ELECTROLYZER SYSTEM AND METHOD OF OPERATING SAME IN STANDBY MODE

Description

FIELD

The present invention is directed to electrolyzer systems and methods of operating the same in a standby mode.

BACKGROUND

In a solid oxide electrolyzer cell (SOEC), a cathode electrode is separated from an anode electrode by a solid oxide electrolyte. When a SOEC is used to produce hydrogen through electrolysis, a positive potential is applied to the air side of the SOEC and oxygen ions are transported from the fuel (e.g., steam) side to the air side. Throughout this specification, the SOEC anode will be referred to as the air electrode, and the SOEC cathode will be referred to as the fuel electrode. During SOEC operation, water (e.g., steam) in the fuel stream is reduced (H₂O+2e→O²⁻+H₂) to form H₂₋ gas and O²⁻ ions, the O^2-ions are transported through the solid electrolyte, and then oxidized (e.g., by an air inlet stream) on the air side (O²⁻ to O₂) to produce molecular oxygen (e.g., oxygen enriched air).

SUMMARY

According to various embodiments, a method of operating an electrolyzer system includes operating the electrolyzer system in a steady state mode by providing steam, heat and electric power to at least one stack of electrolyzer cells to electrolyze the steam and generate a hydrogen containing product stream that is provided to a hydrogen processor; and operating the electrolyzer system in a hot isolated standby mode by stopping the provision of the steam to the at least one stack of electrolyzer cells, stopping the provision of the hydrogen containing product stream to the hydrogen processor, recycling the hydrogen containing product stream through the at least one stack of electrolyzer cells while providing the heat to the at least one stack of electrolyzer cells, and not providing external hydrogen from outside the electrolyzer system to the at least one stack of electrolyzer cells.

According to various embodiments, an electrolyzer system, includes at least one stack of electrolyzer cells; at least one heater configured to provide heat to the at least one stack of electrolyzer cells; a power supply electrically connected to the at least one stack of electrolyzer cells; a steam conduit fluidly connecting a steam source to an inlet of the at least one stack of electrolyzer cells; a water control valve located on the steam conduit; product conduit fluidly connecting an outlet of the at least one stack of electrolyzer cells to a hydrogen processor; a product valve located in fluid communication with the product conduit; a recycle conduit fluidly connecting the inlet of the at least one stack of electrolyzer cells to an outlet of the at least one stack of electrolyzer cells; a recycle blower located in fluid communication with the recycle conduit and configured to recycle a hydrogen containing product stream from the outlet to the inlet through the recycle conduit; and a controller. The controller is configured to operate the electrolyzer system in a steady state mode by opening the steam valve, turning on the at least one heater, the recycle blower and the power supply to provide electric power to the at least one stack of electrolyzer cells to electrolyze the steam to generate the hydrogen containing product stream, and opening the product valve to provide the hydrogen containing product stream to the hydrogen processor; and operate the electrolyzer system in a hot isolated standby mode by closing the steam valve and the product valve, while continuing to operate the at least one heater and the recycle blower without providing external hydrogen from outside the electrolyzer system to the at least one stack of electrolyzer cells.

FIGURES

FIG. 1A is a perspective view of a solid oxide electrolyzer cell (SOEC) stack.

FIG. 1B is a side cross-sectional view of a portion of the stack of FIG. 1A.

FIG. 2 is a schematic view of an electrolyzer system, according to various embodiments of the present disclosure.

FIG. 3A is a cross-sectional view showing air flow in a hotbox of the electrolyzer system of FIG. 2, according to various embodiments of the present disclosure.

FIG. 3B is a cross-sectional view showing steam and hydrogen flow in the hotbox of the electrolyzer system of FIG. 2, according to various embodiments of the present disclosure.

FIG. 3C is a top view showing heat transfer in the hotbox of FIG. 2, according to various embodiments of the present disclosure.

FIG. 4 is a component block diagram of a portion of the electrolyzer system of FIG. 2, according to various embodiments of the present disclosure.

FIG. 5 is a diagram of an electrolyzer cell operating in a hot isolated standby mode, according to various embodiments of the present disclosure.

FIG. 6 is a diagram of the electrolyzer cell of FIG. 5 operating in an isolated electrolysis mode, according to various embodiments of the present disclosure.

FIG. 7 is a flow diagram illustrating a method of operating an electrolyzer system, according to various embodiments of the present disclosure.

FIG. 8A is a schematic view a SOEC system including plural modules operating in a steady mode, according to various embodiments of the present disclosure.

FIG. 8B is a schematic view of the SOEC system of FIG. 8A operating in a standby mode, according to various embodiments of the present disclosure.

DETAILED DESCRIPTION

FIG. 1A is a perspective view of an electrolyzer cell stack 100, such as a solid oxide electrolyzer cell (SOEC) stack, and FIG. 1B is a side cross-sectional view of a portion of the stack 100 of FIG. 1A. Referring to FIGS. 1A and 1B, the stack 100 includes multiple electrolyzer cells (e.g., SOECs) 1 that are separated by interconnects 10, which may also be referred to as gas flow separator plates or bipolar plates. Each electrolyzer cell 1 includes an air electrode 3, an electrolyte 5, such as a solid oxide electrolyte for a SOEC, and a fuel electrode 7. The stack 100 also includes internal fuel riser channels 22.

Various materials may be used for the air electrode 3, electrolyte 5, and fuel electrode 7. For example, the air electrode 3 may comprise an electrically conductive material, such as an electrically conductive perovskite material, such as lanthanum strontium manganite (LSM).

Other conductive perovskites, such as LSCo, etc., or metals, such as Pt, may also be used. The electrolyte 5 may comprise a stabilized zirconia, such as scandia stabilized zirconia (SSZ) or yttria stabilized zirconia (YSZ), yttria-ceria-stabilized zirconia (YCSZ), ytterbia-ceria-scandia-stabilized zirconia (YbCSSZ), or blends thereof. In YbCSSZ, scandia may be present in an amount equal to 9 to 11 mol %, such as 10 mol %, ceria may present in amount greater than 0 and equal to or less than 3 mol %, for example 0.5 mol % to 2.5 mol %, such as 1 mol %, and ytterbia may be present in an amount greater than 0 and equal to or less than 2.5 mol %, for example 0.5 mol % to 2 mol %, such as 1 mol %, as disclosed in U.S. Pat. No. 8,580,456, which is incorporated herein by reference. Alternatively, the electrolyte 5 may comprise another ionically conductive material, such as a doped ceria. The fuel electrode 7 may comprise a cermet comprising a nickel containing phase and a ceramic phase. The nickel containing phase may consist entirely of nickel in a reduced state. The ceramic phase may comprise a stabilized zirconia, such as yttria and/or scandia stabilized zirconia and/or a doped ceria, such as gadolinia, yttria and/or samaria doped ceria. The electrodes and the electrolyte may each comprise one or more sublayers of one or more of the above described materials.

Each interconnect 10 electrically connects adjacent electrolyzer cells 1 in the stack 100. In particular, an interconnect 10 may electrically connect the fuel electrode 7 of one electrolyzer cell 1 to the air electrode 3 of an adjacent electrolyzer cell 1. FIG. 1B shows that the lower electrolyzer cell 1 is located between two interconnects 10.

Each interconnect 10 may be made of or may contain electrically conductive material, such as a metal alloy (e.g., chromium-iron alloy) which has a similar coefficient of thermal expansion to that of the solid oxide electrolyte in the cells (e.g., a difference of 0-10%). For example, the interconnects 10 may comprise a metal (e.g., a chromium-iron alloy, such as 4-6 weight percent iron, optionally 1 or less weight percent yttrium and balance chromium alloy).

Alternatively, any other suitable conductive interconnect material, such as stainless steel (e.g., ferritic stainless steel, SS446, SS430, etc.) or iron-chromium alloy (e.g., Crofer™ 22 APU alloy which contains 20 to 24 wt. % Cr, less than 1 wt. % Mn, Ti and La, and balance Fe, or ZMG™ 232L alloy which contains 21 to 23 wt. % Cr, 1 wt. % Mn and less than 1 wt. % Si, C, Ni, Al, Zr and La, and balance Fe).

Each interconnect 10 includes fuel ribs 12A that at least partially define fuel channels 8A, and air ribs 12B that at least partially define air channels 8B. The interconnect 10 may operate as a gas-fuel separator that separates a fuel, such as steam, flowing to the fuel electrode 7 of one electrolyzer cell 1 in the stack 100 from oxidant, such as air, flowing to the air electrode 3 of an adjacent electrolyzer cell 1 in the stack 100. At either end of the stack 100, there may be an air end plate or fuel end plate (not shown) for providing air or fuel, respectively, to the end electrode. Alternatively, the air end plate or fuel end plate may comprise the same interconnect structure used throughout the stack. An optional conductive contact layer 13, such as a nickel mesh, may be located between the fuel electrode 7 and the fuel ribs 12.

FIG. 2 is schematic view of an electrolyzer system 200, according to various embodiments of the present disclosure. Referring to FIGS. 1A, 1B, and 2, the system 200 may include one or more electrolyzer cell stacks 100 or columns, such as SOEC stacks or columns.

Each column may include one or more electrolyzer cell stacks 100. The electrolyzer cell stack 100 includes multiple electrolyzer cells, such as SOECs, as described with respect to FIGS. 1A and 1B. The system 200 may also include a steam generator 104, a steam recuperator heat exchanger 108, an air recuperator heat exchanger 112, an air blower 118, a recycle blower 126, an outer column heater 350, an inner column heater 360, and a base heater 370. The system 200 may also optionally include at least one of an air pre-heater heat exchanger 54, a water preheater heat exchanger 102, a mixer 106, a hydrogen processor 120 and/or a hydrogen separator (e.g., splitter or valve) 122.

The system 200 may include a hotbox 300 that houses various components, such as the stack 100, the steam recuperator 108, the air recuperator 112, the outer column heater 350, the inner column heater 360 and/or the base heater 370. In some embodiments, the hotbox 300 may include multiple stacks 100 or multiple columns of stacks 100. The water preheater 102 and the steam generator 104 may be located external to the hotbox 300, as shown in FIG. 2.

Alternatively, the water preheater 102 and/or the steam generator 104 may be located inside the hotbox 300. In another alternative embodiment, the SOEC system may have an external steam source, in which case the water preheater 102 and/or the steam generator 104 may be omitted.

During operation, the stack 100 may be provided with steam (e.g., steam inlet stream) and electric power (e.g., current or voltage) from an external power source. In particular, the steam may be provided to the fuel electrodes 7 of the electrolyzer cells 1 of the stack 100, and the power source may apply a voltage between the fuel electrodes 7 and the air electrodes 3, in order to electrochemically split water (e.g., steam) molecules and generate hydrogen and oxygen. Air may also be provided to the air electrodes 3, in order to sweep the oxygen from the air electrodes 3. As such, the stack 100 may output a hydrogen stream and an oxygen-rich exhaust stream, such as an oxygen-rich air stream (“oxygen exhaust stream”).

In order to generate the steam, water may be provided to the system 200 from a water source 50. The water source 50 may include a municipal water supply (e.g., water pipe) and/or a water storage tank. The water may be deionized (DI) water that is deionized as much as is practical (e.g., <0.1 μS/cm), in order to prevent and/or minimize scaling during vaporization. In some embodiments, the water source 50 may include one or more deionization beds (e.g., downstream of the water pipe or tank). The water source 50 may provide the water to the system 200 via a water inlet conduit 250. In various embodiments, the water inlet conduit 250 may include a water flow control device 251 such as a valve, a mass flow controller, a positive displacement pump, a water flow meter, or the like, in order to provide a desired water flow rate to the system 200.

If the system 200 includes the water preheater 102, the water may be provided from the water source 50 to the water preheater 102 through the water inlet conduit 250. The water preheater 102 may be a heat exchanger configured to heat the water using heat recovered from the oxygen exhaust stream from the stack 100. Preheating the water may reduce the total power consumption of the system 200 per unit of hydrogen generated. In particular, the water preheater 102 may recover heat from the oxygen exhaust stream that may not be recoverable by the air recuperator 112, as discussed below. The water preheater may heat the water to a temperature above 50° C., such as a temperature of about 70° C. to 80° C. The oxygen exhaust stream may be output from the water preheater 102 at a temperature above 80° C., such as above 100° C., such as a temperature of about 120° C. to 140° C.

The water output from the water preheater 102 (or from the water source 50 if the water preheater 102 is omitted) may be provided to the steam generator 104 through a water conduit 202. The steam generator 104 may be configured to heat the water to convert the water into steam. The steam generator 104 may include a heating element to vaporize the water and generate steam. For example, the steam generator 104 may include an AC or DC resistance heating element or an induction heating element. Alternatively, the steam generator 104 may comprise a heat exchanger which is located inside the hotbox 300 and which is heated by one or more hot exhaust streams flowing through the hotbox 300. The steam generator 104 heats the water above 100° C. to generate steam, such as a temperature of about 120° C. to 145° C.

The steam generator 104 may include multiple zones/elements that may or may not be mechanically separate. For example, the steam generator 104 may include a pre-boiler to heat the water up to or near to the boiling point. The steam generator 104 may also include a vaporizer configured to convert the pre-boiled water into steam. The steam generator 104 may also include a deaerator to provide a relatively small purge of steam to remove dissolved air from the water prior to bulk vaporization. The steam generator 104 may also include an optional superheater configured to further increase the temperature of the steam generated in the vaporizer. The steam generator 104 may include a demister pad located downstream of the heating element and/or upstream from the super heater. The demister pad may be configured to minimize entrainment of liquid water in the steam output from the steam generator 104 and/or provided to the superheater.

If the steam product is superheated, it will be less likely to condense downstream from the steam generator 104 due to heat loss. Avoidance of condensation is preferable, as condensed water is more likely to form slugs of water that may cause significant variation of the delivered mass flow rate with respect to time. It may also be beneficial to avoid excess superheating, in order to limit the total power consumption of the system 200. For example, the steam may be superheated by an amount ranging from about 10° C. to about 100° C.

In some embodiments, a small amount of liquid water (e.g., from about 0.5% to about 2% of incoming water) may be periodically or continuously discharged from the steam generator 104 via a liquid discharge conduit 224. In particular, the discharged liquid water may include scale and/or other mineral impurities that may accumulate in the steam generator 104 while vaporizing water to generate steam. Therefore, this discharged liquid water is not desirable for being recycled into the water inlet stream from the water source 50. This liquid discharge may be mixed with the hot oxygen exhaust stream output from the water preheater 102 into an exhaust conduit 205. If the hot oxygen exhaust stream has a temperature above 100° C., the liquid water discharge may be evaporated by the hot oxygen exhaust stream, such that no liquid water is required to be discharged from the system 200. The system 200 may optionally include a water pump 124 configured to pump and regulate the liquid water discharge in the liquid discharge conduit 224 output from the steam generator 104 into the exhaust conduit 205 from the water preheater 102. Optionally, a flow regulator, such as proportional solenoid valve, may be added to the liquid discharge conduit 224 in addition to the pump 124 to additionally regulate the flow of the liquid water discharge.

Blowdown from the steam generator 104 may be beneficial for long term operation, as the water will likely contain some amount of mineralization after deionization. Typical liquid blowdown may be on the order of 1 %. The blowdown may be continuous, or may be intermittent, e.g., ten times the steady state flow for 6 seconds out of every minute, five times the steady state flow for 1 minute out of every 5 minutes, etc. The need for a water discharge stream can be eliminated by pumping the blowdown into the hot oxygen exhaust. In this case, the pump 124 and liquid discharge conduit 224 may be omitted.

The steam output from the steam generator 104 may be provided to the steam recuperator 108 via a steam conduit 204. However, if the system 200 includes the optional mixer 106, the steam may be provided to the mixer 106 prior to being provided to the steam recuperator 108 via steam and hydrogen conduit 206. In particular, the steam may include small amounts of dissolved air and/or oxygen. The mixer 106 may be configured to mix the steam with hydrogen gas, in order to maintain a reducing environment in the stack 100, and in particular, at the fuel electrodes 7.

The mixer 106 may be configured to mix the steam with hydrogen received from a hydrogen storage device (e.g., hydrogen storage vessel) 52 and/or with a portion of the hydrogen and steam recycle stream output from the stack 100. The hydrogen addition rate may be set to provide an amount of hydrogen that exceeds an amount of hydrogen needed to react with an amount of oxygen dissolved in the steam. The hydrogen addition rate may either be fixed or set to a constant water to hydrogen ratio. However, if the steam is formed using water that is fully deaerated, the mixer 106 and/or hydrogen addition into the steam may optionally be omitted.

In some embodiments, the hydrogen may be provided to the mixer 106 during system start-up and shutdown modes, and optionally during steady state operation modes. For example, during the start-up and shutdown modes (or other modes where the system 200 is not generating hydrogen, such as a fault mode), the hydrogen may be provided to the mixer 106 from the hydrogen storage device 52 via a stored hydrogen conduit 252. In an alternative embodiment described below, in voltage controlled start-up, shutdown and process stop modes, no external hydrogen is provided to the mixer 106 and the stack 100.

During the steady state operating mode, the hydrogen flow from the hydrogen storage device 52 may be stopped (e.g., by shutting off the outlet valve from the hydrogen storage device). A first portion of a hydrogen exhaust stream (e.g., the hydrogen and steam product steam) generated by the stack 100 is diverted to the mixer 106 through the hydrogen recycle conduit 226 by the recycle blower 126. In particular, the system 200 may include a hydrogen separator 122, such as a splitter and/or valve, configured to selectively divert a portion of the hydrogen exhaust stream flowing through the hydrogen product conduit 220 to the mixer 106 during the steady state mode operation.

The mixed steam and hydrogen inlet stream is provided from the mixer 106 into a steam recuperator heat exchanger 108 via a steam and hydrogen conduit 206. The mixed steam and hydrogen inlet stream in conduit 206 may have a temperature above 100° C., such as 120° C. to 140° C. The mixed steam and hydrogen inlet stream is heated in the steam recuperator 108 by the hydrogen exhaust (i.e., the hydrogen and steam product stream) provided from the stack 100. The hydrogen exhaust may be provided from the stack 100 to the steam recuperator 108 via a hydrogen outlet conduit 210. The heated mixed steam and hydrogen inlet stream is provided from the steam recuperator heat exchanger 108 into the fuel side inlet of the stack 100 via the fuel inlet conduit 208. The mixed steam and hydrogen inlet stream in the fuel inlet conduit 208 may have a temperature above 500° C., such as 550° C. to 600° C.

The hydrogen exhaust is output from the hotbox 300 (e.g., from the steam recuperator 108 and/or the optional air preheater 54) into the hydrogen product conduit 220 at a temperature of 150° C. to 250° C. A second portion of the hydrogen exhaust that is not diverted by the hydrogen separator 122 into the mixer 106 continues through the hydrogen product conduit 220 into the hydrogen processor 120. The hydrogen exhaust may be compressed and/or purified in the hydrogen processor 120. The hydrogen processor 120 may include a high temperature hydrogen pump that operates at a temperature from about 120° C. to about 200° C., in order to remove from about 70% to about 90% of the hydrogen from the hydrogen exhaust. The removed hydrogen is stored and/or provided for one or more end uses. In one embodiment, the hydrogen processor 120 includes an electrochemical hydrogen pump, a liquid ring compressor, a diaphragm compressor or combination thereof. For example, the hydrogen processor may include a series of electrochemical hydrogen pumps, which may be disposed in series and/or in parallel with respect to a flow direction of the hydrogen exhaust, in order to compress the hydrogen exhaust. The final product from compression may still contain traces of water. As such, the hydrogen processor 120 may optionally include a dewatering device, such as a condenser, a temperature swing adsorption reactor or a pressure swing adsorption reactor, to remove this residual water, if necessary.

The air recuperator heat exchanger 112 may be provided with ambient air by an air blower 118 via an air inlet conduit 218 and an optional preheated air conduit 254. The oxygen exhaust output from the stack 100 may be provided to the air recuperator 112 via an oxygen outlet conduit 222. The air recuperator 112 may be configured to heat the air using heat extracted from the stack oxygen exhaust (i.e., the oxygen enriched air). The air inlet stream may be heated in the air recuperator 112 to a temperature above 500° C. , such as 550° C. to 600° C.

The heated air inlet stream is provided from the air recuperator 112 to the air inlet of the stack 100 via the stack air inlet conduit 212.

The oxygen exhaust is output from the air recuperator 112 to the water preheater 102 via the oxygen exhaust conduit 228 at temperature above 200° C., such as 250° C. to 350° C. The oxygen exhaust is output from the water preheater 102 via the exhaust conduit 205 at temperature of at least 80° C.

According to various embodiments, the system 200 may include an optional air preheater heat exchanger 54 disposed outside or inside of the hotbox 300. In particular, the air preheater 54 may be configured to preheat the air inlet stream provided to the hotbox 300 by the air blower 118 via the air inlet conduit 218 using heat in the hydrogen exhaust (i.e., the hydrogen and steam product stream) from the stack 100. The air may be preheated in the air preheater to a temperature above 100° C., such as 150° C. to 250° C. The hydrogen exhaust may be provided from the steam recuperator 108 to the air preheater 54 via a hydrogen conduit 238.

According to various embodiments, the system 200 may include a controller 125, such as a central processing unit, which is configured to control the operation of the system 200. For example, the controller 125 may be wired or wirelessly connected to various elements of the system 200 to control the same.

According to various embodiments, the SOEC stack 100 may most efficiently generate hydrogen at an operating temperature ranging from about 700° C. to 900° C., such as from about 725° C. to about 775° C., or about 750° C. In order to maintain the stack operating temperature, fluids provided to the stack 100 may be heated by various components prior to being provided to the stack 100. The heaters 350, 360, 370 improve the temperature control of the system.

FIGS. 3A and 3B are cross-sectional views showing air flow and steam and hydrogen flow in the hotbox 300 of the electrolyzer system 200 of FIG. 2, according to various embodiments of the present disclosure. FIG. 3C is a top view showing aspects of heat transfer in the hotbox of FIG. 2, according to various embodiments of the present disclosure.

Referring to FIGS. 3A-3C, the hotbox 300 may be disposed on an optional support base 302 and may include an optional cover plate 304. The support base 302 may comprise hollow rails which provide access for a forklift to raise and move the hotbox 300. The hotbox 300 includes a central column 320, the outer column heater 350, the inner column heater 360, and the base heater 370, which may be disposed in the hotbox 300. In particular, the central column 320 may protrude through an opening in the cover plate 304 of the hotbox 300.

The central column 320 may include the steam recuperator 108 and the air recuperator 112. In various embodiments, the air recuperator 112 may be located radially outward from and concentrically surround the steam recuperator 108. It is believed that this configuration may provide a high heat transfer efficiency. However, in an alternative embodiment, the air recuperator 112 may optionally be located radially inward from and be laterally surrounded by the steam recuperator 108 instead. Thus, both the steam recuperator 108 and the air recuperator 112 are located radially inward of the stacks 100 or cell columns 101. The central column 320 may also include an air conduit 322, an air exhaust conduit 324, a steam conduit 326 (see FIG. 3B), and a product conduit 328 (see FIG. 3B). The air conduit 322 comprises the combination of the preheated air conduit 254 and the stack air inlet conduit 212. The air exhaust conduit 324 comprises the combination of the oxygen outlet conduit 222 and the oxygen exhaust conduit 228. The steam conduit 326 comprises the combination of the steam and hydrogen conduit 206 and the fuel inlet conduit 208. The product conduit 328 comprises the combination of the hydrogen outlet conduit 210 and the hydrogen conduit 238.

The cell columns 101 may each include one stack 100 or plural stacks 100 stacked over each other. The cell columns 101 surround around the central column 320. The cell columns 101 may optionally include fuel manifolds 105 (e.g., steam splitter plates) disposed between the stacks 100. The manifolds 105 may be configured to provide steam to adjacent stacks 100 in the same column 101 and receive the hydrogen product output from adjacent stacks 100 in the same column 101. The manifolds 105 of each cell column 101 may be fluidly connected to riser conduits 332 configured to provide the steam to and collect the hydrogen exhaust from the cell columns 101. The riser conduits 332 may include steam riser conduits 332S configured to provide the steam inlet stream to the cell columns 101, and product riser conduits 332P configured to collect the hydrogen exhaust stream (i.e., the hydrogen product stream) output from the cell columns 101, as shown in FIG. 3C.

Thus, the cell columns 101 and/or stacks 100 may be internally manifolded for steam/hydrogen and externally manifolded for oxygen/air. As noted above, the steam inlet stream may also include hydrogen, and the hydrogen product may also include unreacted steam. Alternatively, each cell column 101 may include only one stack 100 and the manifolds 105 and riser conduits 332 may be omitted.

The inner column heater 360 may be disposed between the central column 320 and the cell columns 101 (e.g., one or more stacks 100). In particular, an inner surface of the inner column heater 360 may face the steam recuperator 108 and the air recuperator 112, and an outer surface of the inner column heater 360 may face the stacks 100 or columns 101. The outer column heater 350 may surround the stacks 100 or columns 101. In particular, an inner surface of the outer column heater 350 may face the stacks 100. Thus, the stacks 100 or columns 101 are located radially inward from the outer column heater 350 and radially outward from the inner column heater 360. The steam recuperator 108 and the air recuperator 112 are located radially inward from the inner column heater 360.

As shown in FIG. 3A, in operation, an incoming air inlet stream is provided through the air conduit 322 (e.g., through the preheated air conduit 254) to the top of the air recuperator 112. The air inlet stream may be heated while passing through the air recuperator 112, before exiting the bottom of the air recuperator 112. After exiting the air recuperator 112, the air inlet stream may flow upward through the stack air inlet conduit 212 to the inner facing surfaces of the stacks 100 or columns 101. The inner column heater 360 may heat the air inlet stream in the stack air inlet conduit 212. The air inlet stream may enter the open inner surfaces of the stacks 100 or columns 101 that face the central column 320. The air inlet stream may flow to the surface of the SOEC air electrodes 3 in the stacks 100 or columns 101 via the air channels 8B in the interconnects 10 (see FIG. 1B). Oxygen ions generated from the steam inlet stream at the fuel electrodes 7 by a voltage applied to the stacks 100 may pass through the SOEC electrolytes 5 and may recombine to form oxygen gas (O₂) at the air electrodes 3. The oxygen gas is swept away by the air inlet stream flowing through the air channels 8B in the stacks 100 or columns 101.

The oxygen enriched air (e.g., oxygen/air exhaust) stream then exits outer surfaces of the stacks 100 or columns 101, flows downward through the oxygen outlet conduit 222 toward the bottom of the hotbox 300, and then flows into the bottom of the air recuperator 112. The outer column heater 350 may heat the oxygen enriched air in the oxygen outlet conduit 222. The air recuperator 112 extracts heat from the oxygen exhaust stream as it flows upward through the air recuperator 112, to heat the incoming air inlet stream.

As shown in FIG. 3B, in operation, steam and/or a steam/hydrogen mixture is provided to the central column 320 and flows downward through the steam conduit 326 (e.g., through the steam and hydrogen conduit 206) to the steam recuperator 108. The steam recuperator 108 may be a heat exchanger configured to recover heat from the hydrogen exhaust stream output from the stacks 100 or columns 101. As such, the steam recuperator 108 may be configured to increase the efficiency of the system 200.

The heated steam inlet stream may exit the bottom of the steam recuperator 108 and enter the distribution hub 340. The steam inlet stream may then flow through the fuel inlet conduits 208 to the corresponding riser conduits 332 (e.g., steam riser conduits 332S), which provide the steam inlet stream to the stacks 100 or columns 101. The steam and/or the steam/hydrogen mixture (i.e., the steam inlet stream) flowing through the fuel inlet conduits 208 is heated by the base heater 370 located adjacent to the distribution hub 340. The steam and/or the steam/hydrogen mixture flows to the SOEC fuel electrodes 7 in the stacks 100 or columns 101 via the fuel channels 8A in the interconnects 10. The SOECs in the stacks 100 or columns 101 may convert at least a portion of the steam into hydrogen to generate a hydrogen exhaust stream (i.e., product stream) that may also comprise unreacted steam. The hydrogen exhaust stream may be output from the stacks 100 or columns 101 to the corresponding riser conduits 332 (e.g., product riser conduits 332P). The hydrogen exhaust stream may be provided from the product riser conduits 332P to the distribution hub 340 by the hydrogen outlet conduits 210, which may provide the hydrogen exhaust stream to the bottom of the steam recuperator 108. The hydrogen exhaust stream flowing through the hydrogen outlet conduits 210 is heated by the base heater 370 located adjacent to the distribution hub 340. The hydrogen exhaust stream may flow up through the steam recuperator 108, which may transfer heat from the hydrogen exhaust stream to the incoming steam inlet stream flowing therethrough in the opposite direction. The hydrogen exhaust stream may exit the top of the steam recuperator 108 and enter the hydrogen conduit 238 and then exit the central column 320.

In various embodiments, in order for the recuperators 108, 112 to provide high steam and air flow rates and a low pressure drop while also fitting within the space available in the hotbox 300, the temperature of the output steam inlet stream and/or air inlet stream may be less than a desired operating temperature of the stacks 100 or columns 101. Accordingly, the heaters 350, 360, 370 may be used to supplement that heating provided by the recuperators 108, 112.

For example, the heaters 350, 360, 370 may be configured to heat the air inlet stream, the steam/hydrogen stream (i.e., the steam inlet stream), the hydrogen exhaust stream and/or the oxygen enriched air stream (i.e., oxygen exhaust stream) such that the steam inlet stream and the air inlet stream are provided to the stacks 100 or columns 101 at temperatures as close as possible to the operating temperature of the stack, such as at temperatures ranging from about 700° C. to about 900° C., such as from about 725° C. to about 850° C., or about 750° C. However, higher temperatures may also be used.

In various embodiments, the heaters 350, 360, 370 may include electric heating elements, such as a resistive or inductive heating elements which may be embedded in thermal insulation layers. In some embodiments, the heaters 350, 360, 370 may preferably comprise heating elements disposed in a ceramic fiber insulation material, in order to provide longer heater life.

For example, as shown in FIG. 3B, the outer column heater 350 may include one or more heating elements 352 embedded in a tubular insulation layer 354, which may be formed of ceramic fibers.

In some embodiments, the heaters 350, 360, 370 may include different heating zones in order to provide improved temperature control. For example, the column heaters 350, 360 may have upper, middle, and lower zones, including independently controllable heating elements, in order to heat upper, middle, and lower portions of the stacks 100 at different temperatures, depending on the temperature requirements of different portions of the stacks 100.

In various embodiments, the outer column heater 350 may be disposed along the perimeter of the hotbox 300 and may be configured to radiate heat inward toward the central column 320 and the cell columns 101. For example, the outer column heater 350 may be configured to radiate heat toward the outer surfaces of the stacks 100, columns 101 and/or the riser conduits 332. Accordingly, the outer column heater 350 may be configured to heat the stacks 100 or columns 101 and fluids flowing through the riser conduits 332. The base heater 370 may be configured to heat fluids flowing through the distribution hub 340. For example, the base heater 370 may directly or indirectly heat the conduits 208 and 210 to heat the fluids flowing therethrough. For example, the base heater 370 may be configured to heat a steam/hydrogen mixture (i.e., the steam inlet stream) flowing through the fuel inlet conduits 208 up to the stack operating temperature. In some embodiments, the base heater 370 may also heat the hydrogen exhaust stream flowing through the hydrogen outlet conduits 210, in order to increase the amount of heat transferred to the steam inlet stream in the steam recuperator 108.

For example, depending on the health of the stacks 100, the water utilization rate of the stacks 100, and the air flow rate to the stacks 100, the outer column heater 350 and/or base heater 370 may heat steam or steam/hydrogen mixture provided to the stacks 100 to a temperature ranging from about 700° C. to about 900° C. such as 725° C. to 800° C. or about 750° C. In some embodiments, the outer column heater 350 and/or base heater 370 may increase the temperature of the steam output from the steam recuperator 108 by an amount ranging from about 50° C. to about 300° C., such as from about 75° C. to about 200° C., or from about 100° C. to about 150° C. Accordingly, the stacks 100 may be provided with steam or a steam-hydrogen mixture having a temperature that allows for efficient hydrogen generation.

The inner column heater 360 may surround the central column 320, such that an outer surface of inner column heater 360 faces inner surfaces of the stacks 100 or columns 101 and an inner surface of the inner column heater 360 faces the central column 320 and/or the air recuperator 112. The inner column heater 360 may be configured to heat the stacks 100 or columns 101, for example, by radiating heat outward toward the inner surfaces of the stacks 100 or columns 101. The inner column heater 360 may also heat the air recuperator 112, in order to increase the temperature of the air inlet stream flowing along the outer surface of the air recuperator 112.

In some embodiments, the inner column heater 360 may be configured to heat the air inlet stream provided to the stacks 100 or columns 101, including air in the air recuperator 112 and/or the air inlet stream flowing through the hotbox 300, to a temperature ranging from about 700° C. to about 900° C. such as 725° C. to 800° C. or about 750° C. For example, the inner column heater 360 may be configured to increase the temperature of the air inlet stream output from the air recuperator 112 by an amount ranging from about 100° C. to about 400° C., such as from about 150° C. to about 350° C. or from about 250° C. to about 275° C.

Accordingly, the heaters 350, 360, 370 may be configured to heat the stacks 100 or columns 101, and/or steam inlet stream and air inlet stream provided to the stacks 100 or columns 101, to maintain a desired stack operating temperature and hydrogen production efficiency, without increasing a footprint and/or volume of the hotbox 300. Accordingly, the heaters 350, 360, 370 may beneficially allow for the use of relatively small recuperators 108, 112, while maintaining overall system space and hydrogen production efficiency.

FIG. 4 is a schematic view of a portion of the system 200 of FIG. 2 operating in a standby mode, according to an embodiment. The hotbox 300 is shown schematically. In this embodiment, the water flow control device 251 may comprise a valve (e.g., a shut-off valve or another type of valve) located on the water inlet conduit 250 or on the steam conduit 204. In addition a product valve 221 (e.g., a shut-off valve or another type of valve) is located on the hydrogen product conduit 220 downstream of the hydrogen separator (e.g., splitter) 122, and a hydrogen valve 253 (e.g., a shut-off valve or another type of valve) is located on the stored hydrogen conduit 252 or in the hydrogen storage device 52.

Many operational situations may warrant the electrolyzer system 200 to have its input or output conditions interrupted at the boundary of a given electrolyzer module which includes the hotbox 300. When a given electrolyzer module or hotbox 300 needs to be taken out of the steady state hydrogen production mode, the electrolyzer module may be switched to an isolated hot standby mode.

For the SOEC stack 100 shown in FIGS. 1A and 1B, the nickel mesh 13 and/or the nickel in the fuel electrode (i.e., cathode) 7 oxidizes due to the inflow of atmospheric air to the fuel electrode 7 and the nickel mesh 13 when hydrogen is not present, oxygen is present, there is no electrolysis power, and the temperature is above an activation threshold. The nickel oxidation forms nickel oxide which causes expansion of the fuel electrode 7 and the nickel mesh 13. When the system is restarted and hydrogen flow to the fuel electrode 7 resumes, the nickel oxide is reduced to nickel which causes contraction of the fuel electrode 7 and the nickel mesh 13.

Repeated expansion and contraction cycles can cause damage to the fuel electrode 7 and the nickel mesh.

The external hydrogen from the hydrogen storage device 52 may be supplied to the fuel electrode 7 during system shutdown to prevent nickel oxidation. However, this increases the cost of operating the electrolyzer system 200 because hydrogen is expensive. Furthermore, restarting a SOEC system from room temperature may take a relatively long time, which increases system downtime.

In various embodiments, hydrogen is provided to the fuel electrode 7 and the nickel mesh 13 of a SOEC stack 100 during a hot isolated standby mode to prevent nickel oxidation without using any external hydrogen from the hydrogen storage device 52. In the hot isolated standby mode, at least one of the heaters 350, 360 and/or 370 remains operational and the SOEC stack 100 or column 101 remains at an elevated temperature (e.g., above 400° C.). Hydrogen already present in the SOEC system conduits, fuel channels and riser channels is recycled to the fuel electrode 7 and the nickel mesh 13 of a SOEC stack 100 or column 101 located in the hotbox 300. The controller 125 may place the system 200 into hot isolated standby mode in response to a trigger condition. The trigger condition may include at least one of loss of steam or steam pressure, full hydrogen storage or process 120 downstream, maintenance on the hydrogen processor 120, system restart request, or system maintenance.

As shown in FIG. 4, during the hot isolated standby mode, water flow control valve 251, the product valve 221 and the hydrogen valve 253 are all closed, while the air blower 118 and the recycle blower 126 remain operational. The recycle blower 126 recycles the steam and hydrogen product present in the various conduits (e.g., 238, 220, 226, 206), riser channels 22 and fuel channels 8A past the fuel electrodes 7 and the nickel meshes 13 in the SOEC stack 100 or column 101. Since the hydrogen and steam product cannot flow to the hydrogen processor 120 through the product conduit 220, all of the hydrogen present in the conduits and channels is repeatedly cycled past the fuel electrodes 7 and the nickel meshes 13.

Even if atmospheric air leaks to the fuel side of the SOEC stack 100 and/or oxygen is electrochemically transported through the electrolyte 5 from the air electrode 3 to the fuel electrode 7 of the SOEC 1 during the hot isolated standby mode, the oxygen reacts with hydrogen in the recycled product stream to form steam. Thus, the leaked air and/or electrochemically transported oxygen do not significantly oxidize the nickel in the fuel electrodes 7 and the nickel meshes 13, which reduces damage to the SOEC stack 100 components.

In the descriptions of various embodiments going forward, references are made to SOEC stack 100. It is understood that such references are equally applicable to embodiments utilizing SOEC column 101 as an SOEC column 101 include one or more SEOC stacks 100.

In one embodiment, the direct current (DC) or voltage (i.e., electric power) is not applied to the SOEC stack 100 during the hot isolated standby mode. The hot isolated standby mode may continue until there is insufficient hydrogen left in the recycled product stream. In other words, once a significant portion of the hydrogen reacts with the oxygen to form steam, additional leaked air and/or electrochemically transported oxygen may oxidize the nickel in the fuel electrodes 7 and the nickel meshes 13. Thus, the hot isolated standby mode in which direct current or voltage is not applied to the SOEC stack 100 has a finite duration, and the SOEC system 200 is restarted to operate in a steady state mode before the end of the hot isolated standby mode. Once the system 200 is restarted, direct current or voltage (i.e., electric power) is reapplied to the SOEC stack 100, and valves 251 and 221 are opened and the SOEC stack 100 receives external steam and generates the hydrogen containing product stream that is provided to the hydrogen processor 120.

In other embodiments, the direct current or voltage (i.e., electric power) is applied to the SOEC stack 100 either intermittently or continuously during the hot isolated standby mode to extend the duration of this mode before the SOEC system 200 is restarted.

The SOEC stack 100 may operate in the hot isolated standby mode where oxygen slowly leaks to the fuel electrode and hydrogen is slowly depleted as the hydrogen and steam product is continuously recirculated over the fuel electrode. Once the hydrogen has been depleted to a level where the SOEC cells are in danger of damage (e.g., low-hydrogen threshold), the controller 125 may switch the electrolyzer system 200 from the hot isolated standby mode to an isolated electrolysis mode. In the isolated electrolysis mode, the controller 125 applies the direct current or voltage to the SOEC stack 100 to regenerate the hydrogen in the recycled product stream.

Because the SOEC stack 100 is fluidly isolated from the hydrogen processor 120 in the isolated electrolyzer mode (i.e., the valves 221, 251 and 253 are closed), the steam in the recycled product stream is electrolyzed into hydrogen and oxygen, with the oxygen being transported across the electrolyte 5 from the fuel electrode 7 to the air electrode 3. The electrolysis increases the amount of hydrogen in the product stream which can react with the leaked oxygen if the direct current or voltage to the SOEC stack 100 is turned off. In this embodiment, the controller 125 applies the direct current or voltage to the SOEC stack 100 intermittently, such that the SOEC stack 100 operates alternately in the hot isolated standby mode (in which no direct current or voltage is applied to the SOEC stack 100) and in the isolated electrolysis mode (in which the direct current or voltage is applied to the SOEC stack 100). The blowers 118, 126 continue to operate and the valves 221, 251, 253 are closed in both the hot isolated standby mode and in the isolated electrolysis mode.

In another embodiment described below, an alternative electrolyzer system 800 is illustrated in FIGS. 8A and 8B. Thus, in various embodiments, a method of operating an electrolyzer system (200, 800) includes operating the electrolyzer system in a steady state mode by providing steam, heat and electric power to at least one stack 100 of electrolyzer cells 1 to electrolyze the steam and generate a hydrogen containing product stream that is provided to a hydrogen processor 120. The method also includes operating the electrolyzer system (200, 800) in a hot isolated standby mode by stopping the provision of the steam to the at least one stack 100 of electrolyzer cells 1, stopping the provision of the hydrogen containing product stream to the hydrogen processor 120, recycling the hydrogen containing product stream through the at least one stack 100 of electrolyzer cells 1 while providing the heat to the at least one stack 100 of electrolyzer cells 1, and not providing external hydrogen from outside the electrolyzer system to the at least one stack 100 of electrolyzer cells 1.

In one embodiment, the step of providing the heat comprises heating the at least one stack 100 of electrolyzer cells 1 using at least one heater (350, 360, 370); and the step of recycling the hydrogen containing product stream comprises using a recycle blower 126 to recycle the hydrogen containing product stream from an outlet of the at least one stack 100 of electrolyzer cells 1 through a recycle conduit 226 to an inlet of the at least one stack 100 of electrolyzer cells 1.

In one embodiment, the method further comprises operating the electrolyzer system (200, 800) in a start-up mode by providing the external hydrogen from outside the electrolyzer system to the at least one stack 100 of electrolyzer cells 1. The external hydrogen is provided from a hydrogen storage device 52 to the at least one stack 100 of electrolyzer cells 1 through an open hydrogen valve 253 and a stored hydrogen conduit 252 during the start-up mode. The steam is provided to the at least one stack 100 of electrolyzer cells 1 through an open water control valve 251 and a steam conduit 204 from a steam source (e.g., the water source 50 and/or steam generator 104) during the steady state mode. The hydrogen containing product stream is provided from the at least one stack 100 of electrolyzer cells 1 to the hydrogen processor 120 through an open product valve 221 and a product conduit 220 during the steady state mode. In one embodiment, the hydrogen valve 253, the water control valve 251 and the product valve 221 are closed in the hot isolated standby mode to fluidly isolate the at least one stack 100 of electrolyzer cells 1 from the hydrogen storage device 52, the steam source (50/204) and the hydrogen processor 120. The hydrogen valve 253 may be either open or closed during the steady state mode to optionally provide the external hydrogen to the at least one stack 100 of electrolyzer cells 1, as needed during the steady state mode.

In an alternative embodiment, no external hydrogen is provided to the stack 100 during a voltage controlled start-up mode. In the voltage controlled start-up mode, the hydrogen valve 253 is closed, and the product valve 221 is open. External electric power (e.g., external voltage) is applied to the stack 100 and stack heaters are activated to heat the stack 100. The stack heaters heat the stack 100 from an initial temperature (e.g., room temperature) to a desired steady state temperature at which the system reaches the steady state operating mode. The water control valve 251 may be initially closed and then opened when the stack is sufficiently hot to accept the steam and electrolyze the steam as needed using the external electric power.

In another alternative embodiment, no external hydrogen is provided to the stack during a voltage controlled shutdown mode. The voltage controlled shutdown mode may comprise a voltage controlled gradual cool down mode or a voltage controlled process stop mode. In both the voltage controlled gradual cool down mode and the voltage controlled process stop mode, the external electric power (e.g., external voltage) is applied to the stack 100, the stack heaters are deactivated (i.e., turned off) so that they do not heat the stack 100, the hydrogen valve 253 is closed and the product valve 221 is open. Thus, the hydrogen containing product is provided from the stack 100 and the hotbox 300 through the product valve 221 to the hydrogen product conduit 220.

In the voltage controlled gradual cool down mode, the water control valve 251 is open, and steam is provided to the stack 100 through the open water control valve, such that hydrogen is generated using electrolysis from the steam during the gradual stack 100 cool down, before the system is turned off and all valves are closed once the system reaches the desired temperature (e.g., room temperature). In contrast, in the voltage controlled process stop mode, the water control valve 251 is closed, and no external steam is provided to the stack 100. This maintains stack 100 health despite the stack 100 not being fully operational to avoid maintaining the stack 100 in potentially oxidizing conditions while the stack 100 cools, which may oxidize metal (e.g., nickel) in cermet fuel electrodes of the cells in the stack 100, which may cause the fuel electrodes to change their volume and cause cracks in the cells.

Thus, in some embodiments, the electrolyzer system may also be operated in a voltage controlled shutdown mode by providing electric power to the at least one stack of electrolyzer cells 100, providing the hydrogen containing product stream to the hydrogen processor 120, recycling the hydrogen containing product stream through the at least one stack of electrolyzer cells 100 without providing the heat to the at least one stack of electrolyzer cells 100, and not providing external hydrogen from outside the electrolyzer system to the at least one stack of electrolyzer cells 100. In one embodiment, the voltage controlled shutdown mode comprises a voltage controlled gradual cool down mode in which the steam is provided to at least one stack of electrolyzer cells 100. In another embodiment, the voltage controlled shutdown mode comprises a voltage controlled process stop mode in which the steam is not provided to at least one stack of electrolyzer cells 100.

FIG. 5 is a diagram showing a SOEC cell 1 of the SOEC stack 100 operating in the hot isolated standby mode. The power supply (e.g., DC/DC converter) 500 does not apply any DC or voltage between the air electrode and fuel electrode. The hydrogen and steam product stream circulate over the fuel electrode 7 and the oxygen enriched heated air recirculates over the air electrode 3. In the hot isolated standby mode, the hydrogen and steam product stream may be provided to the fuel electrode 7 via conduit 208, and is exhausted via conduit 210. The recycle blower 126 recirculates the entire hydrogen and steam product stream from conduit 210 back to conduit 208. The air is provided to the air electrode 3 via conduit 212 and is exhausted via conduit 222. FIG. 5 shows the electrochemical oxygen ion transport through the electrolyte 5 from the air electrode 3 to the fuel electrode 7 to convert the hydrogen at the fuel electrode 7 to steam in the hot isolated standby mode.

In one embodiment, a hydrogen detector (e.g., a gas composition sensor) 510 in data communication with the controller 125, and located in any of the conduits 208, 210, 220, 226 and/or 206 may monitor the hydrogen level in the recycled product stream. When the detector 510 detects that the hydrogen level in the recycled product stream is below a low threshold (e.g., a low-hydrogen threshold), the controller 125 may receive the detected hydrogen level and switch the SOEC stack 100 from the hot isolated standby mode to the isolated electrolysis mode to increase the hydrogen concentration in the recycled product stream.

FIG. 6 is a diagram showing the SOEC cell 1 of the SOEC stack 100 operating in the isolated electrolysis mode. In this mode, the power supply 500 applies a DC or voltage across the electrolyzer cell 1 electrochemically that separates the steam at the fuel electrode 7 into hydrogen and oxygen ions. The oxygen ions are electrochemically transported across the electrolyte 5 from the fuel electrode 7 to the air electrode 3. When the detector 510 detects that the hydrogen level in the recycled product stream is above a high hydrogen threshold, the controller 125 may receive the detected hydrogen level and switch the SOEC stack 100 from the isolated electrolysis mode back to the hot isolated standby mode.

This cycle may continue repeatedly and may be assisted by one or more heaters 350, 360 and/or 370 which remain on during both the isolated electrolysis mode and hot isolated standby mode to maintain sufficiently high operating temperatures when the electrolyzer module is isolated for multiple cycles.

FIG. 7 is a flow diagram illustrating a method of operating an electrolyzer system 200, according to various embodiments of the present disclosure. The operations of the process 700 may be performed by one or more of the components described above including the controller 125, the power supply 500, the detector 510 and the isolation valves 221, 251, 253.

At block 702, the electrolyzer system 200 or 800 may initially enter the isolated hot standby mode by closing the isolation valves such that it is fluidically isolated on the fuel side. At block 704, the hot standby mode may continue the hydrogen reaction until the hydrogen is sufficiently depleted. As described above, the isolated hot standby mode may slowly deplete the hydrogen in the cells 1 as it recirculates in the isolated loop. The controller 125 of the electrolyzer system may monitor the hydrogen level using the detector 510 and then proceed to block 706 if the low hydrogen threshold is reached (i.e., detected).

At block 706, the electrolyzer system may enter the isolated electrolysis mode by supplying a relatively small direct current (DC) (e.g., 0.1 to 0.2 amps) from the power supply 500 to the SOEC stack 100 and converting steam to hydrogen at the fuel electrodes 7 of the cells 1 in the stack 100. In other words, while the electrolyzer system may be fluidically isolated on the fuel side, the SOEC stack 100 may receive power as an input. The power induces an electrolysis reaction at the fuel electrodes 7 of the cells 1 in the stack 100 that converts the steam into hydrogen and replenishes the hydrogen circulating in the isolated system. The controller 125 of the electrolyzer system may monitor the hydrogen level in the recycled product stream either periodically or continuously using the detector 510. The isolation valves 221, 251, 253 remain closed.

At block 708, if the high hydrogen threshold is detected by the detector 510, the controller 125 switches the electrolyzer system back to the hot standby mode of block 702. The isolation valves 221, 251, 253 remain closed. This cycle of steps 702 to 708 may repeat as needed to keep the electrolyzer module offline at high temperature.

Thus, in the embodiment of FIG. 5-7, the electric power is not provided to the at least one stack 100 of electrolyzer cells 1 during the hot isolated standby mode. The electrolyzer system (200, 800) is alternately operating in the hot isolated standby mode or in the isolated electrolysis mode. In the isolated electrolysis mode, the electric power is provided to the at least one stack 100 of electrolyzer cells 1 while recycling the hydrogen containing product stream through the at least one stack 100 of electrolyzer cells 1 and providing the heat to the at least one stack 100 of electrolyzer cells 1, while not providing the steam or the external hydrogen from outside the electrolyzer system to the at least one stack 100 of electrolyzer cells 1, and not providing the hydrogen containing product stream to the hydrogen processor.

The method further comprises reacting hydrogen in the recycled hydrogen containing product stream with oxygen (e.g., leaking oxygen) to generate steam at fuel electrodes 7 of the at least one stack 100 of electrolyzer cells 1 operating in the hot isolated standby mode until the hydrogen level reaches a low threshold value. The method further comprises operating the at least one stack 100 of electrolyzer cells 1 in the isolated electrolysis mode by supplying the electric power to at least one stack 100 of electrolyzer cells 1 to electrolyze the steam into the hydrogen and the oxygen until the hydrogen level reaches a high threshold value. The oxygen generated by electrolysis is transported from the fuel electrodes 7 to air electrodes 3 through electrolytes 5 of the at least one stack 100 of electrolyzer cells 1 during the isolated electrolysis mode. The method also includes operating the at least one stack 100 of electrolyzer cells 1 in the hot isolated standby mode by stopping the provision of the electric power to the at least one stack of electrolyzer cells when the hydrogen level reaches a high threshold value in the isolated electrolysis mode.

In another embodiment, rather than detecting hydrogen levels in the product stream and periodically switching between the hot isolated standby mode and the isolated electrolysis mode, the direct current or voltage (i.e., power) may be continuously applied to the SOEC stack 100 from the power supply 500 throughout the hot isolated standby mode. In one embodiment, the electric power that is provided to the at least one stack of electrolyzer cells is controlled by the controller to a cell voltage within a predetermined (e.g., allowable) cell voltage tolerance range during the hot isolated standby mode.

With the electrolyzer system (e.g., module) fluidly isolated on the fuel side, the system voltages may be used as a Proportional-Integral-Derivative (PID) process control variable to maintain a steady cell charge which may correspond to a favorable, constant recycled product stream composition that protects cell health (e.g., prevents nickel mesh and fuel electrode oxidization). Thus, in one embodiment, the applied voltage to the SOEC stack 100 may be selected such that neither the electrolysis reaction (i.e., the splitting of steam into hydrogen and oxygen) nor the reverse “fuel cell” reaction (i.e., oxidation of hydrogen to generate steam) dominate. Thus, substantially no hydrogen is created or depleted during the hot isolated standby mode. In this method, the SOEC cells 1 generate a charged field where neither oxygen leakage nor hydrogen generation affects the fuel electrode composition. In one embodiment, in this mode, the hydrogen in the product stream may react with leaked oxygen to generate steam as hydrogen passes past the fuel electrode which may simultaneously be offset by electrolysis of the steam to generate hydrogen and oxygen to maintain the equilibrium including a given hydrogen level between the high hydrogen condition and the low hydrogen condition. This method reduces the total power consumption versus switching back and forth between the two modes.

Thus, in this alternative embodiment, the electric power is provided to the at least one stack 100 of electrolyzer cells 1 during the hot isolated standby mode is controlled to a cell voltage in the predetermined range (e.g., the electric power is controlled to be at a predetermined level) at which neither an electrolysis reaction nor a reverse steam generation reaction comprising oxidation of the hydrogen dominate, and substantially no hydrogen is created or depleted during the hot isolated standby mode.

FIG. 8A is a schematic view of an alternative electrolyzer system 800 operating in steady state mode to generate a hydrogen containing product stream according to another alternative embodiment. The system 800 includes a plurality of electrolyzer modules 802, 804, 806, 808, according to various embodiments of the present disclosure. Each of the electrolyzer modules 802, 804, 806, 808 may corresponds to a respective system 200 shown in FIG. 2. Thus, each of electrolyzer modules 802, 804, 806, 808 may include a cabinet containing the hotbox 300 and its balance of plant components, such as the blowers 118, 126 and the mixer 106, and optionally the controller 125. While four electrolyzer modules are shown, the system 800 may include any number of electrolyzer modules. Furthermore, the system 800 may also include a power module including a system AC/DC inverter, DC/DC converters and a system controller. The DC/DC converters may be located in each respective electrolysis module or in the common power module.

In the system 800, plural electrolyzer modules 802-808 may share a common product line (e.g., hydrogen product manifold) 810 and a common steam line (e.g., steam inlet manifold) 820. The common product line 810 is fluidly connected to a common hydrogen processor 120. Thus, the hydrogen product conduit 220 described above in each electrolyzer module 802-808 is fluidly connected to the common product line 810. The common steam line 820 is fluidly connected to a common water source 52 and/or steam generator 104. Thus, the steam and hydrogen conduit 206 described above in each electrolyzer module 802 - 808 is fluidly connected to the common steam line 820.

The system 800 includes an individual input valve 832, 834, 836, and 838 for each respective module 802, 804, 806 and 808, and an individual output valve 842, 844, 846, and 848 for each respective module 802, 804, 806 and 808. The input valves correspond to the water control valve 251 and the output valves correspond to the product valve 221 described above.

The common product line 810 also includes a shut-off valve 852 upstream of the common hydrogen processor 120 and an optional safety vent valve 850 on an emergency vent outlet. The safety vent valve 850 may be closed in steady state mode and opened in an emergency operating mode to vent excess pressure from the line 810.

During steady state mode operation, the input valves 832, 834, 836, and 838 and the output valves 842, 844, 846, 848 are open. The common steam line 820 provides a respective steam inlet stream 832a, 834a, 836a, 838a to the respective electrolyzer modules 802, 804, 806 and 808 via respective conduits 206 and the open input valves 832, 834, 836, and 838. The electrolyzer modules 802 - 808 output a respective product stream (e.g., hydrogen and steam mixture) 842a, 844a, 846a, 848a and through the respective conduits 220 and the respective open output valves 842, 844, 846, 848 to the common product line 810. The common product line 810 provides the combined product streams to the hydrogen processor 120 through the open shutoff valve 852. The safety vent valve 850 is closed during the steady state mode.

FIG. 8B is a schematic view of the electrolyzer system 800 operating in the isolated mode in which the shutoff valve 852 on the common product line 810 is closed. Thus, the hydrogen containing product stream is not provided to the hydrogen processor 120 in this mode. Closing the shutoff valve 852 and safety vent valve 850 traps the hydrogen containing product within the common product line 810.

In this mode, the hydrogen generated by one or more electrolyzer modules (e.g., 802) may be re-directed to feed one or more remaining electrolyzer modules (e.g., 804, 806, 808) of the system 800 operating in hydrogen-consuming states. In this case, the electrolyzer module(s) 802 feeding hydrogen to the remaining modules may operate in the steady state mode and supply the hydrogen containing product stream to the common product line 810, while the hydrogen-consuming electrolyzer modules 804, 806, 808 are switched to receive hydrogen from the common product line 810 via the respective conduits 220. The hydrogen-consuming electrolyzer modules 804, 806, 808 may operate in the same manner as the electrolyzer cells described above operating in the hot standby mode where hydrogen is slowly consumed to preserve cathode health, as described above.

Thus, in the isolated mode some of the inlet valves 832 - 838 are open and other inlet valves 832-838 are closed, while all outlet valves 842-848 are open. For example, inlet valve 832 to the hydrogen generating module 802 is open and inlet valves 834-838 to the hydrogen-consuming modules 804-808 are closed. The hydrogen containing product 844a, 846a, 848a flow direction through outlet valves 844, 846, and 848 is reversed compared to steady state mode. The hydrogen containing product flows from the hydrogen-generating module 802 to the common product line 810 and from the common product line 810 to the hydrogen-consuming modules 804, 806, 808.

The pressure in the common product line 810 may be periodically or continuously monitored to control the hydrogen containing product output by the hydrogen-producing module 802 to maintain a constant pressure in the common product line 810. Excess pressure built up in the common product line 810 from excess product produced by hydrogen-producing module 802 may be released by opening the safety vent valve 850 on the common product line 810.

The SEOC stack 100 voltages in each hydrogen-consuming module 804, 806, 808 may be monitored to evaluate if a sufficient amount of hydrogen is being received from the product line 810 and flowing over the fuel electrode of each cell. Alternatively, the detectors 510 described above may be used to measure the hydrogen concentration provided to the SOEC stacks 100 in the hydrogen-consuming modules 804, 806, 808.

In response to determining that more hydrogen is needed, the hydrogen-producing module 802 may be controlled by a system controller to produce more hydrogen (e.g., by increasing the power applied by its power supply 500 and/or by increasing the amount of steam provided to this module 802). In response to determining that less hydrogen is needed, the hydrogen-producing module 802 may be controlled by a system controller to produce less hydrogen (e.g., by decreasing the power applied by its power supply 500 and/or by decreasing the amount of steam provided to this module 802). The hydrogen-generating module 802 may ramp up and down the electrolysis to maintain the desired pressure and amount of hydrogen in the common product line 810.

The recycle blower 126 in each hydrogen-consuming electrolyzer module 804 808 may recycle the hydrogen and steam product mixture within each hot box as described with respect to FIG. 4. The hydrogen supplied from the common product line 810 to each hydrogen recycle conduit 220 and open outlet valve may comprise an equilibrium amount of hydrogen without switching the hydrogen-consuming electrolyzer module to an isolated electrolysis mode. That is, the externally supplied hydrogen from the hydrogen-producing electrolyzer module 802 may permit the hydrogen-consuming electrolyzer module(s) 804-808 to operate continuously in the hot standby mode.

Thus, in this alternative embodiment, the at least one stack 100 of electrolyzer cells 1 comprises a plurality of the stacks of electrolyzer cells, and the electrolyzer system 800 comprises a plurality of electrolyzer modules 802-808 each containing a respective hotbox housing a respective portion of the plurality of the stacks 100 of electrolyzer cells 1. In the steady state mode, the steam is provided to the plurality of electrolyzer modules through a common steam line 820, and the hydrogen containing product stream is provided from the plurality of electrolyzer modules to the hydrogen processor 120 through a common product line 810.

In the hot isolated standby mode, the common product line 810 is fluidly isolated from the hydrogen processor 120 (e.g., by closing the product valve 852 on the common product line 810), the steam is provided to least one hydrogen-generating module 802 of the plurality of electrolyzer modules without providing the steam to remaining hydrogen-consuming modules 804-808 of the plurality of electrolyzer modules (e.g., by opening the water control valve 832 on the steam conduit 206 of at least one hydrogen-generating module 802, and closing the water control valves 834-838 on the steam conduits 206 of remaining hydrogen-consuming modules (804-808), electrolyzing the steam in the at least one hydrogen-generating module 802 to generate the hydrogen containing product stream, and providing the hydrogen containing product stream to the hydrogen-consuming modules 804-808 through the common product line 810.

The preceding description of the disclosed aspects is provided to enable any person skilled in the art to make or use the present invention. Various modifications to these aspects will be readily apparent to those skilled in the art, and the generic principles defined herein may be applied to other aspects without departing from the scope of the invention. Thus, the present invention is not intended to be limited to the aspects shown herein but is to be accorded the widest scope consistent with the principles and novel features disclosed herein.