Integrated system and method for using liquid hydrogen for transportation and power applications

Abstract

A system and a method are disclosed. The system includes a plurality of reversible energy conversion devices, a cryotank configured to store a liquefied fuel comprising hydrogen therein, a liquefier, and a fueling station for hydrogen-based vehicles. The cryotank, the liquefier, the plurality of reversible energy conversion devices, and the fueling station are fluidly connected. Each reversible energy conversion devices is individually controlled and is configured to reversibly convert hydrogen gas into electricity and convert electricity to hydrogen gas. The system also includes at least one interconnect configured to be connected with to a power grid, a data center, or an energy storage.

Description

INTEGRATED SYSTEM AND METHOD FOR USING LIQUID HYDROGEN FORTRANSPORTATION AND POWER APPLICATIONSPRIORITY CLAIM AND CROSS-REFERENCE

[0001] This application claims the benefit of U.S. Provisional Application No. 63 / 555,965, filed February 21, 2024, which application is expressly incorporated by reference herein in its entirety.FIELD OF THE INVENTION

[0002] The disclosure relates to systems and methods for storing, dispensing, and using a liquefied gas generally. More particularly, the disclosed subject matter relates to a system and a method for storing, dispensing, and using liquefied gas such as liquid hydrogen for transportation and power applications.BACKGROUND

[0003] Many motor vehicles are currently powered by internal combustion engines with fossil fuels. Due to limited supply and adverse environmental effects associated with burning petroleum-derived fuels, vehicles are now being developed that are powered by alternative environmentally friendly fuels like hydrogen. Fuel cells can be used to produce electric power for motor vehicles by electrochemically reacting hydrogen fuel with an oxidant such as air. Other hydrogen-powered vehicles can be powered by combustion of hydrogen. Fueling or refueling hydrogen to fuel cell vehicles (FCV) and other hydrogen- powered vehicles presents different challenges from adding petroleum-based fuels like gasoline into a vehicle.

[0004] Hydrogen refueling stations for fuel cell vehicles can store fuel as a gas or a liquid before it is dispensed to vehicles. Liquefied gases or fuels such as liquid hydrogen can be stored in a cryogenic tank, which is thermally insulated from the environment. However, heat leak into a tank causes liquefied gas to vaporize to generate “boil-off’ vapor as the liquid absorbs the heat leak from the environment. Pressure inside the tank increases as the vapor continues to build up in it. Excess vapor must be vented through a relief valve to the environment to keep the tank under the pressure limit, causing loss of some liquefied fuel or gas.

[0005] Tens to hundreds of kilograms of liquid hydrogen (LH2) are vented during the delivery and refill of a customer storage vessel, also known as a cryotank, by an industrial gas company (IGC) delivery tanker, representing a significant financial loss to the customer and negative impact to the environment. Between the IGC refills, the liquid hydrogen storage tank would discharge for intended operation such as filling fuel cell electric vehicles and stay idle between discharge operations, all the while collecting heat due to static heat leak or dynamic heat leak from discharge operations. The cryotank pressure could rise and eventually would require venting to stay within safe pressure limits. Other liquefied gas applications involving liquid helium, liquid natural gas, liquid oxygen, liquid nitrogen, and others generally known as industrial gases face similar challenges, although the economic impact varies depending on the value of the product involved. There is a need to reduce or eliminate such vent losses.

[0006] A system with minimal or zero boil-off is needed. Alternatively, a system to recycle or utilize the boil-off gases is desirable.SUMMARY OF THE INVENTION

[0007] The present disclosure provides a system and a method for storing, dispensing, and using liquefied gas such as liquid hydrogen, for multiple applications, for example, for transportation and power applications.

[0008] In accordance with some embodiments, such a system comprises a plurality of reversible energy conversion devices, a cryotank, and a fueling station.

[0009] Each of the plurality of reversible energy conversion devices is configured to be individually controlled and configured to reversibly convert hydrogen gas into electricity and convert electricity to hydrogen gas.

[0010] The cryotank is configured to store a liquefied fuel therein. The liquefied fuel comprises hydrogen in a liquid phase and a vapor phase.

[0011] The liquefier is configured to receive and convert the hydrogen gas from each of the plurality of reversible energy conversion devices into liquid hydrogen. The liquefier is also configured to feed the liquid hydrogen into the cryotank and receive the vapor phase in the liquefied fuel from the cryotank.

[0012] The fueling station is configured to dispense a portion of the liquefied fuel in a either gaseous or liquid form into a vehicle.

[0013] The system also comprises at least one interconnect, which is configured to be connected to a power grid, a data center, or an electrical energy storage system.

[0014] The cryotank, the liquefier, the plurality of reversible energy conversion devices, and the fueling station are fluidly connected. Each of the liquefier, the cryotank, and the fueling station is configured to supply a portion of the hydrogen gas such as boiloff gas to at least one of the plurality of reversible energy conversion devices.

[0015] In some embodiments, each of the plurality of reversible energy conversion devices is a reversible electrolyzer / fuel cell module. Each module has dual modes including an electrolysis mode and a fuel cell mode.

[0016] The reversible electrolyzer / fuel cell module can be any suitable module. Examples of suitable modules include, but are not limited to, a reversible proton exchange membrane (PEM) fuel cell, a reversible solid oxide cell, a metal hydride hydrogen storage (MHHS) cell coupled with a fuel cell, or any combination thereof.

[0017] In some embodiments, the system further comprises a controller connected electronically with and individually control the cryotank, the liquefier, the plurality of reversible energy conversion devices, the fueling station, and the at least one interconnect.

[0018] The controller is configured to direct or command each of the plurality of reversible energy conversion devices to work in different modes of providing electricity or providing hydrogen gas at the same time.

[0019] In another aspect, the present disclosure provides a method of using the system as described herein. Such a method includes controlling each of the plurality of reversible energy conversion devices to work in a mode of providing electricity or providing hydrogen gas.

[0020] For example, in some embodiments, the method comprises: importing electricity from the power grid; selecting and controlling the plurality of reversible energy conversion devices to use the electricity from the power grid to provide hydrogen gas through electrolysis of water; providing the hydrogen gas to the liquefier; converting the hydrogen gas from each of the plurality of reversible energy conversion devices into liquid hydrogen in the liquefier; and feeding the liquid hydrogen from the liquefier into the cryotank.

[0021] For another example, in some embodiments, the method comprises: importing electricity from the power grid;selecting and controlling a first percentage of the plurality of reversible energy conversion devices to use the electricity from the power grid to provide hydrogen gas through electrolysis of water and provide the hydrogen gas to the liquefier; selecting and controlling a second percentage of the plurality of reversible energy conversion devices to receive and convert hydrogen vapor from the cryotank or the fueling station into electricity, wherein the second percentage is lower than the first percentage; converting the hydrogen gas from the first percentage of the plurality of reversible energy conversion devices into liquid hydrogen in the liquefier; and feeding the liquid hydrogen from the liquefier into the cryotank.

[0022] For another example, in some embodiments, the method comprises: shutting down the liquefier, wherein the plurality of reversible energy conversion devices are controlled to receive and convert the hydrogen vapor from the cryotank or the fueling station into electricity; and supplying the electricity to a power grid, a data center, or an energy storage.

[0023] In accordance with some embodiments, the method described herein comprises controlling each of the plurality of reversible energy conversion devices to work in a mode of providing electricity or providing hydrogen gas based on an input of a price of electricity (p) compared to a first predetermined threshold value (pl) and a second predetermined threshold value (p2), wherein p2 is higher than pl.

[0024] For example, when p < pl (i.e., low electricity price), the method further comprises: importing electricity from the power grid; selecting all the plurality of reversible energy conversion devices to use the electricity from the power grid to provide hydrogen gas through electrolysis of water and provide the hydrogen gas to the liquefier; converting the hydrogen gas from each of the plurality of reversible energy conversion devices into liquid hydrogen in the liquefier; and feeding the liquid hydrogen from the liquefier into the cryotank.

[0025] For another example, when pl < p < p2 (i.e., medium electricity price), the method further comprises: importing electricity from the power grid;selecting a first percentage of the plurality of reversible energy conversion devices to use the electricity from the power grid to provide hydrogen gas through electrolysis of water and provide the hydrogen gas to the liquefier; selecting a second percentage of the plurality of reversible energy conversion devices to receive and convert hydrogen vapor from the cryotank or the fueling station into electricity, wherein the second percentage is lower than the first percentage; converting the hydrogen gas from the first percentage of the plurality of reversible energy conversion devices into liquid hydrogen in the liquefier; and feeding the liquid hydrogen from the liquefier into the cryotank.

[0026] For another example, when p > p2 (i.e., high electricity price), the method further comprises: shutting down the liquefier, wherein the plurality of reversible energy conversion devices are controlled to receive and convert the hydrogen vapor from the cryotank or the fueling station into electricity; and supplying the electricity to a power grid, a data center, or an energy storage.

[0027] The method may further comprise supplying additional hydrogen from an external source to the plurality of reversible energy conversion devices.

[0028] Other features of the system and the methods as described herein.BRIEF DESCRIPTION OF THE DRAWINGS

[0029] The present disclosure is best understood from the following detailed description when read in conjunction with the accompanying drawings. It is emphasized that, according to common practice, the various features of the drawings are not necessarily to scale. On the contrary, the dimensions of the various features are arbitrarily expanded or reduced for clarity. Like reference numerals denote like features throughout specification and drawings.

[0030] FIG. 1 illustrates an exemplary system comprising major components in accordance with some embodiments.

[0031] FIG. 2 illustrates the exemplary system of FIG. 1 in an operation mode under low electricity price in accordance with some embodiments.

[0032] FIG. 3 illustrates the exemplary system of FIG. 1 in an operation mode under medium electricity price in accordance with some embodiments.

[0033] FIG. 4 illustrates the exemplary system of FIG. 1 in an operation mode under high electricity price in accordance with some embodiments.

[0034] FIG. 5 illustrates the exemplary system of FIG. 1 in an operation mode with back-up power in accordance with some embodiments.

[0035] FIG. 6 illustrates the exemplary system of FIG. 5 in an operation mode with back-up power, but limited availability of externally supplied hydrogen, in accordance with some embodiments.DETAILED DESCRIPTION

[0036] This description of the exemplary embodiments is intended to be read in connection with the accompanying drawings, which are to be considered part of the entire written description. In the description, relative terms such as “lower,” “upper,” “horizontal,” “vertical,”, “above,” “below,” “up,” “down,” “top” and “bottom” as well as derivative thereof (e.g., “horizontally,” “downwardly,” “upwardly,” etc.) should be construed to refer to the orientation as then described or as shown in the drawing under discussion. These relative terms are for convenience of description and do not require that the apparatus be constructed or operated in a particular orientation. Terms concerning attachments, coupling and the like, such as “connected” and “interconnected,” refer to a relationship wherein structures are secured or attached to one another either directly or indirectly through intervening structures, as well as both movable or rigid attachments or relationships, unless expressly described otherwise.

[0037] For purposes of the description hereinafter, it is to be understood that the embodiments described below may assume alternative variations and embodiments. It is also to be understood that the specific articles, compositions, and / or processes described herein are exemplary and should not be considered as limiting.

[0038] In the present disclosure the singular forms “a,” “an,” and “the” include the plural reference, and reference to a particular numerical value includes at least that particular value, unless the context clearly indicates otherwise. When values are expressed as approximations, by use of the antecedent “about,” it will be understood that the particular value forms another embodiment. As used herein, “about X” (where X is a numerical value) preferably refers to ±10% of the recited value, inclusive. For example, the phrase “about 8” preferably refers to a value of 7.2 to 8.8, inclusive. Where present, all ranges are inclusive and combinable. For example, when a range of “1 to 5” is recited, the recited range should be construed as including ranges “1 to 4”, “1 to 3”, “1-2”, “1-2 & 4-5”, “1-3 & 5”, “2-5”, andthe like. In addition, when a list of alternatives is positively provided, such listing can be interpreted to mean that any of the alternatives may be excluded, e.g., by a negative limitation in the claims. For example, when a range of “1 to 5” is recited, the recited range may be construed as including situations whereby any of 1, 2, 3, 4, or 5 are negatively excluded; thus, a recitation of “1 to 5” may be construed as “1 and 3-5, but not 2”, or simply “wherein 2 is not included.” It is intended that any component, element, attribute, or step that is positively recited herein may be explicitly excluded in the claims, whether such components, elements, attributes, or steps are listed as alternatives or whether they are recited in isolation.

[0039] The word “tank” or “cryotank” or “vessel” may be used interchangeably.

[0040] In FIGS. 1-6, like items are indicated by like reference numerals, and for brevity, descriptions of the structure, provided above with reference to FIGS. 1-6, are not repeated.

[0041] The methods described herein are described with reference to the exemplary structure described in FIGS. 1-6.

[0042] Liquid hydrogen (LFb) storage together with a liquid pump has proven to be a low-cost hydrogen dispensing option for hydrogen fuel cell electrical vehicles. Compared to the gaseous hydrogen option, liquid storage has a much lower unit cost of storage so that more hydrogen can be stored at the same cost as high-pressure gas. Liquid pumping is up to 10 times more energy efficient than gas compression. Although hydrogen liquefaction is energy intensive, the subsequent savings in transport costs and station dispensing costs along the supply chain outweigh the initial production cost, and liquid hydrogen has become the preferred choice in most of the newly built stations. However, a significant boiloff occurs during the storage of liquid hydrogen. As the storage tank pressure increases, the boiloff vapor has to be vented through a safety relief valve if not used. A system with minimal boiloff is needed. Alternatively, a system to recycle and / or use the boiloff gas is also desirable.

[0043] One of the objectives in the present disclosure is to provide an integrated system with multiple uses, for example, for using liquid hydrogen in transportation and power application.

[0044] Hydrogen is an energy carrier that can be used as a fuel for transportation, energy storage, and backup power generation.

[0045] In transportation, hydrogen can be used to power vehicles with fuel cell drive systems or internal combustion engines that run on hydrogen. Options for storing the fuel onboard include: (1) as a compressed gas at 35 or 70 MPa; (2) as a cryocompressed fluid atcertain pressure; or (3) as liquid hydrogen. The storage pressure for such a cryocompressed fluid is between 450 to 500 bar, and temperature between 50 to 80 K. In all three cases, the storage and delivery of hydrogen in liquid form at the station can offer advantages in vehicle refueling. For compressed gas, the use of LH2 facilitates pressurization and pre-cooling of the gas so as to reduce energy demand of the fueling station equipment, allow for faster refueling, and allow for extended vehicle throughput (back-to-back fueling). For cryocompressed and LH2 onboard storage modes, the use of LH2 simplifies the refueling equipment, and allows rapid vehicle refueling.

[0046] A limitation of the LH2 approach is that liquefaction is a complex process, and industrial liquefaction plants are constructed at large scale (>10 tons per day) for energy efficiency. Hydrogen refueling stations that are smaller than this size will require the construction of a smaller and less efficient liquefier, or the delivery of LH2 to onsite storage tanks. In addition, if the refueling profile (e.g., vehicles per hour) is uneven, the refueling station would experience inefficiencies in performance and H2 losses associated with start-up and cycling of equipment. Additional cycling could also increase maintenance requirements and cost.

[0047] In energy storage applications, H2 can be created using electricity, stored in one or more forms, and used later to create energy in a different form such as electricity, heat or steam. There are multiple options for creating H2 including electrolysis using electricity, or pyrolysis of hydrocarbons using heat. H2 can be converted into electricity using a fuel cell or gas turbine, or heat or steam using a combustion process.

[0048] H2 can be stored as a gas in engineered structures such as tanks or geological structures such as salt caverns. It can also be converted to liquid form in a liquefier, stored in a cryotank, and then converted back to gaseous form when needed for conversion into another form of energy. Liquefaction is energy intensive, and stored LH2 suffers from boil- off due to heat leak into cryotanks which limits the duration H2 can be stored as a liquid without further action to maintain the liquid form.

[0049] Backup energy is a type of energy storage in which an end user maintains a form of stored energy for use when the primary energy source is unavailable. For example, a data center might use battery energy storage or diesel generators to provide electricity in the event of an outage from grid supplied electricity. Backup energy demand can be large but intermittent. For example, a typical data center power demand can be 20 MW, and the backup power demand could last 48 to 72 hours but this demand may not be needed for months or longer. When the data center needs backup power, 15 tpd H2 flow is needed for a total of 30to 45 tonnes. Storing such quantities of hydrogen in gaseous form in pressure vessels is prohibitively expensive, and lower cost storage form such as a salt cavern is geologically limited. This intermittency also makes it challenging for LH2 to be used as a mode of storage, if there are long durations between when backup energy is needed. Long duration results in high boil-off losses. This necessitates refilling of the tank for back-up power uses, due to the non-productive loss of LH2 over time. In addition, the intermittency of the use profile could result in having equipment remain idle for long periods of time and introducing challenges in start-up delays, extra maintenance related to equipment cycling, and poorer economics due to low utilization. A method to refresh the stored LH2 and to minimize boil- off losses is desirable.

[0050] Demand response is another type of energy storage in which an end user uses stored energy to offset demand to the grid. Grids can operate with demand charges which are activated when electricity demand exceeds certain thresholds at various points in time. Such demand charges are imposed by a utility to help maintain stability and operation of the grid. The use of stored energy can allow the net demand for grid electricity to remain below demand charge thresholds, resulting in benefits to both the utility as well as the end user. An example is the use of stored energy to support electric vehicle charging during times when the utility imposes demand charges. This limits the overall demand on the grid, while also improving the performance of local EV charging at the end user. It is challenging to use LH2 in support of demand response applications because of the limitations imposed by boil-off and overall round-trip efficiency. Round-trip efficiency is a term used to indicate how much energy is recovered when energy is stored and then discharged.

[0051] The challenges of storing LH2 over extended periods of time make it difficult to use this approach of using LH2 for energy storage applications. This approach using LH2 as an energy storage medium includes steps: (1). Conversion of electricity into H2 using electrolysis, (2) Liquefaction of H2, and delivery to local storage, (3). Storage as LH2 until electricity is needed, (4). Use of LH2 for power generation, via vaporization and electricity production via: (a), fuel cell, or (b). combustion in a turbine system.

[0052] There have been some efforts to integrate LH2 storage for one application with energy demand from another application. For example, U.S. Patent No. 11,608,938 describes a H2 refueling station wherein LH2 is pressurized using a pump, vaporized in a heat exchanger, and delivered to vehicles for refueling. The heat exchanger provides cooling duty to a facility in need of cooling. While this approach offers advantages through heat integration across an integrated system, it suffers from the limitation that the cooling duty canonly be provided when the refueling operation is in progress and the magnitude and degree of cooling is determine by the refueling operation, rather than the facility in need of cooling duty.

[0053] In one aspect, the present disclosure provides an integrated system for the use of hydrogen in transportation and power applications. In accordance with some embodiments, such a system comprises: a shared liquid hydrogen storage subsystem, a hydrogen refueling station, an array of reversible energy conversion devices, interconnection to a grid, interconnection to demand for backup heat or power, and a controller (or a controller device, or called a central controller). Each device in the array of reversible energy conversion devices is capable of converting hydrogen to electricity and electricity to hydrogen. Suitable examples may include electrolyzer, fuel cell, and a combination thereof. The controller dynamically adjusts the fraction of devices in the array used for each purposes, and the fraction of devices is adjusted over time in response to the demand for long duration energy storage or backup power.

[0054] The shared liquid hydrogen storage system further comprises a hydrogen liquefier and cryotank for storage of liquid hydrogen. The capacity of the hydrogen refueling station is sized such that the annual demand for hydrogen used in the refueling station is at least 50% of the total hydrogen demand used by the system across transportation, energy storage, and backup power. Optionally, the invention includes an electric vehicle charging.

[0055] The present disclosure also provides a method of using liquid hydrogen as an energy carrier for transportation, energy storage and backup power. Such a method comprises providing said system, and operating it in a dynamic manner so that at least 50% of the annual net usage of hydrogen is associated with the transportation application. The fraction of devices in the reversible energy conversion device array used for converting electricity to hydrogen, and hydrogen to electricity is adjusted over time in response to the demand for long duration energy storage or backup power.

[0056] The method also includes the storage of hydrogen as liquid, and a local liquefaction system to convert gaseous hydrogen to liquid hydrogen. The present disclosure may also provide a method of refueling EE vehicles, battery electric vehicles, or combinations thereof.

[0057] The term “dynamic” in “a dynamic manner” for using the system is defined as follows: The daily supply delivery of hydrogen can deviate from the annual average daily supply delivery by up to 100%, and the daily use can deviate from the annual average dailyuse by up to a certain percentage, for example, 250%. The system can accommodate daily mismatches in supply and consumption using the storage capacity of the tank as a buffer.

[0058] The problem to be solved is how to effectively use LH2 as an energy carrier for transportation and energy storage. For transportation applications, there are limits related to scale. Specifically, the optimal size of a liquefier is larger than that of a typical refueling station. For energy storage applications including backup power and demand response, there are limits related to: (1) the boil-off of LH2 over time; (2) energy costs associated with liquefaction; and (3) the utilization, maintenance, and cost of dedicated equipment that might not be used continuously.

[0059] Addressing the primary problem above will help solve the following problems: First, LH2 supply is developed to support use in transportation applications. This includes the design of effective distribution networks for LH2, and also the integration of liquefiers with refueling stations. The aggregation of demand from transportation and secondary applications could bring the total demand into a range where liquefiers (integrated onsite) could be practical.

[0060] Energy storage problems related to the utilization, maintenance, and cost- effective use of equipment associated with the use of hydrogen in backup power and demand response applications.

[0061] Boil-off losses from liquid hydrogen (LH2) energy storage are large over long time periods, resulting in unacceptable round-trip efficiencies and capital costs. This problem makes it impractical to use LH2 for backup power or long-duration energy storage. One of the objectives in the present disclosure is to provide a solution to solve the boil-off problems.

[0062] In one aspect, the present disclosure provides one inventive solution, in which multiple applications for LEE use are coupled together, and a primary application uses a baseline amount of H2 on a daily basis supporting the intermittent uses. In other words, the daily use application creates a base demand which covers LEE storage. The storage tank can be oversized, and the intermittent (secondary and tertiary uses) can “piggyback” off the LEE stored for the primary use.

[0063] Another element is a bank of reversible electrochemical conversion devices that can supplement H2 production via electrolysis when end use demand from secondary and tertiary uses is low, and produce electricity (in fuel cell mode) when secondary and tertiary end use demand is high.

[0064] The present disclosure offers a way to stack multiple applications in one system as described herein. For example, the system can be used to support a truck anddelivery van service at a distribution center, while also supporting other uses such as power applications, which may include data center backup and grid services.

[0065] The present disclosure provides inventive approaches, for example, by stacking the uses, and flexibly operating the system in time, and / or using the storage tank as a buffer to accommodate intermittency. In addition, the reversible electrochemical conversion devices (e.g., electrolyzer / fuel cell) allow the flexible conversion of H2 to power and vice versa in time.

[0066] Most existing efforts to reduce cost or manage boil-off are “brute force” that focus on optimizing hardware (insulation) or reducing capital cost. The system and the method provided in the present disclosure are used to manage this by exploiting the time aspect to share tank space, and conversion equipment to adjust the overall system operation in time to deliver improved performance and economics.

[0067] Reversible uses of reversible electrolyzer / fuel cells components are identified as one way to enable cost effective power-to-gas conversion and vice versa. The combination of these reversible electrolyzer / fuel cells components with liquefaction is inventive, given the energy penalty incurred by the liquefaction process. One skilled in the art would seek to maximize roundtrip efficiency by storing the H2 as gas, rather than in liquid form, where losses are taken from the liquefaction process and boil-off In other words, the combination of reversible electrolyzer / fuel cell systems with H2 storage might be used, but the selection of LH2 storage is considered impractical due to the energetic and economic costs of LH2 in a standalone capacity. However, the invention in the present disclosure recognizes the time value of stacking a favorable end use of LH2 (for transport) to alter this situation and enable overall system efficiency and cost benefit for the integrated system.

[0068] An embodiment is provided to show the configuration and operation of the integrated system comprising: (i) an array of (or a plurality of) reversible electrolyzer / fuel cell modules; (ii) at least one LH2 storage tank; (iii) at least one H2 liquefier; (iv) primary end user in transportation; and (v) secondary end user in power. In some embodiments, the system provided in the present disclosure further comprises one or more controller. A controller is also called a control unit or a central unit.

[0069] An embodiment is provided to show the method of using the LH2 storage tank capacity to time-shift capacity, so production and demand do not have to be instantaneously matched. The ability to adjust the storage level in the tank creates flexibility to support the secondary applications. It also results in more effective capital equipment utilization, which improves economics.

[0070] In the integration systems and the method provided in the present disclosure, LH2 for use in a larger volume application is integrated to support its use in a lower volume application. By integrating the use of the system across multiple applications, the invention creates a larger total volume to address limitations related to scale, and uses the larger volume application to address limitations related to energy efficiency, boil-off losses, maintenance requirements, and costs. The larger and lower volume applications described herein refer to the primary application for transportation and the second applications, respectively. The primary application of transportation uses at least 50% of H2 on an annualized basis. The secondary applications use less than 50% of the total H2 on an annualized basis. This can also be accounted for in terms of LH2 that passes through the storage tank.

[0071] Transportation is the primary use of the system. The high volumes associated with vehicle refueling will determine the sizing, operation, and economics of the liquefier and LH2 storage. The transportation application meets regular significant demand. The transportation application in the present disclosure include, are not limited to, medium duty ground transportation, heavy duty transportation for vehicles, aviation, and off-road vehicle refueling. Examples of heavy-duty ground transportation include, but are not limited to long- haul trucking, drayage, and buses.

[0072] Smaller loads can be intermittent by leveraging transients overlaid on the primary use cycle. These can include backup power, daily peak shifting, or longer duration grid services.

[0073] The system has two exemplary elements that allow it to respond to changing operating requirements, and also improves utilization and economics. The first element is at least one reversible EE-to-power / power-to-EE components (units or devices), where the fraction of devices in each mode is determined by the system operation. The second element is a large capacity LEE storage, wherein the level of the LEE storage offers a second degree of freedom to manage the smaller load application. This element also includes a source of LEE - either delivered LH2 by tanker or other supply, or through an on-site liquefier that produces LH2 and is optionally integrated with the storage tank.

[0074] For the first element, the system has multiple modules, some of which are operating in H2 production and others in power generation.

[0075] In a base operation, when cost of grid power is low, most of the reversible H2- to-power / power-to-EE units are used for electrolysis to provide H2 for the liquefier. Boil-off is recycled back to the liquefier.

[0076] In some embodiments during another base operation, when the cost of grid power is high, some of the reversible H2-to-power / power-to-H2 units are used for power generation to offset expensive grid power. Boil-off is used for power generation.

[0077] For the backup power, the units are used for power generation. Boil-off is used for power generation. Storage level decreases over the duration of the backup power events.

[0078] Sizing of reversible units have to be big enough for backup power use. Arbitraging electricity price is a way to increase utilization so that the backup power does not carry capex (capital expenditure) for neither the LH2 storage nor the power generation units since they are in use for H2 production. Capex is managed by using reversible systems.

[0079] For the second element, the large storage tank is sized to be at least twice the daily average use from the baseline application (transportation in the exemplary case). In practice, the preferred sizing is at least four times the daily load, to provide resilience in the form of buffer supply.

[0080] The storage tank receives supply of LH2. This supply can be delivered by tanker or produced on-site using a liquefier. Typical tanker sizes are up to 4-ton LH2, whereas liquefiers can be sized to deliver as low as 0.1 tpd (ton per day or tonne / day) or up to 30 tpd from an industrial site, or even larger with multiple liquefaction trains (e.g., 60 or 90 tpd).

[0081] During steady operations, the average daily rate of supply matches the average daily total use. However, the element of the invention is that the stored LH2 in the tank can allow short-term mismatches in the daily supply and daily use from their annual averages.

[0082] Referring to FIG. 1, an exemplary system 10 is illustrated in general. Such a system comprises a plurality of reversible energy conversion devices 100, a liquefier 300, a cryotank 400, and a fueling station 500.

[0083] Each of the plurality of reversible energy conversion devices 100 is configured to be individually controlled and configured to reversibly convert hydrogen gas into electricity and convert electricity to hydrogen gas.

[0084] In some embodiments, each of the plurality of reversible energy conversion devices 100 is a reversible electrolyzer / fuel cell module, the electrolyzer / fuel cell module. Each module has dual modes including an electrolysis mode and a fuel cell mode. For example, in the electrolysis mode, water can be electrolyzed to provide hydrogen and oxygen gas. In the fuel cell mode, hydrogen in combination with other chemicals such as oxygen is used to generate electricity.

[0085] The reversible electrolyzer / fuel cell module can be any suitable module. Examples of suitable modules include, but are not limited to, a reversible proton exchange membrane (PEM) fuel cell, a reversible solid oxide cell, a metal hydride hydrogen storage (MHHS) cell coupled with a fuel cell, or any combination thereof.

[0086] In some embodiments, the plurality of reversible energy conversion devices 100 are an array of reversible power-to-EE conversion devices, for example, SOFC (solid oxide fuel cells) / SOEC (solid oxide electrolysis cells) units.

[0087] The cryotank 400 is configured to store a liquefied fuel therein. The liquefied fuel comprises hydrogen in a liquid phase and a vapor phase.

[0088] The liquefier 300 is configured to receive and convert the hydrogen gas from each of the plurality of reversible energy conversion devices into liquid hydrogen. The liquefier 300 is also configured to feed the liquid hydrogen into the cryotank 400 and receive the vapor phase in the liquefied fuel from the cryotank 400.

[0089] The fueling station 500 is configured to dispense a portion of the liquefied fuel in gaseous or liquid form into a vehicle. A hydrogen vehicle refueling station 500 can be an array of stations connected to the LEE storage tank 400. The nominal combined LEE demand for vehicles should be “large” (e.g., 4 to 10+ tpd). Overall, the fueling station 500 has to be big enough such that the cryotank 400 is large enough to support variable load 600.

[0090] The liquefier 300, the cryotank 400, and the fueling station 500 can be part of a liquid hydrogen storage subsystem 800.

[0091] The system 10 also comprises at least one interconnect 11, which is configured to be connected with a power grid, a data center, or an energy storage.

[0092] Referring to FIG. 1, reference number 200 refers to connections to external sources of electricity and hydrogen. These resources are available on demand, but at variable pricing (and optionally, with variable availability). The hydrogen can be delivered and stored nearby, but would be outside the battery limits of the system for this invention. In some embodiments, reference number 200 refers to the power grid.

[0093] As shown in FIG. 1, a local electrical load 600 may include a data center, a distribution center, a commercial or industrial (C&I) site (such as a warehouse and a factory), other local load, or any combination thereof. There is also a need for backup power with significant intermittent load. The need for backup power can be unpredictable. The electrical load can also be for battery electric vehicle charging.

[0094] The liquefier 300, the cryotank 400, the plurality of reversible energy conversion devices 100, and the fueling station 500 are fluidly connected with one another.Each of the liquefier 300, the cryotank 400, and the fueling station 500 is configured to supply a portion of the hydrogen gas such as boiloff gas to at least one of the plurality of reversible energy conversion devices.

[0095] In some embodiments, the cryotank should be sized to be “large” (100 tLH2) relative to the demand from FCV refueling (500).

[0096] In some embodiments, the systems 10 provided in the present disclosure may further comprise one or more control units or a central unit (or called controller) 700.

[0097] The controller 700 is connected electronically with and individually controls the cryotank 400, the liquefier 300, the plurality of reversible energy conversion devices 100, the fueling station 500, and the at least one interconnect 11. The connections can be wireless or through wires. The controller 700 is not shown in FIGS. 2-6 for simplicity, while the system in FIGS. 2-6 also includes one or more controller 700.

[0098] The controller 700 is configured to direct each of the plurality of reversible energy conversion devices 100 to work in different modes of providing electricity or providing hydrogen gas at the same time.

[0099] The controller 700 is used for controlling the steps of the method including selection of the device and the amount of the material flow in each step or going through each component. The control unit(s) may be electronically connected with the related components in the system. The control unit may comprise one or more processors and at least one tangible, non-transitory machine readable medium encoded with one or more programs to be executed by the one or more processors. The control unit is configured to coordinate with each component so as to control the operation for selecting top fill and bottom fills, discharging liquid to refuel fuel cell electric vehicles, monitoring safety, and so on.

[0100] In FIG. 1, the direction in the interconnect 11 represents the flow direction of electricity. The lines with reference number 12 represent the paths and the directions for gaseous hydrogen. The lines with reference number 14 represent the paths for liquid hydrogen. The lines with reference number 18 represent electronic connections between the controller 700 and other components and such dashed lines represent that such connections can be wireless or through wires.

[0101] In another aspect, the present disclosure provides a method of using the system as described herein. Such a method includes controlling each of the plurality of reversible energy conversion devices to work in a mode of providing electricity or providing hydrogen gas. FIGS. 2-6 further illustrate the system and the method.

[0102] In accordance with some embodiments, the method described herein comprises controlling each of the plurality of reversible energy conversion devices to work in a mode of providing electricity or providing hydrogen gas, based on an input of a price of electricity (p) compared to a first predetermined threshold value (pl) and a second predetermined threshold value (p2), wherein p2 is higher than pl.

[0103] The values of pl and p2 can be any suitable numbers. In some embodiments, p2 ($ / kWh) is equal to 1 / 20 x market price of H2 ($ / kg) and pl ($ / kWh) is equal to 1 / 33 x market price of H2 ($ / kg).

[0104] FIG. 2 illustrates the exemplary system of FIG. 1 in an operation mode under certain conditions, for example, under low electricity price, in accordance with some embodiments. This is referred to as the first embodiment, which includes normal operations under low electricity price (Mode 1).

[0105] In this case, grid power 201 is used to power the plurality (i.e. the array) of reversible energy conversion devices 100, which include a plurality of modules 110, 120, and 130. Only three modules are shown for illustration purposes. Since power price is low, all of the units 110, 120, 130 are producing H2 to supply the liquefier 300.

[0106] Boil-off from the LH2 storage tank 400 and the H2 refueling 500 can be recycled to the liquefier. The level 410 of the LH2 in the storage tank 400 increases as the net production of LH2 exceeds the net usage.

[0107] Electricity is imported to the system from the grid 200. The array of reversible Ek-power devices produces H2. H2 is fed to the liquefier, and LEE is stored in a cryotank. The level 410 builds (increases) over time.

[0108] As a general idea for the system in FIGS. 1-6, properly sized 100 and 400 plus adjustment of level 410 are needed to support temporal flexibility (for backup power, long duration energy storage (LDES), and electricity price arbitrage / demand response). Long duration energy storage refers to storing energy for at least eight hours, preferably days or longer.

[0109] In some embodiments, an external hydrogen supply 210 may be included and connected with the liquefier 300. Such external hydrogen supply may include pipeline delivery, local production, or optional local storage. Another option is to include an electrolyzer array powered by external electricity for the external hydrogen supply 210. The external H2 supply could also be liquid hydrogen which can bypass the liquefier 300 and directly enters the LH2 storage tank 400.

[0110] As described herein and referring to FIG. 2, in some embodiments, the method comprises: importing electricity from the power grid; selecting and controlling the plurality of reversible energy conversion devices to use the electricity from the power grid to provide hydrogen gas through electrolysis of water; providing the hydrogen gas to the liquefier; converting the hydrogen gas from each of the plurality of reversible energy conversion devices into liquid hydrogen in the liquefier; and feeding the liquid hydrogen from the liquefier into the cryotank.

[0111] This working mode is implemented when p < pl (i.e., low electricity price). All the plurality of reversible energy conversion devices can be selected to use the electricity from the power grid to provide hydrogen.

[0112] FIG. 3 illustrates the exemplary system of FIG. 1 in an operation mode under certain conditions, for example, under medium electricity price, in accordance with some embodiments. This is referred to as the first embodiment with normal operations under medium electricity price (Mode 2).

[0113] Some of the reversible array units 100 are switched from power-to-Ek, to Fb- to-power 130. The power is used to displace grid power. Some of the boil-off 403 can be used to power the Ek-to-power units 130 that are generating power. Alternately, unit 130 can be turned off. The operating logic will depend on the relative electricity prices and the demand for H2 from fueling.

[0114] Electricity is imported to the system from the grid (200). Most of the array 110, 120 produce H2, but some units 130 consume boil-off to produce power.

[0115] H2 is fed to the liquefier, and LEE is stored in a cryotank.

[0116] The level 410 of the LH2 in the cryotank 400 is steady over time.

[0117] Reliquefy BOG is much easier than GH2 from electrolyzer, so one reversible device 130 maybe turn off in some embodiments.

[0118] As descried above and in FIG. 3, in some embodiments, the method comprises: importing electricity from the power grid;selecting and controlling a first percentage of the plurality of reversible energy conversion devices to use the electricity from the power grid to provide hydrogen gas through electrolysis of water and provide the hydrogen gas to the liquefier; selecting and controlling a second percentage of the plurality of reversible energy conversion devices to receive and convert hydrogen vapor from the cryotank or the fueling station into electricity, wherein the second percentage is lower than the first percentage; converting the hydrogen gas from the first percentage of the plurality of reversible energy conversion devices into liquid hydrogen in the liquefier; and feeding the liquid hydrogen from the liquefier into the cryotank.

[0119] This working mode is implemented when pl < p < p2 (i.e., medium electricity price) in some embodiments.

[0120] FIG. 4 illustrates the exemplary system of FIG. 1 in an operation mode under certain conditions, for example, under high electricity price, in accordance with some embodiments. This is referred to as Mode 3 of the first embodiment.

[0121] Grid electricity demand 203 is reduced by switching more units (or even all) of the reversible array to produce power from H2. The H2 can be supplied from boil-off, with supplementary H2 obtained from external supply 212. In some cases, the level of the cryotank 410 can be drawn down.

[0122] This mode can also be operated as LDES for 4 hr to 1 week energy storage. Longer durations are possible, if the cryotank is large enough.

[0123] Electricity is imported to the system from the grid 200. The array uses boiloff to produce power 112, 122, 132. The liquefier can be turned down to reduce electrical demand 602. The level of storage 401 decreases over time.

[0124] Therefore, in some embodiments, the method comprises: shutting down the liquefier, wherein the plurality of reversible energy conversion devices are controlled to receive and convert the hydrogen vapor from the cryotank or the fueling station into electricity; and supplying the electricity to a power grid, a data center, or an energy storage.

[0125] This mode is implemented when p > p2 (i.e., high electricity price) in some embodiments. The method in this mode may further comprise supplying additional hydrogen from an external source to the plurality of reversible energy conversion devices.

[0126] FIG. 5 illustrates the exemplary system of FIG. 1 in an operation mode with back-up power in accordance with some embodiments. This is referred to as Mode 4 of thefirst embodiment. The system operates similar to Mode 3, but there is a draw-down of the LH2 level 410 in cases where the backup power demand is high.

[0127] In this system, the capex for the LH2 storage tank 400 and power conversion devices 100 are covered by the regular operations, and are effectively “free” to the back-up application to make the economics more amenable.

[0128] Supplemental electricity is generated from the array of conversion devices 100. External or stored EE 210 can be diverted to support power generation. LEE storage level (410) drops. Optionally, the liquefier 300 can be turned down for further power load reduction if electricity price is high.

[0129] In another mode (Mode 6), the system provides hybrid hydrogen vehicle refueling and battery electric vehicle charging.

[0130] The system operates similar to Mode 3, where a portion of the reversible array (100) is used to generate electricity to offset load drawn from the grid to reduce demand charges.

[0131] In the dynamic use of the system, the daily supply delivery of hydrogen can deviate from the annual average daily supply delivery by up to 100%, and the daily use can deviate from the annual average daily use by a certain percentage. The system can accommodate daily mismatches in supply and consumption using the storage capacity of the tank as a buffer.

[0132] The LEE storage tank can hold several-day worth of LEE at average use rate for transportation. For example, a refueling network that delivers 4 tpd of Eb could have a storage tank that holds 40 tonnes of LEb for a 10-day storage capacity (based on average use for transportation). The secondary use could draw down the LH2 level in the tank on a temporary basis. Using the numbers above, a backup power situation that uses 10 tpd could run up to 2.5 days before a full cryotank is drained. In the present disclosure, the secondary use can be accommodated by drawing down the level in the tank in the short term, and then replenishing it later.

[0133] The sizing of the cryotank is based on the transportation use, but it can be oversized to support the secondary applications. In the example above, the normal use average rate of 4 tpd, would increase to 14 tpd (4 for transport and 10 for back power) so the deviation would be 250%.

[0134] In the example, we can convert electricity to Eb at a rate of 90% (36 kWh / kg H2) and convert Eb to electricity at a 90% rate (30 kWh / kg) using a solid oxide system. For aPEM system, the conversion rates would be closer to 60%. Electricity to H2 would be 50 kWh / kg. And Eb to electricity would be at a rate of 20 kWh / kg.

[0135] A typical liquefier is 30 tpd. A refueling station can be sized based on the number of vehicles serviced. A single class 8 truck can take between 50 to 90 kg. Therefore, a station that services 100 trucks a day would dispense 5 to 9 tpd H2.

[0136] FIG. 6 illustrates the exemplary system of FIG. 5 in an operation mode with back-up power, but limited availability of externally supplied hydrogen, in accordance with some embodiments.

[0137] In some embodiments, the cryotank capacity is at least 5 times the average daily use (so a 15 tonne capacity for a 3 tpd station). The example above is for illustration only.

[0138] The present disclosure also provides other embodiments including the working modes described above in combination with other features, for example, Mode 2 in combination with backup power for a data center, Mode 3 in combination with daily peak shaving, and Mode 4 in combination with long-duration energy shifting. Mode 2 may involve intervals on the order of weeks to months in between energy use. Mode 3 might be a variant of Mode 2, where the interval is 4-8 hours rather than weeks to months. Mode 4 would have intervals on the order of days or weeks for energy storage and use.

[0139] In Mode 4, in some embodiments, the liquefier 300 has a capacity of 30 tpd, with sensitivity up to 60 tpd.

[0140] If the LH2 storage level is at 70% base storage, it can increase during slow periods, and can be drawn down for LDES or backup power usage.

[0141] The systems and the method provided in the present disclosure provide many advantages, for example, improvements in the energy efficiency, maintenance requirements, equipment utilization, and economics of using LEE in transportation applications, where the refueling profile is uneven over time (i.e., vehicles arrive non-uniformly during the day). Other benefits include improvements in the energy efficiency, maintenance requirements, equipment utilization, and economics of using LEE in energy storage applications, including backup power and demand response.

[0142] In some embodiments, the larger volume application is transportation, and the lower volume application is energy storage. The typical use profile of the larger volume application, on an average daily use basis, would be determined by the number of vehicles refueled. For example, a truck stop refueling 600 trucks / day would consume roughly 30 tpd of H2, assuming an average fill of 50 kg / truck. The energy content of this volumecorresponds to about 1 GWh (LHV). If the trucks are refueled over a period of 24 hours, this corresponds to an energy delivery rate of 1.25 tH2 (tons of hydrogen) per hour, or 42 MW average load. If the refueling window is smaller (i.e., there are peak hours where truck refueling rates are higher), then the corresponding refueling load would be higher. For example, refueling 600 trucks / d over an 8-hour (rather than 24 hour) window would triple the refueling load for 1 / 3 of the day and reduce it to zero, the other 2 / 3 of the day.

[0143] LH2 for transportation hub as larger volume are estimated as follows:

[0144] A station with the capacity to fuel 100 trucks / day will dispense 5 tpd H2 if the average fill per truck is 50 kg / fill. This corresponds to an average power demand of 7 MW (LHV) if the fueling service is provided evenly over 24 h. If the fueling is performed in an 8- hour fueling window, the average power demand increases to 20 MW.

[0145] A station with the capacity to fuel 600 trucks / day will dispense 30 tpd H2 if the average fill per truck is 50 kg / fill. This corresponds to an average power demand of 41 MW (LHV), if the fueling service is provided evenly over 24 h. If the fueling is performed in an 8- hour fueling window, the average power demand increases to 124 MW).

[0146] A station with the capacity to fuel 1200 trucks / d will dispense 60 tpd H2 if the average fill per truck is 50 kg / fill . This corresponds to an average power demand of 82 MW (LHV) if the fueling service is provided evenly over 24 h. If the fueling is performed in an 8- hour fueling window, the average power demand increases to 248 MW.

[0147] The smaller volume loads can be backup power for an industrial facility or supplemental power to reduce net power demand from the grid for electric vehicle charging. The magnitude of these loads (and the corresponding use of hydrogen) is estimated as follows:

[0148] A data center operating with a power demand of 20 MW would require the equivalent of 24 tpd of H2, if the power were generated with fuel cell systems producing 20 kWh / kg. Backup power using fuel cells and stored hydrogen for 48 continuous hours would require 48 tonnes of H2. A data center operating with a power demand of 100 MW would require the equivalent of 120 tpd of H2, if the power were generated with fuel cell systems producing 20 kWh / kg. Backup power using fuel cells and stored hydrogen for 48 continuous hours would require 240 tonnes of H2.

[0149] An electric vehicle charging facility with twenty 1 MW chargers operating for 10 hours each day would require 10 tpd of H2, if the power were generated with fuel cell systems producing 20 kWh / kg.

[0150] The system and the method may be applicable to different sizes of LH2 storage tank. The system with a large-scale storage of LH2 is feasible. For example, NASA has two spheres that can hold 225 tonnes and 330 tonnes of LH2, respectively, which are used for rocket launches, rather than commercial applications requiring daily filling and use of the LH2 in the sphere. But a large tank having such a large capacity can be also used in the system described herein. In some embodiments, the storage tank has a capacity of 200 to 300 tonnes (20-25 m od). Integrated refrigeration and storage (IRaS) can be also included.

[0151] The system described herein balances the relative use of H2 across applications to enable overall system benefits in terms of shared storage leading to improved roundtrip efficiency and flexible operation. There are also significant economic benefits from the invention. At least two elements described herein offer the benefits. Specifically, the reversible power-to-H2 conversion sub-system allows matching of the energy flows within the system in a way that can be dynamically adjusted based on the needs from transportation and energy storage. The reversibility offers operational flexibility as well as favorable economics. Use of LH2 as a storage medium is not expected because the round-trip efficiency of liquefaction is lower than gaseous storage. In the system described herein, the transportation application is used as the base case to cover the storage. Reversible electrochemical conversion devices are used for secondary applications in some embodiments.

[0152] The primary use is for transportation such as a truck depot, and central hub in a network that delivers LH2 to secondary fueling stations. The types of secondary end users in power such as backup power for data centers, peak shaving and other grid services. The primary application should use at least 50% of annual average daily load. This gives the ability to support the secondary use demand with a tank that is “oversized” relative to a tank for just the primary application.

[0153] In the method described herein, the storage tank level can be used to manage mismatches in time of supply and demand. The storage levels in the tank are adjusted to different applications.

[0154] The following examples are described for illustration.

[0155] Examples 1-3, corresponding to Mode 1-3 as described herein, respectively, show flexible operation of the exemplary systems in response to electricity prices. The related numerical values are selected for illustration and may be subject to change. In Example 1 corresponding to Mode 1 in case of low electricity prices, the cost of hydrogen on a per kilogram basis is more than 30 times the cost of electricity on a per kWh basis, that is,the cost of hydrogen $ / kg H2 > 30 x $ / kWh electricity. In Example 2 corresponding to Mode 2 in case of moderate electricity prices, the cost of hydrogen on a per kilogram basis is between 20 and 30 times the cost of electricity on a per kWh basis, that is, 20 x $ / kWh electricity < $ / kg H2 < 30 x $ / kWh electricity. In Example 3, corresponding to Mode 3 in case of high electricity prices, the cost of hydrogen on a per kilogram basis is less than 20 times the cost of electricity on a per kWh basis, that is, $ / kg H2 < 20 x $ / kWh electricity. The criterion for selecting between the modes is based on the conversion of hydrogen into electricity at a 20 to 30 kWh / kg using fuel cell modules.

[0156] Examples 4-5, corresponding to Mode 4 and Mode 5 as described above, respectively, show the operation with backup power. In Example 4 corresponding to Mode 4, no grid power is used and external hydrogen supply is available. In Example 5 corresponding to Mode 5, no grid power is used and no external H2 supply is available.

[0157] Example 1 corresponds to Mode 1 in case of low electricity prices. For example, the cost of hydrogen on a per kilogram basis is more than 30 times the cost of electricity on a per kWh basis, that is, the cost of hydrogen $ / kg H2 > 30 x $ / kWh electricity.

[0158] Referring to FIG. 2, Example 1 shows an integrated system serving a fuel cell truck depot 500 and local electrical loads 600 totaling 15 MW. These local electrical loads can come from data center operations, distribution center operating loads, commercial facility electrical loads, supplemental power for EV charging or a combination thereof. In this Example, the system is operating in Mode 1 where electricity prices from the grid connection 200 are low and corresponds to FIG. 2.

[0159] The array of reversible H2-to-power devices 100 comprises three 7MW SOEF / SOFC (solid oxide electrolysis cells / solid oxide fuel cells) modules with a total capacity of 21 MW. The grid connection 200 has a capacity of 15 MW. The liquifier 300 has a production capacity of 10 tonnes per day. The cryotank 400 has a capacity of 100 tonnes LH2.

[0160] The fueling station network 500 has a daily demand of 10 tonnes per day, with a boil-off loss rate of 23%. The boiloff rate 502 is 3 tonnes of H2.

[0161] Electricity is imported to the system from grid connection 200. The array of reversible Ek-to-power devices 100 is generating H2. All three units are in H2 production mode. The product H2 is fed to the liquefier 300 via lines 111, 121 and 131, and the LEE product 301 from the liquefier 300 is stored in a cryotank 400. The level of the cryotank 410 increases over time. Boiloff from the cryotank 402 and refueling station 502 are returned to the liquefier 400. Given the low cost of power and its impacts on the system to generatehydrogen, the flow of H2 from external supply 211 is zero. Mode 1 is operated when the cost of hydrogen on a kg basis is more than 30 times the cost of electricity on a $ / kWh basis.

[0162] Table 1 shows the magnitude of power and the flows of the gaseous hydrogen and the liquid hydrogen by the component numbers shown in FIG. 2.

[0163] Table 1.

[0164] Example 2 corresponds to Mode 2, which is normal operation under moderate electricity prices. For example, the cost of hydrogen on a per kilogram basis is between 20 and 30 times the cost of electricity on a per kWh basis, that is, 20 x $ / kWh electricity < $ / kg H2 < 30 x $ / kWh electricity.

[0165] Referring to FIG. 3, Example 2 shows an integrated system serving a fuel cell truck depot 500 and local electrical loads 600 totaling 15 MW. These local electrical loads can come from data center operations, distribution center operating loads, commercial facility electrical loads, supplemental power for EV charging or a combination thereof. In this Example, the system is operating in Mode 2 where electricity prices from the grid connection 200 are moderate and corresponds to FIG. 3.

[0166] The array of reversible H2-to-power devices 100 comprises three 7MW SOEF / SOFC modules with a total capacity of 21 MW. The grid connection 200 has a capacity of 15 MW, but the average draw is 14.2 MW. The liquifier 300 has a production capacity of 10 tonnes per day. The cryotank 400 has a capacity of 100 tonnes LH2. The fueling station network 500 has a daily demand of 10 tonnes per day, with a boil-off loss rate of 23%. The boiloff rate 502 is 3 tonnes of H2.

[0167] Electricity is imported to the system from grid connection 200. The array of reversible H2-to-power devices 100 is generating H2. Units 110 and 120 are in H2production mode, while unit 130 is consuming gaseous H2 403 and producing electricity 132. The product H2 is fed to the liquefier 300 via lines 111 and 121, and the LH2 product 301 from the liquefier 300 is stored in a cryotank 400. The level of the cryotank 410 increases over time. Boiloff from the cryotank 402 and refueling station 502 are returned to the liquefier 400. Given the moderate cost of power and its impacts on the system to generate hydrogen, the flow of H2 from external supply 211 is now positive. The example shows a flow of 5.2 tpd. Mode 2 is operated when the cost of hydrogen on a kg basis is between about 20 to 30 times the cost of electricity on a $ / kWh basis.

[0168] Table 2 shows the magnitude of power and the flows of the gaseous hydrogen and the liquid hydrogen by the component numbers shown in FIG. 3.

[0169] Table 2.* Unit 130 is gas to power; ** Extra H2 is drawn from the LH2 cryotank.

[0170] Example 3 corresponds to Mode 3, which is normal operation under high electricity prices. For example, the cost of hydrogen on a per kilogram basis is less than 20 times the cost of electricity on a per kWh basis, that is, $ / kg Ek < 20 x $ / kWh electricity.

[0171] Referring to FIG. 4, Example 3 shows an integrated system serving a fuel cell truck depot 500 and local electrical loads 600 totaling 15 MW. These local electrical loads can come from data center operations, distribution center operating loads, commercial facility electrical loads, supplemental power for EV charging or a combination thereof. In this Example, the system is operating in Mode 3 where electricity prices from the grid connection 200 are high and corresponds to FIG. 4.

[0172] The array of reversible H2-to-power devices 100 comprises three 7MW SOEF / SOFC modules with a total capacity of 21 MW. The grid connection 200 has a capacity of 15 MW, but the average draw is 3.2 MW. The liquifier 300 has a productioncapacity of 10 tonnes per day. The cryotank 400 has a capacity of 100 tonnes LH2. The fueling station network 500 has a daily demand of 10 tonnes per day, with a boil-off loss rate of 23%. The boiloff rate 502 is 3 tonnes of H2.

[0173] Electricity is imported to the system from grid connection 200, but the magnitude is significantly reduced relative to Examples 1 and 2 (given the higher pricing). The array of reversible H2-to-power devices 100 is generating electricity. All three units are consuming gaseous hydrogen 403 and 404 to generate electricity 112, 122, and 132. The increased generation of power by the system reduces the net power imported 204 from the grid 200. The liquefier 400 is operated a reduced capacity with hydrogen from external supply 211 and boil-off 402 from the cryotank 400 and refueling operations 502. The LH2 product 301 from the liquefier 300 is stored in a cryotank 400. The level of the cryotank 410 decreases over time. Boiloff from the cryotank 402 and refueling station 502 are returned to the liquefier 400. Given the high cost of power, the flow of H2 from external supply 211 is 7.5 tpd. Mode 3 is operated when the cost of hydrogen on a kg basis is less than about 20 times the cost of electricity on a $ / kWh basis.

[0174] Table 3 shows the magnitude of power and the flows of the gaseous hydrogen and the liquid hydrogen by the component numbers shown in FIG. 4.

[0175] Table 3.* Power demand 204 is reduced.

[0176] Example 4 corresponds to Mode 4 as described above, showing operation with backup power. No grid power is used and external hydrogen supply is available.

[0177] Referring to FIG. 5, Example 4 shows an integrated system serving a fuel cell truck depot 500 and providing local electrical loads 600 totaling 15 MW. These localelectrical loads can come from data center backup. In this Example, the system operates in Mode 4 where no grid electricity is available, but external hydrogen supply 211 and 212 is available. The example operation is shown in FIG. 5.

[0178] The array of reversible H2-to-power devices 100 comprises three 7MW SOEF / SOFC modules with a total capacity of 21 MW. The grid connection 200 is not supplying power to the system. The liquifier 300 has a production capacity of 10 tonnes per day. The cryotank 400 has a capacity of 100 tonnes LH2. The fueling station network 500 has a daily demand of 10 tonnes per day, with a boil-off loss rate of 23%. The boiloff rate 502 is 3 tonnes of H2. The array of reversible H2-to-power devices 100 is generating electricity. All three units are consuming gaseous hydrogen 403 and 404 to generate electricity 112, 122, and 132. Array 100 is generating the electricity to power the liquefier 602 and data center 603.

[0179] The liquefier 400 is operated with hydrogen from external supply 211 and boil-off 402 from the cryotank 400 and refueling operations 502. The LH2 product 301 from the liquefier 300 is stored in a cryotank 400. The level of the cryotank 410 decreases over time. Boiloff from the cryotank 402 and refueling station 502 are returned to the liquefier 400. Given the unavailabilty of grid power 200, the flow of H2 from external supply 211 is 10 tpd. Mode 4 is operated when grid power is unavailable and external hydrogen supply is available.

[0180] Table 4 shows the magnitude of power and the flows of the gaseous hydrogen and the liquid hydrogen by the component numbers shown in FIG. 5.

[0181] Table 4.

[0182] Example 5 corresponds to Mode 5 as described above, showing operation with backup power. No grid power is used and no external EE supply is available.

[0183] The liquefier can be turned down to reduce power load 602. In this case, the level 410 of LH2 in cryotank 400 would drop during operation in Mode 5.

[0184] Referring to FIG. 6, Example 5 shows an integrated system serving a fuel cell truck depot 500 and providing local electrical loads 600 totaling 15 MW. These local electrical loads can come from data center backup. In this Example, the system is operating in Mode 5 where no grid electricity is available, and no external hydrogen supply is available. The example operation is shown in FIG. 6.

[0185] The array of reversible H2-to-power devices 100 comprises three 7MW SOEF / SOFC modules with a total capacity of 21 MW. The grid connection 200 is not supplying power to the system. The liquifier 300 has a production capacity of 10 tonnes per day, but is only operated at 2.5 tonnes per day in this mode. Complete shutdown of the liquefier is undesirable for short-term system backup operations because of the difficulties of full-shutdown and restart. The operation of the liquefier at reduced capacity reduces the liquefaction power requirement 602 relative to Mode 4 illustrated in Example 4.

[0186] The cryotank 400 has a capacity of 100 tonnes LH2. The fueling station network 500 has a daily demand of 10 tonnes per day, with a boil-off loss rate of 23%. The boiloff rate 502 is 3 tonnes of H2. The array of reversible H2-to-power devices 100 is generating electricity. All three units are consuming gaseous hydrogen 403 and 404 to generate electricity 112, 122, and 132. Array 100 is generating the electricity to power the liquefier 602 and data center 603.

[0187] The liquefier 400 is operated with boil-off 402 from the cryotank 400 and refueling operations 502. The LH2 product 301 from the liquefier 300 is stored in a cryotank 400. The level of the cryotank 410 decreases over time as additional H2 is removed via 402 to close the mass balance to support operation of array 100. Boiloff from the refueling station 502 is returned to the liquefier 400. Mode 5 is operated when grid power is unavailable and external hydrogen supply is unavailable.

[0188] Table 5 shows the magnitude of power and the flows of the gaseous hydrogen and the liquid hydrogen by the component numbers shown in FIG. 6.

[0189] Table 5.

[0190] The methods and system described herein may be at least partially embodied in the form of computer-implemented processes and apparatus for practicing those processes. The disclosed methods may also be at least partially embodied in the form of tangible, nontransient machine-readable storage media encoded with computer program code. The media may include, for example, RAMs, ROMs, CD-ROMs, DVD-ROMs, BD-ROMs, hard disk drives, flash memories, or any other non-transient machine-readable storage medium, or any combination of these mediums, wherein, when the computer program code is loaded into and executed by a computer, the computer becomes an apparatus for practicing the method. The methods may also be at least partially embodied in the form of a computer into which computer program code is loaded and / or executed, such that the computer becomes an apparatus for practicing the methods. When implemented on a general-purpose processor, the computer program code segments configure the processor to create specific logic circuits. The methods may alternatively be at least partially embodied in a digital signal processor formed of application specific integrated circuits for performing the methods. The methods may partially or fully be performed through cloud operations as well.

[0191] Although the subject matter has been described in terms of exemplary embodiments, it is not limited thereto. Rather, the appended claims should be construed broadly, to include other variants and embodiments, which may be made by those skilled in the art.

Claims

What is claimed is:

1. A system, comprising a plurality of reversible energy conversion devices, where each of the plurality of reversible energy conversion devices is configured to be individually controlled and configured to reversibly convert hydrogen gas into electricity and convert electricity to hydrogen gas; a cryotank configured to store a liquefied fuel therein, the liquefied fuel comprising hydrogen in a liquid phase and a vapor phase; a liquefier configured to reversibly receive and convert the hydrogen gas from each of the plurality of reversible energy conversion devices into liquid hydrogen, and configured to feed the liquid hydrogen into the cryotank and receive the vapor phase in the liquefied fuel from the cryotank; a fueling station configured to dispense a portion of the liquefied fuel in a form of gaseous fuel, a subcooled liquid or a cryocompressed fuel into a vehicle; and at least one interconnect configured to be connected with to a power grid, a data center, or an energy storage, wherein the cryotank, the liquefier, the plurality of reversible energy conversion devices, and the fueling station are fluidly connected, and each of the liquefier, the cryotank, and the fueling station is configured to supply a portion of the hydrogen gas to at least one of the plurality of reversible energy conversion devices.

2. The system of claim 1, wherein each of the plurality of reversible energy conversion devices is a reversible electrolyzer / fuel cell module, the electrolyzer / fuel cell module having duel modes including an electrolysis mode and a fuel cell mode.

3. The system of claim 2, wherein the reversible electrolyzer / fuel cell module comprises a cell selected from the group consisting of a reversible proton exchange membrane (PEM) fuel cell, a reversible solid oxide cell, a metal hydride hydrogen storage (MHHS) cell coupled with a fuel cell, and any combination thereof.

4. The system of claim 1, wherein the cryotank has a size configured to support both transportation uses as a primary application and a secondary application related to power, wherein the primary application is more than 50% of the primary and the secondary applications.

5. The system of claim 1, further comprising a controller connected electronically with and individually control the cryotank, the liquefier, the plurality of reversible energy conversion devices, the fueling station, and the at least one interconnect.

6. The system of claim 1, wherein the controller is configured to direct each of the plurality of reversible energy conversion devices to work in different modes of providing electricity or providing hydrogen gas at the same time.

7. A method of using the system of claim 1, comprising controlling each of the plurality of reversible energy conversion devices to work in a mode of providing electricity or providing hydrogen gas.

8. The method of claim 7, further comprising: importing electricity from the power grid, wherein the plurality of reversible energy conversion devices are selected and controlled to use the electricity from the power grid to provide hydrogen gas through electrolysis of water; providing the hydrogen gas to the liquefier; converting the hydrogen gas from each of the plurality of reversible energy conversion devices into liquid hydrogen in the liquefier; and feeding the liquid hydrogen from the liquefier into the cryotank.

9. The method of claim 7, further comprising: importing electricity from the power grid; selecting a first percentage of the plurality of reversible energy conversion devices to use the electricity from the power grid to provide hydrogen gas through electrolysis of water and provide the hydrogen gas to the liquefier; selecting a second percentage of the plurality of reversible energy conversion devices to receive and convert hydrogen vapor from the cryotank or the fueling station into electricity, wherein the second percentage is lower than the first percentage;converting the hydrogen gas from the first percentage of the plurality of reversible energy conversion devices into liquid hydrogen in the liquefier; and feeding the liquid hydrogen from the liquefier into the cryotank.

10. The method of claim 7, further comprising: shutting down the liquefier, wherein the plurality of reversible energy conversion devices are controlled to receive and convert the hydrogen vapor from the cryotank or the fueling station into electricity; and supplying the electricity to a power grid, a data center, or an energy storage.

11. A method of using the system of claim 1, comprising controlling each of the plurality of reversible energy conversion devices to work in a mode of providing electricity or providing hydrogen gas based on an input of a price of electricity (p) compared to a first predetermined threshold value (pl) and a second predetermined threshold value (p2), wherein p2 is higher than pl.

12. The method of claim 11, wherein when p < pl, the method further comprising: importing electricity from the power grid; selecting all the plurality of reversible energy conversion devices to use the electricity from the power grid to provide hydrogen gas through electrolysis of water and provide the hydrogen gas to the liquefier; converting the hydrogen gas from each of the plurality of reversible energy conversion devices into liquid hydrogen in the liquefier; and feeding the liquid hydrogen from the liquefier into the cryotank.

13. The method of claim 11, wherein when pl < p < p2, the method further comprising: importing electricity from the power grid; selecting a first percentage of the plurality of reversible energy conversion devices to use the electricity from the power grid to provide hydrogen gas through electrolysis of water and provide the hydrogen gas to the liquefier; selecting a second percentage of the plurality of reversible energy conversion devices to receive and convert hydrogen vapor from the cryotank or the fueling station into electricity, wherein the second percentage is lower than the first percentage;converting the hydrogen gas from the first percentage of the plurality of reversible energy conversion devices into liquid hydrogen in the liquefier; and feeding the liquid hydrogen from the liquefier into the cryotank.

14. The method of claim 11, wherein when p > p2, the method further comprising: shutting down the liquefier, wherein the plurality of reversible energy conversion devices are controlled to receive and convert the hydrogen vapor from the cryotank or the fueling station into electricity; and supplying the electricity to a power grid, a data center, or an energy storage.

15. The method of claim 14, further comprising supplying additional hydrogen from an external source to the plurality of reversible energy conversion devices.

16. A method of using the system of claim 1, comprising the use of at least 50% of the energy content stored as liquid H2 in the cryotank for a primary application on an annualized basis for a primary application and the use of less than 50% of the energy content stored as liquid H2 in the cryotank by at least one secondary application.

17. The method of claim 16, where the primary application is selected from medium duty ground transportation, heavy duty ground transportation, aviation, and off-road vehicle refueling.

18. The method of claim 17, where the heavy-duty ground transportation is selected from long-haul tracking, drayage, or buses.

19. The method of claim 16, where the at least one secondary application is selected from backup power for data centers, peak shaving or other energy services for an electric grid or microgrid.

20. The method of claim 19, where the daily level of LH2 stored in the cryotank varies by at least 20% the annual average level, due to usage by the least one secondary applications.

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