JP6503521B1 - Operation method of liquefied natural gas receiving facility - Google Patents

Abstract

The present invention provides a technology that responds to demand response while maintaining stable operation of a liquefied natural gas receiving facility. SOLUTION: A liquefied natural gas receiving facility 2 comprises a storage tank 21 for storing liquefied natural gas, a vaporizer 231 for vaporizing liquefied natural gas discharged therefrom and shipping it in the state of gas, and storage. An electric motor drive gas compression unit 24 for pressurizing the boil-off gas generated in the tank 2 and mixing it with the vaporized natural gas. Then, the study of power consumption reduction is started in the study start process, and the change in the internal pressure of the storage tank 21 when the gas compression unit 24 is stopped in the stoppable period calculation process is predicted to stop the gas compression unit 24 After calculating the possible period, it is determined whether the gas compression unit 24 is stopped or not based on the comparison result of the reduction period and the possible period in the stop possibility determination step. [Selected figure] Figure 2

Description

  The present invention relates to a method of operating a liquefied natural gas receiving facility that receives liquefied natural gas (Liquefied: LNG), stores it in a storage tank, vaporizes the LNG, and ships a product gas.

  With the spread of renewable energy, there is concern that the reliability of the power system will decline. As a countermeasure, the introduction of demand response (Demand Response: hereinafter also referred to as “DR”) is considered, which is a method of adjusting the power demand in which the consumer changes the consumption pattern of electricity by setting the electricity price and paying an incentive. ing.

For example, customers such as factories and large retailers increase / decrease the power demand by switching the operation / stop of the power consumption device or changing the output of the owned power generation facility.
However, especially in the implementation of DR (“lower DR”) that reduces power demand, customers who do not have an in-house power generation facility or storage battery or do not have sufficient capacity are obliged to reduce power demand. As a result, for example, in a factory, it may be necessary to carry out production adjustment, and it will be difficult to participate in the mechanism of DR unless it is certain that the merits of carrying out DR will outweigh the disadvantages caused by production adjustment.

  Here, in Patent Document 1, a demand response system that performs a DR by outputting a power supply and demand adjustment command signal directly from the electric power company side to an electric device control apparatus that controls the operation of the electric equipment on the customer side. Is described. However, it is difficult for an external power company to directly participate in a demand response system that controls the operation of an electric device, for example, for a customer who needs an operation such as securing safety in operating the electric device.

  Further, according to Patent Document 2, BOG (Boil Off Gas: LNG) mixed with liquefied natural gas vaporized by the vaporizer by performing load control of the BOG compressor according to the required heat quantity of the gas consumption destination. Techniques have been described to control the amount of vaporized LNG component) in the tank. On the other hand, Patent Document 2 does not describe the technology related to DR.

Patent No. 6334372 Unexamined-Japanese-Patent No. 2018-112218

  The present invention has been made under such a background, and provides a technology for dealing with demand response (DR) while maintaining stable operation of a liquefied natural gas receiving facility.

The operating method of the liquefied natural gas receiving facility of the present invention is an operating method of the liquefied natural gas receiving facility,
The liquefied natural gas receiving facility includes a storage tank for storing liquefied natural gas received from the outside, a vaporizer for vaporizing liquefied natural gas discharged from the storage tank, and shipping it in the form of a gas, An electric motor-driven gas compressor for pressurizing the boil-off gas generated in the storage tank and mixing it with the natural gas vaporized by the vaporizer;
A study start step of starting a study of power consumption reduction assuming reception of the power consumption reduction request including information related to the reduction period, or an internal pressure of the storage tank when the gas compression unit is stopped Of the gas compression unit on the basis of the comparison result between the reduction possible period and the reduction possible period of the gas compression unit. And a step of judging whether or not to stop the vehicle.

The operation method of the liquefied natural gas receiving facility may have the following features.
(A) including a gas compression unit stopping step of stopping the gas compression unit when it is determined that the gas compression unit can be stopped during the reduction period in the stop possibility determination step.
(B) The vaporizer is a vaporizer for normal operation that vaporizes liquefied natural gas by using seawater supplied from an seawater pump driven by an electric motor as a heat source, and vaporizes liquefied natural gas by using combustion heat of the natural gas as a heat source In addition to carrying out the emergency operation vaporizer for performing the emergency operation and performing the gas compression section stopping step, the normal operation vaporizer is switched to the emergency operation vaporizer to vaporize the liquefied natural gas Carry out the vaporizer switching process.
(C) In the stoppable period calculation step, the change of the internal pressure is made based on the change of the gas phase volume caused by discharging the liquefied natural gas from the storage tank and the amount of boil-off gas generated in the storage tank. To predict. The amount of boil-off gas generated in the storage tank may be determined based on the amount of heat input to the storage tank.
(D) In the stoppable period calculating step, a period in which the predicted value of the change in the internal pressure of the storage tank is less than the upper limit value of the operating pressure provided to the storage tank is the stoppable period.
(E) including a continuation determination step of making a priority determination to continue the operation of the gas compression unit when the reduction period overlaps with a period for receiving liquefied natural gas from the outside to the storage tank. .
(F) A target for setting a target pressure lower than the pressure of the storage tank when the stop possibility determination step is performed to reduce power consumption when the determination result in the stop possibility determination step is negative. A pressure setting process and a pressure reduction process for reducing the internal pressure of the storage tank to the target pressure, and re-implementing the stop possibility determination process after the pressure reduction process.

  According to the present invention, the stoppable period of the gas compression unit for extracting the boil-off gas from the storage tank of liquefied natural gas is calculated, and based on the result, it is determined whether the gas compression unit is stopped or not. Demand response can be implemented without

It is explanatory drawing which shows the relationship of the participant of DR transaction. It is a block diagram of the LNG receiving installation which concerns on embodiment. It is a flowchart of the item implemented in LNG receiving equipment in relation to DR.

  FIG. 1 shows an example of the relationship of participants in a DR transaction. The power transmission and distribution companies 11 and the like include general power transmission and distribution companies such as regional power companies. While the contract of the DR to the power transmission and distribution company 11 can be paid, if it can not meet the request of the DR from the power transmission and distribution company 11, it may be necessary to pay a penalty.

  The resource aggregator 12 collectively adjusts the demand and supply of the DR by putting together a plurality of customers 13, and aims to reduce the risk of payment of reward and penalty payment. As the contents of the supply and demand adjustment, it is possible to illustrate the selection of the customer 13 capable of responding to the DR request from the transmission and distribution company 11, the assignment of the corresponding period, and the like.

The consumers 13 execute DR based on the supply and demand adjustment with the resource aggregator 12. DR includes "up DR" which increases power demand and "down DR" which reduces power demand. When there is a large amount of renewable energy generation and it is necessary to increase the power demand, a request for “raising DR” is issued. On the other hand, when the power demand within the jurisdiction of the power transmission and distribution company 11 is tight, for example, a request for “lower DR” is issued.
The operator of the LNG receiving facility 2 in this example constitutes one of the customers 13 among the participants of the above-described DR transaction.

  In the example shown in FIG. 1, the transmission and distribution provider 11 requests the resource aggregator 12 to make a “reduction DR” (reduction request) including information on the reduction amount and the reduction period. The resource aggregator 12 adjusts the supply and demand of the plurality of customers 13 (customers A and B, and the LNG receiving facility 2) in accordance with the reduction possible amount in order to reduce the power consumption corresponding to the reduction request. . In the example shown in FIG. 1, as a result of the adjustment, it is determined that the customer A and the LNG receiving facility 2 execute the “lower DR”. Then, when the customer A and the LNG receiving facility 2 execute the reduction of the power consumption, the power transmission and distribution company 11 can obtain the effect of reducing the power load in response to the reduction request.

Here, the LNG receiving facility 2 shown in FIG. 1 has a function of receiving and storing the LNG from the outside and vaporizing the stored LNG and shipping it to the customer 3. The LNG receiving facility 2 has a facility configuration applicable to DR, as compared with the customer 13 such as a factory requiring production adjustment to carry out "lower DR" (hereinafter referred to as "DR"). There is.
Hereinafter, a configuration example of the LNG receiving facility 2 of this example will be described with reference to FIG.

  The LNG receiving facility 2 includes an LNG tank 21 for storing the LNG, LNG pumps 211 and 22 for delivering the LNG from the LNG tank 21 for discharging the gas to the demand destination 3, and a gasified gas by vaporizing the LNG. It has a vaporizer (ORV 231, SMV 232 described later) to be in a state, and a heat quantity adjustment unit 26 for obtaining a product gas by adding liquefied petroleum gas (LPG: Liquefied Petroleum Gas) for heat quantity adjustment to the vaporized gas.

  The LNG tank 21 is, for example, a storage tank for storing LNG received from the LNG tanker 4 in the state of liquid cooled to about -162 ° C., and its type (ground tank, underground tank, underground tank, etc.) or There is no particular limitation on the capacity. FIG. 2 shows an example of a ground-type tank in which the upper surface of the cylindrical side wall is covered with a dome-shaped roof.

  The LNG stored in the LNG tank 21 is sent to the vaporizers 231 and 232 via the LNG pump 211 disposed in the LNG tank 21 and the pressure-rising delivery pump 22.

  The LNG receiving facility 2 of this example is an ORV (Open Rack Vaporizer) 231, which is a vaporizer that vaporizes LNG using seawater (S.W.) supplied from a seawater pump (not shown) driven by an electric motor as a heat source, The SMV (Submerged-combustion Vaporizer) 232, which is a vaporizer that vaporizes LNG using the heat of combustion of natural gas as a heat source, can be switched and used. In the LNG receiving facility 2, vaporization of LNG is performed using the ORV 231 during normal operation, and the SMV 232 is in a standby state for emergency operation such as when a power failure occurs. For example, a plurality of ORVs 231 and SMVs 232 are provided in the LNG receiving facility 2.

  Note that, instead of the ORV 231, an intermediate fluid such as propane may be heated using seawater, and IFV (Intermediate Fluid Vaporizer) that vaporizes the LNG by the intermediate medium may be used as a vaporizer for normal operation. Seawater is also supplied to the IFV using an electric motor driven sea water pump.

  The heat amount adjusting unit 26 mixes the LPG for heat amount adjustment with the vaporized gas, and ships a product gas having the heat amount required by the customer 3. The LPG (butane or propane) stored in the LPG tank 25 is delivered to the heat amount adjustment unit 26 in a liquid state via the LPG pump 251. The LPG is vaporized by the heat quantity adjustment unit 26 using the heat medium, and mixed with the vaporized gas delivered from the ORV 231 side to become a product gas. The product gas whose heat amount has been adjusted by the heat amount adjustment unit 26 is paid out to the customer 3.

  Further, in the LNG tank 21 storing the LNG, part of the LNG is vaporized due to the heat input from the outside and the like to generate BOG. In order to prevent the pressure in the LNG tank 21 from becoming excessive, a BOG compressor 24 which is a gas compression unit for extracting BOG is connected to the LNG tank 21. The BOG compressor 24 of this example is driven by an electric motor (not shown).

  The BOG compressor 24 is, for example, a multi-stage BOG compressor provided with three compression stages as shown in FIG. 2 and has a BOG of about 12 to 22 kPaG (pressure on the suction side of the first compression stage) 2 to 2 The pressure is increased to about 7.5 MPaG (the discharge side pressure of the final compression stage). The boosted BOG joins with the LNG vaporized in the vaporizer (ORV 231 or SMV 232), and after adjusting the amount of heat, it is discharged to the customer 3 as a product gas.

In the LNG receiving facility 2 having the above-described configuration, power consumption on the order of several megawatts can be reduced by stopping the BOG compressor 24. Even when the BOG compressor 24 is stopped, the LNG pumps 211 and 22 are not affected, and the liquid delivery of LNG can be continued. In addition, by stopping the ORV 231, power consumption of about several hundred kilowatts can be reduced. When the ORV 231 is stopped, if the SMV 232 is operated, it is possible to carry out the vaporization of LNG continuously.
From these points of view, it can be said that the LNG receiving facility 2 is the customer 13 having an applicable facility configuration when participating in the DR transaction.

  On the other hand, when the pressure in the LNG tank 21 exceeds the upper limit of the operating pressure for a long time while the BOG compressor 24 is stopped for a long time, for example, BOG is released toward the flare (not shown), And there is a loss in which the gas is burned. When the pressure in the LNG tank 21 further increases, a safety valve (not shown) is activated to dissipate excess BOG into the atmosphere.

In particular, in the LNG receiving facility 2, the LNG from the LNG tanker 4 is received once to several times a month. At this time, the amount of BOG generated in the LNG tank 21 increases to several times, for example, about four times the normal time. As described above, it may be difficult to stop the BOG compressor 24 while a large amount of BOG occurs.
Therefore, if the change of the internal pressure of the LNG tank 21 when the BOG compressor 24 is stopped is predicted, and the stoppable period of the BOG compressor 24 is specified, the stable operation of the LNG receiving facility 2 is not impeded. Whether or not to implement can be determined.

また、時刻ｔ１におけるＬＮＧタンク２１の気相容積をＶ１［ｍ^３］としたとき、時刻ｔ２における気相容積Ｖ２［ｍ^３］は下記式（数２）で表される。

Hereinafter, an example of a method of calculating the possible stopping period of the BOG compressor 24 will be described.
Assuming that the stop time of BOG compressor 24 (the start time of BOG accumulation in BOG compressor 24) is t1, and the restart time of BOG compressor 24 (the end of BOG pressure accumulation) is t2, the stop of BOG compressor 24 The period is (t2-t1).
Assuming that the flow rate of LNG delivered from the LNG tank 21 is F [m ³ / h] and the liquid level of the LNG in the LNG tank 21 at time t1 is L1 [m], the liquid level L2 [m] at time t2 is Formula (Formula 1) is represented (ID [m] is the internal diameter of the LNG tank 21).

When the gas phase volume of the LNG tank 21 at time t1 is V1 [m ³ ], the gas phase volume V2 [m ³ ] at time t2 is expressed by the following equation (Equation 2).

Furthermore, the amount of heat input to the LNG tank 21 from outside, such as a heater (not shown) for preventing outside air or ground freezing on a unit time basis, is Qtank [J / h], and the amount of heat input from the LNG pump 211 is Qpump [ J / h] and the amount of heat input from other facilities is Qetc [J / h], the amount of BOG generated per unit time Wbog [kg / h] in the LNG tank 21 is shown in the following equation (Equation 3) (Where λ is the latent heat of vaporization of LNG [J / kg]).

そして、（数１、２）の関係から（数４）よりＶ１、Ｖ２を消去して整理すると、下記式（数５）が得られる。

Furthermore, the pressure in the LNG tank 21 at time t1 is p1 [kPaG], the pressure at time t2 is p2 [kPaG], and the density of BOG at each pressure is p1 and p2 [kg / m ³ ], respectively.
When the temperature in the LNG tank 21 is constant and BOG is not extracted from the LNG tank 21, the amount of BOG generated in the LNG tank 21 during the stop period (t2-t1) and the gas phase side of the LNG tank 21 The following equation (Equation 4) is obtained by mass balance based on the volume change of

Then, when V1 and V2 are eliminated from the relationship of (Equation 1 and 2) and rearranged from (Equation 4), the following equation (Equation 5) is obtained.

  Since the LNG tank 21 is provided with a liquid level gauge, the inside of the LNG tank 21 in that period is based only on the change in the liquid level of the LNG in the LNG tank 21 at each time of t1 and t2 of the liquid level. We can know the pressure change. As described above, since the density ρ1 and 22 of BOG are uniquely determined according to the pressure p1 and p2 at each time, the calculation of the stop period using (Equation 5) is the pressure change in the LNG tank 21 It is done on the basis of

Therefore, by setting the upper limit value of the operating pressure of the LNG tank 21 as the pressure p2 (the density (2 of BOG at that time) of the LNG tank 21 at time t2, the LNG tank is stopped under the condition that the BOG compressor 24 is stopped. The possible stop period (t2-t1) for maintaining the pressure in 21 below the upper limit value of the operating pressure can be specified. As described above, the change (L2-L1) of the liquid level of the LNG during the stoppable period can be predicted from (Equation 1).
In the LNG receiving facility 2 of the present example, it is possible to determine whether to perform DR based on the calculation result of the above-mentioned possible period for stopping the BOG compressor 24.

Hereafter, the specific content at the time of implementing DR by the LNG receiving installation 2 is demonstrated, referring FIG.
The LNG receiving facility 2 operates the LNG pumps 211 and 22, the ORV 231, the BOG compressor 24 and the like during normal operation, and ships the product gas at the heat quantity and flow rate required for the customer 3 ( P11). At this time, operation data (I12: payout flow rate F, liquid level L1 of LNG in the LNG tank 21, heat input amount Qtank for calculation) necessary for calculation of the possible stopping period using the above (Equation 1 to 5) Continuously obtain the ambient temperature, the amount of heat supplied from a heater (not shown), etc.

Furthermore, the LNG receiving facility 2 is expected to receive a DR implementation (reduction of power consumption) request based on changes in the outside air temperature, power supply and demand forecast announced by the power transmission and distribution company 11, etc. It is possible to start the study of reduction (study start process).
In this case, based on the acquired operation data and prediction of temperature change (prediction of Qtank), etc., calculation of Eqs. Predict change (P13). Then, based on the pressure change, the possible stop time of the BOG compressor 24 is calculated (P14).

The above-described calculation may be performed off-line by the operator using a computer, or may be automatically calculated using an operation management system of the LNG receiving facility 2 such as DCS (Distributed Control System). The prediction of the pressure change in the LNG tank 21 and the calculation of the stoppage time of the BOG compressor 24 correspond to the stoppage possible period calculating step of this embodiment.
Furthermore, regarding the vaporizer, the number of ORVs 231 and SMVs 232 currently in operation and the power consumption of the seawater pump are calculated (P21).

  Then, when it is determined that the transmission and distribution company 11 needs to carry out the DR, the resource aggregator 12 makes a prior notification regarding the reduction of the power consumption (I01). In FIG. 3, the resource aggregator 12 is omitted. This communication includes, for example, information on the DR implementation period (reduction period) and the requested reduced power.

When the prior notification is received, the DR implementation period is compared with the stoppable period calculated above to examine whether the BOG compressor 24 can be stopped (P15: stop possibility determination step). For example, when the stoppage possible period of the BOG compressor 24 is longer than the implementation period of the DR, it can be determined that the implementation of the DR is possible.
Then, after the prior notification, when receiving a request for reduction of power consumption (I02) from the resource aggregator 12, it is judged that the BOG compressor 24 is actually stopped (P16), and the operation stop operation is executed (P17: gas compression) Part stop process).

  Further, based on the grasped result of the operating status of the ORV 231 and the SMV 232 (in the normal operation, all the ORVs 231 are operated), the power that can be further reduced is grasped (P22). Then, for example, after performing adjustment with the resource aggregator 12 that power consumption can be further reduced, when the power consumption reduction request (I02) is received, the vaporizer is switched from the ORV 231 to the SMV 232 (P23: vaporizer Switching process).

  On the other hand, as a result of receiving notification in advance and examining whether or not to stop the BOG compressor 24 (P15), for example, if it is found that the stoppable period of the BOG compressor 24 is shorter than the DR implementation period, the resource It is determined that it is not possible to secure a stoppable period commensurate with the request from the aggregator 12.

  At this time, if there is time for receiving an advance notification and an actual power consumption reduction request, operation adjustment may be performed to reduce the pressure in the LNG tank 21. As the contents of operation adjustment, the mixing ratio of BOG to product gas is increased to increase the amount of BOG withdrawn from the LNG tank 21 or to request 3 to increase the amount of product gas received. It can be exemplified to increase the liquid transfer amount of LNG to lower the liquid level of LNG.

  Therefore, if it is determined that stopping the BOG compressor 24 is difficult in the stoppage examination step (P15), the target pressure lower than the pressure of the LNG tank 21 at the time of making the determination is operated. The target pressure at the time of adjustment execution is calculated (P31: target pressure setting step). The target pressure pressure is set to a target pressure at which the stoppage time of the BOG compressor 24 calculated by the above-described method is longer than the DR implementation period.

  After that, if it is determined that the operation adjustment for reducing the internal pressure of the LNG tank 21 to the target pressure can be performed (P32), the operation adjustment is performed (P33: pressure reduction step). Then, the prediction of the internal pressure change of the LNG tank 21 (P13) and the calculation of the possible stopping period of the BOG compressor 24 (P14) are performed, and the possibility of stopping is reexamined (P15). If the internal pressure of the LNG tank 21 has reached the target pressure by the operation adjustment, it can be determined that the BOG compressor 24 can be stopped. Therefore, the resource aggregator 12 requests a reduction in power consumption (I02) When it is determined that the BOG compressor 24 is to be stopped (P16), the operation stop operation is performed (P17).

On the other hand, as described above, even if the period for receiving LNG from the LNG tanker 4 where the amount of BOG generated is several times that for normal operation overlaps with the period for implementing DR, the operation adjustment described above is performed. There is a high possibility that the BOG compressor 24 can not be stopped. Therefore, in this case, it may be determined to give priority to continuing the operation of the BOG compressor 24 by omitting the examination of whether or not to stop the BOG compressor 24 (continuation determination step).
In addition, by adjusting the shipping schedule of the LNG tanker 4 so that the acceptance of LNG will be carried out on Saturdays, Sundays, and public holidays, where there is little possibility that DR implementation requests will be issued, the LNG acceptance period and DR implementation will be carried out. Overlapping periods may be avoided.

  According to the operation method of the LNG receiving facility 2 according to the present embodiment, the following effects can be obtained. The stoppable period of the BOG compressor 24 for extracting BOG from the LNG tank 21 is calculated, and based on the result, it is determined whether the BOG compressor 24 can be stopped or not. It can be implemented.

Here, in the example described with reference to FIG. 3, prediction of the internal pressure change of the LNG tank 21 (P13) and calculation of the stoppage possible period of the BOG compressor 24 (P14) are performed in advance in anticipation of the implementation of DR. , And the example which considers the decision | availability of a stop of the BOG compressor 24 in response to prior notification of DR implementation.
However, this examination order may be changed as appropriate. For example, if there is a sufficient time before receiving the power consumption reduction request (I02) and executing it (stopping the BOG compressor 24), the internal pressure change of the LNG tank 21 after receiving the reduction request And the calculation of the possible stopping period of the BOG compressor 24 (P13, 14: possible stopping period calculation step), and the examination of the possibility of stopping (P15: possible stopping judgment step) may be performed.

11 Power Transmission and Distribution Operator 12 Resource Aggregator 13 Customer 2 LNG Receiving Facility 21 LNG Tank 211, 22 LNG Pump 231 Open Rack Vaporizer (ORV)
232 Submerged Combination Vaporizer (SMV)
24 BOG compressor 3 Demand destination

Claims (8)

A method of operating a liquefied natural gas receiving facility, comprising
The liquefied natural gas receiving facility includes a storage tank for storing liquefied natural gas received from the outside, a vaporizer for vaporizing liquefied natural gas discharged from the storage tank, and shipping it in the form of a gas, An electric motor-driven gas compressor for pressurizing the boil-off gas generated in the storage tank and mixing it with the natural gas vaporized by the vaporizer;
A study start step of starting a study of power consumption reduction assuming reception of the power consumption reduction request including information related to the reduction period, or an internal pressure of the storage tank when the gas compression unit is stopped Of the gas compression unit on the basis of the comparison result between the reduction possible period and the reduction possible period of the gas compression unit. And a stopability determination step of determining whether to stop or not, and a method of operating a liquefied natural gas receiving facility characterized by including.   The method is characterized by including a gas compression unit stopping step of stopping the gas compression unit when it is determined in the stop possibility determination step that the gas compression unit can be stopped during the reduction period. The operating method of the liquefied natural gas receiving facility as described in 1. The vaporizer is a vaporizer for normal operation that vaporizes liquefied natural gas using seawater supplied from a seawater pump driven by an electric motor as a heat source, and emergency operation for vaporizing liquefied natural gas using combustion heat of the natural gas as a heat source Providing a vaporizer for the
In addition to the execution of the gas compressor stop step, the present invention is characterized by performing a vaporizer switching step of switching the vaporizer for normal operation to the vaporizer for emergency operation to vaporize the liquefied natural gas. The operation method of the liquefied natural gas receiving facility according to claim 2.   In the stoppable period calculating step, a change in the internal pressure is predicted based on a change in gas phase volume accompanying discharge of liquefied natural gas from the storage tank and an amount of boil-off gas generated in the storage tank. The operating method of the liquefied natural gas receiving facility according to claim 1 characterized by   The method for operating a liquefied natural gas receiving facility according to claim 4, wherein an amount of boil-off gas generated in the storage tank is determined based on an amount of heat input to the storage tank.   In the stoppable period calculating step, a period in which the predicted value of the change in the internal pressure of the storage tank is less than the upper limit value of the operating pressure provided to the storage tank is defined as the stoppable period. The operation method of the liquefied natural gas receiving facility according to Item 1.   When the reduction period overlaps with a period for receiving liquefied natural gas from the outside to the storage tank, the method further includes a continuation determination step of making a priority determination to continue the operation of the gas compression unit. The operation method of the liquefied natural gas receiving facility according to claim 1. A target pressure setting step of setting a target pressure lower than the pressure of the storage tank when the stop possibility determination step is performed to reduce power consumption if the determination result in the stop possibility determination step is negative. And the pressure reduction step of reducing the internal pressure of the storage tank to the target pressure, wherein the stop possibility determination step is re-executed after the pressure reduction step. How to operate the gas receiving facility.

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