KR101864935B1 - Cryogenic energy storage system using LNG gasification process - Google Patents

Abstract

The present invention relates to a cryogenic energy storage system using a liquefied natural gas gasification process, comprising: a separator connected to a liquefied natural gas source; A first line and a second line separately connected from the separator; A first heat exchanger installed in the first line; A first circulation line connected to the first heat exchanger and circulating the first working fluid that is heat-exchanged with the liquefied natural gas; A first turbine installed in the first circulation line for producing electricity by a first working fluid; A second heat exchanger installed in a second line; A third line connected to the storage gas supply source and the second heat exchanger, respectively; A storage tank connected to the second heat exchanger and storing the liquefied storage gas through heat exchange with the liquefied natural gas in the second heat exchanger; A fourth line connected to the storage tank; And a second turbine installed in the fourth line for producing electricity by the storage gas.

Description

[0001] The present invention relates to a cryogenic energy storage system using a liquefied natural gas (LNG) gasification process,

The present invention relates to a cryogenic energy storage system using a liquefied natural gas gasification process.

Natural gas is one of the cleanest energy sources and is considered an alternative to other fossil fuels due to its relatively low carbon dioxide emissions. Natural gas with a boiling point of about -160 ° C is typically delivered in liquid form for long-distance transport, due to a massive volume reduction of over 600 times. Despite the difficulty of long-distance cryogenic maritime transport, Liquefied Natural Gas (LNG) trading is expected to increase 300% over the next 30 years. Therefore, much research has been concentrated on the natural gas liquefaction process known as the energy concentration process.

In addition, the transported LNG should be converted to natural gas to be used or transported through land pipelines. Therefore, the re-gasification process at the LNG terminal has been studied to use LNG cold energy as power. Dispenza et al. And Rocca have studied the cryogenic exergy of LNG to produce electricity, but have focused primarily on cold transfer. Szargut et al. Studied a cascade LNG cold energy cycle using ethane as the working fluid. Choi et al. Produced electricity from LNG using methane, ethane and propane as working fluids. Garcia and others also studied cascade LNG cooling plants. They considered direct expansion of natural gas for industrial electricity demand. Garcia et al. Have studied the application of residual heat to LNG cooling plants. The above-mentioned studies mainly focused on the generation of LNG using cold energy.

On the other hand, energy storage technology has been studied competitively. Energy storage will play an important role in the current energy structure and will replace increasing energy production. Cryogenic Energy Storage (CES) systems are one of the most notable energy storage technologies in recent years. The CES system was first introduced by Smith using air or nitrogen. Yang et al. Studied the wall temperature of LNG cryogenic storage tanks, and Preston et al. Studied the insulation of cryogenic storage tanks. In 1998, Kishimoto et al. Tested the feasibility of a CES system using a pilot plant. Li et al. Studied CES systems through thermodynamics and economics analysis. Abdo et al. Evaluated the performance of various CES systems. According to Zhang et al., CES systems can have relatively high energy densities (100 to 200 Wh / kg), low capital cost per unit energy, and are environmentally friendly and have a relatively long storage period.

An object of the present invention is to provide a power generation and energy storage system capable of enhancing energy storage efficiency by integrating a liquefied natural gas gasification process and a cryogenic energy storage system, and a power generation and energy storage method using the same.

In order to achieve the above-mentioned object, the present invention provides a separator for a liquefied natural gas, comprising: a separator connected to a source of liquefied natural gas; A first line and a second line separately connected from the separator; A first heat exchanger installed in the first line; A first circulation line connected to the first heat exchanger and circulating the first working fluid that is heat-exchanged with the liquefied natural gas; A first turbine installed in the first circulation line for producing electricity by a first working fluid; A second heat exchanger installed in a second line; A third line connected to the storage gas supply source and the second heat exchanger, respectively; A storage tank connected to the second heat exchanger and storing the liquefied storage gas through heat exchange with the liquefied natural gas in the second heat exchanger; A fourth line connected to the storage tank; And a second turbine installed in the fourth line for producing electricity by the storage gas.

A system according to the present invention comprises a first pump installed in a first line between a separator and a first heat exchanger; And a second pump installed between the separator and the second heat exchanger in the second line.

The system according to the present invention comprises a third pump installed in the first circulation line and connected to the first heat exchanger; A third heat exchanger installed in the first circulation line and connected to the third pump, the first turbine and the first heat exchanger, respectively; And a fourth heat exchanger installed in the first circulation line and connected to the third heat exchanger and the first turbine, respectively.

In the present invention, a plurality of first turbines and a plurality of fourth heat exchangers may be alternately installed in series.

The system according to the present invention comprises a fifth heat exchanger installed after the first heat exchanger in the first line; A second circulation line connected to the fifth heat exchanger and circulating a second working fluid to be heat-exchanged with the liquefied natural gas; And a third turbine installed in the second circulation line and producing electricity by the second working fluid.

The system according to the present invention comprises a fourth pump installed in a second circulation line and connected to a fifth heat exchanger; A sixth heat exchanger installed in the second circulation line and connected to the fourth pump, the third turbine and the fifth heat exchanger, respectively; And a seventh heat exchanger installed in the second circulation line and connected to the sixth heat exchanger and the third turbine, respectively.

In the present invention, a plurality of third turbines and a plurality of seventh heat exchangers may be alternately installed in series.

The system according to the present invention comprises an eighth heat exchanger installed after the first heat exchanger in the first line; And an expander installed in the first line and connected to the eighth heat exchanger.

In the present invention, a plurality of eighth heat exchangers and a plurality of expanders may be alternately installed in series.

The system according to the present invention may further comprise a mixer coupled to each end of the first line and the second line.

The system according to the present invention comprises a compressor installed in a third line and connected to a storage gas source; And a ninth heat exchanger installed in the third line and connected to the compressor.

In the present invention, a plurality of compressors and a plurality of ninth heat exchangers may be alternately installed in series.

The system according to the present invention comprises a fifth pump installed in the fourth line and connected to the storage tank; And a tenth heat exchanger installed in the fourth line and connected to the fifth pump and the second turbine, respectively.

In the present invention, a plurality of tenth heat exchangers and a plurality of second turbines may be alternately installed in series.

In the present invention, the storage gas may be at least one selected from air and nitrogen.

In the present invention, the first working fluid and the second working fluid may independently be at least one selected from methane, argon, propane, and butane.

In the present invention, the compression ratio of the compressor may be 1 to 3.

In the present invention, the expansion ratio of the first turbine and the second turbine may be more than 0 and less than 1.

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The present invention also relates to a first mode of using the above system and producing electricity with the gasification of liquefied natural gas; A second mode of liquefying the storage gas with gasification of liquefied natural gas to store energy; And a third mode for producing electricity with the gasification of the liquefied natural gas and further producing electricity through the liquefied storage gas; ≪ RTI ID = 0.0 > and / or < / RTI >

In the method according to the invention, it is possible to operate in the first mode in the normal time zone, in the second mode in the off-peak time zone, and in the third mode in the on-peak time zone.

In the present invention, by developing a cryogenic energy storage system using the LNG gasification process, it is possible to obtain a high energy storage efficiency of 95.2% by using the LNG more efficiently.

Further, in the present invention, by developing an energy storage system, the total amount of power can be efficiently distributed and used, so that energy that is wasted at a time when electricity demand is low can be saved.

1 is a schematic diagram of a cryogenic energy storage system using a liquefied natural gas gasification process in accordance with the present invention.
2 is a detailed view of a first mode of a cryogenic energy storage system using a liquefied natural gas gasification process according to the present invention.
3 is a detailed view of a second mode of the cryogenic energy storage system using the liquefied natural gas gasification process according to the present invention.
4 is a detailed view of a third mode of the cryogenic energy storage system using the liquefied natural gas gasification process according to the present invention.
FIG. 5 is a detailed view showing streams of the second mode and the third mode of the cryogenic energy storage system using the liquefied natural gas gasification process according to the present invention.
6 is a temperature-entropy (TS) diagram (a) and a pressure-entropy (PS) diagram (b) of a second mode and a third mode of a cryogenic energy storage system using a liquefied natural gas gasification process in accordance with the present invention.
7 is a temperature-enthalpy (TH) diagram (a) and a pressure-enthalpy (PH) diagram (b) of a second mode and a third mode of a cryogenic energy storage system using a liquefied natural gas gasification process in accordance with the present invention.

Hereinafter, the present invention will be described in detail.

1 is a schematic diagram of a cryogenic energy storage system using a liquefied natural gas gasification process in accordance with the present invention. The gasification process is intended to vaporize LNG, which is in a cryogenic state during long-distance transportation, into an industrially usable gas state. In this process, LNG is used to generate electricity. A cryogenic energy storage system is a high energy storage system that uses liquid air or liquid nitrogen as an energy storage medium. Since the LNG gasification process and the cryogenic energy storage system both have cryogenic properties, the integration of the two processes can increase energy storage efficiency.

In the present invention, a system has been developed which not only produces electricity using energy of LNG in a different manner according to time, but also enables energy storage. As the energy storage medium, air which can be easily supplied and discharged can be used. The operation of the system can be operated in three modes: general electricity production, energy storage and electricity production.

1. In the general electric production mode (blue line in FIG. 1, first mode), electricity is produced at the same time as natural gas is produced in the same manner as conventional LNG gasification power generation.

2. In the energy storage mode (the yellow line in FIG. 1, the second mode), the energy is stored in a cryogenic state using the cold heat of the LNG. In the corresponding time zone, electricity is supplied from the outside to the compressor. Therefore, electricity is used to compress the air, and the air is compressed, so that the boiling point is relatively high. Then, the air in the high pressure state is made into liquid air at a very low temperature state by using the cold heat of the LNG, and then stored in the tank. This allows electricity to be stored in cryogenic energy. At this time, since the cold heat of the LNG is used to liquefy the air, the electricity production of the existing LNG gasification power generation is stopped. However, since the LNG is vaporized by the cryogenic energy storage system, the production of natural gas, which is the main purpose of the LNG gasification process, is maintained.

3. Electricity In the additional production mode (the green line in FIG. 1, the third mode), the LNG gasification power generation is performed as before, and the energy of the liquid air stored in the tank is released to dramatically increase the electricity production. First, the pressure of the stored high-pressure liquid air is increased through the pump. Next, it is vaporized into a gaseous state, and then the turbine is used to produce electric power. The air expended by the turbine at atmospheric pressure is again released to the atmosphere.

2 is a detailed view of a first mode of the cryogenic energy storage system using the liquefied natural gas gasification process according to the present invention, Fig. 3 is a detailed view of the second mode, Fig. 4 is a detailed view of the third mode, The inventive development and energy storage system includes a liquefied natural gas source 10, a liquefied natural gas supply line 20, a separator 30, a first pump 40, a first line 50, a first heat exchanger 60 The first circulation line 70, the third pump 80, the third heat exchanger 90, the fourth heat exchanger 100, the first turbine 110, the fifth heat exchanger 120, The third circulation line 130, the fourth pump 140, the sixth heat exchanger 150, the seventh heat exchanger 160, the third turbine 170, the eighth heat exchanger 180, the expander 190, The first pump 210, the second pump 220, the second heat exchanger 230, the storage gas supply source 240, the third line 250, the compressor 260, the ninth heat exchanger 270, a reservoir tank 280, a fourth line 290, a fifth pump 300, a tenth heat exchanger 310, a second turbine 320, and the like.

The liquefied natural gas supply source 10 is a place to supply LNG.

The liquefied natural gas supply line 20 is connected to the liquefied natural gas supply source 10 and the separator 30 to supply LNG from the liquefied natural gas supply source 10 to the separator 30, respectively.

The separator 30 is connected to the liquefied natural gas supply source 10 through the liquefied natural gas supply line 20 at one side and to the first line 50 and the second line 220 at the other side. The separator 30 may include a valve, a switch, or the like so as to send the LNG to either the first line 50 or the second line 220.

The first pump 40 is installed in the first line 50 between the separator 30 and the first heat exchanger 60 and compresses the LNG at a high pressure.

The first line 50 is a long line extending from the separator 30 to the mixer 200 where the LNG and the gasified natural gas stream are delivered in the first line 50.

The first heat exchanger (60) is installed in the first line (50) after the first pump (40) where the heat exchange between the LNG and the first working fluid is effected. The LNG can be at least partially gasified through heat exchange with the first working fluid, and the first working fluid can be condensed by the cold energy of the LNG. As the first working fluid, at least one selected from methane, argon, propane and butane can be used, and methane or argon can be preferably used.

The first circulation line 70 is a rankine cycle line connected to the first heat exchanger 60 in which the first working fluid that is heat exchanged with the LNG circulates to produce electricity.

The third pump 80 is installed in the first circulation line 70 and is connected to the first heat exchanger 60 so that the first working fluid condensed in the first heat exchanger 60 can be compressed.

The third heat exchanger 90 is installed in the first circulation line 70 and includes a third pump 80, a fourth heat exchanger 100, a first turbine 110 and a first heat exchanger 60, . That is to say at the intersection of the line from the first heat exchanger 60 to the first turbine 110 and the line from the first turbine 110 to the first heat exchanger 60, . The third heat exchanger 90 is installed to improve the heat exchange efficiency of the Rankine cycle, and may be omitted if necessary.

The fourth heat exchanger 100 is installed in the first circulation line 70 and connected to the third heat exchanger 90 and the first turbine 110. The heat exchanger 100 exchanges heat with fluid such as seawater, 1 The working fluid can be evaporated.

The first turbine 110 may be installed in the first circulation line 70 and connected to the fourth heat exchanger 100 to produce electricity by the first working fluid evaporated from the fourth heat exchanger 100. The first turbine 110 may be connected to a generator (not shown) for electrical production. The first working fluid may be expanded in the first turbine 110.

As illustrated in the figure, a plurality of first turbines 110 and a plurality of fourth heat exchangers 100 may be alternately installed in series, and the number of each of them is not particularly limited and may be, for example, 1 to 5 .

The fifth heat exchanger 120 is installed in the first line 50 after the first heat exchanger 60 where the LNG can be fully vaporized through heat exchange with the second working fluid, Can be condensed. As the second working fluid, at least one selected from methane, argon, propane and butane can be used, and methane or argon can be preferably used.

The second circulation line 130 is connected to the fifth heat exchanger 120 and, like the first circulation line 70, is a Rankine cycle line in which the second working fluid, which is heat-exchanged with the LNG, circulates and produces electricity do. The second circulation line 130 may be omitted if necessary, and another circulation line may be further provided after the fifth heat exchanger 120.

The fourth pump 140 is installed in the second circulation line 130 and is connected to the fifth heat exchanger 120 and the condensed second working fluid in the fifth heat exchanger 120 can be compressed.

The sixth heat exchanger 150 is installed in the second circulation line 130 and includes a fourth pump 140, a seventh heat exchanger 160, a third turbine 170 and a fifth heat exchanger 120, Where the heat exchange takes place between the second working fluid and can be omitted if necessary.

The seventh heat exchanger 160 is installed in the second circulation line 130 and connected to the sixth heat exchanger 150 and the third turbine 170. The heat exchanger 160 exchanges heat with a fluid such as seawater, 2 The working fluid can be evaporated.

The third turbine 170 may be installed in the second circulation line 130 and connected to the seventh heat exchanger 160 to produce electricity by the second working fluid evaporated from the seventh heat exchanger 160. The third turbine 170 may be connected to a generator (not shown) for electrical production. The second working fluid can be expanded in the third turbine 170.

As illustrated in the figure, a plurality of third turbines 170 and a plurality of seventh heat exchangers 160 may be alternately installed in series, and the number of the respective heaters is not particularly limited and may be, for example, 1 to 5 .

The eighth heat exchanger 180 may be installed in the first line 50 after the fifth heat exchanger 120, where heat exchange with fluid such as seawater may be performed.

The inflator 190 is installed in the first line 50 and is connected to the eighth heat exchanger 180. The LNG is gasified to natural gas via two heat exchangers 60 and 120, but is still in a high pressure state, and the pressure of the natural gas can be lowered through the expander 190.

As illustrated in the figure, a plurality of the eighth heat exchanger 180 and the plurality of inflator 190 may be alternately installed in series, and the number of each of them is not particularly limited and may be, for example, 2 to 10 have.

The mixer 200 is connected to the respective ends of the first line 50 and the second line 220, and then the natural gas transferred from each line can be supplied through the natural gas supply line.

The second pump 210 is installed in the second line 220 between the separator 30 and the second heat exchanger 230 and compresses the LNG at a high pressure.

The second line 220 is a long line extending from the separator 30 to the mixer 200 where the LNG and the gasified natural gas stream are transported in the second line 220.

The second heat exchanger 230 is installed in the second line 220 after the second pump 210, where heat exchange is performed between the LNG and the storage gas. The LNG can be completely gasified through heat exchange with the storage gas, and the storage gas can be liquefied by the cooling energy of the LNG. As the storage gas, at least one selected from air and nitrogen can be used, and air can be preferably used.

The storage gas supply source 240 supplies the storage gas such as air.

The third line 250 is a line connected to the storage gas supply source 240 and the second heat exchanger 230 and extending from the storage gas supply source 240 to the storage tank 280 through which the gas storage gas And the liquefied storage gas are transferred.

The compressor 260 is installed in the third line 250, is connected to the storage gas supply source 240, and compresses the gaseous storage gas to a high pressure. The compression ratio of the compressor 260 may be 1 to 3.

The ninth heat exchanger 270 is installed in the third line 250 and is connected to the compressor 260. The ninth heat exchanger 270 cools the storage gas compressed through the compressor 260 through heat exchange with seawater or the like.

As illustrated in the figure, a plurality of compressors 260 and a plurality of ninth heat exchangers 270 may be alternately installed in series, and the number of each compressor is not particularly limited, and may be, for example, 2 to 10 have.

The storage tank 280 is connected to the second heat exchanger 230 and stores the liquefied storage gas through heat exchange with the LNG in the second heat exchanger 230.

The fourth line 290 is a line extending from the storage tank 280 to atmospheric discharge, through which the liquefied storage gas and the gas storage gas are transferred.

The fifth pump 300 is installed in the fourth line 290 and is connected to the storage tank 280 and compresses the storage gas in a liquid state to a high pressure.

The tenth heat exchanger 310 is installed in the fourth line 290 and is connected to the fifth pump 300 and the second turbine 320. The tenth heat exchanger 310 exchanges the liquid state storage gas with the seawater, Evaporate.

The second turbine 320 is installed in the fourth line 290 and connected to the tenth heat exchanger 310 to produce electricity by the storage gas evaporated from the tenth heat exchanger 310. The second turbine 320 may be connected to a generator (not shown) for electrical production. The storage gas may be sequentially expanded to atmospheric pressure through the second turbine 320 and then discharged to the atmosphere. The expansion ratio of the turbines 110, 170, 320 may be greater than zero and less than one.

As illustrated in the drawing, a plurality of tenth heat exchangers 310 and a plurality of second turbines 320 may be alternately installed in series, and the number of the tenth heat exchangers 310 and the plurality of second turbines 320 is not particularly limited and may be, for example, 2 to 10 .

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The present invention also relates to a first mode of using the above system and producing electricity with the gasification of liquefied natural gas; A second mode of liquefying the storage gas with gasification of liquefied natural gas to store energy; And a third mode for producing electricity with the gasification of the liquefied natural gas and further producing electricity through the liquefied storage gas; ≪ RTI ID = 0.0 > and / or < / RTI >

In the method according to the present invention, the first mode operates at a conventional time, the second mode operates at an off-peak time, an on-peak time, In the third mode. The on-peak time period may be, for example, 10 to 12, 14 to 17, and / or 17 to 19 as the power peak time period. The off-peak time zone may be, for example, 22:00 to 8:00 or 24:00 to 6:00. The normal time zone may be any time zone other than the on-peak time zone and the off-time zone.

[Example]

1. LPCES system design

The CES system has advantages due to its cryogenic characteristics when it is combined with an LNG regasification plant. In the present invention, an LNG regasification plant (LPCES) system integrated with CES, comprising a regasification power generation unit and a CES unit, was designed and mathematically optimized. To meet the demand for natural gas across industries and homes, LNG regasification plants operate continuously. However, producing electricity in off-peak hours is inefficient due to relatively lower demand and lower price than the on-peak time zone. There is also surplus electricity produced at other power plants during off-peak hours. Therefore, another use of LNG according to time changes is proposed. In this case, LNG cold energy is applied to store electricity during the off-peak time period. During the on-peak hours, this stored electricity can be supplied to meet high demand and balance the overall electricity supply.

The LPCES system consists of a regasification power generation unit and a CES unit. Figure 1 shows how the LPCES system behaves differently over time. Three different days of the day are identified by power demand: normal time, off-peak time, and on-peak time. The off-peak time zone is the time zone in which electricity demand is low due to human inactivity, especially at night. Conversely, high demand for electricity is expected in the on-peak time zone, especially in the afternoon. The normal time zone is between the off-peak time zone and the on-peak time zone. In the normal time zone, the system produces electricity by the regasification power generation unit. The system uses LNG cold energy to liquefy the working fluid in the re-gasification power generation unit. In the off-peak time zone, the system operates in an energy storage mode to store electricity in the CES unit. At this time, the regasification unit does not operate because the entire LNG cold energy is used to liquefy the air in the CES unit and store the electricity. In the on-peak time zone, the system operates in an energy supply mode to release stored liquid air. During this process, the cold energy of the liquid air is used to produce electricity by the air turbine. In addition, LNG cold energy is used in the regasification unit in the on-peak time zone, so electricity is produced from both units.

Aspen HYSYS was used as a calculation tool to describe three different time-varying modes: Conventional mode, Energy storage mode, and Energy release mode. The mass flow rate of LNG is assumed to be 105 kg / s (approximately 3 million tons / year), which corresponds to the capacity of a commercial LNG regasification plant. In a CES unit, the liquid air was stored at 5 [deg.] C below its boiling point and the loss of cooling energy was ignored. Other operating conditions are shown in Table 1. Table 1 shows the operating conditions of the LPCES system.

LNG inlet temperature -162 ° C LNG inlet pressure 1.3 bar LNG mass flow rate 105 kg / s Natural gas outlet pressure 70 bar Natural gas outlet temperature -10 ° C Isentropic Efficiency of an Air Compressor 0.90 Isentropic Efficiency of an Air Turbine 0.92 Isentropic Efficiency of a Generator Turbine 0.92 Isentropic Efficiency of a Natural Gas Expander 0.90 Isentropic Efficiency of a Pump 0.90 Minimum temperature difference in heat exchanger 5 ℃ Sea water temperature 15 ℃

1.1. Normal mode (first mode)

The regasification power generation unit produces electricity during the normal time period, and Fig. 2 shows the normal mode. This unit is operated by two generators based on the Rankine cycle. First, LNG is supplied to the pump and compressed to 300 bar. LNG then produces electricity by passing LNG cold energy through the generator. The first generator uses argon as the working fluid, and the second generator uses methane as the working fluid. After both generators, LNG becomes natural gas but still has high pressure. Thus, the natural gas expands through the expander using power generation. In this overall stage, the regasification power generation unit produces 14.136 MW of electricity in the normal mode.

1.2. Energy storage mode (second mode)

The CES unit stores electricity for off-peak hours. 3 shows unit operation in the energy storage mode. In this time zone, the air is compressed by an air compressor utilizing surplus electricity. When the air is pressurized to 25.44 bar, it is liquefied by the LNG through the heat exchanger. This pressure is the minimum pressure that satisfies the heat exchange with the LNG. Finally, the liquid air is stored at -154.5 DEG C, which is 5 DEG C lower than its boiling point. On the other hand, LNG is gasified into natural gas through heat exchange with air and discharged under the same conditions as normal mode.

1.3. Energy supply mode (third mode)

In the energy supply mode, both the regasification power generation unit and the CES unit produce electricity. 4 shows a process in an energy supply mode. First, the regasification power generation unit operates in the normal mode. Second, the CES unit pumps the stored liquid air to the pump and pressurizes it to 120 bar. The residual heat from the energy storage mode heats the air to 60 ° C to maximize air turbine efficiency. Finally, the gasified air at 120 bar is depressurized to 1 bar through an air turbine producing electricity. By producing electricity in a CES unit, the system can supply a large amount of electricity during the on-peak hours.

2. Optimization Modeling

Minimizing electrical consumption in air compressors and maximizing electrical production in air turbines is important in achieving higher energy storage efficiencies in CES systems. The pressure variation in each installation affects the amount of power, so it is explained here that finding the optimal compression ratio and expansion ratio. Two commercial software are used to find the optimal ratio. One is the gPROMS model builder that solves the optimization problem. The other is Multiflash, which calculates the thermodynamic properties of the air using the Peng-Robinson equation of the state model.

2.1. Compressor model

The compression ratio of each compressor affects the storage power. In order to minimize the total power consumed during the energy storage mode, it was optimized as follows.

[Equation 1]

min: CW _total =? CW _Ci

Where CW is the power consumed by the compressor and the subscript Ci represents the i-th compressor in the CES unit. The power consumption of each compressor is calculated as follows.

&Quot; (2) "

(H_out - H_in)CW =

(H _out - H _in )

&Quot; (3) "

H _out = (H _{out , isentropic} - H _in ) / (? _{Isentropic , compressor} ) + H _in

은 질량 유속, H는 비엔탈피, η은 등엔트로피 효율이다. 아래 첨자 out은 출구 스트림, 아래 첨자 in은 입구 스트림, 아래 첨자 isentropic은 등엔트로피 조건을 나타낸다. H_{out , isentropic}은 공기의 열역학 특성에 의해 정의되는데, 여기서here

Is the mass flow rate, H is the non-enthalpy, and η is isentropic efficiency. The subscript out represents the exit stream, the subscript in the inlet stream, and the subscript isentropic represents the entropy condition. H _{out , isentropic} is defined by the thermodynamic properties of the air, where

&Quot; (4) "

S _{out , isentropic} = S _in

&Quot; (5) "

S _{out , isentropic} = f (T _{out , isentropic} , P _out )

&Quot; (6) "

H _{out , isentropic} = f (T _{out , isentropic} , P _out )

&Quot; (7) "

Compression ratio = P _out / P _in

Where S is the non-entropy, T is the temperature, P is the pressure, and f is the function.

2.2. Turbine model

In addition, the expansion ratio of each turbine affects the supply power, and thus is optimized similarly to the compressor. The following equation is used to maximize the total production power.

&Quot; (8) "

max: GW _total = GW _Ti

Where GW is the power produced by the air turbine and the subscript Ti represents the i th air turbine in the CES unit. The production power of each air turbine is calculated as follows.

&Quot; (9) "

(H_out - H_in)GW =

(H _out - H _in )

&Quot; (10) "

H _out = (H _{out , isentropic} - H _in ) × η _{isentropic , turbine} + H _in

Where H _{out , isentropic} is calculated in the same way as the compressor model, where

&Quot; (11) "

S _{out , isentropic} = S _in

&Quot; (12) "

S _{out , isentropic} = f (T _{out , isentropic} , P _out )

&Quot; (13) "

H _{out , isentropic} = f (T _{out , isentropic} , P _out )

&Quot; (14) "

Expansion ratio = P _out / P _in

2.3. Constraint

Constraints are necessary to prevent the occurrence of an impossible state. From the viewpoint of the discharge temperature, the compression ratio of the compressor can not exceed 3. The following constraints generally represent the operation of the installation.

&Quot; (15) "

1 ≤ compression ratio ≤ 3

&Quot; (16) "

0 < Expansion ratio < 1

In addition, the inlet and outlet streams of the plant can not be in a liquid state as shown in equations (17) and (18).

&Quot; (17) "

VF _in = 1

&Quot; (18) "

VF _out = 1

Where VF is the vapor fraction.

3. Results

A regasification unit integrated with the CES unit is newly proposed and the optimization model is as described above. The simulation results including the compression ratio, the expansion ratio, the storage power, and the supply power of the CES unit by the optimization are shown in Table 2. Table 2 shows the simulation results of the CES unit.

Compression ratio Storage Power (MW) Air compressor 1 2.244 19.73 Air compressor 2 2.250 19.46 Air compressor 3 2.247 19.41 Air compressor 4 2.242 19.31 Pump (LNG) 1.745 Sum 79.655 Expansion ratio Power Supply (MW) Air turbine 1 0.315 18.86 Air turbine 2 0.302 19.91 Air turbine 3 0.297 20.40 Air turbine 4 0.295 20.59 Pump (air) -3.896 Sum 75.864

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4. Thermodynamic Analysis

We focused on the CES unit and expressed the stream number in Fig. In the energy storage mode, air is compressed to streams 1 through 9. Since cooling after each compressor uses seawater, the cooling temperature is limited to 20 [deg.] C in streams 1-9. Next, the air is liquefied by the LNG cold energy through streams 9-10. Thereafter, the liquid air is injected into the liquid air reservoir. When air is discharged from the liquid air reservoir, it is pressurized to 120 bar through streams 10-11. The air then drives the air turbine into streams 11 through 19. Finally, 1 bar of air is vented to the atmosphere.

FIG. 6A shows the temperature-entropy diagram of the air, and FIG. 6B shows the pressure-entropy diagram of the air. The bubble point line and the dew point line were drawn based on Multiflash software. Each diagram illustrates the behavior of air passing through the stream line. In these diagrams, significant entropy changes appear in streams 9-10. This is because LNG cold energy is used to liquefy air at this stage.

FIG. 7A shows the temperature-enthalpy curve of the air, and FIG. 7B shows the pressure-enthalpy curve of the air. The enthalpy behaves similarly to the entropy, but seems to be less varied with the pressure change. Streams 1-9 and streams 12-19 indicate that the enthalpy is primarily affected by temperature changes.

10: Liquefied natural gas source
20: Liquefied natural gas supply line
30: separator
40: first pump
50: First line
60: first heat exchanger
70: 1st circulation line
80: Third pump
90: Third heat exchanger
100: fourth heat exchanger
110: first turbine
120: fifth heat exchanger
130: second circulation line
140: Fourth pump
150: Sixth heat exchanger
160: Seventh heat exchanger
170: Third turbine
180: the eighth heat exchanger
190: inflator
200: Mixer
210: Second pump
220: second line
230: second heat exchanger
240: Storage gas source
250: Line 3
260: Compressor
270: the ninth heat exchanger
280: Storage tank
290: fourth line
300: fifth pump
310: the tenth heat exchanger
320: Second turbine

Claims (21)

A separator connected to a liquefied natural gas source;
A first line and a second line separately connected from the separator;
A first heat exchanger installed in the first line;
A first circulation line connected to the first heat exchanger and circulating the first working fluid that is heat-exchanged with the liquefied natural gas;
A first turbine installed in the first circulation line for producing electricity by a first working fluid;
A second heat exchanger installed in a second line;
A third line connected to the storage gas supply source and the second heat exchanger, respectively;
A storage tank connected to the second heat exchanger and storing the liquefied storage gas through heat exchange with the liquefied natural gas in the second heat exchanger;
A fourth line connected to the storage tank; And
And a second turbine installed in the fourth line for producing electricity by the storage gas.
The method according to claim 1,
A first pump installed in the first line between the separator and the first heat exchanger; And
And a second pump installed in the second line between the separator and the second heat exchanger.
The method according to claim 1,
A third pump installed in the first circulation line and connected to the first heat exchanger;
A third heat exchanger installed in the first circulation line and connected to the third pump, the first turbine and the first heat exchanger, respectively; And
Further comprising a fourth heat exchanger installed in the first circulation line and connected to the third heat exchanger and the first turbine, respectively.
The method of claim 3,
Wherein a plurality of first turbines and a plurality of fourth heat exchangers are alternately installed in series.
The method according to claim 1,
A fifth heat exchanger installed after the first heat exchanger in the first line;
A second circulation line connected to the fifth heat exchanger and circulating a second working fluid to be heat-exchanged with the liquefied natural gas; And
And a third turbine installed in the second circulation line to produce electricity by the second working fluid.
6. The method of claim 5,
A fourth pump installed in the second circulation line and connected to the fifth heat exchanger;
A sixth heat exchanger installed in the second circulation line and connected to the fourth pump, the third turbine and the fifth heat exchanger, respectively; And
And a seventh heat exchanger installed in the second circulation line and connected to the sixth heat exchanger and the third turbine, respectively.
The method according to claim 6,
Wherein a plurality of third turbines and a plurality of seventh heat exchangers are alternately installed in series.
The method according to claim 1,
An eighth heat exchanger installed after the first heat exchanger in the first line; And
Further comprising an expander installed in the first line and connected to the eighth heat exchanger.
9. The method of claim 8,
And a plurality of eighth heat exchangers and a plurality of inflators are alternately installed in series.
The method according to claim 1,
Further comprising a mixer coupled to each end of the first line and the second line.
The method according to claim 1,
A compressor installed in the third line and connected to the storage gas supply source; And
And a ninth heat exchanger installed in the third line and connected to the compressor.
12. The method of claim 11,
And a plurality of compressors and a plurality of ninth heat exchangers are alternately installed in series.
The method according to claim 1,
A fifth pump installed in the fourth line and connected to the storage tank; And
And a tenth heat exchanger installed in the fourth line and connected to the fifth pump and the second turbine, respectively.
14. The method of claim 13,
Wherein a plurality of tenth heat exchangers and a plurality of second turbines are alternately installed in series.
The method according to claim 1,
Wherein the storage gas is at least one selected from air and nitrogen.
6. The method of claim 5,
Wherein the first working fluid and the second working fluid are each independently at least one selected from methane, argon, propane, and butane.
12. The method of claim 11,
Wherein the compression ratio of the compressor is between 1 and 3.
The method according to claim 1,
Wherein the expansion ratio of the first turbine and the second turbine is greater than zero and less than one.
delete Use of the system according to claim 1,
A first mode for producing electricity with gasification of liquefied natural gas;
A second mode of liquefying the storage gas with gasification of liquefied natural gas to store energy; And
A third mode for producing electricity with the gasification of the liquefied natural gas and further producing electricity through the liquefied storage gas; ≪ / RTI > wherein said at least one mode is selected from the group consisting of:
21. The method of claim 20,
Operates in the first mode in the normal time zone,
Operates in the second mode in the off-peak time zone,
And a third mode in an on-peak time zone.

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