Patent Publication Number: US-2023155214-A1

Title: Electrolyzer system with steam generation and method of operating same

Description:
FIELD 
     The present invention is directed to electrolyzer systems including solid oxide electrolyzer cells (SOEC) and methods of operating the same. 
     BACKGROUND 
     Solid oxide fuel cells (SOFC) can be operated as an electrolyzer in order to produce hydrogen and oxygen, referred to as solid oxide electrolyzer cells (SOEC). In SOFC mode, oxide ions are transported from the cathode side (air) to the anode side (fuel) and the driving force is the chemical gradient of partial pressure of oxygen across the electrolyte. In SOEC mode, a positive potential is applied to the air side of the cell and the oxide ions are now transported from the fuel side to the air side. Since the cathode and anode are reversed between SOFC and SOEC (i.e. SOFC cathode is SOEC anode, and SOFC anode is SOEC cathode), going forward, the SOFC cathode (SOEC anode) will be referred to as the air electrode, and the SOFC anode (SOEC cathode) will be referred to as the fuel electrode. During SOEC mode, water in the fuel stream is reduced (H 2 O+2e→O 2− +H 2 ) to form H 2  gas and O 2−  ions, O 2−  ions are transported through the solid electrolyte, and then oxidized on the air side (O 2−  to O 2 ) to produce molecular oxygen. Since the open circuit voltage for a SOFC operating with air and wet fuel (hydrogen, reformed natural gas) is on the order of 0.9 to 1V (depending on water content), the positive voltage applied to the air side electrode in SOEC mode raises the cell voltage up to typical operating voltages of 1.1 to 1.3V. 
     SUMMARY 
     In various embodiments, provided is an electrolyzer system comprising: a steam generator configured to generate steam; a stack of solid oxide electrolyzer cells configured to generate a hydrogen stream using the steam generated by the steam generator; a hydrogen blower configured to pressurize the hydrogen stream generated by the stack; and a hydrogen processor configured to compress the pressurized hydrogen stream. 
     In various embodiments, provided is a fuel cell system comprising: a hotbox; a stack of solid oxide fuel cells disposed in the hotbox and configured to generate power; an anode tail gas oxidizer (ATO) disposed in the hotbox; a fuel exhaust processor configured to separate an anode exhaust stream received from the stack and output a carbon dioxide stream and a hydrogen stream; a hydrogen blower configured to pressurize the hydrogen stream; a hydrogen processor configured to compress the pressurized hydrogen stream; and a carbon dioxide processor configured to compress the carbon dioxide stream. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       The accompanying drawings, which are incorporated herein and constitute part of this specification, illustrate example embodiments of the invention, and together with the general description given above and the detailed description given below, serve to explain the features of the invention. 
         FIG.  1 A  is a perspective view of a solid oxide electrolyzer cell (SOEC) stack, and  FIG.  1 B  is a side cross-sectional view of a portion of the stack of  FIG.  1 A . 
         FIGS.  2 A and  2 B  are schematic views of process flow diagrams showing process flows through an electrolyzer system according to various embodiments of the present disclosure. 
         FIG.  3    is a schematic view showing a process flow in an alternative electrolyzer system  201 , according to various embodiments of the present disclosure. 
         FIG.  4    is a schematic representation of a solid oxide fuel cell (SOFC) system, according to various embodiments of the present disclosure. 
         FIG.  5    is a schematic view showing a process flow in a fuel processor of the fuel cell system of  FIG.  4   , according to various embodiments of the present disclosure. 
     
    
    
     DETAILED DESCRIPTION 
     The various embodiments will be described in detail with reference to the accompanying drawings. Wherever possible, the same reference numbers will be used throughout the drawings to refer to the same or like parts. References made to particular examples and implementations are for illustrative purposes, and are not intended to limit the scope of the invention or the claims. 
     Ranges can be expressed herein as from “about” one particular value, and/or to “about” another particular value. When such a range is expressed, examples include from the one particular value and/or to the other particular value. Similarly, when values are expressed as approximations, by use of the antecedent “about” or “substantially” it will be understood that the particular value forms another aspect. In some embodiments, a value of “about X” may include values of +/−1% X. It will be further understood that the endpoints of each of the ranges are significant both in relation to the other endpoint, and independently of the other endpoint. 
     It will be apparent to those skilled in the art that various modifications and variations can be made to the present disclosure without departing from the spirit and scope of the disclosure. Since modifications combinations, sub-combinations and variations of the disclosed embodiments incorporating the spirit and substance of the disclosure may occur to persons skilled in the art, the disclosure should be construed to include everything within the scope of the appended claims and their equivalents. 
     Herein, a “solid oxide cell” may refer to a solid oxide electrolyzer cell and/or a solid oxide fuel cell. 
     SOEC Systems 
       FIG.  1 A  is a perspective view of a solid oxide cell stack  100 , and  FIG.  1 B  is a side cross-sectional view of a portion of the stack  100  of  FIG.  1 A . Referring to  FIGS.  1 A and  1 B , the stack  100  includes multiple solid cells  1  that may be solid oxide fuel cells or solid oxide electrolyzer cells. The solid oxide cells  1  are separated by interconnects  10 , which may also be referred to as gas flow separator plates or bipolar plates. Each solid oxide cell  1  includes an air electrode  3 , a solid oxide electrolyte  5 , and a fuel electrode  7 . The stack  100  also includes internal fuel riser channels  22 . 
     Each interconnect  10  electrically connects adjacent solid oxide cells  1  in the stack  100 . In particular, an interconnect  10  may electrically connect the fuel electrode  7  of one solid oxide cell  1  to the air electrode  3  of an adjacent solid oxide cell  1 .  FIG.  1 B  shows that the lower solid oxide cell  1  is located between two interconnects  10 . 
     Each interconnect  10  includes ribs that at least partially define fuel channels  8  (collectively, layer  9 ). The interconnect  10  may operate as a gas-fuel separator that separates a fuel, such as a hydrocarbon fuel, flowing to the fuel electrode  7  of one solid oxide cell  1  in the stack  100  from oxidant, such as air, flowing to the air electrode  3  of an adjacent solid oxide 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. 
       FIGS.  2 A and  2 B  are schematic views showing a process flows in an electrolyzer system  200 , according to various embodiments of the present disclosure. Referring to  FIGS.  1 A,  1 B,  2 A and  2 B , the system  200  may include an electrolyzer cell (SOEC) stack  100  including multiple solid oxide electrolyzer cells (SOECs), which may be configured as described with respect to  FIGS.  1 A and  1 B . The system  200  may also include a steam generator  104 , a steam recuperator  108 , a steam heater  110 , an air recuperator  112 , and an air heater  114 . The system  200  may also include an optional water preheater  102  and an optional mixer  106 . 
     The system  200  may include a hotbox  250  to house various components, such as the stack  100 , steam recuperator  108 , steam heater  110 , air recuperator  112 , and/or air heater  114 . In some embodiments, the hotbox  250  may include multiple stacks  100 . The water preheater  102  and the steam generator  104  may be located external to the hotbox  250  as shown in  FIGS.  2 A and  2 B . Alternatively, the water preheater  102  and/or the steam generator  104  may be located inside the hotbox  250 . 
     During operation, the stack  100  may be provided with steam and electric 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 molecules and generate hydrogen (e.g., H 2 ) and oxygen (e.g., O 2 ). 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 may be deionized (DI) water that is deionized as much as is practical (e.g., &lt;0.1 μS/cm), in order to prevent and/or minimize scaling during vaporization. In some embodiments, the water source  50  may include deionization beds. In various embodiments, the system  200  may include a water flow control device (not shown) such as a mass flow controller, a positive displacement pump, a control valve/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 . The water preheater  102  may be a heat exchanger configured to heat the water using heat recovered from the oxygen exhaust stream. 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 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 110° C. to 120° C. 
     The water output from the water preheater  102  or the water source  50  may be provided to the steam generator  104 . A portion of the water may vaporize in the water preheater. The steam generator  104  may be configured to heat the water not vaporized in the water preheater to convert the water into steam. For example, 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. 
     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 to ambient conditions. 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. 
     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. 10× the steady state flow for 6 seconds out of every minute, 5× 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. 
     The steam output from the steam generator  104  may be provided to the steam recuperator  108 . 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 . In particular, the steam may include small amounts of dissolved air and/or oxygen. As such, 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  52  and/or with a portion of the hydrogen 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 may optionally be omitted. 
     In some embodiments, the hydrogen may be provided by the external hydrogen source during system startup and/or during steady-state operations. For example, during startup, the hydrogen may be provided from the hydrogen storage device, and during steady-state, the hydrogen may be provided from the hydrogen storage device  52  and/or by diverting a portion of the hydrogen stream (i.e., hydrogen exhaust stream) generated by the stack  100  to the mixer  106 . In particular, the system  200  may include a hydrogen diverter  116 , such as a splitter, pump, blower and/or valve, configured to selectively divert a portion of the generated hydrogen stream to the mixer  106 , during steady-state operation. 
     The steam recuperator  108  may be a heat exchanger configured to recover heat from the hydrogen stream output from the stack  100 . As such, the steam recuperator  108  may be configured to increase the efficiency of the system  200 . The steam may be heated to at least 700° C., such as 720° C. to 780° C. in the steam recuperator  108 . 
     The steam output from the steam recuperator  108  may be provided to the steam heater  110  which is located downstream from the steam recuperator  108 , as shown in  FIG.  2 A . The steam heater  110  may include a heating element, such as a resistive or inductive heating element. The steam heater  110  may be configured to heat the steam to a temperature above the operating temperature of the stack  100 . For example, depending on the health of the stack  100 , the water utilization rate of the stack  100 , and the air flow rate to the stack  100 , the steam heater  110  may heat the steam to a temperature ranging from about 900° C. to about 1200° C., such as 920° C. to 980° C. Accordingly, the stack  100  may be provided with steam or a steam-hydrogen mixture at a temperature that allows for efficient hydrogen generation. Heat may also be transported directly from the steam heater to the stack by radiation (i.e., by radiant heat transfer). 
     In one alterative embodiment shown in  FIG.  2 B , the steam recuperator  108  may be located downstream from the steam heater  110  such that steam existing the steam heater  110  enters the steam recuperator  108  instead of vice-versa. In another alternate embodiment, the steam heater  110  may include a heat exchanger configured to heat the steam using heat extracted from a high-temperature fluid, such as a fluid heated to about 1200° C. or more. This fluid may be provided from a solar concentrator farm or a power plant, such as a nuclear reactor power plant, for example. Alternatively, if the fluid is a high temperature steam, such as steam provided from a nuclear reactor power plant, then such steam may be provided to the fuel electrodes  7  of the stack  100 . In this case, the water source  50  may comprise a source of high temperature steam, and one or more of the water preheater  102 , steam generator  104 , steam recuperator  108  and/or steam heater  110  may be omitted. 
     In some embodiments, the steam heater  110  may include multiple steam heater zones with independent power levels (divided vertically or circumferentially or both), in order to enhance thermal uniformity, in some embodiments. 
     In some embodiments, the operations of the steam recuperator  108  and the steam heater  110  may be combined into a single component. For example, the steam recuperator  108  may include a voltage source configured to apply a voltage to heat exchange fins of the steam recuperator  108 , such that the heat exchange fins operate as resistive heating elements and heat the steam to a temperature high enough to be provided to the stack  100 , such as a temperature ranging from about 900° C. to about 1200° C. The high temperature steam (or optionally a steam/hydrogen mixture) output from the steam heater  110  may be provided to the fuel electrodes  7  of the stack  100 . 
     The oxygen exhaust output from the stack  100  may be provided to the air recuperator  112 . The air recuperator  112  may be provided with ambient air by an air blower  118 . The air recuperator  112  may be configured to heat the air using heat extracted from the oxygen exhaust. In some embodiments, the ambient air may be filtered to remove contaminants, prior to being provided to the air recuperator  112  or the air blower  118 . 
     Air output from the air recuperator  112  may be provided to the air heater  114 . The air heater may include a resistive or inductive heating element configured to heat the air to a temperature exceeding the operating temperature of the stack  100 . For example, depending on the health of the stack  100 , the water utilization rate of the stack  100 , and the air flow rate to the stack  100 , the air heater  114  may heat the air to a temperature ranging from about 900° C. to about 1200° C., such as 920° C. to 980° C. Accordingly, the stack  100  may be provided with air at a temperature that allows for efficient hydrogen generation. Heat may also be transported directly from the air heater to the stack by radiation. 
     The higher the temperature output from the air recuperator, the less power is required for the air heater  114 . Increased pressure drop on either side of the air recuperator  112  may be counteracted with increased air blower  118  power. Increased pressure drop may aid the circumferential mass flow uniformity, creating a more uniform heat transfer environment, and higher temperature for the air inlet stream output from the air recuperator  112 . 
     In alternative embodiments, the air heater  114  may include a heat exchanger configured to heat the air using heat extracted from a high-temperature fluid, such as a fluid heated to about 1200° C., or more. This fluid may be provided from a solar concentrator farm or a nuclear reactor, for example. 
     The air heater  114  may include multiple air heater zones with independent power levels (divided vertically or circumferentially or both), in order to enhance thermal uniformity, in some embodiments. In some embodiments, the air heater  114  may be disposed below the air recuperator  112 , or between the stack  100  and the steam recuperator  108 . The air heater  114  may include baffles having slits of different sizes at different heights along the baffles, to allow air to exit the air heater  114  approximately evenly in both temperature and height, at all heights along the air heater  114 . Air from the air heater  114  is provided to the air electrodes  3  of the stack  100 . 
     In some embodiments, the air recuperator  112  and the air heater  114  may be combined into a single component. For example, the air recuperator  112  may include a voltage source configured to apply a voltage to heat exchange fins of a heat exchanger included in the air recuperator  112  combined component, such that the fins operate as resistive heating elements and heat the air to a temperature high enough to be provided to the stack  100 , such as a temperature ranging from about 900° C. to about 1200° C. 
     According to various embodiments, the system  200  may include an optional air preheater  54  disposed outside of the hotbox  250 . In particular, the air preheater  54  may be configured to preheat air provided to the hotbox  250  by the air blower  118 . In some embodiments, the air preheater  54  may operate using electricity. In other embodiments, the air preheater  54  may operate using a hydrocarbon fuel, such as natural gas or the like. For example, if the system  200  is provided with power from a power source that is intermittent or provides an insufficient amount of power to operate an electric heater, such solar or wind power generation systems, the air preheater  54  may utilize a hydrocarbon power source (e.g., a gas heater). Alternatively, the air preheater  54  may be omitted. 
     Because the air preheater  54  is located outside of the hotbox  250 , the air preheater  54  may be advantageously serviced without the need to access the inside of the hotbox  250  and/or interrupt the operation of the stack  100  and/or other components located inside of the hotbox  250 . In some embodiments, the air preheater  54  may allow for the air heater  114  to be omitted if the air preheater  54  heats the air above stack temperature. However, in other embodiments, the system  200  may include both the air preheater  54  and the air heater  114 . 
     During system startup, the air preheater  54  may be configured to heat air provided to the hotbox to a temperature sufficient to increase the internal temperature of the hotbox  250  and/or the temperature of the stack  100  up to a temperature approaching the operating temperature thereof. Preheated air provided to the air recuperator  112  may also operate to preheat stack exhaust provided through the air recuperator  112  to the water preheater  102  during system startup. Since the stack oxygen exhaust may be initially output at a relatively low temperature, the air preheater  54  may be used to indirectly preheat the water provided from the water source  50  to the hotbox  250 . 
     During steady-state operation, the air preheater  54  may also be configured heat air to a temperature sufficient to maintain the hotbox  250  at steady-state operating temperature, such as 750 to 950° C. For example, the heat output of the air preheater  54  may be lower during steady-state operation than during system startup. 
     In some embodiments, the system  200  may be operated in a thermal neutral configuration, where each electrolyzer cell  1  in the stack  100  is provided with a thermal-neutral voltage. In particular, the current provided to each electrolyzer cell  1  may be varied such that the heat generated by I 2 R heating balances the (endothermic) heat of reaction. As such, use of the steam heater  110  and/or the air heater  114  may be minimized or eliminated during steady-state thermal neutral operation. 
     A hydrogen stream (i.e., hydrogen exhaust stream) from the stack  100  may be a warm stream containing hydrogen gas and water. The hydrogen stream may be output from the steam recuperator  108  at a temperature of 120° C. to 150° C. The steam recuperator  108  may be fluidly connected to a hydrogen processor  500  by an output conduit  502 . In some embodiments, the hydrogen processor  500  may be connected to, a hydrogen storage device or tank  504 . 
     The hydrogen processor  500  may include a hydrogen pump, a condenser, or a combination thereof. The hydrogen pump may be an electrochemical hydrogen pump and/or may be configured to operate at a high temperature. For example, the hydrogen pump may be configured to operate at a temperature of from about 120° C. to about 150° C., in order to remove from about 70% to about 90% of the hydrogen from the hydrogen stream. The compressor may be a liquid ring compressor or a diaphragm compressor, for example. In some embodiments, the condenser may be an air-cooled or water-enhanced, air-cooled condenser and/or heat exchanger configured to cool a hydrogen stream to a temperature sufficient to condense water vapor in the hydrogen stream. For example, the hydrogen processor  500  may be configured to compress the hydrogen stream to a desired pressure, such as about 2500 to about 8000 psig. Compression may include multiple stages, with inter-stage cooling, and water removal. 
     In various embodiments, the hydrogen processor  500  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 stream, in order to compress the hydrogen stream. The final product from compression may still contain traces of water. As such, the hydrogen processor  500  may include a dewatering device, such as a temperature swing adsorption reactor or a pressure swing adsorption reactor, to remove this residual water, if necessary. The final product may be high pressure (e.g., about 2500 to about 8000 psig) purified, hydrogen. The product may also contain some nitrogen gas, which may be dissolved air in the water. The nitrogen may be removed automatically during electrochemical compression. 
     A remaining un-pumped effluent from the hydrogen processor  500  may be a water rich stream that is fully vaporized. This water rich stream may be fed to a blower for recycle into the mixer  106  or stream recuperator  108 , eliminating the need for water vaporization in the steam generator  104 . The system may be configured to repurify (e.g., in DI beds) the residual water and provide the residual water removed from the compressed hydrogen stream to the water preheater. Electrochemical compression may be more electrically efficient than traditional compression. 
     The hydrogen streams of multiple stacks  100  on site may be combined into a single stream. This combined stream may be cooled as much as practical using, for example, air coolers or heat exchangers cooled by a site cooling water tower, which may be part of the hydrogen processor  500 . The hydrogen output from the hydrogen processor  500  may be provided to the hydrogen tank  504  for storage or use, such as to be used as a fuel in a fuel cell power generation system. 
     Steam loss into the hydrogen stream may be minimized by increasing the hydrogen pump pressure to a pressure ranging from about 20-50 psig, for example. This separation may be at the electrolyzer module level, system level, stamp level, or site level. 
     Water condensation and compression of the hydrogen stream may consume a significant amount of power. In some embodiments, air flow to the stack  100  may be reduced or stopped, such that the stack  100  outputs pure or nearly pure oxygen gas as stack exhaust. In addition, the air and fuel sides of the electrolyzer cells  1  may be operated at an equal pressure ranging from about 20 psig to about 50 psig. In some embodiments, air provided to the stack  100  may be provided at a pressure of about 100 slm or less. 
     High pressure operation may allow for the elimination of the power and equipment associated with the first stage of the hydrogen stream compression, may reduce the size of the initial condenser stage, due to the higher dew point due to the higher pressure, and/or may reduce the physical space required for flow channels, due to the higher density associated with higher pressure. 
     As noted above, the system  200  may be configured to operate with a variety of different hydrogen processors  500 , which may be provided on site by a third party. As such, it may be difficult to match the flow and/or production rate of the hydrogen stream output from the system  200  with the throughput of a particular hydrogen processor  500 . In particular, such variations may induce positive and/or negative pressure fluctuations within the output conduit  502 . For example, if the throughput of the hydrogen processor  500  is too high (e.g., the hydrogen processor  500  pulls too hard on the hydrogen stream) a negative pressure may be induced within the system  200 , or if the throughput is too low, a positive pressure may be induced within the system  200 . 
     Such pressure fluctuations may cause problems within the system  200 . For example, excessive negative pressures may result in air leaking into the system  200 , or may result in a high pressure variation across the electrolytes of the stack  100 , which may increase the risk of electrolyte damage, such as cracking. Excessively high pressures may also result in pressure variations across the electrolytes and increase the risk of electrolyte damage. 
     Accordingly, the system may include a first output conduit  502 A, a second output conduit  502 B, and a hydrogen blower  510 . The first output conduit  502 A may fluidly connect the fuel cell stack  100  and an inlet of the hydrogen blower  510 . The second output conduit  502 B may fluidly connect an outlet of the hydrogen blower  510  to the hydrogen processor  500 . The hydrogen blower  510  may be configured to increase the pressure of the hydrogen stream output from the hotbox  250 . For example, the hydrogen blower  510  may be configured to increase the pressure of a hydrogen stream by from about 2 to about 15 pounds per square in gauge (psig), such as from about 5 to about 10 psig. The hydrogen blower  510  may also operate to isolate the components of the hotbox  250 , such as the stack  100 , from pressure fluctuations induced by the operation of the hydrogen processor  500 . 
     In some embodiments, the hydrogen blower  510  may be configured to receive a hydrogen stream generated by a single electrolyzer system  250  or stack  100 , as shown in  FIG.  2 A . In other embodiments, the hydrogen blower  510  may be configured to receive hydrogen streams generated by multiple electrolyzer systems  250  and/or by multiple stacks  100 . 
     In various embodiments, the system  200  may include an optional water knockout device  530  configured to remove condensed water from the hydrogen stream, in order to reduce and/or prevent liquid water accumulation in the hydrogen blower  510 . 
     In some embodiments, the hydrogen diverter  116  may be used to divert the hydrogen stream, such that hydrogen may be fed to displace most or all of the steam in the system  200 . The hydrogen diverter  116  may then closed to maintain a reducing atmosphere in the stack  100 , without any additional hydrogen consumption. Air flow to the stack  100  may be significantly reduced or eliminated. In some embodiments, there may be a minimum air flow to keep the air heater  114  from overheating. 
     In some embodiments, condensed water may be recycled to the feed of the process (feed to the DI beds) in the water source  50 . Hydrogen added to the steam in the mixer  106  may be produced during the first stage or any intermediate stage of the compression train, and may be dehumidified if necessary. The hydrogen storage device  52  may include a low/intermediate pressure storage tank for the hydrogen provided through the mixer  106  to the stack  100 . 
     According to various embodiments, the system  200  may include a controller  125 , such as a central processing unit, that 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. 
     In some embodiments, the controller  125  may be configured to control the speed of the hydrogen blower  510  based on a flow rate of the hydrogen stream and/or an inlet pressure generated by the hydrogen processor  500 . 
     In some embodiments, the controller  125  may be configured to control the system  200 , such that the system  200  may be operated in a standby mode where no hydrogen stream is generated. During the standby mode, electrical heaters associated with (i.e., located in a heat transfer relationship with) the stack  100  may be run at the minimum power level needed to keep the electrolyzer cells  1  at a desired standby temperature. The desired standby temperature may be different from the desired production operating temperature, and may be impacted by an acceptable time needed to return to a desired operating temperature. 
     Recovery from standby mode to steady-state operation may allow for hydrogen generation to be initiated at a lower temperature than the standard steady-state operating temperature. At the lower temperature, cell resistance may be higher, which may provide additional heating to increase the stack  100  to the steady-state operating temperature. 
     Water/steam feed can be significantly reduced or eliminated. Hydrogen addition to the steam in the mixer  106  may also be significantly reduced or eliminated. 
     According to various embodiments, the controller  125  may be configured to control the operation of the system  200  based on various site-wide control parameters. For example, the controller  125  may be configured to control hydrogen production based on any of: the operational limits of each SOEC stack; power availability; instantaneous average power costs, including the impact of demand charges at all tiers; instantaneous marginal power costs, including the impact of demand charges at all tiers; instantaneous power renewable content; available hydrogen storage capacity; stored energy available for use (e.g., either thermal storage or electrical storage); a hydrogen production plan (e.g., a daily, weekly, or month plan, etc.); hydrogen production revenue implications (e.g., sales price, adjustments for production levels, penalties for nonperformance, etc.); a maintenance plan; the relative health of all hotboxes on site; the compression/condensation train mechanical status; the water/steam/hydrogen feed availability; the weather conditions and/or forecast; any other known external constraints, either instantaneous, or over some production plan period (e.g., only allowed so much water per month, or so many MW-hr per month); and/or the minimum acceptable time to start producing hydrogen from standby mode (if standby is predicted to last multiple hours, it may be desirable to allow the cells to cool below operating temperature). 
       FIG.  3    is a schematic view showing a process flow in an alternative electrolyzer system  201 , according to various embodiments of the present disclosure. The electrolyzer system  201  may be similar to the electrolyzer system  200 , so only the differences there between will be discussed in detail. 
     Referring to  FIG.  3   , the electrolyzer system  201  may include an air preheater  154  disposed inside of the hotbox  250 . The air preheater  154  may be a heat exchanger configured to preheat air provided from the air blower  118 , using heat extracted from the hydrogen stream output from the steam recuperator  108 . The preheated air may then be provided to the air recuperator  112 . Thus, the internal air preheater  154  located inside the hotbox  250  replaces the external air preheater  54  (shown in  FIGS.  2 A and  2 B ) located outside the hotbox  250 . In this embodiment, additional electricity or an additional gas heater is not required to provide heat to the air preheater  154 . The air preheater is also beneficial in that the hydrogen/steam stream to the hydrogen diverter  116  is substantially cooler, allowing the hydrogen separator to be made of cheaper materials. 
     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 . 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. The hot oxygen exhaust stream may have a temperature above 100° C., such as 110 to 130° C., for example 120° C. ° C. As such, 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  201 . The system  201  may optionally include a pump  124  configured to pump and regulate the liquid water discharge output from the steam generator  104  into the oxygen exhaust output from the water preheater  102 . Optionally, a proportional solenoid valve may be added in addition to the pump  124  to additionally regulate the flow of the liquid water discharge. 
     SOFC Systems 
       FIG.  4    is a schematic representation of a solid oxide fuel cell (SOFC) system  300 , according to various embodiments of the present disclosure. Referring to  FIG.  4   , the system  300  includes a hotbox  350  and various components disposed therein or adjacent thereto. The hotbox  350  may contain at least one fuel cell stack  302 , such as a solid oxide fuel cell stack containing alternating fuel cells and interconnects. One solid oxide fuel cell of the stack contains a ceramic electrolyte, such as yttria stabilized zirconia (YSZ), scandia stabilized zirconia (SSZ), scandia and ceria stabilized zirconia or scandia, yttria and ceria stabilized zirconia, an anode electrode, such as a nickel-YSZ, a nickel-SSZ or nickel-doped ceria cermet, and a cathode electrode, such as lanthanum strontium manganite (LSM). The interconnects may be metal alloy interconnects, such as chromium-iron alloy interconnects. The stacks  302  may be arranged over each other in a plurality of columns. 
     The hotbox  350  may also contain an anode recuperator  310 , a cathode recuperator  320 , an anode tail gas oxidizer (ATO)  330 , an anode exhaust cooler  340 , a vortex generator  372 , and a water injector  360 . The system  300  may also include a catalytic partial oxidation (CPOx) reactor  312 , a mixer  316 , a CPOx blower  314  (e.g., air blower), a main air blower  342  (e.g., system blower), and an anode recycle blower  318 , which may be disposed outside of the hotbox  350 . However, the present disclosure is not limited to any particular location for each of the components with respect to the hotbox  350 . 
     The CPOx reactor  312  receives a fuel inlet stream from a fuel inlet  30 , through a fuel conduit  301 A. The fuel inlet  30  may be a fuel tank or a utility natural gas line including a valve to control an amount of fuel provided to the CPOx reactor  312 . The CPOx blower  314  may provide air to the CPOx reactor  202  during system start-up. The fuel and/or air may be provided to the mixer  316  by a fuel conduit  301 B. Fuel flows from the mixer  316  to the anode recuperator  310  through a fuel conduit  301 C. The fuel is heated in the anode recuperator  310  by a portion of the fuel exhaust and the fuel then flows from the anode recuperator  310  to the stack  302  through a fuel conduit  301 D. 
     The main air blower  342  may be configured to provide an air stream (e.g., air inlet stream) to the anode exhaust cooler  340  through air conduit  302 A. Air flows from the anode exhaust cooler  340  to the cathode recuperator  320  through air conduit  302 B. The air is heated by the ATO exhaust in the cathode recuperator  320 . The air flows from the cathode recuperator  320  to the stack  302  through air conduit  302 C. 
     Anode exhaust (e.g., fuel exhaust) generated in the stack  302  is provided to the anode recuperator  310  through anode exhaust conduit  306 A. The anode exhaust may contain unreacted fuel and may also be referred to herein as fuel exhaust. The anode exhaust may be provided from the anode recuperator  310  to a shift reactor  380 , such as a water gas shift (WGS) reactor, by anode exhaust conduit  306 B. A water injector  360  may be fluidly connected to the anode exhaust conduit  306 B. The anode exhaust may be provided from the shift reactor  380  to the anode exhaust cooler  340  by anode exhaust conduit  306 C. The anode exhaust heats the air inlet stream in the anode exhaust cooler  340  and may then be provided from the anode exhaust cooler  340  to the fuel exhaust processor  400 . 
     In particular, the anode exhaust may be output from the anode exhaust cooler  340  to the fuel exhaust processor  400  by a first recycling conduit  308 A. In some embodiments, anode exhaust may be provided to the fuel exhaust processor  400  by an optional second recycling conduit  308 B. In particular, the second recycling conduit  308 B may be configured to provide hotter anode exhaust to the fuel exhaust processor  400  than the first recycling conduit  308 A, since anode exhaust is cooled in the anode exhaust cooler  340  prior to entering the first recycling conduit  308 A. 
     The shift reactor  380  may be any suitable device that converts components of the fuel exhaust into free hydrogen (H 2 ) and/or water. For example, the shift reactor  380  may comprise a tube or conduit containing a catalyst that converts carbon monoxide (CO) and water vapor in the fuel exhaust stream into carbon dioxide and hydrogen, via the water gas shift reaction (CO+H 2 O↔CO 2 +H 2 ). Thus, the shift reactor  380  increases the amount of hydrogen and carbon dioxide in the anode exhaust and decreases the amount of carbon monoxide in the anode exhaust. For example, the shift reactor  380  may reduce the amount of carbon monoxide in the anode exhaust to about 5% by volume or less, such as about 4% or less, or about 3% or less. The catalyst may be any suitable catalyst, such as an iron oxide or a chromium-promoted iron oxide catalyst. 
     Cathode exhaust generated in the stack  302  flows to the ATO  330  through cathode exhaust conduit  304 A. The vortex generator  372  may be disposed in the cathode exhaust conduit  304 A and may be configured to swirl the cathode exhaust. The swirled cathode exhaust may mix with hydrogen output from the fuel exhaust processor  400  before being provided to the ATO  330 . The mixture may be oxidized in the ATO  330  to generate ATO exhaust. The ATO exhaust flows from the ATO  330  to the cathode recuperator  320  through the cathode exhaust conduit  304 B. Exhaust flows from the cathode recuperator  320  and out of the hotbox  350  through cathode exhaust conduit  304 C. 
     Water flows from a water source  50 , such as a water tank or a water pipe, to the water injector  360  through a water conduit. The water injector  360  injects water directly into first portion of the anode exhaust provided in the anode exhaust conduit  306 C. Heat from the first portion of the anode exhaust (also referred to as a recycled anode exhaust stream) provided in the exhaust conduit  306 C vaporizes the water to generate steam. The steam mixes with the anode exhaust, and the resultant mixture is provided to the anode exhaust cooler  340 . The mixture is then routed through the fuel exhaust processor  400  and provided to the mixer  316 . The mixer  316  is configured to mix the steam and first portion of the anode exhaust with fresh fuel (i.e., fuel inlet stream). This humidified fuel mixture may then be heated in the anode recuperator  310  by the anode exhaust, before being provided to the stack  302 . The system  300  may also include one or more fuel reforming catalysts located inside and/or downstream of the anode recuperator  310 . The reforming catalyst(s) reform the humidified fuel mixture before it is provided to the stack  302 . 
     The system  300  may further a system controller  325  configured to control various elements of the system  300 . The system controller  325  may include a central processing unit configured to execute stored instructions. For example, the system controller  325  may be configured to control fuel and/or air flow through the system  300 , according to fuel composition data. 
     Fuel Exhaust Processors 
       FIG.  5    is a schematic view showing components of the fuel exhaust processor  400 , according to various embodiments of the present disclosure. Referring to  FIGS.  4  and  5   , the fuel exhaust processor  400  may include a hydrogen separator  410 , a system controller  425 , a splitter  440 , a low temperature shift reactor  450 , and a heat exchanger  444 . The system controller  425  may be a central processing unit configured to execute stored instructions. For example, the system controller  425  may be configured to control anode exhaust, hydrogen and/or carbon dioxide flow through the fuel exhaust processor  400 . In some embodiments, the system controller  425  may be operatively connected to the system controller  325  of the SOFC system  300 , such that the system controller  425  may control the fuel exhaust processor based on operating conditions of the SOFC system  300 . 
     The splitter  440  may be configured to receive anode exhaust from the first recycling conduit  308 A. The splitter  440  may be fluidly connected to the hotbox  350  and the hydrogen separator  410 . For example, a first return conduit  406 A may fluidly connect an outlet of the splitter  440  to the hotbox  350 , and a first separator conduit  401 A and a second separator conduit  401 B may fluidly connect an outlet of the splitter  440  to the hydrogen separator  410 . In particular, a first portion of the anode exhaust may be output from the splitter  440  and provided to the shift reactor  450  via the first separator conduit  401 A, and anode exhaust output form the shift reactor  450  may be supplied to the hydrogen separator  410  by the second separator conduit  401 B. A second portion of the anode exhaust may be output from an outlet of the splitter  440  to the first return conduit  406 A. Anode exhaust output from the fuel exhaust processor  400  may be move through the first return conduit  406 A to the mixer  316  of the SOFC system  300 , by the anode recycle blower  318 . However, the anode recycle blower  318  may be disposed in any other suitable location. 
     The shift reactor  450  may be a WGS reactor similar to the shift reactor  380 , but may configured to operate at a lower temperature than the shift reactor  380 . Accordingly, the shift reactor  380  may be referred to as a high temperature shift reactor, and the shift  450  may be referred to as a low temperature shift reactor. The shift reactor  450  may be configured to further reduce the carbon monoxide content of the anode exhaust provided to the fuel exhaust processor  400 . For example, the shift reactor  450  may be configured to reduce the carbon monoxide content of the anode exhaust to less than about 0.3% by volume, such as less than about 0.2%, or less than about 0.1%. 
     Purified anode exhaust (e.g., low carbon monoxide content anode exhaust) output from the shift reactor  450  may be provided to the hydrogen separator  410  by a second separator conduit  401 B. The heat exchanger  444  may be operatively connected to the second separator conduit  401 B and may be configured to cool anode exhaust passing there through. For example, the heat exchanger  444  may include fans and/or cooling fins configured to transfer heat to air supplied thereto. Accordingly, the heat exchanger  444  may be configured to cool the anode exhaust, in order to prevent overheating and/or damage to the hydrogen separator  410 . In some embodiments, the heat exchanger  444  may be omitted. For example, if the shift reactor  450  includes an internal cooling system, as disclosed below with respect to  FIGS.  4 A and  4 B , the heat exchanger  444  may optionally be omitted. 
     In various embodiments, the fuel exhaust processor  400  may be fluidly connected to multiple fuel cell systems  10 . For example, the fuel exhaust processor  400  may be configured to process anode exhaust output from two or more fuel cell systems, and may be configured to return hydrogen rich fuel streams to both fuel cell systems. 
     The hydrogen separator  410  may include one or more hydrogen pumps, which may each include electrochemical hydrogen pumping cells  420 . For example, as shown in  FIG.  2   , the hydrogen separator  410  may include a first hydrogen pump  414 A, a second hydrogen pump  414 B, and a third hydrogen pump  414 C, that each comprise stacked hydrogen pumping cells  420 . However, the present disclosure is not limited to any particular number of hydrogen pumps. For example, in various embodiments, the first hydrogen pump  414 A and the second hydrogen pump  414 B may be combined into a single stack of hydrogen pumping cells  420 . In other embodiments, the first, second, and third hydrogen pumps  414 A,  414 B,  414 C may be combined into a single stack of hydrogen pumping cells  420 . 
     In some embodiments, the first hydrogen pump  414 A may include a larger number of hydrogen pumping cells  420  than the second and/or third hydrogen pumps  414 B,  414 C. For example, the first hydrogen pump  414 A may include twice the number of hydrogen pumping cells  420  as the second hydrogen pump  414 B and/or the third hydrogen pump  414 C. 
     In still other embodiments, the fuel exhaust processor  400  may output only a single hydrogen stream. For example, the third hydrogen pump  414 C may be omitted. In particular, heat generated by exothermic reactions in the ATO  330  may be used to offset heat losses due to endothermic fuel reformation reactions occurring in the anode recuperator  310 , by using the ATO exhaust to heat air provided to the fuel cell stack  302  in the cathode recuperator  320 . 
     The second separator conduit  401 B may provide anode exhaust to an anode inlet of the first hydrogen pump  414 A. An anode outlet of the first hydrogen pump  414 A may be fluidly connected to an anode inlet of the second hydrogen pump  414 B by a first exhaust conduit  402 A. An anode outlet of the second hydrogen pump  414 B may be fluidly connected to an anode inlet of the third hydrogen pump  414 C, by a second exhaust conduit  402 B. An anode outlet of the third hydrogen pump  414 C may be fluidly connected to a carbon dioxide processor  520  by a third output conduit  502 C and a fourth output conduit  502 D. 
     The carbon dioxide processor  520  may be fluidly connected to a carbon dioxide storage device or tank  524 . The carbon dioxide processor  520  may operate to compress and/or cool a carbon dioxide stream received from the fuel exhaust processor  400 . The processor may be a condenser and/or dryer configured to remove water from the carbon dioxide stream. The carbon dioxide stream may be provided to the carbon dioxide processor  520  in the form of a vapor, liquid, solid or supercritical carbon dioxide. 
     A first hydrogen conduit  404 A may be fluidly connected to a cathode outlet of the first stack  410 A, a second hydrogen conduit  404 B may be fluidly connected to a cathode outlet of the second stack  410 B, and a third hydrogen conduit  404 C may be fluidly connected to a cathode outlet of the third stack  410 C. The first hydrogen conduit may be fluidly connected to a first return conduit  406 A, and the second hydrogen conduit  404 B may be fluidly connected to the first hydrogen conduit  404 A. In particular, the first return conduit  406 A may be configured to provide hydrogen extracted from the anode exhaust by the first hydrogen pump  114 A, the second hydrogen pump  414 B, and or the third hydrogen pump  414 C to the mixer  316 , such that the hydrogen may be recycled to the stack  302 . 
     The third hydrogen conduit  404 C may be fluidly connected to the fuel cell system  300  by a second return conduit  406 B. In particular, the second return conduit  406 B may be configured to provide hydrogen extracted from the anode exhaust by the third stack  114 C to the second return conduit  406 B, which may provide the hydrogen to the ATO  330 . 
     In some embodiments, an optional fourth hydrogen conduit  404 D may fluidly connect the third hydrogen conduit  404 C to the first hydrogen conduit  404 A. An optional fifth hydrogen conduit  404 E may fluidly connect the second hydrogen conduit  404 B to the third hydrogen conduit  404 C. A first output conduit  502 A and a second output conduit  502 B may fluidly connect the first hydrogen conduit  404 A to a hydrogen processor  500 . 
     The hydrogen processor  500  may include, for example, a condenser and/or a compressor and may be fluidly connected to a hydrogen storage tank  504 . The condenser may be an air-cooled or water-enhanced, air-cooled condenser and/or heat exchanger configured to cool a hydrogen stream received from the fuel exhaust processor  400 , to a temperature sufficient to condense water vapor in the hydrogen stream. The compressor may also be configured to compress the hydrogen, and the hydrogen tank  504  may be configured to store the compressed hydrogen. 
     The first return conduit  406 A may fluidly connect the splitter  440  to the mixer  316  of the fuel cell system  300 . The second return conduit  406 B may fluidly connect the first separator conduit  401 A to the ATO  330 , and may also be fluidly connected to the third hydrogen conduit  404 C. In other embodiments, the second return conduit  406 B may be fluidly connected to an outlet of the splitter  440 . A third return conduit  406 C may fluidly connect the second separator conduit  401 B to the second return conduit  406 B. 
     In various embodiments, the fuel exhaust processor  400  may include various valves to control fluid flow. For example, a first separator conduit valve  401 V 1  and a second separator conduit valve  401 V 2  may be respectively configured to control anode exhaust flow through the first and second separator conduits  401 A,  401 B. A first hydrogen conduit valve  404 V 1 , a second hydrogen conduit valve  404 V 2 , a third hydrogen conduit valve  404 V 3 , a fourth hydrogen conduit valve  404 V 4 , and a fifth hydrogen conduit valve  404 V 5  may be configured to respectively control hydrogen flow through the first, second, third, fourth, and fifth hydrogen conduits  404 A,  404 B,  404 C,  404 D,  404 E. A hydrogen storage valve  503 , such as a two way valve, may be configured to control hydrogen flow from the first hydrogen conduit  404 A into the output conduit  502 . A second return conduit valve  406 V 2  and a third return conduit valve  406 V 3 , may be configured to respectively control anode exhaust flow through the second and third return conduits  406 B,  406 C. 
     In some embodiments, the fuel exhaust processor  400  may be fluidly connected to multiple hotboxes  100 . For example, the splitter  440  may receive anode exhaust from multiple recycling conduits  308 A/ 308 B, and may be fluidly connected to multiple return conduits  406 A,  406 B. For example, the recycling conduits  308 A/ 308 B and the return conduits  406 A,  406 B may be branched and connected to different hotboxes  100 . 
     The system  300  may be configured to operate with a variety of different hydrogen processors  500  and/or carbon dioxide processors  520 , which may be provided on site by a third party. As such, it may be difficult to match the flow and/or production rate of the hydrogen and/or carbon dioxide streams output from the fuel exhaust processor  410  with the throughput of a particular carbon dioxide processor  520 . In particular, such variations may induce positive and/or negative pressure fluctuations. For example, if the throughput of the hydrogen processor  500  is too high (e.g., the hydrogen processor  500  pulls too hard on the hydrogen stream) a negative pressure may be induced within the system  300 , or if the throughput is too low, a positive pressure may be induced within the system  300 . 
     Such pressure fluctuations may cause problems within the system  300 . For example, excessive negative pressures may result in air leaking into the system  300 , or may result in a high pressure variation across the electrolytes of the system  300 , which may increase the risk of electrolyte damage, such as cracking. Excessively high pressures may also result in pressure variations across the electrolytes and increase the risk of electrolyte damage. 
     Accordingly, the system  300  may include a hydrogen blower  510  fluidly connected to the first and second output conduits  502 A,  502 B. The first output conduit  502 A may fluidly connect a hydrogen outlet of the fuel exhaust processor  400  to an inlet of the hydrogen blower  510 . The second output conduit  502 B may fluidly connect an outlet of the hydrogen blower  510  to the hydrogen processor  500 . The hydrogen blower  510  may be configured to increase the pressure of the hydrogen stream. For example, the hydrogen blower  510  may be configured to increase the pressure of a hydrogen stream by from about 2 to about 15 pounds per square in gauge (psig), such as from about 5 to about 10 psig. The hydrogen blower  510  may also operate to isolate components of the system  300 , such as fuel exhaust processor  400  and/or the stack  302 , from pressure fluctuations induced by the hydrogen processor  500 . 
     The system  300  may also include a carbon dioxide blower  512  fluidly connected to the third and fourth output conduits  502 C,  502 D. The third outlet conduit  502 C may fluidly connect a carbon dioxide outlet of the fuel exhaust processor  400  and an inlet of the carbon dioxide blower  512 . The second carbon dioxide conduit  502 B may fluidly connect an outlet of the carbon dioxide blower  512  to the carbon dioxide processor  520 . The carbon dioxide blower  512  may be configured to increase the pressure of the carbon dioxide stream. For example, the carbon dioxide blower  512  may be configured to increase the pressure of a carbon dioxide stream by from about 2 to about 15 pounds per square in gauge (psig), such as from about 5 to about 10 psig. The carbon dioxide blower  512  may also operate to isolate the components of the isolate components of the system  300 , such as fuel exhaust processor  400  and/or the stack  302 , from pressure fluctuations induced by the carbon dioxide processor  520 . 
     In various embodiments, the system  300  may include an optional water knockout device  530  configured to remove condensed water from the hydrogen stream, in order to reduce and/or prevent liquid water accumulation in the hydrogen blower  510 . In other embodiments, the system  300  may include an optional water knockout device  532  configured to remove condensed water from the carbon dioxide stream, in order to reduce and/or prevent liquid water accumulation in the carbon dioxide blower  512 . 
     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.