Patent Application
20240372370
The present invention relates to a green energy transportation system and a green energy transportation method.
With growing concern about global environmental issues, the use of so-called renewable energy is increasing as a substitute for finite fossil fuels such as oil, coal, and liquefied natural gas (hereinafter referred to as LNG) and as a measure to mitigate global warming. The renewable energy is renewed in natural phenomena represented by wind, solar, solar thermal, geothermal, hydraulic power, wave power, biomass, etc., and power generation systems using one or more of these types of energy have been proposed.
For example, Patent Literature 1 discloses a wind power generation system including a wind power generator connected to an electric power system so as to generate wind power, an energy storage device connected to the electric power system so as to charge and discharge the power generated by the wind power generator, and a power generation controller that controls power generation of the wind power generator as well as controls charge and discharge of the energy storage device. In this wind power generation system of Patent Literature 1, the power generation controller includes: a system information acquiring unit that acquires a system information indicating the state of the electric power system; a status information acquiring unit that acquires a power generation status information pertaining to the wind power generator and a storage status information pertaining to the power storage device; an information generating unit that generates a power generation plan information pertaining to a power generation plan and a variation range correlation information correlated to the variation range of the power generation plan; and an information transmitting unit that transmits the power generation plan information and the variation range correlation information generated by the information generating unit to a power provider that operates the power system. Based on the system information acquired by the system information acquisition unit and the power generation status information and storage status information acquired by the status information acquisition unit, a power generation output of the wind power generator and a charging/discharging of the energy storage device are controlled. This enables integrated operation of wind-generated power and the power system, thereby contributing to a stable operation of the power system.
Patent Document 2 discloses a power generation system by a renewable energy that generates electricity by a combination of a first power generation facility consisting of a solar power generation facility and a second power generation facility consisting of a wind power generation facility. Patent Literature 2 describes that the power generation system includes a total output controller that calculates a first output upper limit of the second power generation facility based on an interconnection approval amount and an amount of power generated by the first power generation facility, an upper limit re-setting operator that calculates a second output upper limit of the second power generation facility based on the first output upper limit and a current amount or an amount of change of power generation of the second power generation facility, and a controller that sends the second output upper limit to the second power generation facility and controls the power generation of the second power generation facility upon receiving the second output upper limit. This makes it possible to prevent the output of the power generation system from exceeding the interconnection approval amount and to prevent the amount of power generation of the solar power generation facility and wind power generation facility from significantly falling below the interconnection approval amount.
However, those renewable energy power generation facilities represented by the wind power and the solar power etc. are often installed in polar regions and desert regions, which are generally remote from densely populated urban and suburban energy consumption areas in considerations of natural conditions such as wind conditions, land costs, social impacts, etc. Therefore, there is a need of transportation technologies for a renewable energy to efficiently transport the energy from such remote locations to energy-consuming areas at low cost. In addition, it is important to reduce the emission of carbon dioxide, which is one of the causes of global warming due to the greenhouse effect, during the energy transportation in order to promote the spread of a renewable energy. In light of the above circumstances, it is an object of the present invention to provide a transportation system and a transportation method that can efficiently transport a renewable energy with low environmental impact from its power generation facilities in remote areas to energy consumption areas.
In order to achieve the above object, the present invention is directed to a green energy transportation system including: a power generator that generates and stores electricity from a renewable energy; a hydrogen generator that generates hydrogen by electrolysis of water using the electricity obtained from the power generator; a methane synthesizer that generates methane by a Sabatier reaction using the hydrogen generated by the hydrogen generator and a recycled CO2 as raw materials; a methane transportation system that transports the methane generated in the methane synthesizer to an energy consumption site without emitting CO2 into an atmosphere; a power generation and carbon capture unit that generates electricity by reacting the methane transported by the methane transportation system with oxygen, and recovers carbon discharged during the generation of electricity as recycled CO2; and a CO2 transportation system that transports the recycled CO2 to a methane synthesis site where the methane synthesizer is installed without emitting CO2 into an atmosphere.
The present invention is also directed to a green energy transportation method including: a power generation step that generates and stores electricity from a renewable energy; a hydrogen generation step that generates hydrogen by electrolysis of water using the electricity obtained from the power generation unit; a methane synthesis step that generates methane by a Sabatier reaction using the hydrogen generated by the hydrogen generation step and a recycled CO2 as raw materials; a methane transportation step that transports the methane generated in the methane synthesis step to an energy consumption site without emitting CO2 into an atmosphere; a power generation and carbon capture step that generates electricity by reacting the methane transported by the methane transportation step with oxygen, and recovers carbon discharged during the generation of electricity as recycled CO2; and a CO2 transportation step that transports the recycled CO2 to a site where the methane synthesis step is performed without emitting CO2 into an atmosphere.
According to the present invention, it is possible to efficiently transport a renewable energy to an energy consumption site from its power generation facilities in remote areas with low environmental impact.
Hereinbelow, a first embodiment of the green energy transportation system using a renewable energy as an energy source will be described. As shown in
The methane transportation system M5 transports liquefied methane liquefied by the methane liquefaction unit M4 to the energy consumption site by a liquefied methane tanker driven by a first power unit without CO2 emissions to the atmosphere. The power generation and carbon capture unit M7 has a CO2 liquefaction unit that liquefies the recovered recycled CO2 for transportation in the form of liquid CO2. The methane synthesizer M3 has a liquefied CO2 receiving and regasifying unit that regasifies liquefied CO2 transported by the liquefied CO2 transportation system M8 after receiving it in a liquefied CO2 storage tank. In this case, the CO2 transportation system M8 transports the liquefied CO2 obtained by the CO2 liquefaction unit to the methane synthesis site where the methane synthesizer M3 is installed by using a liquefied CO2 tanker that is driven by a second power unit without CO2 emissions to the atmosphere. The values shown in parentheses in
Of the above series of equipment and systems, the hydrogen generator M2, the methane synthesizer M3, and the methane liquefaction unit M4 are sometimes collectively referred to as the PtG Complex (Power to Gas Complex), and the liquefied methane receiving and regasifying unit M6 and the power generation and carbon capture unit M7 are sometimes collectively referred to as the power generation complex. The energy transportation system of this first embodiment of the present invention can use a number of existing infrastructure facilities such as shipping terminals, LNG tankers, and receiving terminals for LNG which are used in Japan and around the world as fuel for power generation or city gas for household use, and therefore the hurdle to realize this green energy transportation system as an alternative energy source of fossil fuels will not be high. Hereinbelow, each of the devices and systems that constitutes the green energy transportation system will be described in detail.
Unlike energy generated by combustion of fossil fuels such as oil, coal, and natural gas, the power generator M1 handles a renewable energy that can be used repeatedly because it is derived from natural phenomena on the earth. Typical renewable energies include wind power, photovoltaic power generation, solar thermal power generation, geothermal power generation, hydroelectric power generation, biomass power generation, wave/tidal-current/tidal power generation, etc. Electricity generated by these renewable energies can be transmitted through AC power cables which are most commonly used.
A generation method of the wind power uses force of the wind to rotate a wind turbine, and its rotational motion is transmitted to a generator to generate electricity. A generation method of the photovoltaic power uses solar cells composed of semiconductors or dyes that is irradiated with sunlight to directly convert light energy into electricity. A generation method of the solar thermal power uses a reflector that concentrates sunlight, and heat of this concentrated sun light generates a high-temperature steam which rotates a turbine for electric generation. A generation method of the geothermal power uses steam, produced from rainwater that has percolated underground and heated by magma, to rotate a turbine for electric generation. A generation method of the hydroelectric power uses a force of falling water stored in a dam to rotate a turbine for electric generation. A generation method of the biomass power uses biomass fuels for combustion that are made by recycled organic resources derived from plants and animals other than fossil fuels, such as unused wood resources, sewage sludge, and general waste, such that steam generated by a combustion heat is used to rotate turbine for electric generation. Wave power generation, tidal-current power generation, and tidal power generation all use ocean energy for power generation. Wave power generation using wave energy can be broadly classified into the following types. Namely, a first type rotates a turbine by using air currents generated by a vertical movement of the sea surface in an air chamber. A second type uses wave energy that is converted into hydraulic pressure via a movable body so as to generate electricity using a hydraulic motor. A third type uses a drop (height) of a sea water discharged from a water storage pond to the sea level so as to rotate a turbine for electric generation where the water storage pond stores the sea water originated from an overflow of sea waves. A generation method of the tidal-current power uses a kinetic energy of tidal-current to rotate a turbine for electric generation. A generation method of the tidal power uses a difference in tidal level caused by tides to rotate a turbine for electric generation which is similar to a hydropower generation.
The power generator M1 can use any of the above-described renewable energies as an energy source, but in the following description, the power generator M1 using the wind power as the energy source for electric generation will be exemplarily described. The wind power can stably generate electricity throughout the day and night, and therefore it is suitable for using existing LNG infrastructure facilities, unlike solar photovoltaic and solar thermal power generation which cannot generate electricity at night. According to an article by Cristina L. Archer et al. (Journal of Geophysical Research, Vol. 110, D12110, doi: 10.1029/2004JD005462, 2005), the potential for wind power is estimated to have about five times the world's entire energy demand. If all the energy needed by mankind is supplied from renewable energies, the concentration of carbon dioxide in the atmosphere can be returned to pre-industrial levels, which may suppress the progression of global warming and bring back to the cold weather of the pre-industrial era.
When the wind power is used as a renewable energy source, it is preferable to operate it as a single power plant as a whole by installing a plurality of wind turbine generators to take advantage of economies of scale, and this type of operation is sometimes referred to as a wind farm. As shown in
The types of the above-described wind turbine generators can be broadly classified into a fixed-speed wind turbine using cage-type induction generator (SCIG) or a variable-speed wind turbine using a doubly fed induction generator (DFIG) or a permanent magnet synchronous generator (PMSG). Among these, the variable-speed wind generator is preferable because it is connected to the grid using a power converter and thus can control the generator speed independently of the grid frequency, and the PMSG is more preferable because it can be gearless by being multi-polarized.
The wind farm can achieve, for example, an output capacity of 15,000 MW by installing 1,000 units of wind turbine generators (V236-15.0 MW) manufactured by VESTAS as shown in Table 1 below, in a substantially matrix pattern.
There are two types of power transmission from the wind turbine generator to the substation 4 described above, i.e., AC transmission and DC transmission, which are appropriately selected in consideration of the economy. As shown in
In contrast, as shown in
The hydrogen generator M2, located in the subsequent stage of the power generator M1 described above, produces hydrogen by electrolysis of water using the renewable energy obtained by the power generator M1 as an energy source. The hydrogen produced in this way is also referred to as green hydrogen. The apparatus that performs electrolysis of water (also referred to as water electrolysis) can be classified into several types depending on the type of electrolyte, i.e., solid oxide water electrolysis cell apparatus (SOEC), solid polymer water electrolysis apparatus, and alkaline water electrolysis apparatus.
The solid oxide water electrolysis cell apparatus (SOEC) electrolyzes water at a high temperature of about 600 to 1100° C. by the reverse reaction of solid oxide fuel cells (SOFC) which will be described later. As shown in
As shown in
As shown in
The hydrogen generator (water electrolyzer) M2 preferably has a hydrogen storage facility that stores a part of the hydrogen generated by the electrolysis of water, which can supply a fixed amount of hydrogen to the methane synthesizer M3 in the subsequent stage even if the amount of electricity generated by the power generator M1 fluctuates greatly due to wind conditions, which can vary day and night or seasonally. The specific structure of the hydrogen storage facility is not limited, and the facility may have a high-pressure hydrogen tank, which stores compressed hydrogen under high pressure, or the facility may use a hydrogen storage alloy made of alkaline earth alloy, rare earth alloy, titanium alloy, or other alloys. When storing hydrogen in the high-pressure hydrogen tank, it is preferable to use high-tensile steel such as API 5L-X80, special stainless steel, aluminum alloys, polymer composite materials, etc. as materials for the high-pressure hydrogen tank to prevent embrittlement due to high-pressure hydrogen.
The methane synthesizer M3, located in the subsequent stage of the hydrogen generator M2, produces methane by methanization of hydrogen (H2) produced in the hydrogen generator M2 and recycled carbon dioxide (CO2) as raw materials through the Sabatier reaction shown in Reaction Formula 1 below.
CO2+4H2═CH4+2H2O [Reaction Formula 1]
The Sabatier reaction is carried out, for example, under a high temperature and high pressure of about 200 to 700° C. and 3.0 to 7.0 MPaG, in the presence of a catalyst of nickel series or ruthenium series loaded on a support in an amount of 5 to 20% by mass on the support basis, in which the support is made of alumina, magnesia, zirconia, yttrium oxide, ceria, titania, zeolite, or a solid solution containing two or more of these. Accordingly, a plurality of methane synthesis reactors 21 to 24 connected in series, as shown in
As shown in
CO2+H2=CO+H2O [Reaction Formula 2]
The reverse water gas shift reaction can produce carbon monoxide (CO), which is more reactive than CO2, and therefore oxo alcohols or higher hydrocarbons can be produced by the oxo alcohol synthesis reaction or Fischer-Tropsch reaction after extracting a part of the product gas and separating the CO therefrom. Since the Sabatier reaction is exothermic while the reverse water gas shift reaction is endothermic, the reaction heat generated in Sabatier reactors 21 to 24 can be used to heat the feed gas to the reverse water gas shift reactor 20 to increase the thermal efficiency of the entire system.
In the above-described Sabatier reaction, the stoichiometric amount of hydrogen is 4 moles to 1 mole of carbon dioxide gas, but it is not realistic in an actual system to achieve complete (100%) reaction with this stoichiometric amount, and about 2 to 4% of unreacted gas will remain in the product gas. Therefore, if the product gas of the Sabatier reaction is introduced directly into the methane liquefaction unit M4 in the subsequent stage, the carbon dioxide gas will solidify during the cooling process to form dry ice, which will lead to blockage of the liquefaction facility. It is therefore preferable to provide a carbon dioxide gas removal system 30 using amine solution or the like before the methane liquefaction unit M4 like a conventional LNG liquefaction plant. The carbon dioxide gas removed in the carbon dioxide gas removal system 30 can be recycled to the Sabatier reaction along with the hydrogen that is not liquefied in the liquefaction process described below.
Hydrogen, on the other hand, is not liquefied and is recycled to the methane synthesizer M3 as described below. In this instance, as shown in Table 2 below, it is preferable that an excess amount of hydrogen gas is introduced into the reactor in a range of 4.05 to 7.00 moles relative to a stoichiometric amount of 4 moles of hydrogen gas in the Sabatier reaction. This allows the Sabatier reaction to proceed in a direction of methane synthesis, which can reduce the number of the reactors. Since an increase in the amount of hydrogen gas recycled will increase the cost of the methane liquefaction facility, hydrogen recycling compressors, etc., the amount of hydrogen gas recycled is determined in consideration of the cost of methane synthesis.
The methane liquefaction unit M4, which is located at subsequent stage of the methane synthesizer M3, can employ a liquefaction process that is in practical use in LNG plants that liquefies natural gas. Since the critical temperature of methane is −82° C., the liquefaction process employs a cryogenic liquefaction process such as the mixed refrigerant process, cascade process, and expander process, which can liquefy methane by cooling it to −162° C. under atmospheric pressure. In any of the above processes, the methane gas used as feed gas for the methane liquefaction unit M4 contains almost no impurities that can cause corrosion or other problems in the liquefaction facilities unlike the natural gas used as feedstock for LNG plants, and therefore a condensate separation facility and a mercury removal facility can be omitted.
The mixed refrigerant process is a method having a pre-cooling step using propane refrigerant followed by a cooling step using mixed refrigerant consisting of ethane, propane, etc. This process has been used in many projects under license from Air Products and Linde. Specifically, as shown in
Next, the methane pre-cooled with the above-described propane refrigerant is introduced into a main cryogenic heat exchanger 38 such that the methane gas is liquefied by cooling to about −140° C. by a mixed refrigerant sequentially compressed by MR compressors 37a to 37c, and then it is adiabatically expanded (isentropic expansion) by a flash drum 39 (also referred to a stripper), an expander, or Joule-Thomson expansion valve (J-T valve). The main cryogenic heat exchanger 38 has a structure like a Linde's main cryogenic heat exchanger as shown in
In the cascade process, as shown in
In the expander process, as shown in
The flash drums 39, 47, and 55, which play the role of the stripper described above, all flash the liquefied methane liquefied by the methane gas liquefaction facility in the previous stage under a pressure of 0.8 to 2.0 barA and a temperature of −170 to −184° C. The non-liquefied hydrogen generated by the stripper is preferably recycled to the methane synthesizer M3 for reuse as a feedstock after recovering cold heat, for example, in the configuration shown in
As described above, the lower limit of low-load operation of a coil-type heat exchanger using mixed refrigerant is generally about 20% of its design flow rate. Therefore, if it is desired to operate at a load lower than 20% of its design flow rate, it is preferable to adopt the above-described cascade process or expander process without using a coil-type heat exchanger, and the cascade process is more preferable. For example, in the case of the cascade process, the use of a shell-and-tube heat exchanger or a cross-flow plate-fin heat exchanger enables stable operation within the range of 1 to 100% of the design flow rate.
The above-described mixed refrigerant process, cascade process, and expander process all liquefies methane gas by cooling to about −160° C. under atmospheric pressure, but they can liquefy methane gas by cooling it to about −120 to −130° C. under pressurized condition. The pressurized liquefied methane can be produced, for example, by a liquefaction process shown in
The refrigerant introduced into the pressurized heat exchanger 61 can be a single or multi-component substance suitable for refrigeration, such as propane, propylene, ethane, carbon dioxide, etc., and this refrigerant can be cooled by a cooling system 63 consisting of conventional heat exchanger and a refrigerant compressor. A boil-off gas generated from a storage tank, etc. of the pressurized liquefied methane and an exhaust gas discharged from a gas-liquid separation tank provided downstream of the expansion mechanism described above have approximately the same temperature as the pressurized liquefied methane, and therefore these gases can be used as a combustion gas after being heated up by recovery of cryogenic heat in the pressurized heat exchanger 61.
In the first embodiment of the present invention, it is preferable to use a rotary positive displacement type compressor driven by a synchronous motor for the refrigerant compressor in any of these liquefaction processes described above. The synchronous motor has a feature in that the motor rotates in synchronization with a frequency of an AC power source to be used, and by changing the AC frequency with an inverter, it is possible to freely control the number of rotations. A screw-type compressor is preferred for the rotary positive displacement type compressor. The reason for this is that when an output of the wind power generation fluctuates relatively moderate, i.e. from 70 to 100%, an axial flow type or a centrifugal type can be used, but when the fluctuation of this output is large, i.e. from 0 to 100%, use of the axial flow type or the centrifugal type necessitates a recycling operation to avoid surging that may occur in the 0 to 70% range, which wastes the drive power. In order to avoid this waste, it is preferable to use only the screw type, which is a rotary positive displacement type compressor, or to combine the screw type with the axial flow type or the centrifugal type.
The above-described screw type compressor has a structure in which a pair of rotors, each having spiral projections and spiral grooves that intermesh with each other, are enclosed in a casing as shown in
An LNG tanker used for marine transportation of LNG can be used for the liquefied methane transportation system M5 that transports a liquefied methane liquefied by the methane liquefaction unit M4 described above. When the LNG tanker is used, it is necessary to install a liquefied methane storage tank at a shipping terminal of the liquefied methane in order to load the liquefied methane to the LNG tanker. As shown in
The liquefied methane transportation system M5 is driven by a first power unit that does not emit CO2 into the atmosphere. Such a first power unit can be either an engine driven type by combustion of hydrogen or fossil fuel (internal combustion engine), which is accompanied by a facility to recover CO2 in the exhaust gas emitted during the combustion in the case of fossil fuel combustion, or a battery-driven type. The former engine-driven type is classified into several types that includes a steam turbine type that combusts boil-off gas generated by a heat input from a tank, heavy oil, or both of these fossil fuels to generate steam in a boiler and the resulting steam is used to rotate a turbine, a second type that drives a generator by a diesel engine fueled by the above-described boil-off gas or heavy oil, and the resulting electricity is supplied to an electric motor to rotate a propeller, or a third type that directly drive the propeller by a gas-fired diesel engine that combusts a mixture of these boil-off gas and heavy oil. In all of these types, a CO2 recovery facility is required because combustion exhaust gas containing CO2 is discharged during the combustion of fossil fuels. There is no particular limitation regarding the type of CO2 recovery facility, and for example, a method of absorption by a chemical absorption solution in a similar manner to a CO2 recovery facility provided in conjunction with a CCGT power generation as described below can be suitably adopted. The CO2 recovered from the flue gas containing CO2 can be reused as a raw material in the methane synthesizer M3.
On the other hand, a secondary battery that can be repeatedly charged and discharged is used for the latter battery-driven type, and in particular, it is preferable to use a lithium-ion secondary (rechargeable) battery in which charging and discharging is repeated by lithium ions moving between the positive electrode and negative electrode facing each other with a separator between them. The lithium-ion secondary battery can be charged using either electricity from the above-described renewable energy from the power generator M1 or electricity from the power generation and carbon capture unit M7, both of which can propel a cryogenic tanker without generating CO2.
The liquefied methane transported by the liquefied methane transportation system M5 is received by the liquefied methane receiving and regasifying unit M6. As shown in
Specifically, the liquefied methane unloaded from the cryogenic tanker T is received into the liquefied methane tank 73 via the unloading arm 71 and the unloading line 72. The structure of liquefied methane tank 73 is not limited, and its type can be, for example, a ground metal two-shell high-floor type that consists of an inner tank made of 9% Ni steel or aluminum alloy and an outer tank made of common carbon steel, with perlite filled and nitrogen introduced between the inner and outer tanks, a PC outer tank type that uses a pre-stressed concrete (PC) instead of carbon steel for the outer tank of the ground metal two-shell high-floor type, or an underground membrane type that has a cold insulator inside a concrete frame and a stainless steel membrane is stretched over an inner surface of the cold insulator.
The liquefied methane discharged from the above-described liquefied methane tank 73 by the first pump 74 is pressurized by the second pump 75a for high pressure service or the booster pump 75b for low pressure service, and then respectively introduced into the vaporizer 76a for high pressure service or the vaporizer 76b for low pressure service. A part of a boil-off gas generated by the heat input to the liquefied methane tank 73 is pressurized by the return gas blower 77 and introduced into the low-temperature tank of the cryogenic tanker T in order to suppress the pressure drop in the tank of the cryogenic tanker T during unloading of the liquefied methane. The remaining boil-off gas is pressurized to a predetermined pressure by the BOG compressor 78 and then sent to the power generation and carbon capture unit M7 together with the low-temperature methane gas vaporized in the above-described vaporizer 76b. The liquefied methane pressurized by the second pump 75a is partially extracted and used as a refrigerant for the CO2 liquefaction system described below.
LNG vaporizers can be used for the above-described vaporizers, and either one of the following types is adopted that is an open rack type in which the liquefied methane is vaporized by exchanging heat with seawater flowing down the surface of the panels, a submerged type in which heat exchange tubes are provided in a concrete water tank, such that LNG introduced into the heat exchanger tubes is vaporizes by water to which a high-temperature combustion gas generated by a combustion burner is injected for heating, an intermediate heat medium type in which LNG introduced into one side of a shell-and-tube heat exchanger is vaporized by an intermediate medium such as propane evaporated in seawater and introduced into the other side of the heat exchanger, or an air temperature type in which air is used as the heat source. Although any of these types can be adopted, the open rack type shown in
In the power generation and carbon capture unit M7, the above-described methane gas regasified in the liquefied methane receiving and regasifying unit M6 is subject to react with oxygen to generate electricity. In this case, one of the following power generation methods can be used: combined cycle power generation, power generation using solid oxide fuel cells, or power generation using the Allam cycle with an oxygen plant and a carbon dioxide cycle.
Combined cycle power generation (also referred to as GTCC) is a two-type power generation system that combines a gas turbine and a steam turbine, as shown in
An exhaust gas discharged from the waste heat recovery boiler 85 contains CO2 produced by the combustion of the above-described methane gas, which is separated and recovered in the carbon recovery unit (carbon capturer) 87. There are no particular limitations regarding the method of CO2 separation and recovery in the carbon recovery unit 87, and the method can be a chemical absorption method in which CO2 is chemically absorbed using a solvent such as amine, a physical absorption method in which CO2 is absorbed by a physical absorption solution such as methanol under high pressure, a membrane separation method in which CO2 is separated using a membrane through which CO2 is selectively permeated, or a physical adsorption method in which CO2 is adsorbed onto a solid adsorbent such as molecular sieve (synthetic zeolite) and then CO2 is desorbed and recovered by depressurizing or heating the adsorbent.
Among these methods, the chemical absorption method or physical adsorption method is preferred, and the chemical absorption method using amine absorption liquid or the physical adsorption method using molecular sieve is more preferred, and the chemical absorption method using amine absorption liquid is most preferred. The facility to perform the chemical absorption method using amine absorption liquid is shown in
Fuel cells use a technology that generates electricity through a chemical reaction between hydrogen and oxygen, which is the reverse reaction of the electrolysis of water. Typical fuel cells are categorized into four (4) types; a solid oxide fuel cell (SOFC) that uses an oxygen ion conductive solid oxide as an electrolyte, a phosphoric-acid fuel cell (PAFC) that uses a hydrogen conductive aqueous solution of phosphoric acid as an electrolyte, a molten carbonate fuel cell (MCFC) that use a mixture of carbonate ion conductive lithium carbonate and sodium carbonate as an electrolyte, and a solid polymer electrolyte fuel cell (PEFC) that use a hydrogen ion conductive solid polymer membrane as the electrolyte. In the power generation and carbon capture unit M7 of the first embodiment of the present invention, any of the above types of fuel cells can be employed by providing a reformer to generate hydrogen from methane gas in a previous stage, but the solid oxide fuel cell (SOFC), which have the highest power generation efficiency among these, is more preferred.
The solid oxide fuel cell consists of the equipment shown in
The Allam cycle is a supercritical CO2 cycle power generation system. As shown in
The recycled CO2 recovered in the power generation and carbon capture unit M7 is transferred to the CO2 liquefaction unit. As shown in
Liquid CO2 at a temperature of −56 to −33° C., which has been depressurized to a pressure of 5.2 to 12.8 barA by the above-described liquid turbine 123, is stored in the insulated spherical storage tank 124 that can store the liquefied CO2 under these pressure and temperature conditions. The liquefied CO2 stored in this spherical storage tank 124 is loaded onto a liquefied CO2 tanker as a CO2 transportation system and transported to a methane synthesis site, where the liquefied CO2 is regasified and then used in the methane synthesizer M3 as a feedstock for the Sabatier reaction. There is no particular limitation regarding the regasification method of this liquid CO2. For example, it is preferable that seawater or fresh water is used to heat the liquid CO2 having a temperature of −56 to −33° C. to about 0° C., and waste heat from the product gas of the Sabatier reaction is used to heat it from 0° C. to about 200° C.
As mentioned above, the temperature and pressure of the liquefied methane and the liquefied CO2 are both different, so it is preferable to use dedicated cryogenic tankers for transporting these liquefied methane and liquefied CO2, respectively. During this tanker transportation, the liquefied CO2 in tankers reaches pressures of 5.2 to 12.8 barA and temperatures of −56 to −33° C., it is therefore preferable that tank material of cryogenic tankers for liquefied CO2 is low-temperature service steel such as aluminum-killed carbon steel, 1.5% Ni nickel steel, or high-tensile strength nickel steel for low-temperature service. Since liquefied CO2 has a higher liquid density than liquefied methane, it is preferable to use a cryogenic tanker for liquefied CO2 with, for example, four (4) to eight (8) cylindrical tanks that are turned sideways (horizontal shape) as shown in
On the other hand, for cryogenic tankers for liquefied methane, it is preferable to use Moss-type tankers with 3 to 7 spherical tanks, and materials of these spherical tanks should include the following: if the liquefied methane during transportation reaches pressures of −0.05 to 0.25 barG and a temperature of −162° C., preferred materials for these spherical tanks are 6-7.5% Ni steel (JIS, SL7N590), 8.5-9.5% Ni steel (JIS, SL9N590), 18-8 stainless steel, or aluminum alloy 5083, or if the liquefied methane reaches pressures of 8.0-12.8 barA and temperatures of −120 to −130° C., 6-7.5% Ni steel, 8.5-9.5% Ni steel, 18-8 stainless steel, aluminum alloy 5083, or 5% Ni steel is preferred.
If a common cryogenic tanker can be shared for transporting the liquefied methane and the liquefied CO2, instead of using dedicated cryogenic tankers as described above, a significant cost reduction can be achieved because a dedicated tanker for liquefied CO2 will not be needed. In other words, if a cryogenic tanker that loads liquefied methane at the liquefied methane shipping terminal at the PtG complex and transports the liquefied methane to the liquefied methane receiving terminal at the power generation complex can be shared with a cryogenic tanker that loads liquefied CO2 at the liquefied CO2 shipping terminal at the power generation complex and transports the liquefied CO2 from there to the PtG complex for the return journey, transportation costs can be significantly reduced. In this case, the cryogenic tanker with 3 to 7 spherical tanks, or 4 to 8 horizontal cylindrical tanks can also be used, as described above. However, since liquefied methane needs to be transported at lower temperatures than liquefied CO2, the material of these spherical tanks or horizontal cylindrical tanks must be selected to withstand such low-temperature liquefied methane.
Specifically, when a transporting condition of liquefied methane is at a pressure of −0.05 to 0.25 barG and a temperature of −162° C., and a transporting condition of liquefied CO2 is at a pressure of 5.2 to 12.8 barA and a temperature of −56° C. to −33° C., the tank materials of the common cryogenic tanker used for transporting the liquefied methane and the liquefied CO2 should be selected from among 6-7.5% Ni steel, 8.5-9.5% Ni steel, 18-8 stainless steel, and aluminum alloy 5083.
On the other hand, when a transporting condition of pressurized liquefied methane is at a pressure of 8.0 to 12.8 barG and a temperature of −120 to −130° C., and a transporting condition of liquefied CO2 is at a pressure of 5.2 to 10.8 barA and a temperature of −56° C. to −33° C., the tank materials of the common cryogenic tanker used for transporting the pressurized liquefied methane and the liquefied CO2 should be selected from among 6-7.5% Ni steel, 8.5-9.5% Ni steel, 18-8 stainless steel, aluminum alloy 5083, and 5% Ni steel. Transporting the liquefied methane in the pressurized condition would allow the use of 5% Ni steel, which is less expensive than 6-7.5% Ni steel, 8.5-9.5% Ni steel, 18-8 stainless steel, and aluminum alloy 5083.
Next, an energy transportation method using the green energy transportation system of the first embodiment of the present invention described above will be described. The energy transportation method using the energy transportation system of the first embodiment of the present invention includes a power generation step that generates and stores electricity from a renewable energy, a hydrogen generation step that generates hydrogen by electrolysis of water using electricity obtained in the power generation step, a methane synthesis step that generates methane by methanation through a Sabatier reaction using the hydrogen produced in the hydrogen generation step and a recycled CO2 as raw materials, a methane liquefaction step that liquefies methane by using a rotary positive displacement type refrigerant compressor driven by a synchronous motor to which electricity from the renewable energy is supplied as an energy source via a variable speed motor inverter so as to transport the methane produced in the methane synthesis step in the form of liquefied methane, a methane transportation step that transports the methane produced in the methane synthesis step and liquefied in the methane liquefaction step to an energy consumption site without emitting CO2 into the atmosphere, a liquefied methane receiving and regasfying step that regasifies the liquefied methane after received it into a liquid methane storage tank, a power generation and carbon capture step that generates electricity by using the methane, which is transported in the form of liquefied methane by the methane transportation step and then temporarily received and regasified in the liquefied methane receiving and regasifying step, as a feedstock to react with oxygen, and recovers carbon discharged during the generation of electricity in a form of recycled CO2 consisting of highly concentrated CO2 gas, and a CO2 transportation step that transports the recycled CO2 recovered in the power generation and carbon capture step to a site where the methane synthesis step is performed without emitting CO2 into the atmosphere.
The methane transportation step transports liquefied methane liquefied in the methane liquefaction step to the energy consumption site by a liquefied methane tanker driven by the first power unit without CO2 emissions to the atmosphere. The power generation and carbon capture step has a CO2 liquefaction step that liquefies the recycled CO2 so as to transport the recovered recycled CO2 in the form of liquid CO2, and the methane synthesis step has a liquefied CO2 receiving and regasifying step that regasifies the liquefied CO2 transported in the liquefied CO2 transport step after receiving it into the liquefied CO2 storage tank. In this case, the CO2 transportation step transports the liquefied CO2 liquefied in the CO2 liquefaction step to the methane synthesis site where the methane synthesis step is performed by a liquefied CO2 tanker driven by a second power unit without CO2 emissions to the atmosphere. The second power unit that does not emit CO2 into the atmosphere uses, as in the case of the liquefied methane transportation system M5 described above, an engine driven unit by combustion of hydrogen or fossil fuel (internal combustion engine), and in the case of fossil fuel combustion, it is accompanied by a facility to recover CO2 in the exhaust gas discharged during the combustion, or battery-driven unit such as a lithium-ion rechargeable battery.
In the power generation step for generating electricity from renewable energy sources described above, any of the following renewable energy sources may be used as energy sources: wind power, photovoltaic power, solar thermal power, geothermal power, hydroelectric power, biomass power, wave/tidal-current/tidal power, etc., but wind turbine generators are suitably employed. In this case, a storage battery installed beside the above-described wind turbine generator should be set to have a capacity value in the range of 106 to 126% of the wind turbine rating of the wind turbine generator, and the storage battery should be operated in the operational range of 20 to 90% of the wind turbine rating.
In the electrolysis of water in the above-described hydrogen generation step, the minimum electrolysis load, which is the power required for the electrolysis of water, should be preferably set within the range of 5 to 30% of the wind turbine rating. It is preferable to control the system such that if the power generated by the wind turbine generator, whose variable is the wind speed, is less than the minimum electrolysis load, its shortage is made up from the storage battery in which the above storage is performed. Whereas if the power generated by the wind turbine is equal to or above the minimum electrolysis load, the generated power is used for the electrolysis of water, and an excess power of the generated power over the minimum electrolysis load is charged to the storage battery under conditions of below an upper limit set within a range of 5 to 15% of the wind turbine rating and within the operational range of the storage battery. In principle, this control scheme allows the methane liquefaction processing of the methane liquefaction facility to be operated successively without stopping.
Next, as mentioned above, the procedure for loading/unloading the liquefied methane and the liquefied CO2 to/from a common cryogenic tanker for transporting the liquefied methane and the liquefied CO2 will be described based on an exemplary case: the storage conditions for the liquefied methane to be handled are a pressure of −0.05 to 0.25 barG and a temperature of −162° C., and the storage conditions for the liquefied CO2 are a pressure of 5.2 to 12.8 barA and a temperature of −56 to −33° C. As shown in
The liquefied methane in the spherical tank is unloaded by operating the submerged pump while introducing methane gas at a low temperature of, for example, −50° C. as a displacement gas into the tank from the first feed nozzle Ni, and the methane gas is continuously introduced after the unloading is completed to pressurize the tank to, for example, 6.92 barA.
The cold CO2 gas with a pressure of 6.92 barA and a temperature of −50° C., for example, is introduced from a lower section of the tank by the second feed nozzle N2, and methane gas in the tank is vented from the first vent nozzle V1 and the discharge nozzle Li of the submerged pump to replace methane gas with carbon dioxide gas. The density ratio of the methane gas to the CO2 gas at the time of this substitution is 1:2.75.
(S3) Liquefied CO2 Loading with CO2 Gas Venting
The low-temperature liquefied CO2 with a pressure of 6.92 barA and a temperature of −50° C., for example, is introduced from a lower section of the tank by the second feed nozzle N2 for loading, while the CO2 gas in the tank is vented from the first vent nozzle V1 and discharge nozzle Li of the submerged pump to replace CO2 gas with liquid CO2.
The liquefied CO2 in the tank is unloaded by operating the submerged pump while introducing low temperature CO2 gas of −50° C., for example, as a replacement gas into the tank from the first feed nozzle Ni.
The cold methane gas with a pressure of 6.92 barA and a temperature of −50° C., for example, is introduced from an upper section of the tank and the pump column by the first feed nozzle Ni and the discharge nozzle Li of the submerged pump, while the CO2 gas in the tank is vented from the second vent nozzle V2 to replace the CO2 gas with methane gas. The density ratio of the methane gas to the CO2 gas during this substitution is 1:2.75.
The liquefied methane is sprayed from an upper section of the tank by the first feed nozzle Ni to cool the tank to a cryogenic temperature of, for example, −130° C., and then the liquefied methane is introduced from the second feed nozzle N2 while venting methane gas from the first vent nozzle V1 and discharge nozzle Li of the submerged pump so as to perform loading with gradual rising of the liquid level from the bottom.
Next, the procedure for loading/unloading the pressurized liquefied methane and the liquefied CO2 will be described based on an exemplary case where the storage conditions for the pressurized liquefied methane to be handled are a pressure of 8.0 to 12.8 barA and a temperature of −120 to −130° C., and the storage conditions for liquefied CO2 are a pressure of 5.2 to 10.8 barA and a temperature of −56 to −33° C.
The pressurized liquefied methane in the tank is unloaded by operating the submerged pump while introducing methane gas at a low temperature of, for example, −50° C. as a displacement gas into the tank from the first feed nozzle Ni, and the methane gas is continuously introduced after the unloading is completed to pressurize the tank to, for example, 10 barA.
The cold CO2 gas with a pressure of 10 barA and a temperature of −40° C., for example, is introduced from a lower section of the tank by the second feed nozzle N2, and methane gas in the tank is vented through the first vent nozzle V1 and the discharge nozzle Li of the submerged pump to replace the methane gas with carbon dioxide gas. The density ratio of the methane gas to the CO2 gas during this substitution is 1:2.75.
(S3) Liquefied CO2 Loading with CO2 Gas Venting
The low-temperature liquefied CO2 with a pressure of 10 barA and a temperature of −40° C., for example, is introduced from a lower section of the tank by the second feed nozzle N2 for loading, while the CO2 gas in the tank is vented from the first vent nozzle V1 and the discharge nozzle Li of the submerged pump to replace CO2 gas with liquid CO2.
The liquefied CO2 in the tank is unloaded by operating the submerged pump while introducing CO2 gas at a low temperature of −40° C., for example, as a replacement gas into the tank from the first feed nozzle Ni.
The cold methane gas with a pressure of 10 barA and temperature of −40° C., for example, is introduced from an upper section of the tank and the pump column by the first feed nozzle Ni and the discharge nozzle Li of the submerged pump, while the CO2 gas in the tank is vented from the second vent nozzle V2 to replace the CO2 gas with methane gas. The density ratio of the methane gas to the CO2 gas during this substitution is 1:2.75.
The liquefied methane is sprayed from an upper section of the tank by the first feed nozzle Ni to cool the tank to a cryogenic temperature of, for example, −90° C., and then the liquefied methane is introduced from the second feed nozzle N2 while venting methane gas from the first vent nozzle V1 and discharge nozzle Li of the submerged pump so as to perform loading with gradual raising of the liquid level from the bottom.
At the liquefied methane receiving terminal, the above-described operation S1 is sequentially performed one by one to the plurality of tanks filled with liquefied methane, and when operation S1 is completed, operations S2 and S3 are continuously performed in each of the plurality of tanks, which can eventually performs unloading of the liquefied methane and loading of the liquefied CO2 in all tanks.
On the other hand, at the methane synthesis site, the above-described operation S4 is sequentially performed one by one to the plurality of tanks filled with the liquefied CO2, and when operation S4 is completed, operations S5 and S6 are continuously performed in each of the plurality of tanks, which can eventually performs unloading of the liquefied CO2 and loading of the liquefied methane in all tanks. The above unloading/loading operations are the same for pressurized liquefied methane.
The unloading/loading operations will be specifically described based on a case where a cryogenic tanker has four spherical tanks, at the liquefied methane receiving terminal, as shown in
Similarly, at the liquefied methane receiving station, as shown in
It is preferable that an equivalent amount of CO2 emitted into the atmosphere from the entire steps, i.e., from the power generation step to the CO2 transport step described above, is less than 3% of carbon consumed in the entire steps in terms of CO2, and it is more preferable that the equivalent amount of CO2 emitted is less than 1%. In order to offset this preferable equivalent amount of 3% or less of CO2 emission, and more preferable equivalent amount of 1% or less of CO2 emission, it is preferable to use CO2 recovered from the combustion gas of biomass power generation or biomass combustion facilities, or from direct air capture (DAC) as the above-described recycled CO2. This will achieve a zero CO2 emission in the green energy transportation according to the embodiment of the present invention, when these biomass power generation or biomass combustion facilities, or direct air capture is taken into account in the CO2 emissions as a whole.
The energy transportation system of the first embodiment of the present invention described above includes the marine transportation via cryogenic tankers to transport methane and CO2, but this marine transportation is not required when the PtG complex and the power generation complex are located within the same continent, such as within the Eurasian, North American, and South American continents. In these cases, it is preferable to transport methane gas and CO2 gas in the form of high-pressure gases via pipelines instead of transporting them by cryogenic tankers.
For example, on the North American continent, a network of natural gas pipelines extends across the United States as shown in
As shown in
The methane transportation system M15 is a methane gas pipeline that transports methane gas produced by the methane synthesizer M13 from a methane synthesis site to an energy consumption site. In order to maintain the pressure of methane gas flowing inside this methane gas pipeline within the range of about 50 to 125 barA, a methane gas compression system M14 consisting of rotary positive displacement type compressors, each driven by a synchronous motor to which electricity from the renewable energy is supplied as an energy source via an inverter for variable speed motor, are provided at the front end of the methane gas pipeline as the methane transportation system M15 and at one or more relay points located at moderate intervals in the methane gas pipeline. In the subsequent stage of the methane transportation system M15, there is preferably provided a metering machine and a gas composition analyzer to measure the methane gas transported by the methane gas pipeline.
The CO2 transportation system M18 is a CO2 pipeline that transports recycled CO2 collected by the power generation and carbon capture unit M16 from the energy consumption site to the methane synthesis site. As with the methane gas pipeline described above, in order to maintain the pressure of the recycled CO2 flowing inside the CO2 pipeline within the range of about 50 to 125 barA, a CO2 gas compressor M17 consisting of compressors, each driven by a synchronous motor to which electricity from the renewable energy is supplied as an energy source via an inverter for variable speed motors, are installed at the front end of the CO2 pipeline as the CO2 transportation system M18 and at one or more relay points located at moderate intervals in the CO2 pipeline.
The booster compressor for methane gas, which is installed when the pipeline for methane gas is laid over a long distance as described above, is preferably powered by feeding electricity from wind power generation to the VFD for synchronous motors via an extra-high-voltage direct current (HVDC) transmission, but purchased power may also be used to feed electricity to the VFD for synchronous motors. Similarly, the CO2 booster compressor, which is installed when the CO2 pipeline is long, is preferably powered by feeding electricity from wind power generation to the VFD for the synchronous motors via an extra-high-voltage direct current (HVDC) transmission, but purchased power may also be used to feed electricity to the VFD for the synchronous motor.
Next, an energy transportation method using the energy transportation system of the second embodiment of the present invention described above will be described. The energy transportation method using the energy transportation system of the second embodiment of the present invention includes a power generation step that generates and stores electricity from the renewable energy, a hydrogen generation step that generates hydrogen by electrolysis of water using the power (electricity) obtained in the power generation step, a methane synthesis step that generates methane gas by methanation through a Sabatier reaction using the hydrogen generated in the hydrogen generation step and a recycled CO2 as raw materials, a methane transportation step that transports the methane gas produced in the methane synthesis step to an energy consumption site without emitting CO2 into the atmosphere, a power generation and carbon capture step that generates electricity by a reaction of the methane gas as a feedstock transported by the methane transportation step with oxygen and recovers carbon discharged during the generation of electricity in a form of recycled CO2, and a CO2 transportation step that transports the recycled CO2 recovered in the power generation and carbon capture step to the site where the methane synthesis step is performed without emitting CO2 into the atmosphere.
Of the above series of steps, the methane transportation step includes the transportation step of high-pressure methane gas through a methane gas pipeline extended from the methane synthesis site performing the methane synthesis step to the energy consumption site, in which the high-pressure methane gas is obtained by compressing the methane gas in a rotary positive displacement type compressor driven by a synchronous motor to which electricity from the renewable energy is supplied as an energy source via a variable speed motor inverter. The CO2 transportation step also includes the transportation step of high-pressure recycled CO2 through a CO2 pipeline extended from the energy consumption site to the methane synthesis site, in which the high-pressure recycled CO2 is obtained by compressing the recycled CO2 with a rotary positive displacement type compressor driven by a synchronous motor to which electricity from the renewable energy is supplied as an energy source via a variable speed motor inverter.
In the above methane transportation step, the methane gas may be boosted or pressurized in the middle of the methane gas pipeline by using a methane gas booster compressor driven by a synchronous motor to which electricity from the renewable energy is supplied as an energy source via an ultra-high voltage direct current cable, or electricity is supplied from purchased electricity. Similarly, in the CO2 transportation step, the recycled CO2 may be boosted or pressurized in the middle of the CO2 pipeline by using a CO2 booster compressor driven by a synchronous motor to which electricity from the renewable energy is supplied as an energy source via an ultra-high voltage direct current cable, or electricity is supplied from purchased electricity.
A configuration of the power distribution when using, for example, a wind turbine generator as an energy source of a renewable energy is shown in
A green energy transportation system comprising: a power generator that generates and stores electricity from a renewable energy; a hydrogen generator that generates hydrogen by electrolysis of water using the electricity obtained from the power generator; a methane synthesizer that generates methane by a Sabatier reaction using the hydrogen generated by the hydrogen generator and a recycled CO2 as raw materials; a methane transportation system that transports the methane produced in the methane synthesizer to an energy consumption site without emitting CO2 into an atmosphere; a power generation and carbon capture unit that generates electricity by reacting the methane transported by the methane transportation system with oxygen, and recovers carbon discharged during the generation of electricity as recycled CO2; and a CO2 transportation system that transports the recycled CO2 to a methane synthesis site where the methane synthesizer is installed without emitting CO2 into an atmosphere.
The green energy transportation system according to clause 1, wherein the electrolysis by the hydrogen generator is performed by a solid oxide water electrolysis apparatus, a solid polymer water electrolysis apparatus, or an alkaline water electrolysis apparatus.
The green energy transportation system according to clause 1, wherein the hydrogen generator has a hydrogen storage system to store the generated hydrogen.
The green energy transportation system according to clause 1, wherein an excess amount of hydrogen as the raw material is introduced into a reactor of the methane synthesizer in a range of 4.05 to 7.00 moles relative to a stoichiometric amount of 4 moles.
The green energy transportation system according to clause 4, wherein the methane synthesizer has a reverse water gas shift reactor that produces carbon monoxide from the raw materials of the hydrogen and the recycled CO2 immediately before the reactor that performs the Sabatier reaction.
The green energy transportation system according to clause 1, wherein the power generation by the power generation and carbon capture unit is selected from a combined cycle, a solid oxide fuel cell, or an Allam cycle with an oxygen plant and a carbon dioxide cycle.
The green energy transportation system according to clause 1 further comprising: a methane liquefaction unit that liquefies the methane by using a rotary positive displacement type refrigerant compressor driven by a synchronous motor to which electricity from a renewable energy is supplied as an energy source via a variable speed motor inverter so as to transport the methane generated in the methane synthesizer in a form of liquid; a liquefied methane receiving and regasifying unit that regasifies the liquid methane transported by the methane transportation system after receiving it into a liquefied methane storage tank such that the methane transportation system transports the liquefied methane liquefied by the methane liquefaction unit to an energy consumption site by a liquefied methane tanker driven by a first power unit without emitting CO2 to an atmosphere; a CO2 liquefaction unit that liquefies the recycled CO2 recovered in the power generation and carbon capture unit so as to transport the recycled CO2 in a form of liquid; and a liquefied CO2 receiving and regasifying unit that regasifies the liquefied CO2 transported by the CO2 transportation system after received it into a liquefied CO2 storage tank such that the CO2 transportation system transports the liquefied CO2 obtained in the CO2 liquefaction unit to the methane synthesis site where the methane synthesizer is installed by a liquefied CO2 tanker driven by a second power unit without emitting CO2 into a atmosphere
The green energy transportation system according to clause 7, wherein each of the first power unit and the second power unit is either a rechargeable battery or an internal combustion engine fueled by hydrogen or liquefied methane.
The green energy transportation system according to clause 7, wherein the methane liquefaction unit has a stripper that flushes the liquefied methane under a pressure of 0.8 to 2.0 barA and a temperature of −170 to −180° C., and a non-liquefied hydrogen produced by the stripper is recycled to the methane synthesizer and reused as a raw material.
The green energy transportation system according to clause 8, wherein the methane liquefaction unit has a heat exchanger to exchange heat between methane and refrigerant, and the heat exchanger is designed that a flow rate of methane containing the non-liquefied hydrogen is ensured to have at least 20% of a design flow rate.
The green energy transportation system according to clause 6, wherein the CO2 liquefaction unit includes a compressor that compresses the recycled CO2 recovered in the power generation and carbon capture unit to a pressure of 45 to 80 barA and a heat exchanger that cools the recycled CO2 for liquefaction to a temperature of −33 to −56° C. by using a cold heat from regasification of the liquefied methane of a pressure of 10 to 100 barA.
The green energy transportation system according to clause 11, wherein the CO2 liquefaction unit further includes a liquid turbine that recovers power by depressurizing the liquefied CO2, which is liquefied by the heat exchanger, to a pressure of 5.2 to 12.8 barA.
The green energy transportation system according to clause 11, wherein the CO2 liquefaction unit further includes an insulated spherical storage tank that stores the liquefied CO2 at a pressure of 5.2 to 12.8 barA and a temperature of −56 to −33° C.
The green energy transportation system according to clause 1, wherein the methane transportation system includes a methane gas pipeline that transports a methane gas produced by the methane synthesizer to an energy consumption site, and methane gas compressors installed at a front end and a relay point of the methane gas pipeline each consisting of a rotary positive displacement type driven by a synchronous motor to which electricity from the renewable energy is supplied as an energy source via a variable speed motor inverter so as to maintain a pressure of the methane gas flowing inside the methane gas pipeline in a range of 50 to 125 barA, and
A green energy transportation method comprising: a power generation step that generates and stores electricity from a renewable energy; a hydrogen generation step that generates hydrogen by electrolysis of water using electricity obtained in the power generation unit; a methane synthesis step that generates methane by a Sabatier reaction using the hydrogen generated in the hydrogen generation step and a recycled CO2 as raw materials; a methane transportation step that transports the methane produced in the methane synthesis step to an energy consumption site without emitting CO2 into an atmosphere; a power generation and carbon capture step that generates electricity by reacting the methane transported by the methane transportation step with oxygen, and recovers carbon discharged during the generation of electricity in a form of recycled CO2; and a CO2 transportation step that transports the recycled CO2 to a site where the methane synthesis step is performed without emitting CO2 into an atmosphere.
The green energy transportation method according to clause 15, wherein a part of the hydrogen generated by the electrolysis of water is stored such that a fixed amount of hydrogen is supplied as a raw material to the methane synthesis step.
The green energy transportation method according to clause 15, wherein the power generation by the renewable energy is performed by a wind turbine generator equipped with a storage battery, and the storage battery is set to have a capacity value in a range of 106 to 126% of a wind turbine rating of the wind turbine, and the storage battery is operated in an operational range of 20 to 90% of the wind turbine rating.
The green energy transportation method as claimed in clause 17, wherein the electrolysis of water in the hydrogen generation step is set to have a minimum electrolysis load, which is a power required for the electrolysis of water, within a range of 5 to 30% of the wind turbine rating, and if a generated power by the wind turbine, whose variable is the wind speed, is less than the minimum electrolysis load, its shortage is made up from the storage battery, and if the generated power is equal to or above the minimum electrolysis load, the generated power is used for the electrolysis of water, and an excess power of the generated power over the minimum electrolysis load is charged to the storage battery under conditions below an upper limit set within a range of 5 to 15% of the wind turbine rating and within the operational range of the storage battery.
The green energy transportation method according to clause 18 further comprising: a methane liquefaction step that liquefies the methane using a rotary positive displacement type refrigerant compressor driven by a synchronous motor to which electricity from the renewable energy is supplied as an energy source via a variable speed motor inverter; a liquefied methane receiving and regasifying step that regasifies the liquefied methane after receiving it into a liquefied methane storage tank such that the methane transportation step transports the liquefied methane liquefied by the methane liquefaction unit to an energy consumption site by a liquefied methane tanker driven by a first power unit without emitting CO2 to an atmosphere; a CO2 liquefaction step that liquefies the recycled CO2; and a liquefied CO2 receiving and regasifying unit that regasifies the liquefied CO2 transported by the CO2 transportation step after received in a liquefied CO2 storage tank such that the CO2 transportation step transports the liquefied CO2 liquefied in the CO2 liquefaction step to the methane synthesis site where the methane synthesis step is performed by a liquefied CO2 tanker driven by a second power unit without emitting CO2 to an atmosphere
The green energy transportation method according to clause 19, wherein the wind turbine generator is a permanent magnet synchronous generator, and the AC voltage generated by the wind turbine generator is boosted to 30 to 110 kV by a transformer and then converted to a DC power having DC voltage of 10 to 20 kV and DC current of 5.0 to 10.0 kA by an AC-DC converter, and the DC power is fed to an electrolyzer that performs the electrolysis of water via a DC-DC converter consisting of a solid-state transformer to step down to 100 to 150V as well as fed to the synchronous motor that drives the refrigerant compressor.
The green energy transportation method according to clause 19, wherein dedicated cryogenic tankers are respectively used for the liquefied methane transportation and the liquefied CO2 transportation, and when the liquefied CO2 to be transported has a pressure of 5.2 to 12.8 barA and a temperature of −56 to −33° C., the cryogenic tanker for the liquefied CO2 is equipped with 3 to 7 spherical tanks or 4 to 8 horizontal cylindrical tanks, and material of the tanks is aluminum-killed carbon steel, 1.5% Ni nickel steel, or high tensile nickel steel for low temperature service.
The green energy transportation method according to clause 19, wherein the cryogenic tanker for liquefied methane is a Moss type with 3 to 7 spherical tanks, and when the liquefied methane to be transported has a pressures of −0.05 to 0.25 barG and a temperature of −162° C., material of the tanks is 6-7.5% Ni steel, 8.5-9.5% Ni steel, 18-8 stainless steel, or aluminum alloy 5083, and when the liquefied methane has pressures of 8.0 to 12.8 barA and temperatures of −120 to −130° C., material of the tanks is −7.5% Ni steel, 8.5-9.5% Ni steel, 18-8 stainless steel, aluminum alloy 5083, or 5% Ni steel.
The green energy transportation method according to clause 19, wherein the methane transportation step transports a liquefied methane at a pressure of −0.05 to 0.25 barG and a temperature of −162° C., and the CO2 transportation step transports liquefied CO2 at a pressure of 5.2 to 12.8 barA and a temperature of −56 to −33° C., and a common cryogenic tanker with 3 to 7 spherical tanks or 4 to 8 horizontal cylindrical tanks is shared for transportation of the liquefied methane and the liquefied CO2, where material of the tanks is 6-7.5% Ni steel, 8.5-9.5% Ni steel, 18-8 stainless steel, or aluminum alloy 5083.
The green energy transportation method according to clause 19, wherein the methane transportation step transports a pressurized liquefied methane at a pressure of 8.0 to 12.8 barA and a temperature of −120 to −130° C., and the CO2 transportation step transports a liquefied CO2 at a pressure of 5.2 to 10.8 barA and a temperature of −56 to −33° C., and a common cryogenic tanker with 3 to 7 spherical tanks or 4 to 8 horizontal cylindrical tanks is shared for transportation of the pressurized liquefied methane and the liquefied CO2, where material of the tanks is 6-7.5% Ni steel, 8.5-9.5% Ni steel, 18-8 stainless steel, aluminum alloy 5083, or 5% Ni steel.
The green energy transportation method according to clause 24, wherein the pressurized liquefied methane is produced by exchanging heat of a pre-pressurized methane gas with a refrigerant for cooling, followed by flushing to partially depressurize to a pressure of 8.0 to 12.8 barA by using an expansion mechanism.
The green energy transportation method according to clause 23 or 24, wherein each of the tanks on the cryogenic tanker has a first feed nozzle with a discharge outlet at an upper section in the tank, a second feed nozzle with a discharge outlet at a lower section in the tank, a first vent nozzle with a discharge outlet at an upper section of the tank, a second vent nozzle with a discharge outlet at a lower section of the tank, and a discharge nozzle of a column for a submerged pump, and the liquefied methane and the liquefied CO2 are alternately transported by repeating the following operations S1 to S6 using these five nozzles:
The green energy transportation method according to clause 26, wherein the operation S1 is sequentially performed to the tanks filled with the liquefied methane one by one, and when the operation S1 is completed, the operations S2 and S3 are continuously performed in each of the tanks, which eventually performs unloading of the liquefied methane and loading of the liquefied CO2 in all the tanks at a liquefied methane receiving site,
The green energy transportation method according to clause 15, wherein the methane transportation step uses a methane gas pipeline extended from the methane synthesis site where the methane synthesis step is performed to an energy consumption site to transport a high-pressure methane gas obtained by compressing the methane by a rotary positive displacement type compressor driven by a synchronous motor to which electricity from the renewable energy as an energy source is supplied via a variable speed motor inverter, and
The green energy transportation method according to clause 28, wherein the methane transportation step includes a methane gas pressurize step in a middle of the methane gas pipeline which uses a booster compressor for methane gas driven by a synchronous motor to which electricity is supplied from a purchased electricity or from the renewable energy as an energy source via an ultra-high voltage direct current cable, and
The green energy transportation method according to clause 15, wherein an equivalent amount of CO2 emission to an atmosphere is equal to or less than 3% of carbon consumed in the entire steps from the power generation step to the CO2 transportation step.
The green energy transportation method according to clause 30, wherein CO2 recovered from a biomass power generation or a combustion gas of biomass combustion facilities or CO2 recovered from direct air capture is used as the recycled CO2 to offset the 3% or less of the CO2 emissions.
| Number | Date | Country | Kind |
|---|---|---|---|
| 2023-064400 | Apr 2023 | JP | national |
