WO2020054068A1

WO2020054068A1 - Method for operating liquefied natural gas receiving equipment

Info

Publication number: WO2020054068A1
Application number: PCT/JP2018/034255
Authority: WO
Inventors: 浩二郎倉田; 高橋　真二; 篤志神谷
Original assignee: 日揮グローバル株式会社
Priority date: 2018-09-14
Filing date: 2018-09-14
Publication date: 2020-03-19
Also published as: EP3851730A4; EP3851730A1; JPWO2020054068A1; JP6503521B1; KR20210058819A

Abstract

[Problem] To provide a technique for handling a demand response while maintaining stable operation of liquefied natural gas receiving equipment. [Solution] This liquefied natural gas receiving equipment 2 is provided with a storage tank 21 for storing liquefied natural gas, a vaporizer 231 for vaporizing liquefied natural gas that has been fed out from the storage tank and shipping same in a gaseous state, and an electric motor-driven gas compression unit 24 for pressurizing boil-off gas that has generated in the storage tank 2 and mixing same into the vaporized natural gas. In an examination start step, examination of consumed power reduction is started. In a potential stop period calculation step, a change in internal pressure of the storage tank 21 is predicted for a case where the gas compression unit 24 is stopped, and a potential stop period for the gas compression unit 24 is calculated. Thereafter, in a stop feasibility determination step, the feasibility of stopping the gas compression unit 24 is determined on the basis of a comparison result of a reduction period and the potential stop period.

Description

Operation of liquefied natural gas receiving equipment

<< The present invention relates to a method of operating a liquefied natural gas receiving facility for receiving liquefied natural gas (Liquefied: LNG), storing it in a storage tank, vaporizing the LNG and shipping the product gas.

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

For example, consumers, such as factories and large retail stores, increase or decrease power demand by switching between operating and stopping power consuming devices and changing the output of owned power generation equipment.
However, in particular, in the implementation of DR for reducing power demand (“down DR”), a customer who does not have a private power generation facility or a storage battery or has insufficient capacity has to reduce power demand. As a result, for example, a factory may need to perform production adjustment, and it is difficult to participate in the DR mechanism unless it is certain that the merits of performing DR will exceed the disadvantages caused by production adjustment.

Here, Patent Literature 1 discloses a demand response system that outputs a power supply and demand adjustment command signal directly from a power company side to an electric device control device that controls the operation of electric devices on the consumer side and performs DR. Is described. However, it is difficult for an external power company to directly participate in a demand response system that directly controls the operation of an electric device for a customer who needs to perform operations such as ensuring safety when operating the electric device.

Patent Document 2 also discloses that BOG (Boil Off Gas: LNG) mixed with liquefied natural gas vaporized by a vaporizer by controlling the load of a BOG compressor in accordance with the required heat quantity of a gas consuming destination. A technique for adjusting the amount of LNG vaporized in the tank is described. On the other hand, Patent Document 2 does not describe a technique related to DR.

Japanese Patent No. 6343372 JP 2018-112218 A

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

The method for operating the liquefied natural gas receiving facility of the present invention is a method for operating the liquefied natural gas receiving facility,
The liquefied natural gas receiving facility is a storage tank for storing liquefied natural gas received from outside, a liquefied natural gas discharged from the storage tank is vaporized, and a vaporizer for shipping in a gas state, An electric motor-driven gas compressor for boosting the boil-off gas generated in the storage tank and mixing it with the natural gas vaporized by the vaporizer,
Receiving a request for power consumption reduction including information related to the reduction period, or assuming that it is received, a study start step to start studying power consumption reduction, and the internal pressure of the storage tank when the gas compression unit is stopped The change of the gas compression unit is predicted based on a comparison result between the reduction period and the stoppage period of the gas compression unit. And determining whether or not to stop the vehicle.

The method of operating the liquefied natural gas receiving facility may have the following features.
(A) A gas compression unit stopping step of stopping the gas compression unit when it is determined in the stoppage determination step that the gas compression unit can be stopped during the reduction period.
(B) the vaporizer is a normal operation vaporizer for vaporizing liquefied natural gas using seawater supplied from a seawater pump driven by an electric motor, and a liquefied natural gas using the heat of combustion of the natural gas as a heat source. And a vaporizer for emergency operation to be performed, and in addition to performing the gas compression unit stopping step, switch the vaporizer for normal operation to the vaporizer for emergency operation to vaporize liquefied natural gas. Carry out a vaporizer switching process.
(C) In the stoppable period calculating step, the change in the internal pressure is determined based on a change in the gas phase volume caused by the discharge of the liquefied natural gas from the storage tank and a boil-off gas amount generated in the storage tank. To predict. The amount of boil-off gas generated in the storage tank is determined based on the amount of heat input to the storage tank.
(D) In the stoppable period calculating step, a period during which the predicted value of the change in the internal pressure of the storage tank is less than the upper limit of the operating pressure provided in the storage tank is defined as the stoppable period.
(E) In a case where the reduction period overlaps with a period for receiving liquefied natural gas from the outside with respect to the storage tank, a continuation determination step of making a determination that gives priority to continuing operation of the gas compression unit is included. .
(F) a target for setting a target pressure lower than the pressure of the storage tank at the time of performing the stoppage determination step in order to reduce power consumption when the determination result is negative in the stoppage determination step. The method includes a pressure setting step and a pressure lowering step of reducing the internal pressure of the storage tank to the target pressure. After the pressure lowering step, the stop possibility determination step is performed again.

The present invention calculates a stoppable period of the gas compression unit for extracting boil-off gas from the liquefied natural gas storage tank, and determines whether to stop the gas compression unit based on the calculated result. Demand response can be performed without hindering the response.

It is explanatory drawing which shows the relationship of the participant of DR transaction. It is a lineblock diagram of an LNG receiving facility concerning an embodiment. It is a flowchart of the item implemented in LNG receiving equipment in connection with DR.

Fig. 1 shows an example of the relationship between 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. If a DR contract is made to the power transmission and distribution company 11, a reward may be obtained, but if a request for DR from the power transmission and distribution company 11 cannot be met, a penalty may need to be paid.

(4) The resource aggregator 12 adjusts the demand and supply of the DR collectively for the plurality of consumers 13 to distribute rewards and reduce the risk of penalty payment. Examples of the contents of the supply and demand adjustment include selection of a customer 13 that can respond to a DR request from the power transmission and distribution company 11 and assignment of a response period.

Each of the customers 13 executes the DR based on the supply and demand adjustment with the resource aggregator 12. DR includes “up DR” for increasing power demand and “down DR” for reducing power demand. When the amount of power generated from renewable energy is large and the power demand needs to be increased, a request for an “up DR” is issued. On the other hand, when the power demand in the jurisdiction of the power transmission and distribution company 11 is tight, a request for “down DR” is issued.
The company of the LNG receiving facility 2 of this example constitutes one of the customers 13 among the participants of the above-mentioned DR transaction.

In the example illustrated in FIG. 1, the power transmission and distribution company 11 requests the resource aggregator 12 for a “down DR” including information on the reduction amount and the reduction period (reduction request). The resource aggregator 12 adjusts the supply and demand of the plurality of customers 13 (customers A, B, and LNG receiving facilities 2) in accordance with each reducible amount in order to reduce power consumption corresponding to the reduction request. . In the example illustrated in FIG. 1, as a result of the adjustment, it is determined that the customer A and the LNG receiving facility 2 perform “down DR”. Then, as 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 LNG from the outside, vaporizing the stored LNG, and shipping it to the demand destination 3. This LNG receiving facility 2 has a facility configuration that can be applied to DR in comparison with a customer 13 such as a factory or the like that requires production adjustment when performing “down DR” (hereinafter referred to as “DR”). There is.
Hereinafter, a configuration example of the LNG receiving facility 2 of the present example will be described with reference to FIG.

The LNG receiving facility 2 includes an LNG tank 21 for storing LNG,

LNG pumps

211 and 22 for delivering LNG from the LNG tank 21 to discharge gas to the demand destination 3, and an LNG vaporizing gas for vaporizing LNG. It is provided with a vaporizer (ORV 231 and SMV 232 to be described later) to be brought into a state, and a calorie adjusting unit 26 for adding a liquefied petroleum gas (LPG: Liquefied Petroleum Gas) to the vaporized gas to obtain a product gas.

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

Ｌ The LNG stored in the LNG tank 21 is sent to the

vaporizers

231 and 232 via the LNG pump 211 provided in the LNG tank 21 and the delivery pump 22 for increasing pressure.

The LNG receiving facility 2 of this example includes an ORV (Open Rack Vaporizer) 231 that is a vaporizer that vaporizes LNG by using seawater (SW) supplied from a seawater pump (not shown) driven by an electric motor as a heat source. An SMV (Submerged-combustion @ Vaporizer) 232, which is a vaporizer for vaporizing LNG using the heat of combustion of natural gas as a heat source, can be used by switching. In the LNG receiving facility 2, LNG is vaporized 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, in the LNG receiving facility 2, a plurality of ORVs 231 and SMVs 232 are provided.

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

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

(4) In the LNG tank 21 for storing LNG, part of the LNG is vaporized due to heat input from the outside or the like, and BOG is generated. In order to prevent the pressure in the LNG tank 21 from becoming excessive, the LNG tank 21 is connected to a BOG compressor 24 which is a gas compression unit for extracting BOG. 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 having three compression stages as shown in FIG. 2, and is configured to reduce the BOG of about 12 to 22 kPaG (the suction side pressure of the first compression stage) to 2 to 22 kPaG. The pressure is increased to about 7.5 MPaG (pressure on the discharge side of the final compression stage). The boosted BOG merges with the LNG vaporized by the vaporizer (ORV231 or SMV232), and is calorie-adjusted, and then delivered to the demand destination 3 as a product gas.

In the LNG receiving facility 2 having the above configuration, the power consumption of about several megawatts can be reduced by stopping the BOG compressor 24. Even if the BOG compressor 24 is stopped, the LNG pumps 211 and 22 are not affected, and the LNG supply can be continued. Further, 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, the LNG can be continuously vaporized.
From these viewpoints, it can be said that the LNG receiving facility 2 is a customer 13 having an applicable facility configuration when participating in the DR transaction.

On the other hand, when the BOG compressor 24 is stopped for a long time and the pressure in the LNG tank 21 exceeds the upper limit of the operating pressure, the BOG is released, for example, toward a flare (not shown), and the flare is released. The gas is burned and losses occur. When the pressure in the LNG tank 21 further increases, a safety valve (not shown) is operated, and excess BOG is released into the atmosphere.

In particular, in the LNG receiving facility 2, LNG is received from the LNG tanker 4 once to several times a month. At this time, the amount of BOG generated in the LNG tank 21 increases to several times the normal time, for example, to about four times. It may be difficult to stop the BOG compressor 24 during a period in which a large amount of BOG occurs.
Therefore, by predicting a change in the internal pressure of the LNG tank 21 when the BOG compressor 24 is stopped and specifying the period during which the BOG compressor 24 can be stopped, the DR operation can be performed without hindering the stable operation of the LNG receiving facility 2. It can be determined whether or not the operation can be performed.

Hereinafter, an example of a method of calculating the stoppable period of the BOG compressor 24 will be described.
Assuming that the stop time of the BOG compressor 24 (start time of accumulating BOG in the BOG compressor 24) is t1, and the restart time of the BOG compressor 24 (end time of accumulating BOG) is t2, the stop of the BOG compressor 24 is stopped. The period is (t2-t1).
Assuming that the discharge flow rate of LNG from the LNG tank 21 is F [m ³ / h] and the liquid level of LNG in the LNG tank 21 at time t1 is L1 [m], the liquid level L2 [m] at time t2 is This is expressed by the following equation (ID [m] is the inner diameter of the LNG tank 21).

Further, assuming that 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 represented by the following equation (Equation 2).

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

Furthermore, the pressure in the LNG tank 21 at time t1 is p1 [kPaG], the pressure at time t2 is p2 [kPaG], and the BOG densities at each pressure are ρ1 and ρ2 [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 taking a mass balance based on the volume change of

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

Since the LNG tank 21 is provided with a liquid level gauge, the LNG tank 21 in the LNG tank 21 during the period is determined based on only the change in the liquid level of the LNG in the LNG tank 21 at each time of the liquid level t1 and t2. You can know the pressure change. As described above, since the BOG densities ρ1 and ρ2 are uniquely determined according to the pressures p1 and p2 at each time, the calculation of the stop period using (Equation 5) is based on the pressure change in the LNG tank 21. It is done based on.

Therefore, by setting the upper limit value of the operating pressure of the LNG tank 21 as the pressure p2 of the LNG tank 21 at the time t2 (the density ρ2 of the BOG at that time), the LNG tank 24 is operated under the condition that the BOG compressor 24 is stopped. It is possible to specify a possible stop period (t2−t1) for maintaining the pressure in the pressure 21 below the upper limit of the operating pressure. As described above, the change (L2-L1) in the liquid level of 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 the DR based on the calculation result of the stoppable period of the BOG compressor 24 described above.

Hereinafter, with reference to FIG. 3, specific contents when performing DR in the LNG receiving facility 2 will be described.
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 required heat quantity and flow rate to the demand destination 3 ( P11). At this time, the operation data (I12: the discharge flow rate F, the liquid level L1 of the LNG in the LNG tank 21, and the heat input Qtank) necessary for calculating the stoppable period using the above (Equations 1 to 5). The external temperature and the amount of heat supplied from a heater (not shown) are continuously obtained.

Further, the LNG receiving facility 2 expects to receive a DR execution (reduction in power consumption) request based on a change in outside temperature, a power supply / demand forecast announced by the power transmission and distribution company 11, and the like. Examination of reduction can be started (examination start step).
In this case, based on the acquired operation data and the prediction of the temperature change (prediction of Qtank), the equations (3, 5) are calculated and the pressure in the LNG tank 21 from the time when the DR is predicted to be performed is calculated. A change is predicted (P13). Then, the possible stop time of the BOG compressor 24 is calculated based on the pressure change (P14).

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

{Circle around (4)} When the transmission and distribution company 11 determines that the DR is required, the resource aggregator 12 notifies the resource aggregator 12 in advance of the reduction in power consumption (I01). In FIG. 3, the description of the resource aggregator 12 is omitted. This notification includes, for example, information on the DR implementation period (reduction period) and the requested power reduction.

When the advance notification is received, the DR execution period is compared with the previously calculated stoppage period to determine whether the BOG compressor 24 can be stopped (P15: stoppage determination step). For example, when the period during which the BOG compressor 24 can be stopped is longer than the period during which DR is performed, it can be determined that the DR can be performed.
Then, upon receiving a power consumption reduction request (I02) from the resource aggregator 12 after the advance notification, it is determined that the BOG compressor 24 is actually stopped (P16), and an operation stop operation is performed (P17: gas compression). Department stop process).

(4) Further, based on the result of grasping the operation status of the ORVs 231 and SMV232 (all the ORVs 231 operate during normal operation), the power that can be further reduced is grasped (P22). Then, for example, after adjusting with the resource aggregator 12 to the effect 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 step).

On the other hand, as a result of examining whether or not the BOG compressor 24 can be stopped after receiving the advance notice (P15), for example, when it is found that the stoppage period of the BOG compressor 24 is shorter than the DR execution period, It is determined that a stoppable period appropriate for the request from the aggregator 12 cannot be secured.

At this time, if there is enough time between receiving the advance notification and receiving the actual power consumption reduction request, an operation adjustment for reducing the pressure in the LNG tank 21 may be performed. The contents of the operation adjustment include increasing the mixing ratio of BOG to the product gas to increase the amount of BOG extracted from the LNG tank 21 or requesting the demand destination 3 to increase the amount of the product gas received. , The LNG liquid level is decreased by increasing the LNG supply amount, and the like.

Therefore, if it is determined that the stop of the BOG compressor 24 is difficult at the stage of determining whether or not to stop (P15), the operation is performed such that the target pressure becomes lower than the pressure of the LNG tank 21 at the time of making the determination. The target pressure at the time of performing the adjustment is calculated (P31: target pressure setting step). The target 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 execution period.

After that, when 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 internal pressure change of the LNG tank 21 is predicted (P13), the stoppage possible period of the BOG compressor 24 is calculated (P14), and the stoppage determination is performed again (P15). If the internal pressure of the LNG tank 21 has reached the target pressure due to the operation adjustment, it is possible to determine that the BOG compressor 24 can be stopped. Therefore, the resource aggregator 12 requests a reduction in power consumption (I02). In response to this, it is determined that the BOG compressor 24 should be stopped (P16), and an operation stop operation is executed (P17).

On the other hand, as described above, when the amount of BOG generated is several times as large as the normal time, and the LNG receiving period from the LNG tanker 4 and the DR execution period overlap, the operation adjustment described above may be performed. There is a high possibility that the BOG compressor 24 cannot be stopped. Therefore, in this case, the determination of whether or not the BOG compressor 24 can be stopped may be omitted, and a determination may be made that gives priority to continuing the operation of the BOG compressor 24 (continuation determination step).
The LNG tanker 4 is scheduled to receive LNG on Saturdays, Sundays, and public holidays, where it is unlikely that a request for DR will be issued. Overlapping periods may be avoided.

According to the method of operating the LNG receiving facility 2 according to the present embodiment, the following effects are obtained. The stoppage period of the BOG compressor 24 for extracting BOG from the LNG tank 21 is calculated, and whether or not the BOG compressor 24 can be stopped is determined based on the calculated result. Therefore, the DR can be determined without hindering the stable operation of the LNG receiving facility 2. Can be implemented.

Here, in the example described with reference to FIG. 3, in anticipation of the execution of DR, the prediction of the change in the internal pressure of the LNG tank 21 (P13) and the calculation of the period during which the BOG compressor 24 can be stopped (P14) are performed in advance. In this example, the BOG compressor 24 is considered whether or not to stop in response to prior notification of the DR execution.
However, this study order may be changed as appropriate. For example, if there is a sufficient time from when the power consumption reduction request (I02) is received to when it is executed (the BOG compressor 24 is stopped), the internal pressure change of the LNG tank 21 is performed after the reduction request is received. May be calculated, the stoppage period of the BOG compressor 24 may be calculated (P13, 14: stoppage period calculation step), and the possibility of stoppage may be examined (P15: stoppage determination step).

11 Power transmission and distribution company 12 Resource aggregator 13 Customer 2 LNG receiving facility 21 LNG tank 211, 22LNG pump 231 Open rack vaporizer (ORV)
232 Submerged combination vaporizer (SMV)
24 BOG compressor 3 Demand destination

Claims

A method of operating a liquefied natural gas receiving facility,
The liquefied natural gas receiving facility is a storage tank for storing liquefied natural gas received from outside, a liquefied natural gas discharged from the storage tank is vaporized, and a vaporizer for shipping in a gas state, An electric motor-driven gas compressor for boosting the boil-off gas generated in the storage tank and mixing it with the natural gas vaporized by the vaporizer,
Receiving a request for power consumption reduction including information related to the reduction period, or assuming that it is received, a study start step to start studying power consumption reduction, and the internal pressure of the storage tank when the gas compression unit is stopped The change of the gas compression unit is predicted based on a comparison result between the reduction period and the stoppage period of the gas compression unit. A method of operating a liquefied natural gas receiving facility, comprising: a step of determining whether to stop the vehicle.
The 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. 2. The method for operating the liquefied natural gas receiving facility according to 1.
The vaporizer is a vaporizer for normal operation of vaporizing liquefied natural gas using seawater supplied from a seawater pump driven by an electric motor as a heat source, and an emergency operation for vaporizing liquefied natural gas using the heat of combustion of the natural gas as a heat source. And a vaporizer for
In addition to performing the gas compression unit stopping step, performing a vaporizer switching step of vaporizing the liquefied natural gas by switching the vaporizer for normal operation to the vaporizer for emergency operation. A method for operating the liquefied natural gas receiving facility according to claim 2.
In the stoppable period calculating step, the change in the internal pressure is predicted based on a change in the gas phase volume caused by liquefied natural gas being discharged from the storage tank and a boil-off gas amount generated in the storage tank. The method for operating a liquefied natural gas receiving facility according to claim 1, wherein:
The method according to claim 4, wherein the amount of boil-off gas generated in the storage tank is obtained based on an amount of heat input to the storage tank.
The said stop possible period calculation process WHEREIN: The period in which the predicted value of the change of the internal pressure of the said storage tank is less than the upper limit of the operating pressure provided in the said storage tank is made into the said stop possible period. Item 4. An operation method of the liquefied natural gas receiving facility according to Item 1.
When the reduction period overlaps a period for receiving liquefied natural gas from the outside with respect to the storage tank, a continuation determination step of performing a determination that gives priority to continuing operation of the gas compression unit is included. The method for operating a 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 at the time of performing the stop possibility determination step, in order to reduce power consumption, when the determination result is negative in the stop possibility determination step. 2. The liquefied natural plant according to claim 1, further comprising: a pressure reduction step of reducing the internal pressure of the storage tank to the target pressure, wherein after the pressure reduction step, the stoppage determination step is performed again. How to operate gas receiving equipment.