WO2019230603A1 - Unité d'alimentation en gaz et dispositif de génération d'énergie de co-combustion - Google Patents

Unité d'alimentation en gaz et dispositif de génération d'énergie de co-combustion Download PDF

Info

Publication number
WO2019230603A1
WO2019230603A1 PCT/JP2019/020731 JP2019020731W WO2019230603A1 WO 2019230603 A1 WO2019230603 A1 WO 2019230603A1 JP 2019020731 W JP2019020731 W JP 2019020731W WO 2019230603 A1 WO2019230603 A1 WO 2019230603A1
Authority
WO
WIPO (PCT)
Prior art keywords
path
gas
liquefier
lng
supply unit
Prior art date
Application number
PCT/JP2019/020731
Other languages
English (en)
Japanese (ja)
Inventor
治幸 松田
貴保 藤浦
西村　真
見治 名倉
彰利 藤澤
清水　邦彦
雄治 栗城
Original Assignee
株式会社神戸製鋼所
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by 株式会社神戸製鋼所 filed Critical 株式会社神戸製鋼所
Publication of WO2019230603A1 publication Critical patent/WO2019230603A1/fr

Links

Images

Classifications

    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F17—STORING OR DISTRIBUTING GASES OR LIQUIDS
    • F17C—VESSELS FOR CONTAINING OR STORING COMPRESSED, LIQUEFIED OR SOLIDIFIED GASES; FIXED-CAPACITY GAS-HOLDERS; FILLING VESSELS WITH, OR DISCHARGING FROM VESSELS, COMPRESSED, LIQUEFIED, OR SOLIDIFIED GASES
    • F17C13/00—Details of vessels or of the filling or discharging of vessels
    • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
    • Y02E—REDUCTION OF GREENHOUSE GAS [GHG] EMISSIONS, RELATED TO ENERGY GENERATION, TRANSMISSION OR DISTRIBUTION
    • Y02E60/00—Enabling technologies; Technologies with a potential or indirect contribution to GHG emissions mitigation
    • Y02E60/30—Hydrogen technology
    • Y02E60/32—Hydrogen storage
    • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
    • Y02P—CLIMATE CHANGE MITIGATION TECHNOLOGIES IN THE PRODUCTION OR PROCESSING OF GOODS
    • Y02P90/00—Enabling technologies with a potential contribution to greenhouse gas [GHG] emissions mitigation
    • Y02P90/45—Hydrogen technologies in production processes

Definitions

  • the present invention relates to a gas supply unit and a co-fired power generation apparatus including the gas supply unit.
  • a gas supply unit that vaporizes liquefied natural gas (LNG; Liquid Natural Gas) and supplies the generated natural gas (NG; Natural Gas) to a predetermined demand destination is known. ing.
  • This gas supply unit is used to supply natural gas as a fuel to a combustor, for example, in a thermal power generation process.
  • Patent Document 1 discloses a processing system in which LNG flowing out of an LNG storage tank is sent to a vaporizer by a pump and NG generated by the vaporizer is supplied to a customer.
  • boil-off gas (BOG) generated by evaporation of LNG in the LNG storage tank is liquefied by heat exchange with liquid nitrogen, and the liquefied BOG (LNG) is returned to the LNG storage tank.
  • BOG boil-off gas
  • Patent Document 2 also discloses a gas reliquefaction device that liquefies BOG generated in a liquefied gas storage tank by heat exchange with liquid nitrogen and returns the liquefied gas to the tank.
  • Patent Documents 1 and 2 liquefy the boil-off gas generated in the LNG storage tank or the liquefied gas storage tank using the cold heat of liquid nitrogen, and return it to the LNG storage tank or the liquefied gas storage tank. There is room for improvement in terms of efficiency.
  • An object of the present invention is to provide a gas supply unit capable of efficiently liquefying LNG boil-off gas and a co-fired power generation apparatus including the gas supply unit.
  • a gas supply unit includes an LNG tank that stores liquefied natural gas, an LNG path through which the liquefied natural gas that has flowed out of the LNG tank flows, the LNG path, and an inflow from the LNG path
  • An LNG vaporizer that vaporizes liquefied natural gas an LH2 tank that stores liquid hydrogen (also referred to as “LH2”), an LH2 path through which liquid hydrogen that flows out of the LH2 tank flows, and the LH2 path
  • An LH2 vaporizer that vaporizes liquid hydrogen flowing in from the path, a BOG path through which boil-off gas generated by evaporation of liquefied natural gas flows in at least one of the LNG tank and the LNG path, the BOG path, and the LH2
  • the liquid hydrogen flowing in from the LH2 path and the BOG path A liquefier that cools and liquefies the boil-off gas by heat exchange with an inflow boil-off gas; and a return path that is connected to the liquefier and
  • the present invention it is possible to provide a gas supply unit capable of efficiently liquefying LNG boil-off gas, and a mixed combustion power generation apparatus including the gas supply unit.
  • FIG. 1 schematically shows the configuration of the gas supply unit 1 and the co-fired power generation apparatus 100.
  • FIG. 1 shows only main components of the gas supply unit 1 and the co-fired power generation device 100, and the gas supply unit 1 and the co-fired power generation device 100 may include arbitrary components that do not appear in FIG. .
  • the co-fired power generation device 100 is a device that generates thermal power using natural gas G2 and hydrogen gas G1 as fuel. As shown in FIG. 1, the co-fired power generation apparatus 100 mainly includes a gas supply unit 1 and a co-fired power generation unit 40 that generates power using natural gas G2 and hydrogen gas G1 supplied from the gas supply unit 1 as fuel. Yes.
  • the gas supply unit 1 is arranged alongside the NG supply unit 20 for supplying the natural gas G2 to the co-firing power generation unit 40, and a hydrogen gas supply unit for supplying the hydrogen gas G1 to the co-firing power generation unit 40. 10 are included.
  • the co-fired power generation unit 40 includes a combustor (not shown) that combusts the natural gas G2 and the hydrogen gas G1 supplied from the gas supply unit 1, and a gas turbine 41 that is rotated by the combustion gas.
  • the co-firing power generation unit 40 generates power by rotating the gas turbine 41 with combustion gas.
  • the NG supply unit 20 includes an LNG tank 21, an LNG path 23, an LNG pump 22, and an LNG vaporizer 24.
  • the LNG tank 21 stores the liquefied natural gas L2.
  • a boil-off gas G is generated by evaporating a part of the liquefied natural gas L2 by heat entering from the outside.
  • the LNG path 23 is a pipe through which the liquefied natural gas L2 flowing out from the LNG tank 21 flows. As shown in FIG. 1, one end of the LNG path 23 is connected to the LNG tank 21 and the other end is connected to the mixed combustion power generation unit 40. Even in the LNG path 23, a part of the liquefied natural gas L2 is evaporated by heat entering from the outside, and the boil-off gas G can be generated.
  • the LNG pump 22 raises the liquefied natural gas L2 flowing out from the LNG tank 21 to a predetermined pressure and sends it out toward the LNG vaporizer 24. As shown in FIG. 1, the LNG pump 22 is disposed upstream of the LNG vaporizer 24 in the LNG path 23 in the flow direction of the liquefied natural gas L2.
  • the LNG vaporizer 24 is a heat exchanger that vaporizes the liquefied natural gas L2 flowing from the LNG path 23, and is disposed on the downstream side of the LNG pump 22 in the LNG path 23.
  • the LNG vaporizer 24 includes a first flow path 24A connected to the LNG path 23 and a second flow path 24B through which the heat source medium H2 flows, and the liquefied natural gas flowing through the first flow path 24A. Heat exchange is possible between the gas L2 and the heat source medium H2 flowing through the second flow path 24B.
  • the liquefied natural gas L2 is vaporized by this heat exchange to generate natural gas G2, and the natural gas G2 is supplied to the co-firing power generation unit 40 as fuel.
  • the heat source medium H2 for example, seawater or air can be used, but it is not particularly limited.
  • the hydrogen gas supply unit 10 includes an LH2 tank 11, an LH2 path 13, an LH2 pump 12, and an LH2 vaporizer 14.
  • the LH2 tank 11 stores liquid hydrogen L1 (LH2).
  • the LH2 path 13 is a pipe through which the liquid hydrogen L1 flowing out from the LH2 tank 11 flows. As shown in FIG. 1, the LH2 path 13 has one end connected to the LH2 tank 11 and the other end connected to the mixed combustion power generation unit 40.
  • the LH2 pump 12 raises the liquid hydrogen L1 flowing out from the LH2 tank 11 to a predetermined pressure and sends it out toward the LH2 vaporizer 14. As shown in FIG. 1, the LH2 pump 12 is disposed upstream of the LH2 vaporizer 14 in the LH2 path 13 in the flow direction of the liquid hydrogen L1.
  • the LH2 vaporizer 14 is a heat exchanger that vaporizes the liquid hydrogen L1 flowing from the LH2 path 13, and is disposed downstream of the LH2 pump 12 in the LH2 path 13.
  • the LH2 vaporizer 14 includes a first flow path 14A connected to the LH2 path 13 and a second flow path 14B through which the heat source medium H1 flows, and liquid hydrogen flowing through the first flow path 14A. Heat exchange is possible between L1 and the heat source medium H1 flowing through the second flow path 14B.
  • the liquid hydrogen L1 is vaporized by this heat exchange to generate hydrogen gas G1, and the hydrogen gas G1 is supplied to the co-fired power generation unit 40 as fuel.
  • the heat source medium H1 for example, seawater or air can be used, but it is not particularly limited.
  • the gas supply unit 1 further includes a BOG path 32, a liquefier 30, and a return path 31.
  • the BOG path 32 is a pipe into which the boil-off gas G generated when the liquefied natural gas L2 evaporates in the LNG tank 21 flows.
  • the BOG path 32 has one end connected to the upper part of the LNG tank 21 and the other end connected to the inlet of the liquefier 30.
  • a branch path 35 is connected in the middle of the BOG path 32, and a BOG compressor 33 is arranged on the branch path 35.
  • the BOG compressor 33 can boost the boil-off gas G flowing from the BOG path 32 into the branch path 35 to a predetermined pressure.
  • the boosted boil-off gas G (natural gas) may be supplied to the mixed combustion power generation unit 40 as fuel.
  • a BOG path 38 into which the boil-off gas G generated by the evaporation of the liquefied natural gas L2 upstream from the LNG pump 22 in the LNG path 23 may be provided.
  • the boil-off gas G generated by the evaporation of the liquefied natural gas L2 before being pressurized by the LNG pump 22 can be guided to the liquefier 30.
  • the liquefier 30 is a heat exchanger that cools and liquefies the boil-off gas G.
  • the liquefier 30 includes a first flow path 91 connected to the BOG path 32 and the return path 31, and a second flow path 92 connected to the LH2 path 13. More specifically, the downstream end of the BOG path 32 is connected to the inlet of the first flow path 91, and the upstream end of the return path 31 is connected to the outlet of the first flow path 91.
  • the liquid hydrogen L1 flowing into the second flow path 92 from the LH2 path 13 liquid hydrogen L1 before flowing into the LH2 vaporizer 14
  • the boil-off gas G can be cooled and liquefied by heat exchange with the boil-off gas G flowing into the flow path 91.
  • the liquid hydrogen L1 is vaporized in the LH2 vaporizer 14 after obtaining a part of the heat of vaporization through heat exchange with the boil-off gas G in the liquefier 30. Since the flow rate of the boil-off gas G flowing into the liquefier 30 varies depending on conditions such as the outside air temperature, it is difficult to reliably vaporize the liquid hydrogen L1 in the liquefier 30. Therefore, in order to reliably vaporize the liquid hydrogen L1, it is necessary to arrange the LH2 vaporizer 14 downstream of the liquefier 30.
  • the return path 31 is a pipe for returning the boil-off gas G (liquefied natural gas L2) liquefied by the liquefier 30 to the LNG tank 21. As shown in FIG. 1, the return path 31 has an upstream end connected to the outlet of the first flow path 91 of the liquefier 30 and a downstream end connected to the LNG tank 21.
  • the gas supply unit 1 is disposed in the LNG tank 21 that stores the liquefied natural gas L2, the LNG path 23 in which the liquefied natural gas L2 that has flowed out of the LNG tank 21 flows, and the LNG path 23.
  • the LNG vaporizer 24 that vaporizes the liquefied natural gas L2 flowing in from the LNG path 23, the LH2 tank 11 that stores the liquid hydrogen L1, the LH2 path 13 in which the liquid hydrogen L1 flowing out of the LH2 tank 11 flows, and the LH2 path 13 Is generated when the liquefied natural gas L2 evaporates in the LNG tank 21 (or the upstream side of the LNG pump 22 in the LNG path 23) and the LH2 vaporizer 14 that vaporizes the liquid hydrogen L1 flowing in from the LH2 path 13 BOG path 32 (BOG path 38) through which the boil-off gas G flowing in, and the BOG path 2 and a LH2 path 13, a liquefier 30 that cools and liquefies the boil-off gas G by heat exchange between the liquid hydrogen L1 flowing from the LH2 path 13 and the boil-off gas G flowing from the BOG path 32, and a liquefier 30 And a return path 31 for returning the boil-off gas G liquefied by the lique
  • the boil-off gas G can be liquefied with high efficiency.
  • the amount of liquefied natural gas L2 returned to the LNG tank 21 through the return path 31 increases, and the amount of boil-off gas G compressed by the BOG compressor 33 can be reduced.
  • the pressure increase in the gas state by the BOG compressor 33 requires much power compared to the pressure increase in the liquid state by the LNG pump 22.
  • the energy efficiency in the gas supply to the co-firing power generation unit 40 can be improved by reducing the processing amount by the BOG compressor 33 as described above.
  • the NG supply unit 20 and the hydrogen gas supply unit 10 have the same demand for gas supply (mixed combustion power generation unit 40), problems such as an increase in cost for arranging them close to each other can be avoided.
  • the gas supply unit 2 and the co-fired power generation apparatus 200 according to Embodiment 2 of the present invention basically have the same configuration as the gas supply unit 1 and the co-fired power generation apparatus 100 according to the first embodiment and have the same effects.
  • the second embodiment is different from the first embodiment in that a bypass path 50 that bypasses the liquefier 30 is connected to the LH2 path 13. Only differences from the first embodiment will be described below.
  • the gas supply unit 2 further includes a bypass path 50, a bypass valve 51, a detection mechanism 60, and a control unit 70.
  • the BOG path 32 is provided with a flow rate adjusting valve 34.
  • the bypass path 50 is a pipe connected to the LH2 path 13 so as to bypass the liquefier 30. As shown in FIG. 2, the upstream end of the bypass path 50 is connected between the LH2 pump 12 and the liquefier 30 in the LH2 path 13. On the other hand, the downstream end of the bypass path 50 is connected between the liquefier 30 and the LH2 vaporizer 14 in the LH2 path 13.
  • the liquid hydrogen L1 whose pressure is increased by the LH2 pump 12 can be caused to flow to the bypass path 50 to bypass the liquefier 30. Then, the liquid hydrogen L1 flowing through the bypass path 50 can be merged with the liquid hydrogen L1 flowing out from the liquefier 30, and then flow into the LH2 vaporizer 14.
  • the bypass valve 51 controls the inflow of the liquid hydrogen L1 from the LH2 path 13 to the bypass path 50, and is constituted by a flow rate adjusting valve in the present embodiment.
  • a flow rate adjusting valve By adjusting the opening degree of the bypass valve 51, the flow rate of the liquid hydrogen L1 flowing from the LH2 path 13 into the bypass path 50 is adjusted, and thereby the liquid hydrogen L1 flowing into the liquefier 30 (second flow path 92).
  • the flow rate is also adjusted.
  • the bypass valve is not limited to the flow rate adjustment valve, and may be, for example, an on-off valve.
  • the detection mechanism 60 is a sensor for obtaining various detection values for detecting the closed state of the first flow path 91 (flow path through which the boil-off gas G flowing from the BOG path 32 flows). That is, since the liquid hydrogen L1 is a cryogenic liquid, the liquefied natural gas L2 that has been excessively cooled by the liquid hydrogen L1 is frozen in the first flow path 91, thereby closing the first flow path 91. Sometimes. On the other hand, the blockage of the first flow path 91 due to the freezing of the liquefied natural gas L2 can be detected from the detection result of the detection mechanism 60. As shown in FIG. 1, the detection mechanism 60 in the present embodiment includes a differential pressure detection unit 61, an outlet temperature detection unit 62, a liquefier temperature detection unit 63, an inlet side flow rate detection unit 64, and an outlet side flow rate detection. Part 65.
  • the differential pressure detector 61 is a sensor that detects the differential pressure before and after the first flow path 91. That is, the differential pressure detector 61 can detect the difference between the pressure of the boil-off gas G flowing into the first flow path 91 and the pressure of the liquefied natural gas L2 flowing out of the first flow path 91. When it is larger, the blockage of the first flow path 91 can be detected.
  • the outlet temperature detector 62 is a sensor that detects the temperature of the liquefied natural gas L2 that has flowed out of the first flow path 91.
  • the outlet temperature detection unit 62 is provided in the vicinity of the outlet of the first flow path 91, but the position is not particularly limited.
  • the liquefier temperature detection unit 63 is a sensor that detects the temperature of the liquefier 30. Even when the temperature detected by these sensors is lower than a predetermined threshold temperature, the blockage of the first flow path 91 can be detected.
  • the inlet-side flow rate detection unit 64 is a sensor that detects the flow rate of the boil-off gas G on the inlet side of the first flow path 91.
  • the outlet side flow rate detection unit 65 is a sensor that detects the flow rate of the liquefied natural gas L2 on the outlet side of the first flow path 91. Even when the flow rate detection values by these sensors are lower than a predetermined threshold value, the blockage of the first flow path 91 can be detected.
  • the detection mechanism 60 includes at least one of a differential pressure detection unit 61, an outlet temperature detection unit 62, a liquefier temperature detection unit 63, an inlet side flow rate detection unit 64, and an outlet side flow rate detection unit 65. Well, it is not limited to those including all of these detection units.
  • the control unit 70 controls the bypass valve 51 based on the detection result by the detection mechanism 60, and includes a reception unit 71, a storage unit 72, a comparison determination unit 73, and a bypass valve control unit 74. These are the functions of the CPU (Central Processing Unit) in the computer constituting the control unit 70.
  • CPU Central Processing Unit
  • the accepting unit 71 accepts information on the detection result by the detection mechanism 60. That is, detection results by the differential pressure detection unit 61, the outlet temperature detection unit 62, the liquefier temperature detection unit 63, the inlet side flow rate detection unit 64, and the outlet side flow rate detection unit 65 are input to the reception unit 71.
  • the storage unit 72 stores various threshold values used for controlling the bypass valve 51.
  • the storage unit 72 stores the threshold [Delta] P H of the differential pressure across the first flow path 91, the low-temperature side threshold T L and the high temperature side threshold T H of the outlet temperature of the liquefier 30 for the outlet temperature of the liquefier 30, respectively doing.
  • the storage unit 72 may further store a threshold value for the temperature of the liquefier 30 and a threshold value for the flow rate on the inlet side and the outlet side of the liquefier 30.
  • the comparison determination unit 73 compares the detection result input to the reception unit 71 with the threshold value stored in the storage unit 72.
  • the bypass valve control unit 74 controls the opening degree of the bypass valve 51 based on the comparison result by the comparison determination unit 73.
  • step S1 compared with the threshold value [Delta] P H of the actual differential pressure [Delta] P and the differential pressure detected by the differential pressure detection unit 61 determines whether or not [Delta] P is less than [Delta] P H (step S1).
  • [Delta] P is not less than [Delta] P H ( "NO” in step S1), and increases the opening degree of the bypass valve 51 (step S2).
  • step S2 increases the opening degree of the bypass valve 51
  • the flow rate of the liquid hydrogen L1 flowing into the liquefier 30 from the LH2 path 13 is reduced, and freezing in the first flow path 91 is alleviated.
  • [Delta] P is less than [Delta] P H ( "YES” in step S1), the without adjustment of the opening degree of the bypass valve 51, the flow proceeds to step S3.
  • step S3 the actual temperature T LNG of the liquefied natural gas L2 detected by the outlet temperature detection unit 62 is compared with the low temperature side threshold value TL, and it is determined whether or not T LNG exceeds TL .
  • TLNG is equal to or less than TL (“NO” in step S3)
  • the opening degree of the bypass valve 51 is increased (step S4).
  • the opening degree of the bypass valve 51 is not adjusted, and the process proceeds to step S5.
  • step S5 compared with the temperature T LNG and the high temperature side threshold T H, it determines whether T LNG is less than T H. Here, ( "NO” in step S5). If T LNG is above T H, reducing the opening degree of the bypass valve 51 (step S6). As a result, the amount of liquid hydrogen L1 flowing into the liquefier 30 is increased, and the liquefied natural gas L2 can be cooled to an appropriate temperature. On the other hand, if T LNG is less than T H ( "YES” in step S5), and without adjustment of the opening degree of the bypass valve 51, the flow returns to step S1.
  • the opening degree of the bypass valve 51 based on the detection result by the detection mechanism 60, the flow rate of the liquid hydrogen L1 flowing into the liquefier 30 is prevented so as to prevent freezing in the first flow path 91. Can be adjusted.
  • the present invention is not limited to this. Control using the detection results of the liquefier temperature detection unit 63, the inlet side flow rate detection unit 64, and the outlet side flow rate detection unit 65 may be similarly performed.
  • the bypass valve 52 may be provided not only in the bypass path 50 but also in the LH2 path 13. As shown in FIG. 4, the bypass valve 52 is disposed upstream of the liquefier 30 in the LH2 path 13 and downstream of the connection portion at the upstream end of the bypass path 50.
  • the bypass valve 52 is a flow rate adjustment valve (or an on-off valve) similarly to the bypass valve 51, and is controlled by the control unit 70. That is, increasing the opening degree of the bypass valve 52 increases the flow rate of the liquid hydrogen L1 flowing into the liquefier 30, and decreasing the opening degree of the bypass valve 52 decreases the flow rate of the liquid hydrogen L1 flowing into the liquefier 30. Can be reduced. Thus, by using two valves together, it becomes easier to adjust the flow rate of the liquid hydrogen L1 flowing into the liquefier 30. Alternatively, the bypass valve 51 may be omitted, and the flow rate of the liquid hydrogen L1 flowing into the liquefier 30 may be adjusted using only the bypass valve 52.
  • bypass valve 51 is automatically controlled by the control unit 70
  • the present invention is not limited to this. That is, the detection mechanism 60 and the control unit 70 may be omitted, and the bypass valve 51 may be manually controlled.
  • the gas supply unit 3 and the co-fired power generation apparatus 300 according to Embodiment 3 of the present invention basically have the same configuration as the gas supply unit 2 and the co-fired power generation device 200 according to the second embodiment and have the same effects.
  • the second embodiment is different from the second embodiment in that a plurality of liquefiers 30 are provided. Only differences from the second embodiment will be described below.
  • the gas supply unit 3 includes a plurality of liquefiers 30 (first liquefier 30A and second liquefier 30B).
  • the first liquefier 30A and the second liquefier 30B have the same configuration, and have a first flow path 91 through which the boil-off gas G flows and a second flow path 92 through which liquid hydrogen L1 flows.
  • the LH2 route 13 is branched into a plurality of routes (two in this embodiment). Specifically, the LH2 path 13 extends from the outlet of the LH2 tank 11 to the inlet of the co-fired power generation unit 40 and is connected to the first LH2 path 13A connected to the first liquefier 30A (second flow path 92). And a second LH2 path 13B having both ends connected to the first LH2 path 13A so as to bypass the first liquefier 30A while being connected to the vessel 30B (second flow path 92).
  • the BOG path 32 is branched into a plurality of paths (two in this embodiment). Specifically, the BOG path 32 extends from the LNG tank 21 to the first liquefier 30A and has a first BOG path 32A having a downstream end connected to the inlet of the first flow path 91 of the first liquefier 30A. A second BOG path 32B extending from the middle of the 1BOG path 32A to the second liquefier 30B and having a downstream end connected to the inlet of the first flow path 91 of the second liquefier 30B. The first liquefier 30A and the second liquefier 30B are arranged in parallel in two branched paths of the LH2 path 13 and the BOG path 32.
  • the return path 31 includes a first return path 31A connected to the outlet of the first flow path 91 of the first liquefier 30A and a second return connected to the outlet of the first flow path 91 of the second liquefier 30B. And a path 31B.
  • the first return path 31 ⁇ / b> A has an upstream end connected to the outlet of the first flow path 91 of the first liquefier 30 ⁇ / b> A and a downstream end connected to the LNG tank 21.
  • the second return path 31B has an upstream end connected to the outlet of the first flow path 91 of the second liquefier 30B and a downstream end connected in the middle of the first return path 31A.
  • the gas supply unit 3 includes an LH2 switching valve 55 that switches inflow of liquid hydrogen L1 into each of the first liquefier 30A and the second liquefier 30B, and boil-off to each of the first liquefier 30A and the second liquefier 30B.
  • a BOG switching valve 83 that switches inflow of the gas G.
  • the LH2 switching valve 55 includes a first LH2 switching valve 53 disposed on the upstream side of the first liquefier 30A in the first LH2 path 13A, and an upstream side of the second liquefier 30B in the second LH2 path 13B. 2nd LH2 change-over valve 54 arranged in.
  • the first LH2 switching valve 53 and the second LH2 switching valve 54 are, for example, on-off valves, and are controlled by the control unit 70.
  • the BOG switching valve 83 includes a first BOG switching valve 81 disposed on the downstream side of the connection portion of the second BOG path 32B in the first BOG path 32A, and a second BOG switching valve 82 disposed on the second BOG path 32B.
  • the first BOG switching valve 81 and the second BOG switching valve 82 are, for example, on-off valves, and are controlled by the control unit 70.
  • the use of the first liquefier 30A and the second liquefier 30B can be switched as follows. First, when the first LH2 switching valve 53 and the first BOG switching valve 81 are open and the second LH2 switching valve 54 and the second BOG switching valve 82 are closed, the liquid hydrogen L1 and the boil-off gas G do not flow into the second liquefier 30B. , Flows only into the first liquefier 30A.
  • the timing for switching the use of the liquefier 30 is based on the detection results of the differential pressure detection unit 61, the outlet temperature detection unit 62, the liquefier temperature detection unit 63, the inlet side flow rate detection unit 64, or the outlet side flow rate detection unit 65. You may decide based on. That is, when the detection result by these detection units exceeds the threshold value or falls below the threshold value, it is determined that the flow path of the liquefier 30 being used is blocked by freezing, and switching to use of another liquefier 30 is possible. Good. In addition, when the flow path is closed in both the first liquefier 30A and the second liquefier 30B, the liquid hydrogen L1 may flow through the bypass path 50.
  • the use of the liquefier 30 is not limited to the case of being automatically switched, and may be switched manually. Further, three or more liquefiers 30 may be provided, and branch paths and switching valves may be provided according to the number of liquefiers 30.
  • the gas supply unit 4 and the co-fired power generation apparatus 400 according to Embodiment 4 of the present invention basically have the same configuration as the gas supply unit 3 and the co-fired power generation apparatus 300 according to the third embodiment and have the same effects.
  • the third embodiment is different from the third embodiment in that it further includes a melting mechanism 110 that melts LNG frozen in the first flow path 91 of the liquefier 30. Only differences from the third embodiment will be described below.
  • the melting mechanism 110 in the present embodiment is configured to return a part of the hydrogen gas G1 vaporized by the LH2 vaporizer 14 to the upstream side of the liquefier 30 in the LH2 path 13.
  • the melting mechanism 110 includes a hydrogen return path 111, switching valves 113 to 115, and a blower 112.
  • the upstream end of the hydrogen return path 111 is connected to the downstream side of the LH2 vaporizer 14 in the first LH2 path 13A, and the downstream end is branched into a plurality (two in this embodiment).
  • one of the branch paths is connected between the first LH2 switching valve 53 and the first liquefier 30A in the first LH2 path 13A, and the other of the branch paths is the second in the second LH2 path 13B. It is connected between the 2LH2 switching valve 54 and the second liquefier 30B.
  • switching valves 113 and 114 are arranged on the respective branch paths.
  • the blower 112 pumps the hydrogen gas G1 toward the upstream side of the liquefier 30, and is arranged in the hydrogen return path 111. Further, on the upstream side of the blower 112, a switching valve 115 that switches inflow and shut-off of the hydrogen gas G1 to the blower 112 is disposed.
  • the switching valves 113 and 115 are opened and the blower 112 is operated. Accordingly, the hydrogen gas G1 is returned to the upstream side of the first liquefier 30A through the hydrogen return path 111 and flows into the second flow path 92 of the first liquefier 30A.
  • the heat transfer surface of the second flow path 92 is warmed by the heat of the hydrogen gas G1
  • the heat transfer surface of the first flow path 91 is also warmed by heat transfer from the second flow path 92 to the first flow path 91. It is done.
  • the LNG frozen in the first flow path 91 can be thawed.
  • the melting process can be similarly performed by opening the switching valve 114 instead of the switching valve 113.
  • the melting mechanism is not limited to returning the hydrogen gas G1 to the upstream side of the liquefier 30, and may return the natural gas G2 to the upstream side of the liquefier 30. However, it is preferable to return the hydrogen gas G1 in order to avoid trouble when the natural gas G2 is caused to flow through the first flow path 91 closed by freezing.
  • the melting mechanism may be a blower that blows air to the liquefier 30 and melts it by the heat of the air, may be a heater attached to the liquefier 30, or is a pipe that flows seawater. It may be melted by the heat of the seawater.
  • the melting mechanism 110 is provided in the gas supply unit including the plurality of liquefiers 30 in the present embodiment.
  • the melting mechanism 110 may be provided in the gas supply unit including the single liquefier 30. Good.
  • the use of the gas supply unit is not limited to this. That is, the natural gas G2 and the hydrogen gas G1 may be supplied from the gas supply unit to any demand destination other than the mixed combustion power generation unit 40.
  • Embodiments 1 to 4 have described the case where the LH2 pump 12 is disposed upstream of the liquefier 30, but an LH2 pump may be further disposed between the liquefier 30 and the LH2 vaporizer 14.
  • the gas supply unit includes an LNG tank that stores liquefied natural gas, an LNG path through which the liquefied natural gas that has flowed out of the LNG tank flows, and a liquefied natural gas that is disposed in the LNG path and flows in from the LNG path.
  • An LNG vaporizer that vaporizes gas; an LH2 tank that stores liquid hydrogen (also referred to as “LH2”); an LH2 path through which liquid hydrogen that has flowed out of the LH2 tank flows; and an LH2 path that is disposed in the LH2 path.
  • An LH2 vaporizer that vaporizes inflowing liquid hydrogen, a BOG path through which boil-off gas generated by evaporation of liquefied natural gas in at least one of the LNG tank and the LNG path, and the BOG path and the LH2 path Connected to the liquid hydrogen flowing in from the LH2 path and from the BOG path
  • a liquefier that cools and liquefies the boil-off gas by heat exchange with the boil-off gas that enters, and a return path that is connected to the liquefier and returns the boil-off gas liquefied by the liquefier to the LNG tank.
  • the liquefied natural gas flowing out from the LNG tank is vaporized by the LNG vaporizer, and the liquid hydrogen flowing out from the LH2 tank is vaporized by the LH2 vaporizer, and the natural gas and hydrogen gas are supplied to a predetermined demand destination.
  • the LNG boil-off gas is cooled and liquefied in the liquefier, the cold heat of the liquid hydrogen flowing out from the LH2 tank can be used.
  • the boil-off gas of LNG can be liquefied efficiently compared with the case where liquid nitrogen is used as a cold heat source conventionally.
  • the gas supply unit further includes a bypass path connected to the LH2 path so as to bypass the liquefier, and a bypass valve that controls inflow of liquid hydrogen from the LH2 path to the bypass path. Also good.
  • Liquid hydrogen is a cryogenic liquid whose temperature is lower than that of liquid nitrogen and well below the freezing point of methane, which is the main component of natural gas. For this reason, for example, when the flow rate of liquid hydrogen flowing into the liquefier is excessive with respect to the flow rate of the boil-off gas, the boil-off gas is excessively cooled, and as a result, the LNG freezes in the flow path of the liquefier. Sometimes. On the other hand, according to the above configuration, even when the flow rate of liquid hydrogen is excessive with respect to the flow rate of boil-off gas, the amount of liquid hydrogen flowing into the liquefier can be controlled using the bypass path and the bypass valve. Therefore, it is possible to prevent LNG from freezing in the flow path of the liquefier.
  • the liquefier may have a flow path through which boil-off gas flowing from the BOG path flows.
  • the gas supply unit includes a differential pressure detection unit that detects a differential pressure before and after the flow path, an outlet temperature detection unit that detects the temperature of the liquefied natural gas that has flowed out of the flow path, and a liquefaction that detects the temperature of the liquefier.
  • the bypass valve can be automatically controlled based on various detection results for detecting freezing of LNG in the flow path of the liquefier. For this reason, the amount of liquid hydrogen flowing into the liquefier can be easily controlled as compared with the case where the bypass valve is manually controlled.
  • the LH2 path and the BOG path may be branched into a plurality of paths.
  • the plurality of liquefiers may be arranged in parallel in the plurality of paths.
  • the gas supply unit further includes an LH2 switching valve that switches inflow of liquid hydrogen to each of the plurality of liquefiers, and a BOG switching valve that switches inflow of boil-off gas to each of the plurality of liquefiers. May be.
  • the gas supply unit may further include a melting mechanism for melting the liquefied natural gas frozen in the flow path in which the boil-off gas flowing from the BOG path flows in the liquefier.
  • the liquefier can be reused by melting it.
  • the melting mechanism may be configured to return a part of the hydrogen gas vaporized by the LH2 vaporizer to the upstream side of the liquefier in the LH2 path.
  • a part of the hydrogen gas generated by the LH2 vaporizer can be used as a heat source for melting frozen LNG. Therefore, energy can be saved as compared with the case of using another heat source that requires energy.
  • the co-fired power generation apparatus includes the gas supply unit according to the above-described embodiment and a co-fired power generation unit that generates power using natural gas and hydrogen gas supplied from the gas supply unit as fuel.
  • this co-fired power generation apparatus includes the gas supply unit according to the above-described embodiment, the LNG boil-off gas can be efficiently liquefied. For this reason, it is possible to reduce the amount of boil-off gas that is boosted by the compressor and sent to the co-firing power generation unit. Therefore, energy saving can be achieved by reducing the power of the compressor.

Landscapes

  • Engineering & Computer Science (AREA)
  • Mechanical Engineering (AREA)
  • General Engineering & Computer Science (AREA)
  • Filling Or Discharging Of Gas Storage Vessels (AREA)

Abstract

La présente invention concerne une unité d'alimentation en gaz comprenant : un réservoir de GNL pour stocker du gaz naturel liquéfié ; un trajet de GNL à travers lequel s'écoule le gaz naturel liquéfié qui s'est écoulé hors du réservoir de GNL ; un vaporisateur de GNL pour vaporiser un gaz naturel liquéfié qui s'écoule à partir du trajet de GNL ; un réservoir de LH2 pour stocker de l'hydrogène liquide ; un trajet de LH2 à travers lequel s'écoule l'hydrogène liquide qui s'est écoulé hors du réservoir de LH2 ; un vaporisateur de LH2 pour vaporiser de l'hydrogène liquide qui s'écoule depuis le trajet de LH2 ; un trajet de gaz d'évaporation dans lequel s'écoule un gaz d'évaporation généré dans le réservoir de GNL et/ou le trajet de GNL ; un liquéfacteur qui refroidit et liquéfie le gaz d'évaporation en échangeant de la chaleur entre l'hydrogène liquide qui s'écoule à partir du trajet de LH2 et du gaz d'évaporation qui s'écoule à partir du trajet de gaz d'évaporation ; et un trajet raccordé au liquéfacteur pour renvoyer le gaz d'évaporation liquéfié par le liquéfacteur au réservoir de GNL.
PCT/JP2019/020731 2018-06-01 2019-05-24 Unité d'alimentation en gaz et dispositif de génération d'énergie de co-combustion WO2019230603A1 (fr)

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
JP2018106143A JP2019210976A (ja) 2018-06-01 2018-06-01 ガス供給ユニット及び混焼発電装置
JP2018-106143 2018-06-01

Publications (1)

Publication Number Publication Date
WO2019230603A1 true WO2019230603A1 (fr) 2019-12-05

Family

ID=68698161

Family Applications (1)

Application Number Title Priority Date Filing Date
PCT/JP2019/020731 WO2019230603A1 (fr) 2018-06-01 2019-05-24 Unité d'alimentation en gaz et dispositif de génération d'énergie de co-combustion

Country Status (2)

Country Link
JP (1) JP2019210976A (fr)
WO (1) WO2019230603A1 (fr)

Cited By (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
CN114233526A (zh) * 2021-08-11 2022-03-25 哈尔滨工程大学 一种抑制天然气发动机爆震以及失火的氨重整系统及方法
CN114893718A (zh) * 2022-05-27 2022-08-12 正星氢电科技郑州有限公司 液氢、lng合建站系统
CN114893719A (zh) * 2022-05-27 2022-08-12 正星氢电科技郑州有限公司 加氢、加液化天然气合建站的bog气体回收系统及方法

Families Citing this family (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
KR102388256B1 (ko) * 2020-08-25 2022-04-21 한국기계연구원 액체수소 플랜트

Citations (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
JP2010025152A (ja) * 2008-07-15 2010-02-04 Mitsubishi Heavy Ind Ltd 天然ガス処理設備および液化天然ガス運搬船
JP2011182516A (ja) * 2010-02-26 2011-09-15 Tamotsu Minagawa 電力需給平準化システム
JP2014522476A (ja) * 2011-05-30 2014-09-04 バルチラ・オイル・アンド・ガス・システムズ・アーエス Ｌｐｇボイルオフガスを液化するための燃料としてのｌｎｇの使用
JP2016089942A (ja) * 2014-11-04 2016-05-23 株式会社Ihi 低温液化ガス設備
CN105627096A (zh) * 2015-09-11 2016-06-01 荆门宏图特种飞行器制造有限公司 Lng储罐

Patent Citations (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
JP2010025152A (ja) * 2008-07-15 2010-02-04 Mitsubishi Heavy Ind Ltd 天然ガス処理設備および液化天然ガス運搬船
JP2011182516A (ja) * 2010-02-26 2011-09-15 Tamotsu Minagawa 電力需給平準化システム
JP2014522476A (ja) * 2011-05-30 2014-09-04 バルチラ・オイル・アンド・ガス・システムズ・アーエス Ｌｐｇボイルオフガスを液化するための燃料としてのｌｎｇの使用
JP2016089942A (ja) * 2014-11-04 2016-05-23 株式会社Ihi 低温液化ガス設備
CN105627096A (zh) * 2015-09-11 2016-06-01 荆门宏图特种飞行器制造有限公司 Lng储罐

Cited By (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
CN114233526A (zh) * 2021-08-11 2022-03-25 哈尔滨工程大学 一种抑制天然气发动机爆震以及失火的氨重整系统及方法
CN114893718A (zh) * 2022-05-27 2022-08-12 正星氢电科技郑州有限公司 液氢、lng合建站系统
CN114893719A (zh) * 2022-05-27 2022-08-12 正星氢电科技郑州有限公司 加氢、加液化天然气合建站的bog气体回收系统及方法
CN114893719B (zh) * 2022-05-27 2023-11-21 正星氢电科技郑州有限公司 加氢、加液化天然气合建站的bog气体回收系统及方法
CN114893718B (zh) * 2022-05-27 2024-04-19 正星氢电科技郑州有限公司 液氢、lng合建站系统

Also Published As

Publication number Publication date
JP2019210976A (ja) 2019-12-12

Similar Documents

Publication Publication Date Title
WO2019230603A1 (fr) Unité d'alimentation en gaz et dispositif de génération d'énergie de co-combustion
CN109416002B (zh) 船舶
KR101271041B1 (ko) 연료가스 공급장치 및 방법
KR101489738B1 (ko) 선박의 연료가스 공급 시스템
JP5227000B2 (ja) Ｌｎｇ貯蔵タンク
JP5662313B2 (ja) 液化天然ガスの変換
KR100748734B1 (ko) 이중 연료 사용 엔진이 장착된 액화천연가스 운반선의 연료가스 공급 시스템
JP6678077B2 (ja) 船舶
KR20120007641A (ko) Ｌｎｇ의 재기화 시스템
JP5494819B2 (ja) Ｌｎｇ気化設備
KR101883466B1 (ko) 선박의 증발가스 처리 시스템 및 방법
KR102113919B1 (ko) 액화가스 재기화 시스템 및 이를 구비하는 선박
KR101750890B1 (ko) 액화가스 운반선의 증발가스 재액화 장치
KR20230166112A (ko) 선박의 가스 소비 장치용 가스 공급 시스템의 열교환기를 냉각하는 방법
KR20190041859A (ko) Lng연료를 이용한 액화가스 재액화장치 및 이를 가지는 액화가스운반선
JP4625650B2 (ja) 低温液化ガス供給装置
JP7476355B2 (ja) 船舶の液化ガス再気化方法およびそのシステム
KR102276358B1 (ko) 증기 열교환기 운전 시스템 및 방법
KR102433265B1 (ko) 가스 처리 시스템 및 이를 포함하는 해양 부유물
JP2001248797A (ja) Ｌｐｇ貯蔵タンク内に発生するボイルオフガスの再液化装置
KR102433264B1 (ko) 가스 처리 시스템 및 이를 포함하는 해양 부유물
KR101742294B1 (ko) Lng 재기화 플랜트 및 lng 재기화 방법
JP2022186667A (ja) 流体を再液化し消費ユニットへ供給する回路
KR20220067754A (ko) 액화가스 재기화 시스템의 쿨다운 방법
KR20210033375A (ko) 열매 처리 시스템 및 이를 포함하는 선박

Legal Events

Date Code Title Description
121 Ep: the epo has been informed by wipo that ep was designated in this application

Ref document number: 19811414

Country of ref document: EP

Kind code of ref document: A1

NENP Non-entry into the national phase

Ref country code: DE

122 Ep: pct application non-entry in european phase

Ref document number: 19811414

Country of ref document: EP

Kind code of ref document: A1