrogen line HL3 connecting the first heat exchanger 510 and the second heat exchanger 520. It is supplied to the expander 530 through the branched fourth hydrogen line HL4. The fourth hydrogen line HL4 is connected to the second heat exchanger 520, and the hydrogen gas cooled by expansion in the expander 530 is used as a refrigerant for cooling the hydrogen gas in the second heat exchanger 520.

The expanded hydrogen gas whose temperature rises while cooling the hydrogen gas in the second heat exchanger 520 is connected to the refrigerant outlet of the second heat exchanger 520, and is connected to the second hydrogen line at the front end of the first heat exchanger 510. It can be re-supplied to the first heat exchanger 510 along the sixth hydrogen line HL6 joined to (HL2).

Hydrogen at least partially liquefied by heat exchange with hydrogen gas expanded in the second heat exchanger 520 is separated by a separator ( 540) is supplied.

The fifth hydrogen line HL5 is provided with an expansion valve (no reference numeral given) for cooling the hydrogen gas-liquid mixture supplied from the second heat exchanger 520 to the separator 540 or the hydrogen liquid by adiabatic expansion. can That is, hydrogen supplied from the second heat exchanger 520 to the separator 540 along the fifth hydrogen line HL5 may be further liquefied by expansion in the expansion valve.

Separator 540 of the present embodiment gas-liquid separates the hydrogen gas-liquid mixture introduced into the separator 540 along the fifth hydrogen line HL5, and connects the separator 540 with a liquid hydrogen tank (not shown). Only liquid hydrogen can be supplied to the liquid hydrogen tank through the line HL7.

Non-liquefied hydrogen or flashed gaseous hydrogen separated in the separator 540 is connected to the separator 540 and is connected to the second hydrogen line HL2 at the front of the first heat exchanger 510 in the eighth hydrogen line ( HL8) may be fed back to the first heat exchanger 510.

According to this embodiment, by liquefying hydrogen using the cold heat of LNG, it is possible to store hydrogen in a liquid state in a liquid hydrogen tank and store hydrogen in a liquid state, thereby making it easy to store and transport.

Hydrogen stored in the liquid hydrogen tank may be directly supplied to a liquid hydrogen consumer by having a pipe line directly connected to the liquid hydrogen consumer. The liquid hydrogen demand source may be provided in the floating power plant according to the present embodiment, or may be provided on land or in another vessel.

Alternatively, the liquid hydrogen may be supplied to the liquid hydrogen demand place by unloading the liquid hydrogen tank itself into the liquid hydrogen demand place.

Hydrogen is a future clean energy that is clean, infinite, and has about 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.

That is, according to the present invention, the liquefied gas is regasified and supplied to a gas demand place on land, electricity is produced using the liquefied gas, and a heat source (steam) is produced using waste heat discharged from power generation, and waste heat It is economical and eco-friendly because hydrogen is produced using the heat source and liquefied gas produced by liquefied gas, and by liquefying hydrogen with the cold heat of liquefied gas, it facilitates the transportation and storage of hydrogen, and at the same time improves the efficiency of the fuel supply system and floating power plant operation cost can be reduced.

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 transformed without departing from the technical gist of the present invention. it did

100: regasification system
200: fuel supply system
300: waste heat recovery system
400: hydrogen production system
500: hydrogen liquefaction system
GL1: regasification line
GL2: fuel supply line
GL3: preheating line
GL4 : Hydrogen Production Line
SL: steam supply line
HL1 ~ HL8 : Hydrogen line
PL: power supply line

Claims (14)

A gas engine that generates electricity using liquefied gas as fuel and has a limited methane number;
a fuel supply system including a fuel vaporizer for vaporizing liquefied gas according to a methane number required by the gas engine, and supplying fuel gas to the gas engine;
a waste heat recovery system for producing steam by recovering waste heat generated by combustion of the fuel gas in the gas engine;
a hydrogen production system for producing hydrogen using the remaining fuel gas supplied to the gas engine and the steam produced by the waste heat recovery system;
a hydrogen liquefaction system for liquefying the produced hydrogen by using cold heat of liquefied gas to be supplied to the fuel supply system;
a hydrogen production line supplying the fuel gas vaporized in the fuel vaporizer to the hydrogen production system;
a hydrogen liquefaction pump supplying the liquefied gas to the hydrogen liquefaction system; and
A floating power plant comprising a; preheating line for supplying heated liquefied gas to the fuel vaporizer while cooling the hydrogen in the hydrogen liquefaction system. The method of claim 1,
The hydrogen liquefaction system,
A first heat exchanger for cooling the hydrogen by exchanging heat between the hydrogen and the liquefied gas;
The first heat exchanger and the fuel supply system are connected by a preheating line that allows the liquefied gas whose temperature has risen by heat exchange in the first heat exchanger to be supplied to the fuel supply system. The method of claim 2,
The fuel supply system,
a fuel compressor for compressing the fuel gas vaporized in the fuel vaporizer to a pressure required by the gas engine; and
A fuel heater for heating the fuel gas compressed by the fuel compressor to a temperature required by the gas engine;
The preheating line is connected from the first heat exchanger to the fuel vaporizer, and the liquefied gas whose temperature has risen in the first heat exchanger is supplied to the fuel vaporizer. The method of claim 2,
The hydrogen liquefaction system,
a second heat exchanger further cooling the hydrogen cooled by the cooling heat of the liquefied gas in the first heat exchanger; and
An expander for cooling some of the hydrogen supplied from the first heat exchanger to the second heat exchanger by expansion; further comprising,
In the second heat exchanger, the hydrogen cooled in the first heat exchanger is cooled by the hydrogen refrigerant cooled by expansion in the expander. The method of claim 4,
The hydrogen liquefaction system,
Further comprising, a floating power plant. The method of claim 5,
The hydrogen liquefaction system,
A separator for gas-liquid separation of the hydrogen passing through the expansion valve and supplying hydrogen in a liquid state to a liquid hydrogen tank; further comprising a floating power plant. The method of claim 3,
The hydrogen production system,
A reformer for producing hydrogen by reforming the fuel gas and the steam;
The hydrogen production line is connected from the rear end of the fuel compressor to the front end of the reformer, so that the fuel gas compressed in the fuel compressor is supplied to the reformer. The method of claim 1,
A regasification system for regasifying the liquefied gas and supplying it to a land-based gas demander;
In the floating power plant, a floating power plant in which regasification gas, electric power, hydrogen gas and liquid hydrogen are produced using the liquefied gas. vaporizing the liquefied gas according to the methane number required by the gas engine;
supplying fuel gas vaporized according to a methane number required by the gas engine as fuel gas of the gas engine;
generating electric power by using fuel gas as fuel in the gas engine;
recovering waste heat generated by combustion of fuel gas in the gas engine to produce steam;
producing hydrogen using vaporized fuel gas and steam suitable for a methane number required by the gas engine as raw materials; and
Including; liquefying the produced hydrogen by heat exchange with the liquefied gas to be vaporized,
A method of operating a floating power plant that supplies heated liquefied gas while exchanging heat with the hydrogen to the vaporizing step. The method of claim 9,
Supplying the liquefied gas as fuel gas of a gas engine,
A method of operating a floating power plant comprising the; step of compressing the fuel gas vaporized from the liquefied gas. delete The method of claim 9,
The step of liquefying the hydrogen by heat exchange with liquefied gas,
primary cooling by heat-exchanging the hydrogen with liquefied gas; and
Branching some of the primarily cooled hydrogen to further cool it by expansion, and using the hydrogen further cooled by the expansion as a refrigerant to branch and secondarily cool the remaining hydrogen; further comprising, floating How to operate a food power plant. The method of claim 12,
further cooling the secondary cooled hydrogen by an expansion valve; and
Gas-liquid separation of the hydrogen further cooled by the expansion valve; further comprising,
The gas-liquid separated liquid hydrogen is stored, and the separated gaseous hydrogen is re-supplied to the step of first cooling the hydrogen. The method of claim 9,
It further includes; vaporizing the liquefied gas and supplying it to a gas demand place on land,
In the floating power plant, a method of operating a floating power plant for producing regasified gas, electric power, hydrogen and liquid hydrogen using the liquefied gas.

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