Methods of and apparatus for operating a reformer with varying natural gas fuel supplies

Abstract

Provided herein generally are methods and apparatus for the operation of a fuel cell unit or system, or a combustion based device using a variety of different natural gas fuel sources. In certain embodiments, a conduit containing a catalytic bed and an oxygen sensor is used to determine the gas species and their relative concentrations in a natural gas fuel.

Description

[0001] METHODS OF AND APPARATUS FOR OPERATING A REFORMER WITH VARYING NATURAL GAS FUEL SUPPLIES

[0002] CROSS-REFERENCE TO RELATED APPLICATIONS

[0003] This application claims the benefit of and priority to U.S. Provisional Patent Application

[0004] No. 63 / 601,975, filed November 22, 2023, and U.S. Provisional Patent Application

[0005] No. 63 / 624,425, filed January 24, 2024, the entire disclosures of which are hereby incorporated by reference in their entireties for all purposes.

[0006] BACKGROUND

[0007] As the world moves away from fossil fuels and towards renewable and clean or “green” energy, hydrogen energy is an attractive solution to reducing the carbon footprint created by many energy sources. Hydrogen produced from water via electrolysis using a renewable energy source does not produce any greenhouse gases and can be a completely carbon-free process. Fuel cells, which use hydrogen to produce electricity and water, have the possibility to impact clean energy for the future.

[0008] Consequently, fuel cell systems continue to be the focus of considerable research due to the potential of fuel cell systems or simply, “fuel cells,” i.e., devices for the electrochemical conversion of hydrogen to electricity, to play a greatly expanded role for general applications including main power units (MPUs) and auxiliary power units (APUs) for households and businesses. Fuel cells also can be used for specialized applications, for example, as on-board electrical generating devices for electric vehicles, backup power sources for residential-use devices, main power sources for leisure-use, outdoor and other power-consuming devices in out- of-grid locations, and lighter weight, higher power density, ambient temperature-independent replacements for portable battery packs.

[0009] Because large scale, economic production of hydrogen, infrastructure required for its distribution, and practical means for its storage (especially as a transportation fuel) widely are believed to be a long way off, much current research and development is directed to the production of the hydrogen used to power fuel cells because many of the current techniques contribute to further carbon emissions. That is, a majority of hydrogen today is produced from fossil fuels such as coal and oil, which in practice produces carbon dioxide, a greenhouse gas.

[0010] To that end, fuel cell systems such as solid oxide fuel cell systems, which currently are used in residential applications, typically use natural gas (mainly methane) as a fuel source. The xyyural gas is reformed into hydrogen, which is used by a fuel cell stack to generate electricity. Depending on the process used to reform the methane, carbon monoxide and / or carbon dioxide can be created as by-products. Consequently, to reduce the carbon footprint of a fuel cell unit further, public natural gas utilities are beginning to experiment with mixing hydrogen into the natural gas supplied to residential fuel cell systems. In this way, the hydrogen is used directly by the fuel cell stack without the need to be reformed thereby not producing any by-product carbon dioxide.

[0011] Notwithstanding the feasibility and capability of the current natural gas source piping networks to handle the particular chemical characteristics of the lighter and smaller hydrogen molecule, public natural gas utilities supply natural gas with a variety of other components present and at varying amounts. For example, in addition to mainly methane, natural gas can contain varying amounts of hydrogen, ethane, propane, butane, hexane and other non- hydrocarbon components such as nitrogen and carbon dioxide.

[0012] Accordingly, methods are needed to estimate the amount of other components or constituents present in a natural gas fuel supply for operating any device using a metered flow of natural gas fuel such as a fuel cell unit so that the appropriate flow rate of the natural gas fuel can be adjusted along with the incoming air to maintain a consistent oxygen to carbon (O:C) ratio of the natural gas fuel stream entering a reformer of a fuel cell unit to efficiently run the fuel cell unit and avoid the deleterious effects of a poor ratio such as coking and flashing.

[0013] SUMMARY

[0014] It has now been discovered that methods and apparatus can accurately measure the concentrations of gas species in a natural gas fuel using various sensors or meters in combination. For a given natural gas fuel flow, the relative concentrations of up to three gas species and the total real flow rate of the natural gas fuel can be measured relative to a baseline calibration using a combination of a volumetric flow meter, a differential pressure meter, and a mass flow meter. Two gas species and the total real flow rate of the natural gas fuel can be determined using only two of these three meters. Knowing the concentrations of the primary constituents and composition of a natural gas fuel can assist in the delivery, metering, and use of the natural gas fuel for a fuel cell unit or system, or a variety of combustion based applications, such as internal combustion engines, water heaters, and heating, ventilation and air conditioning (HVAC) systems. For example, knowing the concentrations of the primary constituents and compositions of a natural gas fuel can inform a flow rate of natural gas fuel and / or a flow rate of air through a reformer for efficient operation of a fuel cell unit and system. Accordingly, the fuel cell unit can operate efficiently and effectively using a variety of different natural gas fuel supplies in different areas of the world, or from a dedicated supplier.

[0015] In addition, an oxygen sensor, for example, that measures the partial pressure of oxygen leaving a conduit containing a catalytic bed, e.g., a reformer of a fuel cell unit, either by itself or in combination with other sensors or meters depicted and described herein, can be used to measure the concentration of hydrogen and / or other hydrocarbon species in relation to other species or constituents in a natural gas fuel. That is, using the catalytic bed in combination with an electrochemical oxygen partial pressure measurement, a temperature dependency of the catalytic oxidation (and subsequent oxygen partial pressure change) of individual natural gas fuel constituents can be used to determine the composition of the natural gas fuel. Again, knowing the composition of the natural gas fuel can inform of the flow rate of natural gas fuel and / or flow rate of air into the conduit containing the catalytic bed, e.g., the reformer of a fuel cell unit. Such measurements and apparatus can be used for nearly any application that needs to control an air to fuel ratio, for example, in fuel cell units or systems, or in combustion based devices such as internal combustion engines, water heaters, and HVAC systems.

[0016] Further, the combination of the two above recited ideas can be used to further refine or define the composition of the natural gas fuel and its delivery, metering and use for various applications as described herein. For example, in the fuel cell context, prior to the reformer lighting, the only flow information will come from the flow sensors or meters (where “sensor” and “meter” can be used interchangeably herein unless the context dictates otherwise). These flow sensors will establish the initial flow rate settings based on the estimated real flow rate and species concentrations. After the electrochemical sensor gathers information about species contents via the oxygen partial pressure plateaus during warm up, this will either validate or refine the estimated species concentrations determined by the flow sensors, which can be used to further refine the flow rate adjustments.

[0017] As other examples, the electrochemical sensor can provide a correction for the presence of inert phases (e.g., nitrogen), and unexpected hydrocarbon species, or cases where there are similar concentrations of both hydrogen and a hydrocarbon with offsetting physical properties making the measurements ambiguous. As an additional example, nitrogen has a similar molecular weight / density as ethane, so the flow sensor measurement method which assumes no nitrogen is present will overpredict the concentration of ethane if a substantial amount of nitrogen is introduced. If, in this case, the electrochemical sensor finds there is less ethane than expected from the flow sensors, this can be fed back into the sensor loop as a correction effectively giving estimates of 4 total gas phases (in this case, methane, hydrogen, ethane and nitrogen).

[0018] In one aspect, the present teachings provide methods of operating an apparatus or a device using a natural gas fuel, such as a fuel cell unit, an internal combustion engine, a water heater, or an HVAC system, with varying natural gas supplies.

[0019] In various embodiments, the present teachings provide methods of operating a fuel cell unit with varying natural gas supplies comprising: flowing a natural gas fuel at a flow rate through a fixed volume conduit comprising an inlet and an outlet; performing at least two of the following after the inlet of the fixed volume conduit: measuring a relative heat capacity of the natural gas fuel flowing past a thermal based mass flow meter in thermal communication with the fixed volume conduit to provide a heat capacity measurement; measuring a relative viscosity of the natural gas fuel flowing through the fixed volume conduit to provide a viscosity measurement, wherein the fixed volume conduit is in fluid communication with a differential pressure meter; and measuring a relative density of the natural gas fuel flowing though the fixed volume conduit to provide a density measurement, wherein the fixed volume conduit is in fluid communication with a volumetric flow meter; wherein the thermal based flow meter, the pressure meter and the volumetric flow meter, when present, are located along the fixed volume conduit in any respective position along the direction of flow of the natural gas fuel; and the heat capacity measurement, the viscosity measurement and the density measurement, when measured, are expressed in normal liter per minute (NLPM) based on the thermal based mass flow meter, the differential pressure meter and the volumetric flow meter, respectively, being calibrated with 100% methane over a range of flow rates; and flowing the natural gas fuel past the outlet of the fixed volume conduit into a reformer of a fuel cell unit; wherein if a second gas species is present in the natural gas fuel, the second gas species being one of hydrogen or another hydrocarbon, then two of the three measuring steps are required; and using at least two of the heat capacity measurement, the viscosity measurement and the density measurement in relation to the fluid properties of methane and the second gas species to estimate the relative concentrations of methane and the second gas species; estimating the real fluid properties of the natural gas fuel using the relative concentrations of methane and the second gas species; and applying appropriate corrections to the flow rate of the natural gas fuel through the reformer based on the estimated real fluid properties, wherein: a flow rate of air mixed with the natural gas fuel prior to entering the reformer is decreased proportionally to the concentration of hydrogen to maintain a consistent oxygen to carbon ratio, or a flow rate of air mixed with the natural gas fuel prior to entering the reformer is increased proportionally to the concentration of the other hydrocarbon to maintain a consistent oxygen to carbon ratio.

[0020] In various embodiments, the present teachings provide methods of operating a fuel cell unit with varying natural gas supplies comprising: flowing a natural gas fuel at a flow rate through a fixed volume conduit comprising an inlet and an outlet; measuring a relative heat capacity of the natural gas fuel flowing past a thermal based mass flow meter in thermal communication with the fixed volume conduit to provide a heat capacity measurement; measuring a relative viscosity of the natural gas fuel flowing through the fixed volume conduit to provide a viscosity measurement, wherein the fixed volume conduit is in fluid communication with a differential pressure meter; and measuring a relative density of the natural gas fuel flowing though the fixed volume conduit to provide a density measurement, wherein the fixed volume conduit is in fluid communication with a volumetric flow meter; wherein the thermal based flow meter, the pressure meter and the volumetric flow meter are located along the fixed volume conduit in any respective position along the direction of flow of the natural gas fuel; and the heat capacity measurement, the viscosity measurement and the density measurement are expressed in normal liter per minute (NLPM) based on the thermal based mass flow meter, the differential pressure meter and the volumetric flow meter, respectively, being calibrated with 100% methane over a range of flow rates; and flowing the natural gas fuel past the outlet of the fixed volume conduit into a reformer of a fuel cell unit; wherein if a second gas species and a third gas species are present in the natural gas fuel, the second gas species and the third gas species being selected from the group consisting of hydrogen, another hydrocarbon and a third hydrocarbon, using the heat capacity measurement, the viscosity measurement and the density measurement in relation to the fluid properties of methane, the second gas species and the third gas species to estimate the relative concentrations of methane, the second gas species and the third gas species; estimating the real fluid properties of the natural gas fuel using the relative concentrations of methane, the second gas species and the third gas species; and applying appropriate corrections to the flow rate of natural gas fuel through the reformer based on the estimated real fluid properties, wherein: if the concentration of hydrogen is greater than the concentration of the total amount of carbon contained in the third gas species, the flow rate of air mixed with the natural gas fuel prior to entering the reformer is decreased proportionally to the difference between the concentration of hydrogen and the concentration of the third gas species to maintain a consistent oxygen to carbon ratio, or if the concentration of hydrogen is less than the concentration of the total amount of carbon contained in the third gas species, the flow rate of air mixed with the natural gas fuel prior to entering the reformer is increased proportionally to the difference between the concentration of hydrogen and the concentration of the third gas species to maintain a consistent oxygen to carbon ratio, or if no hydrogen is present, the flow rate of air mixed with the natural gas fuel prior to entering the reformer is increased proportionally to the total amount of carbon contained in the second gas species and the third gas species to maintain a consistent oxygen to carbon ratio.

[0021] In another aspect, the present teachings provide methods of determining the concentration of hydrogen and other hydrocarbon species in a natural gas fuel.

[0022] In various embodiments, the present teachings provide methods of determining the concentration of hydrogen in a natural gas fuel comprising: measuring a partial pressure of oxygen exiting a conduit containing a catalytic bed, wherein a natural gas fuel is passed at flow rate through the conduit until the oxygen is substantially consumed by a partial oxidation reaction with the catalytic bed occurring above about 500 °C; wherein a plateau of the partial pressure of oxygen occurs between about 360 °C and about 440 °C, the initial partial pressure of oxygen minus the plateau of partial pressure of oxygen being proportional to the concentration of hydrogen in the natural gas fuel.

[0023] In certain embodiments, the present teachings provide methods of determining the concentration of ethane and hydrogen in a natural gas fuel comprising: measuring a partial pressure of oxygen exiting a conduit containing a catalytic bed, wherein a natural gas fuel is passed at flow rate through the conduit until the oxygen is substantially consumed by a partial oxidation reaction with the catalytic bed occurring above about 500 °C; wherein a plateau of the partial pressure of oxygen occurs between about 280 °C and about 320 °C, the initial partial pressure of oxygen minus the plateau of partial pressure of oxygen being proportional to the concentration of ethane in the natural gas fuel; and wherein a plateau of the partial pressure of oxygen occurs between about 360 °C and about 440 °C, the initial partial pressure of oxygen minus the plateau of partial pressure of oxygen being proportional to the concentration of hydrogen in the natural gas fuel.

[0024] In some embodiments, the present teachings provide methods of determining the concentration of multiple gas species in a natural gas fuel comprising: measuring a partial pressure of oxygen exiting a conduit containing a catalytic bed, wherein a natural gas fuel is passed at flow rate through the conduit until the oxygen is substantially consumed by a partial oxidation reaction with the catalytic bed occurring above about 500 °C; wherein a first plateau of the partial pressure of oxygen occurs, the initial partial pressure of oxygen minus the first plateau of partial pressure of oxygen being proportional to the concentration of a first gas species in the natural gas fuel; wherein a second plateau of the partial pressure of oxygen occurs, the initial partial pressure of oxygen minus the second plateau of partial pressure of oxygen being proportional to the concentration of a second gas species in the natural gas fuel; and wherein additional plateaus of the partial pressure of oxygen occur, the initial partial pressure of oxygen minus each of the additional plateaus of partial pressure of oxygen being proportional to a respective concentration of additional gas species in the natural gas fuel.

[0025] In another aspect, the present teachings provide apparatus to carry out the methods as described herein.

[0026] For example, a flow sensor assembly for a device as described herein using a metered flow of natural gas fuel such as a fuel cell unit, comprising: a fixed volume conduit positioned upstream of and in fluid communication with a reformer of a fuel cell unit; at least two of the following three meters: a mass flow meter in thermal communication with a flow of a natural gas fuel through the fixed volume conduit; a differential pressure meter tapped into the fixed volume conduit and in fluid communication with the flow of the natural gas fuel through the fixed volume conduit; and a volumetric flow meter tapped into the fixed volume conduit at a first crosssection and at a second cross-section smaller than the first cross-section and in fluid communication with the flow of the natural gas fuel through the fixed volume conduit; wherein the at least two of the mass flow sensor, the differential pressure meter, and the volumetric flow meter are located in any order contiguously along the fixed volume conduit; and a central processing unit in electrical communication with the at least two of the mass flow meter, the differential pressure meter, and the volumetric flow meter, and adapted to control the flow rate of the natural gas fuel through the fixed volume conduit based on feedback from the at least two of the mass flow meter, the differential pressure meter, and the volumetric flow meter.

[0027] In various embodiments, the presenting teachings provide a voltage sensor assembly comprising a first electrochemical sensor acting as an oxygen sensor located at the outlet of a conduit containing a catalytic bed, wherein the oxygen sensor is in electrical communication with a central processing unit, adapted to determine a flow rate of natural gas fuel and / or a flow rate of air through the conduit based on feedback from the first electrochemical sensor. Such an arrangement can be useful for a variety of applications using a flow of natural gas fuel, such as a metered flow of natural gas fuel along with air, for example, in fuel cell units and systems, and in combustion based devices such as an internal combustion engine, a water heater, or an HVAC system.

[0028] In some embodiments, the present teachings provide a voltage sensor assembly comprising a first electrochemical sensor acting as an oxygen sensor located at the outlet of a reformer of a fuel cell unit, wherein the oxygen sensor is in electrical communication with a central processing unit, adapted to determine a flow rate of natural gas fuel and / or a flow rate of air through the reformer based on feedback from the first electrochemical sensor to maintain a consistent oxygen to carbon ratio.

[0029] In another aspect, the present teachings provide a flow sensor assembly in combination with a voltage sensor assembly, including methods of using the combination for a variety of devices as described herein.

[0030] DESCRIPTION OF THE DRAWINGS

[0031] It should be understood that the drawings described below are for illustration purposes only. Like numerals generally refer to like parts. The drawings are not necessarily to scale, with emphasis generally being placed upon illustrating the principles of the present teachings. The drawings are not intended to limit the scope of the present teachings in any way.

[0032] FIGS. 1A and IB are schematic diagrams of embodiments of a thermal based mass flow sensor or mass flow meter (MFM) where the depiction in FIG. 1A is a MFM with absolute temperature measurements and the depiction in FIG. IB is a MFM with relative temperature measurements.

[0033] FIGS. 2A-2C are schematic diagrams of embodiments of differential pressure meters or pressure drop meters or sensors ( ΔP), where the depiction in FIG. 2A is a ΔP with absolute pressure measurements, the depiction in FIG. 2B is a ΔP with an absolute pressure measurement versus ambient pressure, and the depiction in FIG. 2C is a ΔP with relative pressure measurements. FIG. 2D is a schematic image illustrating the representation of a known pressure drop as shown in FIGS. 2A-2C (as well as as shown in other schematic diagrams herein).

[0034] FIGS. 3A and 3B are schematic diagrams of embodiments of a volumetric flow meter or density meter (DM), where the depiction in FIG. 3A is a DM with absolute pressure measurements and the depiction in FIG. 3B is a DM with relative pressure measurements. FIG. 3C is a schematic diagram illustrating the representation of a generic flow restriction as shown in FIGS. 3A and 3B (as well as shown in other schematic diagrams herein), including, but not limited to, a Venturi, an orifice, or a nozzle.

[0035] FIG. 4 is a schematic diagram of a fixed volume conduit having three meters present (one each of a mass flow meter, a density meter and a differential pressure meter) and connected to a reformer at the outlet of the fixed volume conduit and a flow meter device associated with the inlet of the conduit including a central processing unit (CPU) to control the flow of fluid into the conduit.

[0036] FIG. 5 is a schematic diagram of a flow sensor assembly having a fuel / air mixer at its outlet immediately before the reformer of a fuel cell unit.

[0037] FIG. 6 is a schematic diagram of a flow sensor assembly have a by-pass conduit and a second by-pass conduit with three meters present (one each of a mass flow meter, a density meter and a differential pressure meter), each on a different conduit of the flow sensor assembly, where the conduits are in fluid communication with each other via a first manifold near the inlets of the conduits and a second manifold near the outlets of the conduits.

[0038] FIGS. 7A-7C are schematic diagrams of embodiments of a combination of a density meter (P*1and P*2or ΔP*) and a differential pressure meter (P1and / or P2, or ΔP).

[0039] FIGS. 8A-8C are schematic diagrams of embodiments of a partially combined density meter (P*1and P*2or ΔP*) and a differential pressure meter (P1and / or P2, or ΔP).

[0040] FIGS. 9A-9E are schematic diagrams of embodiments of combinations of a mass flow meter (MFM) and a differential pressure meter (P1 and / or P2) for direct flow measurements.

[0041] FIGS. 10A-10G are schematic diagrams of embodiments of combinations of a mass flow meter (MFM) and a differential pressure meter (P1 and / or P2) for by-pass flow measurements.

[0042] FIGS. 11A-11E are schematic diagrams of embodiments of a combination of a mass flow meter (MFM) and a differential pressure meter (P1 and / or P2) for direct flow measurements and upstream thereof, a flow metering device with a valve to control the flow of natural gas fuel through the fixed volume conduit via a manifold.

[0043] FIGS. 12A-12E are schematic diagrams of embodiments of a combination of a mass flow meter (MFM) and a differential pressure meter (P1 and / or P2) for direct flow measurements and downstream thereof, a flow metering device with a valve to control the flow of natural gas fuel from the fixed volume conduit via a manifold. FIGS. 13A-13G are schematic diagrams of embodiments of a combination of a mass flow meter (MFM) and a differential pressure meter (P1 and / or P2) for by-pass flow measurements and upstream thereof, a flow metering device with a valve to control the flow of natural gas fuel through the fixed volume conduit via a manifold.

[0044] FIGS. 14A-14G are schematic diagrams of embodiments of a combination of a mass flow meter (MFM) and a differential pressure meter (P1 and / or P2) for by-pass flow measurements and downstream thereof, a flow metering device with a valve to control the flow of natural gas fuel from the fixed volume conduit via a manifold.

[0045] FIGS. 15A-15E are schematic diagrams of embodiments of a combination of a mass flow meter (MFM), a differential pressure meter (P1 and / or P2), and a volumetric flow meter or a density meter (DM) for direct flow measurements.

[0046] FIGS. 16A-16G are schematic diagrams of embodiments of a combination of a mass flow meter (MFM), a differential pressure meter (P1 and / or P2), and a volumetric flow meter or a density meter (DM) for by-pass flow measurements.

[0047] FIGS. 17A and 17B are schematic diagrams of embodiments of a combination of a mass flow meter (MFM), a differential pressure meter (P1 and / or P2), and a volumetric flow meter or a density meter (DM) for direct flow measurements for dual by-pass flow measurements.

[0048] FIGS. 18A-18E are schematic diagrams of embodiments of a combination of a mass flow meter (MFM), a differential pressure meter (P1 and / or P2), and a volumetric flow meter or a density meter (DM) for direct flow measurements, and upstream thereof, a flow metering device with a valve to control the flow of natural gas fuel through the fixed volume conduit via a manifold. FIGS. 18F-18J are schematic diagrams of embodiments of a combination of a mass flow meter (MFM), a differential pressure meter (P1 and / or P2), and a volumetric flow meter or a density meter (DM) for direct flow measurements, downstream thereof, a flow metering device with a valve to control the flow of natural gas fuel from the fixed volume conduit via a manifold.

[0049] FIGS. 19A-19G are schematic diagrams of embodiments of a combination of a mass flow meter (MFM), a differential pressure meter (P1 and / or P2), and a volumetric flow meter or a density meter (DM) for by-pass flow measurements, and upstream thereof, a flow metering device with a valve to control the flow of natural gas fuel through the fixed volume conduit via a manifold. FIGS. 20A-20G are schematic diagrams of embodiments of a combination of a mass flow meter (MFM), a differential pressure meter (P1 and / or P2), and a volumetric flow meter or a density meter (DM) for by-pass flow measurements, and downstream thereof, a flow metering device with a valve to control the flow of natural gas fuel from the fixed volume conduit via a manifold.

[0050] FIG. 21 is a schematic diagram showing the theoretical placement of any of a mass flow meter, a differential pressure meter, and a volumetric flow meter as stand alone or in any of the groupings illustrated or described herein, where each of the meters or combinations thereof could be located at any of the 10 marked locations labeled “1” through “10.”

[0051] FIGS. 22A-22C are schematic diagrams of the placement of a combination of a mass flow meter (MFM), a differential pressure meter ( ΔP), and a volumetric flow meter or a density meter (DM) in two or three positions identified in FIG. 18, which placements permit the differentiation of three gas species.

[0052] FIGS. 23A and 23B are schematic diagrams of the placement of a combination of a mass flow meter (MFM), a differential pressure meter (ΔP), and a volumetric flow meter or a density meter (DM) in two or three positions identified in FIG. 18, which placements permit the differentiation of three gas species.

[0053] FIG. 24 is a schematic diagram of the placement of a combination of a mass flow meter (MFM), a differential pressure meter (ΔP), and a volumetric flow meter or a density meter (DM) at positions a and / or b and ab, positions c and / or d and cd, and at abed, which placements permit the differentiation of three or more gas species using the multiple meters in series or in parallel (e.g., natural gas fuel containing ethane and propane being combined from multiple sources).

[0054] FIG. 25 is a graph of average catalytic bed temperature versus the mole fraction of oxygen out of the reformer for natural gas fuels having a methane to hydrogen ratio of 4: 1 (open squares) and 2: 1 (solid circles).

[0055] FIG. 26 is a graph of average catalytic bed temperature versus the mole fraction of water out of the reformer for natural gas fuels having a methane to hydrogen ratio of 4: 1 (open squares) and 2: 1 (solid circles).

[0056] FIG. 27 is a graph of the flow rate of air required to maintain a constant O:C ratio as a function of the ratio of hydrogen to methane at a given flow rate of fuel. FIGS. 28A-28C are schematic cross-sectional diagrams of embodiments of voltage sensor assemblies associated with a fixed volume conduit containing a catalyst bed, where FIG. 28A applies voltage taps with separate reference electrodes, FIG. 28B applies voltage taps with a shared or common reference electrode, and FIG. 28C applies a relative voltage across the two voltage taps without the use of a reference electrode.

[0057] DETAILED DESCRIPTION

[0058] As described herein, the present teachings generally provide methods of operating a device using varying supplies of natural gas fuel, i.e., containing different substituent fractions, as well as apparatus for carrying out the methods. The methods and apparatus are applicable to and useful for nearly any fuel cell unit or system, or combustion based device where an air to fuel ratio is important and needs to be controlled. Examples of such combustion based devices include, but are not limited to, internal combustion engines, water heaters, and HVAC systems.

[0059] More specifically, a method has been developed to accurately measure the species concentrations and flow rates of multiple gas species using various sensors in combination. For a given gas flow, the relative concentrations of up to three gas species and the total real flow rate can be measured relative to a baseline calibration using a combination of a volumetric flow measurement, pressure drop and a mass flow measurement. Practically speaking, the volumetric flow measurement, mass flow measurement and pressure drop detect fluctuations in relative density, heat capacity and viscosity, respectively. When the constituent species of a fluid changes or a new species is introduced, the density, heat capacity and viscosity will change, and the sensor or meter measurements will diverge in predictable ways based on their dependence upon different fluid properties. Using the comparison of these three properties relative to a baseline calibration, the ratios of three gas species can be determined along with a correction to the flow rate measurement, accounting for differing errors between or amongst the individual sensors. It is also possible to measure the relative concentrations of two gas species and the flow rate correction using any combination of two of the three sensor types.

[0060] Moreover, the sensor or meter measurements assist in adjusting the flow rate of natural gas fuel and / or the flow rate of air, for example, through a reformer of a fuel cell unit, to efficiently operate the reformer and fuel cell stack and afterburner at a consistent O:C ratio, e.g., ideally near one to one ratio of O:C, to avoid deleterious effects of coking or flashing. The methods of the present teachings also include measuring the partial pressure of oxygen leaving a conduit containing a catalytic bed, e.g., a reformer of a fuel cell unit, to facilitate the determination of the concentration of hydrogen and other hydrocarbons in the natural gas fuel flowing through the conduit. Measuring the partial pressure of the oxygen leaving a conduit can also assist the other sensors and meters described herein providing other data points and useful information for understanding the constituents and their percentages in a natural gas fuel from a variety of sources and differing quality. Understanding these parameters can assist in operating a fuel cell unit or system, or a combustion based device more efficiently. For example, using these parameters and operating a fuel cell unit more efficiently helps to conserve fuel and more efficiently convert the fuel to electricity as well as increasing the longevity of the fuel cell unit no matter the different percentages of constituents.

[0061] More specifically, for a fuel cell unit or system, the flow sensors are useful during start up to determine the fuel composition, as the typical sensors used to measure fuel / air ratio would not be able to provide this information while the system is still cold. It is very important to have the best possible measurements during the transient start up process to make the process efficient and avoid damaging the fuel cells. Further, electrochemical sensors (e.g., oxygen sensors) incorporated directly into the reformer can provide natural gas fuel composition measurements locally prior to entering the fuel cell stack and yield information about the reformer performance, differentiating the chemistry of the reformer from the fuel cell stack whereas using a typical sensor downstream of the fuel cell stack would not make this distinction.

[0062] To facilitate an understanding of the present invention, a number of terms and phrases are defined below. Although much of the description herein and examples are directed to fuel cell units and systems, it should be understood that the present teachings are equally applicable to other applications that use natural gas fuel, for example, a metered flow of natural gas fuel. Both the flow sensors and the catalytic bed with electrochemical sensor (oxygen sensor) can be used individually or in combination to effectively evaluate and / or control the air to fuel ratio for fuel cell units and systems, and combustion based devices. Such combustion based devices include internal combustion engines, water heaters and HVAC systems.

[0063] Unless defined otherwise, all technical and scientific terms used herein have the same meaning as commonly understood by one of ordinary skill in the art to which this invention belongs. The abbreviations used herein have their conventional meaning within the chemical arts. Throughout the description, where systems are described as having, including, or comprising specific components, or where processes and methods are described as having, including, or comprising specific steps, it is contemplated that, additionally, there are systems of the present invention that consist essentially of, or consist of, the recited components, and that there are processes and methods according to the present invention that consist essentially of, or consist of, the recited processing steps.

[0064] In the application, where an element or component is said to be included in and / or selected from a list of recited elements or components, it should be understood that the element or component can be any one of the recited elements or components, or the element or component can be selected from a group consisting of two or more of the recited elements or components.

[0065] Further, it should be understood that elements and / or features of an apparatus or a method described herein can be combined in a variety of ways without departing from the spirit and scope of the present invention, whether explicit or implicit herein. For example, where reference is made to a particular component of a system, that component can be used in various embodiments of systems of the present invention and / or in methods of the present invention, unless otherwise understood from the context. In other words, within this application, embodiments have been described and depicted in a way that enables a clear and concise application to be written and drawn, but it is intended and will be appreciated that embodiments may be variously combined or separated without parting from the present teachings and invention(s). For example, it will be appreciated that all features described and depicted herein can be applicable to all aspects of the invention(s) described and depicted herein.

[0066] The articles “a” and “an” are used in this disclosure to refer to one or more than one (i.e., to at least one) of the grammatical object of the article, unless the context is inappropriate. By way of example, “an element” means one element or more than one element.

[0067] The term “and / or” is used in this disclosure to mean either “and” or “or” unless indicated otherwise.

[0068] It should be understood that the expression “at least one of’ includes individually each of the recited objects after the expression and the various combinations of two or more of the recited objects unless otherwise understood from the context and use. The expression “and / or” in connection with three or more recited objects should be understood to have the same meaning unless otherwise understood from the context.

[0069] The use of the term “include,” “includes,” “including,” “have,” “has,” “having,” “contain,” “contains,” or “containing,” including grammatical equivalents thereof, should be understood generally as open-ended and non-limiting, for example, not excluding additional unrecited elements or steps, unless otherwise specifically stated or understood from the context.

[0070] Where the use of the term “about” is before a quantitative value, the present invention also includes the specific quantitative value itself, unless specifically stated otherwise. As used herein, the term “about” refers to a ±10%, ±5%, ±3% or ±2% variation from the nominal value unless otherwise indicated or inferred from the context.

[0071] At various places in the present specification, variables or parameters are disclosed in groups or in ranges. It is specifically intended that the description include each and every individual sub-combination of the members of such groups and ranges. For example, an integer in the range of 0 to 40 is specifically intended to individually disclose 0, 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14, 15, 16, 17, 18, 19, 20, 21, 22, 23, 24, 25, 26, 27, 28, 29, 30, 31, 32, 33, 34, 35, 36, 37, 38, 39, and 40, and an integer in the range of 1 to 20 is specifically intended to individually disclose 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14, 15, 16, 17, 18, 19, and 20.

[0072] The use of any and all examples, or exemplary language herein, for example, “such as” or “including,” is intended merely to illustrate better the present invention and does not pose a limitation on the scope of the invention unless claimed. No language in the specification should be construed as indicating any non-claimed element as essential to the practice of the present invention.

[0073] As a general matter, formulations specifying a percentage are by volume unless otherwise specified. Further, if a variable is not accompanied by a definition, then the previous definition of the variable controls.

[0074] Terms and expressions indicating spatial orientation or altitude such as “upper,” “lower,” “top,” “bottom,” horizontal,” “vertical,” and the like, unless their contextual usage indicates otherwise, are to be understood herein as having no structural, functional or operational significance and as merely reflecting the arbitrarily chosen orientation of the various views of apparatus, devices, components, and features of the present teachings that may be illustrated in certain of the accompanying figures. As used herein, a “reformer” refers to the component of a fuel cell unit or fuel cell system that contains a catalytic bed that converts hydrocarbons into hydrogen for use by the fuel cell stack of a fuel cell unit or fuel cell system.

[0075] As used herein, a “fuel cell stack” refers to the component of a fuel cell unit or fuel cell system where the electrochemical reaction takes place to convert hydrogen or electrochemically- oxidizable species to electricity. The fuel cell stack includes cells comprised of an anode, a cathode, and an electrolyte, often formed in layers. In operation, hydrogen and any other electrochemically oxidizable component(s) of a reformate entering a fuel cell stack, for example, from a reformer and / or a fluid mixing device, combine with oxygen anions within an anode layer of the fuel cell stack to produce water and / or carbon monoxide and electrons (electricity). The electrons generated within the anode layer migrate through the external load and back to the cathode layer where oxygen combines with the electrons to provide oxygen anions which selectively pass through the electrolyte layer and the anode layer.

[0076] As used herein, a “fuel cell unit” generally refers to a reformer, a fuel cell stack, and an afterburner. A fuel cell unit can include a vaporizer, where an outlet of the vaporizer is in operable fluid communication with an inlet of the reformer and / or the fuel cell stack. The reformer produces hydrogen from a hydrocarbon source, which reformation usually also produces carbon dioxide as a by-product. A fuel cell unit can include various valve assemblies, sensor assemblies, conduits, pumps, blowers and other components associated with such a unit, which other components can be considered the “balance of plant.” The balance of plant can also include pumps, heat exchangers, gaskets, compressors, recirculation blowers, and / or humidifiers.

[0077] As used herein, “fuel cell system” generally refers to a fuel cell unit and the balance of plant. A fuel cell system often includes a plurality of fuel cell units. A plurality of fuel cell units can share the balance of plant. It should be understood that a “fuel cell unit” and a “fuel cell system” can be used interchangeably herein unless the context dictates otherwise. Moreover, it should be understood that known and conventional fuel cells come in a variety of types and configurations including phosphoric acid fuel cells (PAFCs), alkaline fuel cells (AFCs), polymer electrolyte membrane (or proton exchange membrane) fuel cells (PEMFCs), and solid oxide fuel cells (SOFCs).

[0078] A “thermal based mass flow meter” and similar descriptors refer to a sensor which measures either a differential temperature ( ΔT) or absolute temperatures (T2-T1) directly upstream and downstream of a heat source and uses this measurement to estimate the mass flow rate being proportional to the expected heat capacity of the gas or to a baseline calibration value such as a pure natural gas fuel, i.e., 100% methane. Simultaneously, this measurement can be compared against different sensor data as a proxy for heat capacitance variation versus the baseline due to changes in gas composition. See FIGS. 1A and IB for embodiments of athermal based mass flow meter.

[0079] A “differential pressure meter” and similar descriptors refer to a device that can measure either in absolute (P1and / or P2) in or pressure drop across (ΔP) a given fixed volume conduit and does not necessarily require a reference point (P) measurement, assuming that the downstream pressure drop is consistent for a given flow rate and gas composition (static system). This measurement can be compared against different sensor data as a proxy for viscosity variation versus the baseline due to changes in gas composition. See FIGS. 2A-2C for embodiments of a differential pressure meter.

[0080] A “volumetric flow meter” or “density measurement meter” and similar descriptors refer to a device which compares the pressure of a flow in a pipe of a given cross section area to the pressure at a smaller cross-sectional area, which can be achieved with the use of a venturi, nozzle, orifice or other flow restriction. These pressure probes should be in close enough proximity such that the viscous pressure drop between them is negligible. This measurement can be compared against different sensor data as a proxy for density variation versus the baseline due to changes in gas composition. See FIGS. 3A and 3B for embodiments of a volumetric flow meter.

[0081] A “known pressure drop” generally refers to a consistent pressure drop that will not change over time relative to gaseous volumetric or mass flow examples. Examples include, but are not limited to, an orifice, a manifold, a tube, a pipe, a fitting, a gas conduit assembly, a gas utilizing appliance, and a gas measurement appliance. See FIG. 2D for a representation of a known pressure drop in the figures herein.

[0082] Mass and volume type flow meters are used to monitor and control the flow rate of natural gas fuel as well as the flow rate of air mixed with the natural gas fuel before or while entering a reformer of a fuel cell unit. Both meters require calibration to a specific fuel, here, methane (CH4), as it is the main constituent in natural gas fuel. When a composition of natural gas fuel moves away from the calibrated gas, each type of flow meter diverges from the real flow in different ways. For example, a mass flow meter will diverge proportional to heat capacitance or heat capacity. A volumetric flow meter (or density measurement meter) will diverge proportional to density. Thus, using the difference between these two measurements, the concentration of a known or suspected second gas species can be predicted along with the real flow rate so that it can be adjusted for a consistent oxygen to carbon ratio, ideally about 1: 1. Example 1 herein illustrates the situation when pure methane is diluted primarily with ethane. Nomenclature

[0083] For a mass flow / heat capacitance meter (MFM),

[0084] Therefore, the ratio between the real flow rate and the flow rate measured by the MFM is proportional to the variation of the product of the fluid density and heat capacity relative to that of the assumed (or calibration) fluid.

[0085] For a volume flow / density meter (DM),

[0086] Therefore, the ratio between the real flow rate and the flow rate measured by the DM is proportional to the square root of the variation of the density relative to that of the assumed (or calibration) fluid.

[0087] Therefore, when the MFM and DM are used simultaneously, the ratio between them is equivalent to:

[0088] For pure methane diluted primarily with a second gas species, the total sensor error can be defined as e such that:

[0089] It is found that, generally, the molar concentration (or partial pressure “p”) of the diluting species “X” can be approximated as proportional to the error: where “a” can be determined either by calibration or using thermodynamic calculations.

[0090] Using only this linear relation, a close estimate of the actual mass flow rate and concentration of methane can be made such that:

[0091] Theoretically, pressure drop across a specific geometry could be used as a proxy for viscosity, in a similar way to how MFM and DM are proxies for thermal capacitance and density, respectively, as the pressure drop through a particular pipe geometry is approximated as:

[0092] Where f is a friction factor that is proportional to the Reynolds number for laminar flow, with all geometry factors lumped in. The friction factor is defined as where is the coefficient of friction but can be treated as a calibration parameter related to the geometry and surface roughness and substituting for f in the pressure drop equation yields:

[0093] Therefore, pressure drop is proportional to the viscosity and velocity. If the velocity can be determined independently, the deviation of the pressure drop from the baseline value can be used as a proxy for the viscosity of the mixture, which will change with species concentrations.

[0094] Multiply by cross-sectional area to convert from velocity to volumetric flow rate: where is a re-formulated calibration parameter, relating pressure drop directly to volumetric flow rate at a constant viscosity.

[0095] Deviation of this flow measurement relative to either mass flow (heat capacity) or volume flow (density) meters will be inversely proportional to deviations in the viscosity. General sensor theory where there are two gas species:

[0096] Sensor Errors:

[0097] Mass versus density sensor

[0098] Density versus pressure sensor

[0099] Mass versus pressure sensor

[0100] For a suspected or known second gas species “X” in natural gas, any of the above three can be fit to thermodynamic data or calibration function to find the concentration of the second gas species:

[0101] Where a linear or higher order function may be appropriate depending on the relative species thermodynamic properties

[0102] Concentration of methane is:

[0103] Real flow rate is:

[0104] General sensor theory where there are three gas species:

[0105] Sensor Errors:

[0106] Mass versus density sensor Density versus pressure sensor

[0107] Mass versus pressure sensor

[0108] For a suspected or known second gas species “X” and a third gas species “F” in natural gas, two of the above three relations can be fit to thermodynamic data or calibration functions to find the concentration of the second and third gas species:

[0109] Where a linear or higher order function may be appropriate depending on the relative species thermodynamic properties

[0110] Concentration of methane is:

[0111] Real flow rate is:

[0112] Using these relationships, a heat capacity measurement, a viscosity measurement and a density measurement, when measured, can be expressed in normal liter per minute (NLPM) based on the thermal based mass flow meter, the differential pressure meter and the volumetric flow meter, respectively, being calibrated with 100% methane over a range of flow rates. Consequently, the real flow rate of the natural gas fuel through the reformer can be determined and adjusted accordingly including the flow rate of air through the reformer to provide a consistent oxygen to carbon ratio. See, for example, Example 1 where such measurements are produced using such a model as well as determining the appropriate adjustments to the mass flow meter flow rate setting. As previously mentioned, when the constituent species of a fluid changes or a new species is introduced, the density, thermal capacitance and viscosity will change, and the sensor measurements will diverge in predictable ways based on their dependence upon different fluid properties.

[0113] The ratio between the real volumetric flow rate and the flow rate measured by the thermal based mass flow meter is proportional to the product of the ratios of the heat capacity of the baseline (i.e., 100% methane) to the real heat capacity and the baseline density to the real density. If the product of the heat capacity and density increases relative to the baseline calibration fluid, the thermal based flow meter will overpredict the real flow rate, as is the case with the introduction of a heavier species such as ethane into natural gas. Conversely, if the product of the heat capacity and / or density decrease, the thermal based mass flow meter will underpredict the real flow rate, as is the case with the introduction of hydrogen into natural gas. Because of this dependency, the thermal based flow meter measurement can simultaneously act as a relative heat capacity measurement.

[0114] The ratio between the real flow rate and the flow rate measured by the volumetric flow meter is proportional to the square root of the ratio between the density of the baseline to the real density. If the density increases relative to the baseline calibration fluid, the volume flow meter will overpredict the real flow rate. Conversely, if the density decreases relative to the baseline calibration fluid, the volume based flow meter will underpredict the real flow rate. Because of this dependency, the volume based flow meter can simultaneously act as a relative density measurement.

[0115] The ratio between the real flow rate and the flow rate measured by the differential pressure meter is proportional to the ratio between the real viscosity and the viscosity of the baseline. If the viscosity of the fluid decreases relative to the baseline, the differential pressure meter will overpredict the real flow rate. Conversely, if the viscosity of the fluid increases relative to the baseline, the differential pressure meter will overpredict the real flow rate. Because of this dependency, the differential pressure meter can simultaneously act as a relative viscosity measurement.

[0116] Using the sensor measurement relations to fluid properties, the relative concentrations of two suspected fluid species can be estimated using two different sensor measurements or the relative concentrations of up to three suspected fluid species can be estimated using three different sensor measurements by applying knowledge of each species thermodynamic properties obtained from simple thermodynamic relations. Once the relative species concentrations are estimated, the real fluid properties can be estimated in turn and the appropriate corrections can be applied to the sensor controlling the flow rate of the natural gas fuel based on its relationships to the fluid properties.

[0117] Alternatively, if the properties of the species or baseline fluid are ambiguous or unknown, an expanded calibration matrix could be applied such that readings are taken from each sensor for various applied fluid mixtures and flow rates relative to the baseline, spanning the two or three different species which are of interest. This will create an array from which the real flow rates and species concentrations can be interpolated rather than relying on thermodynamic calculations.

[0118] The current balance of plant typically uses a thermal based mass flow sensor to control the amount of natural gas fuel being fed into the reformer of a fuel cell unit. The mass flow sensor is calibrated using 100% methane, with the voltage feedback from that sensor recorded over a preset range of natural gas fuel flow rates, generally between zero and 10 L for a 1.5 kW fuel cell system. The calibration generates a curve which is then used to drive the required pulse width modulation (PWM) for a proportional valve (e.g., a flow metering valve or device) for the natural gas fuel. For example, if seven liters of natural gas fuel is needed, the fuel valve will open until the voltage signal feedback from the sensor reaches the pre-calibrated voltage for “seven liters” using pure methane.

[0119] Natural gas contains varying amounts of methane, anywhere from 60-98 plus percent, with the balance generally being C2-C5 components, with the vast majority of those components being C2 (ethane) and C3 (propane) (usually well over 90%). These higher hydrocarbons have a higher mass and thermal capacity than methane, therefore the mass sensors voltage increases for the same volume of gas passing through the sensor. This decrease in observed volumetric flow for the same mass flow can be as high as 15-20% for an 85-90% methane containing natural gas, to as little as 3-7% for a 90-96% methane containing natural gas.

[0120] Assuming that the thermal sensor is contained in a fixed volume conduit, a pressure sensor downstream of the mass flow sensor, but in that same fixed volume then any reduction in flow rate associated with the increase mass and thermal capacity of the natural gas fuel going through the mass flow sensor should produce a reduction in pressure (PV = nRT). Using the same logic as above, now mix in, for example, 20% hydrogen into the natural gas fuel. The thermal sensor is calibrated for 100% methane. The relative mass density of the natural gas fuel feed has now dropped because hydrogen has a molar mass of 2 [g / mol] and methane is 16 [g / mol]. Therefore, the volumetric flow past the thermal sensor for the same given calibration voltage will be higher than what is being measured by the sensor. The higher volumetric flow rate will then drive the secondary pressure sensor signal higher. Because hydrogen is one of the only constituents that would actually decrease the relative mass of the fuel and cause that increase in volumetric flow, an estimated hydrogen concentration can be realized by calibrating the relative increase in flow and pressure. This concept can be very useful for running any fuel cell unit or system, or combustion based device.

[0121] To start and run a reformer, the oxygen to carbon ratio is very important, because if too low and then coking will occur, and if too high, the catalyst can be sintered or even cause flashing, Given the reformer feeds the fuel cell stack, any changes that are driven by undetected changes in fuel composition can reduce power output, decrease efficiency and even permanently damage the fuel cell. Back to a 20% hydrogen additional to natural gas fuel as the model, effective O:C ratio needs to be considered. Changing the composition of the carbon part of the calculation changes the effective ratio if the air flow into the reformer is not adjusted accordingly. If 20% of the natural gas fuel feed is now hydrogen, the effect O:C would go lean. Given that the kinetics for hydrogen combustion are faster than reforming kinetics for hydrocarbons such as methane, the hydrogen would react to create water, which could help to reform fuel but over the partial pressure of oxygen going into the fuel cell would still be higher, decreasing the overall efficiency and directly impacting the thermal characteristics of the system, especially for a partial oxidation (“POX”) driven reaction.

[0122] However, having calculated the hydrogen concentration based on the measurements from the meters, that value can be used to then reduce the amount of POX air being added to the natural gas fuel stream to more accurately maintain the O:C ratio that was originally desired. This maximizes the efficiency gain obtained by the additional hydrogen. It also increases the relative partial pressure of electrochemically oxidizable fuel in the reformate stream by reducing the dilution associated with the nitrogen from the POX air. It will also decrease the associated balance of plant load as the POX air blower (or steam generator) won’t need to work as hard for a given fuel input. Accordingly, the present teachings provide a method of operating a fuel cell unit with varying natural gas supplies comprising: flowing a natural gas fuel at a flow rate through a fixed volume conduit comprising an inlet and an outlet; performing at least two of the following after the inlet of the fixed volume conduit: measuring a relative heat capacity of the natural gas fuel flowing past a thermal based mass flow meter in thermal communication with the fixed volume conduit to provide a heat capacity measurement; measuring a relative viscosity of the natural gas fuel flowing through the fixed volume conduit to provide a viscosity measurement, wherein the fixed volume conduit is in fluid communication with a differential pressure meter; and measuring a relative density of the natural gas fuel flowing though the fixed volume conduit to provide a density measurement, wherein the fixed volume conduit is in fluid communication with a volumetric flow meter; wherein the thermal based flow meter, the pressure meter and the volumetric flow meter, when present, are located along the fixed volume conduit in any respective position along the direction of flow of the natural gas fuel; and the heat capacity measurement, the viscosity measurement and the density measurement, when measured, are expressed in normal liter per minute (NLPM) based on the thermal based mass flow meter, the differential pressure meter and the volumetric flow meter, respectively, being calibrated with 100% methane over a range of flow rates; and flowing the natural gas fuel at the flow rate past the outlet of the fixed volume conduit into a reformer of a fuel cell unit; wherein if a second gas species is present in the natural gas fuel, the second gas species being one of hydrogen or another hydrocarbon, then two of the three measuring steps are required; and using at least two of the heat capacity measurement, the viscosity measurement and the density measurement in relation to the fluid properties of methane and the second gas species to estimate the relative concentrations of methane and the second gas species; estimating the real fluid properties of the natural gas fuel using the relative concentrations of methane and the second gas species; and applying appropriate corrections to the flow rate of the natural gas fuel through the reformer based on the estimated real fluid properties, wherein: a flow rate of air mixed with the natural gas fuel prior to entering the reformer is decreased proportionally to the concentration of hydrogen to maintain a consistent oxygen to carbon ratio, or a flow rate of air mixed with the natural gas fuel prior to entering the reformer is increased proportionally to the concentration of the other hydrocarbon to maintain a consistent oxygen to carbon ratio.

[0123] In various embodiments of the above, if the heat capacity measurement of the natural gas fuel increases relative to the viscosity measurement or the density measurement, then increasing the flow rate of the natural gas fuel into the reformer of the fuel cell unit proportional to the difference between the measurements, or if the heat capacity measurement of the natural gas fuel decreases relative to the viscosity measurement or the density measurement, then decreasing the flow rate of the natural gas fuel into the reformer of the fuel cell unit proportional to the difference between the measurements, or if the density measurement of the natural gas fuel decreases relative to the viscosity measurement and the second gas species is hydrogen, then decreasing the flow rate of the natural gas fuel into the reformer of the fuel cell unit proportional to the difference between the density measurement and the viscosity measurement, or if the density measurement of the natural gas fuel decreases relative to the viscosity measurement and the second gas species is another hydrocarbon, then increasing the flow rate of the natural gas fuel into the reformer of the fuel cell unit proportional to the difference between the density measurement and the viscosity measurement. In some embodiments, the methods include using two of the three measuring steps to estimate the hydrogen concentration in the natural gas fuel in the absence of another hydrocarbon. In certain embodiments, when two measuring steps are used, the method further comprises determining the relative concentrations of two gaseous species present in the natural gas fuel.

[0124] In various embodiments, the present teachings provide a method of operating a fuel cell unit with varying natural gas supplies comprising: flowing a natural gas fuel at a flow rate through a fixed volume conduit comprising an inlet and an outlet; measuring a relative heat capacity of the natural gas fuel flowing past a thermal based mass flow meter in thermal communication with the fixed volume conduit to provide a heat capacity measurement; measuring a relative viscosity of the natural gas fuel flowing through the fixed volume conduit to provide a viscosity measurement, wherein the fixed volume conduit is in fluid communication with a differential pressure meter; and measuring a relative density of the natural gas fuel flowing though the fixed volume conduit to provide a density measurement, wherein the fixed volume conduit is in fluid communication with a volumetric flow meter; wherein the thermal based flow meter, the pressure meter and the volumetric flow meter are located along the fixed volume conduit in any respective position along the direction of flow of the natural gas fuel; and the heat capacity measurement, the viscosity measurement and the density measurement are expressed in normal liter per minute (NLPM) based on the thermal based mass flow meter, the differential pressure meter and the volumetric flow meter, respectively, being calibrated with 100% methane over a range of flow rates; and flowing the natural gas fuel at the flow rate past the outlet of the fixed volume conduit into a reformer of a fuel cell unit; wherein if a second gas species and a third gas species are present in the natural gas fuel, the second gas species and the third gas species being selected from the group consisting of hydrogen, another hydrocarbon and a third hydrocarbon, using the heat capacity measurement, the viscosity measurement and the density measurement in relation to the fluid properties of methane, the second gas species and the third gas species to estimate the relative concentrations of methane, the second gas species and the third gas species; estimating the real fluid properties of the natural gas fuel using the relative concentrations of methane, the second gas species and the third gas species; and applying appropriate corrections to the flow rate of natural gas fuel through the reformer based the estimated real fluid properties, wherein: if the concentration of hydrogen is greater than the concentration of the total amount of carbon contained in the third gas species, the flow rate of air mixed with the natural gas fuel prior to entering the reformer is decreased proportionally to the difference between the concentration of hydrogen and the concentration of the third gas species to maintain a consistent oxygen to carbon ratio, or if the concentration of hydrogen is less than the concentration of the total amount of carbon contained in the third gas species, the flow rate of air mixed with the natural gas fuel prior to entering the reformer is increased proportionally to the difference between the concentration of hydrogen and the concentration of the third gas species to maintain a consistent oxygen to carbon ratio, or if no hydrogen is present, the flow rate of air mixed with the natural gas fuel prior to entering the reformer is increased proportionally to the total amount of carbon contained in the second gas species and the third gas species to maintain a consistent oxygen to carbon ratio.

[0125] In some embodiments of the above, if the heat capacity measurement of the natural gas fuel increases relative to the viscosity measurement and the density measurements, then increasing the flow rate of the natural gas fuel into the reformer of the fuel cell unit proportional to the difference among the measurements, or if the heat capacity measurement of the natural gas fuel decreases relative to the viscosity measurement and the density measurement, then decreasing the flow rate of the natural gas fuel into the reformer of the fuel cell unit proportional to the difference among the measurements, or if the heat capacity measurement and the density measurement are the same but both decrease relative to the viscosity measurement, then decreasing the flow rate of the natural gas fuel into the reformer, or if the heat capacity measurement and the viscosity measurement are the same but both increase relative to the density measurement, then increasing the flow rate of the natural gas fuel into the reformer, or if the heat capacity measurement increases relative to the density measurement but decreases relative to the viscosity measurement, then a correction of the flow rate of natural gas fuel and / or a flow rate of air is needed dependent on the relative differences among the measurements and the expected constituent properties in the natural gas fuel, or if the viscosity measurement is less than the density measurement regardless of the heat capacity measurement, then the meters need to be recalibrated, or an error has occurred, or an unexpected species has been introduced and the natural gas fuel should be characterized.

[0126] In some embodiments, the methods include using the three measuring steps to estimate the concentration of hydrogen and the other hydrocarbon in the natural gas fuel. In certain embodiments, when three measuring steps are used, the method further comprises determining the relative concentrations of three gaseous species present in the natural gas fuel.

[0127] In various embodiments, the thermal mass flow meter measures absolute temperature measurements or relative temperature differences. In some embodiments, the differential pressure meter measures absolute pressure measurements, or absolute pressure measurement versus ambient pressure, or relative pressure differences. In certain embodiments, the density measurement meter measures absolute pressure measurements, or relative pressures differences, where a second measurement is at a smaller cross-sectional area than a first measurement.

[0128] In various embodiments, the fixed volume conduit is a single conduit.

[0129] In some embodiments, the fixed volume conduit comprises a by-pass conduit, wherein an inlet and an outlet of the by-pass conduit is in fluid communication with an interior of the fixed volume conduit. In certain embodiments, the inlet of the by-pass conduit is in fluid communication with the interior of the fixed volume conduit via a manifold. In some embodiments, the outlet of the by-pass conduit is in fluid communication with the interior of the fixed volume conduit via a manifold. In particular embodiments, the fixed volume conduit comprises a second by-pass conduit, wherein an inlet and an outlet of the second by-pass conduit is in fluid communication with an interior of the fixed volume conduit.

[0130] In certain embodiments, the consistent oxygen to carbon ratio is a predetermined ratio. For example, the predetermined ratio can be between about 0.7: 1 to about 1:0.7, about 0.8: 1 to about 1:0.8, about 0.9: 1 to about 1:0.9., or about 1: 1.

[0131] The present teachings also include apparatus for carrying out the methods of the invention. For example, referring to FIG. 4, the present teachings provide a flow sensor assembly 10 for a fuel cell unit, comprising: a fixed volume conduit 14 positioned upstream of and in fluid communication with a reformer 16 of a fuel cell unit; at least two of the following three meters (all three meter are shown): a mass flow meter 20 in thermal communication with a flow of a natural gas fuel through the fixed volume conduit; a differential pressure meter 24 tapped into the fixed volume conduit and in fluid communication with the flow of the natural gas fuel through the fixed volume conduit; and a volumetric flow meter 26 tapped into the fixed volume conduit at a first cross-section and at a second cross-section smaller than the first cross-section and in fluid communication with the flow of the natural gas fuel through the fixed volume conduit; wherein the at least two of the mass flow sensor, the differential pressure meter, and the volumetric flow meter are located in any order contiguously along the fixed volume conduit; and a central processing unit 28 in electrical communication with the at least two of the mass flow meter, the differential pressure meter, and the volumetric flow meter, and adapted to control the flow rate of the natural gas fuel through the fixed volume conduit based on feedback from the at least two of the mass flow meter, the differential pressure meter, and the volumetric flow meter. In various embodiments, the flow sensor assembly further comprises a flow metering device 30 located upstream of or downstream of the at least two of the mass flow meter, the differential pressure meter, and the volumetric flow meter, wherein the flow metering device 30 is in electrical communication with the central processing unit 28 and is adapted to control the flow rate of natural gas fuel 22 and / or flow rate of air through the fixed volume conduit based on feedback from the at least two of the mass flow meter, the differential pressure meter, and the volumetric flow meter.

[0132] FIG. 5 is a schematic diagram of a flow sensor assembly 10’ including a CPU 28’ in electrical communication with a fuel / air mixer 32 to control the flow rate of air into the natural gas stream in the fuel air mixer. The fuel / air mixer 32 is in fluid communication with the fixed volume conduit (not shown) and the reformer 16’, located immediately before it as part of a fuel cell unit 18 (i.e., the reformer, a fuel cell stack and an afterburner).

[0133] FIG. 6 is a schematic of one embodiment of a flow sensor assembly 10” having a bypass conduit 42 and a second by-pass conduit 48, where the by-pass conduit and the second bypass conduit are in fluid communication with each other and a central (fixed volume) conduit 50 via a first manifold 44 at an upstream end of the conduits based on the flow of natural gas fuel 22’ and via a second manifold 46 at the downstream end of the conduits. The figure depicts the presence of each of the three meters on different conduits in different locations along their respective conduits. That is, the mass flow meter 20’ is associated with the by-pass conduit 42, the differential pressure meter 24’ is associated with the second by-pass conduit 48, and the volumetric flow meter 26 is associated with the central conduit 50. Each of the meters is in electrical communication with a CPU 28”. The CPU also is in electrical communication with a flow metering device 30’ to control the flow of fluid through the flow sensor assembly.

[0134] It should be understood that a single conduit can represent a fixed volume conduit and that when one or more by-pass conduits are present, the combination of the conduits represents a fixed volume such that the various principles applied herein to a single fixed volume conduit are equally applicable to systems having one or more by-pass conduits. It also should be understood that the arrangement and presence of one or more meters as described and / or depicted herein can take various positions and combination of meters including arrangements and combinations not explicitly depicted or taught herein but within the scope of the present teachings. FIGS. 7-20 depict embodiments of the apparatus of the present teachings showing the various placement of the meters described herein including the different measurements that can be taken by each of the meters. The figures also depict the use of by-pass conduits, manifolds, flow metering valve / devices, demonstrating the breadth of designs that can be accomplished, all as described herein. That is, the thermal based flow meter, the pressure meter and the volumetric flow meter can be located along the fixed volume conduit in any respective position along the direction of flow of the natural gas fuel, including being located on a by-pass conduit and / or a second by-pass conduit, and / or an nthorder number of by-pass conduits. It should be understood that the figures of the various permutations of the design of the apparatus are merely illustrative and not exhaustive. Thus, other variations as described but not depicted are included within the scope of the present teachings. Moreover, embodiments with one or more by-pass conduits can overall be considered to be of a fixed volume, for example, a fixed volume conduit.

[0135] More specifically, FIGS. 7A-7C depict embodiments of a combination of a density meter (P*1and P*2or ΔP*) and a differential pressure meter (P1and / or P2, or ΔP), where in FIG. 7A- 7B absolute pressure measurements are obtained, in FIG. 7B absolute pressure measurement P1is compared to ambient pressure, and in FIG. 7C relative pressure measurements are obtained.

[0136] FIG. 8A-8C are schematic diagrams of embodiments of a partially combined density meter (P*1and P*2or ΔP*) and a differential pressure meter (P1and / or P2, or ΔP), where FIG. 8A-8B absolute pressure measurements are obtained, in FIG. 8B absolute pressure measurement P1is compared to ambient pressure, and in FIG. 8C relative pressure measurements are obtained.

[0137] FIGS. 9A-9E are schematic diagrams of embodiments of combinations of a mass flow meter (MFM) and a differential pressure meter (P1 and / or P2) for direct flow measurements. FIGS. 9D and 9E depict an internal known pressure drop between P1 and P2.

[0138] FIGS. 10A-10G are schematic diagrams of embodiments of combinations of a mass flow meter (MFM) and a differential pressure meter (P1 and / or P2) for by-pass flow measurements. FIGS. 10A and 10B depict the mass flow meter and differential pressure meter to be on different conduits, where FIGS. 10C-10G depict the meters on the same conduit. FIGS. 10B, 10D and 10G depict an internal known pressure drop between P1 and P2.

[0139] FIGS. 11A-11E are schematic diagrams of embodiments of a combination of a mass flow meter (MFM) and a differential pressure meter (P1 and / or P2) for direct flow measurements and upstream thereof, a flow metering device with a valve to control the flow of natural gas fuel through the fixed volume conduit via a manifold. FIGS. 11D and 11E depict an internal known pressure drop between P1 and P2.

[0140] FIGS. 12A-12E are schematic diagrams of embodiments of a combination of a mass flow meter (MFM) and a differential pressure meter (P1 and / or P2) for direct flow measurements and downstream thereof, a flow metering device with a valve to control the flow of natural gas fuel from the fixed volume conduit via a manifold. FIGS. 12D and 12E depict an internal known pressure drop between P1 and P2.

[0141] FIGS. 13A-13G are schematic diagrams of embodiments of a combination of a mass flow meter (MFM) and a differential pressure meter (P1 and / or P2) for by-pass flow measurements and upstream thereof, a flow metering device with a valve to control the flow of natural gas fuel through the fixed volume conduit via a manifold. FIGS. 13B, 13C, and 13G depict an internal known pressure drop between P1 and P2.

[0142] FIGS. 14A-14G are schematic diagrams of embodiments of a combination of a mass flow meter (MFM) and a differential pressure meter (P1 and / or P2) for by-pass flow measurements and downstream thereof, a flow metering device with a valve to control the flow of natural gas fuel from the fixed volume conduit via a manifold. FIGS. 14B, 14C, and 14G depict an internal known pressure drop between P1 and P2.

[0143] FIGS. 15A-15E are schematic diagrams of embodiments of a combination of a mass flow meter (MFM), a differential pressure meter (P1 and / or P2), and a volumetric flow meter or a density meter (DM) for direct flow measurements. FIG. 15E depicts an internal known pressure drop between P1 and P2.

[0144] FIGS. 16A-16G are schematic diagrams of embodiments of a combination of a mass flow meter (MFM), a differential pressure meter (P1 and / or P2), and a volumetric flow meter or a density meter (DM) for by-pass flow measurements. FIGS. 16F and 16G depict an internal known pressure drop between P1 and P2.

[0145] FIGS. 17A and 17B are schematic diagrams of embodiments of a combination of a mass flow meter (MFM), a differential pressure meter (P1 and / or P2), and a volumetric flow meter or a density meter (DM) for direct flow measurements for dual by-pass flow measurements. FIG. 17B depicts an internal known pressure drop between P1 and P2. FIGS. 18A-18E are schematic diagrams of embodiments of a combination of a mass flow meter (MFM), a differential pressure meter (P1 and / or P2), and a volumetric flow meter or a density meter (DM) for direct flow measurements, and upstream thereof, a flow metering device with a valve to control the flow of natural gas fuel through the fixed volume conduit via a manifold. FIGS. 18F-18J are schematic diagrams of embodiments of a combination of a mass flow meter (MFM), a differential pressure meter ( P1 and / or P2), and a volumetric flow meter or a density meter (DM) for direct flow measurements, downstream thereof, a flow metering device with a valve to control the flow of natural gas fuel from the fixed volume conduit via a manifold. FIGS. 18E and 18J depict an internal known pressure drop between P1 and P2.

[0146] FIGS. 19A-19G are schematic diagrams of embodiments of a combination of a mass flow meter (MFM), a differential pressure meter (P1 and / or P2), and a volumetric flow meter or a density meter (DM) for by-pass flow measurements, and upstream thereof, a flow metering device with a valve to control the flow of natural gas fuel through the fixed volume conduit via a manifold. FIGS. 19F and 19G depict an internal known pressure drop between P1 and P2.

[0147] FIGS. 20A-20G are schematic diagrams of embodiments of a combination of a mass flow meter (MFM), a differential pressure meter (P1 and / or P2), and a volumetric flow meter or a density meter (DM) for by-pass flow measurements, and downstream thereof, a flow metering device with a valve to control the flow of natural gas fuel from the fixed volume conduit via a manifold. FIGS. 20F and 20G depict an internal known pressure drop between P1 and P2.

[0148] Theoretically, each of the three meters described herein, as stand alone or in any of the groupings possible, could be located at any of the 10 positions shown in FIG. 21. To differentiate between two species, one each of any two sensors are required at any of these positions (or a combined two sensor module as described in prior diagrams). To differentiate between three species, one MFM, one DM and one ΔP are required at any of these positions or in any order / combination at any position (or a combined three sensor module as described in diagrams herein). FIGS. 22A-22C, 23A and 23B depict the various placement of each of the three meters in respective positions generally according to the design shown in FIG. 21.

[0149] FIG. 24 is a schematic diagram of the placement of a combination of a mass flow meter (MFM), a differential pressure meter ( ΔP). and a volumetric flow meter or a density meter (DM) at positions a and ab, positions c and cd, and at abed, which placements permit the differentiation of three or more gas species using the multiple meters in series or in parallel (e.g., natural gas fuel containing ethane and propane being combined from multiple sources). Returning to the meters, in various embodiments of methods and apparatus, the mass flow meter is adapted to measure absolute temperatures or a relative temperature difference. In various embodiments, the differential pressure meter is adapted to measure absolute pressures, an absolute pressure versus ambient pressure, or a relative pressure difference. In some embodiments, the volumetric flow meter is adapted to measure absolute pressures, or a relative pressure difference.

[0150] As for calibration of the meters, in various embodiments, the mass flow meter is calibrated using 100% methane and a voltage reading of the mass flow meter indicates a relative heat capacity of the natural gas fuel at a measured flow rate. In some embodiments, the differential pressure meter is calibrated using 100% methane and a voltage reading of the differential pressure meter indicates a relative viscosity of the natural gas fuel at a measured flow rate. In some embodiments, the volumetric flow meter is calibrated with 100% methane and a voltage reading of the volumetric flow meter indicates a relative density of the natural gas fuel at a measured flow rate.

[0151] In various embodiments, introduction of air into the natural gas fuel stream can be done at an inlet of the fixed volume conduit, downstream from the inlet of the fixed volume conduit, and / or at or immediately before the inlet of the reformer, e.g., the fixed volume conduit is in fluid communication with a fuel / air mixer immediately before the reformer.

[0152] As described herein, the fixed volume conduit can be a single conduit. The fixed volume conduit can include a by-pass conduit, wherein an inlet and an outlet of the by-pass conduit can be in fluid communication with an interior of the fixed volume conduit. The flow sensor assembly can include one or more by-pass conduits. In some embodiments, at least two of the mass flow meter, the differential pressure meter, and the volumetric flow meter are located at any position along the fixed volume conduit and one or more by-pass conduits. In certain embodiments, the mass flow meter, the differential pressure meter, and the volumetric flow meter are present and are located at any position along the fixed volume conduit and one or more of the by-pass conduits.

[0153] In various embodiments, the inlet of the by-pass conduit is in fluid communication with the interior of the fixed volume conduit via a first manifold. In some embodiments, the flow metering device is in fluid communication with the first manifold. In some embodiments, the outlet of the by-pass conduit is in fluid communication with the interior of the fixed volume conduit via a second manifold. In various embodiments, a second by-pass conduit having an inlet and an outlet, wherein an inlet of the second by-pass conduit is in fluid communication with the first manifold and an outlet of the second by-pass conduit is in fluid communication with the second manifold. In such cases, the mass flow meter, the differential pressure meter, and the volumetric flow meter can be present and can be located at any position along the fixed volume conduit, the by-pass conduit, and the second by-pass conduit.

[0154] Oxygen Sensor

[0155] The methods and apparatus of the present teachings can also include, an oxygen sensor, for example, that measures the partial pressure of oxygen leaving a conduit containing a catalytic bed (e.g., a reformer of a fuel cell unit). Either by itself or in combination with other sensors or meters depicted and described herein, an oxygen sensor can be used to measure the concentration of hydrogen and / or other hydrocarbon species in relation to other species or constituents in a natural gas fuel. That is, using the catalytic bed in combination with an electrochemical oxygen partial pressure measurement, a temperature dependency of the catalytic oxidation (and subsequent oxygen partial pressure change) of individual natural gas fuel constituents can be used to determine the composition of the natural gas fuel. Again, knowing the composition of the natural gas fuel can inform the flow rate of natural gas fuel and / or flow rate of air into the conduit containing the catalytic bed, e.g., the reformer of a fuel cell unit.

[0156] For pure methane, its flow measurement is 100% accurate, i.e., a 1: 1 O:C ratio;

[0157] Flow rates are set to 1: 1 O:C ratio assuming pure methane, but the real flow rate of natural gas is 12% lower than measured such that our method predicts the actual mixture is 90% CHr to 10% C2H6. The chemistry assuming only CH4and C2H6 effectively becomes: which is 9% low on hydrogen and 3% low on CO compared to what is expected. Correcting the flowrate to match the initial setpoint for volumetric flow rat yields: which is still 5% low on oxygen, but we have excess methane which could be reformed internally to the cell. If we correct the O:C ratio accounting for total carbon in both methane and ethane, we get:

[0158] Assumptions include ethane reforms just as readily as methane if not more so; and low or offsetting concentrations of additional species such as N2, C3H8and C4H10.

[0159] Drawbacks include overestimating the amount of carbon due to presence of inert phases (e.g., CO2and / or N2), then the O:C ratio would be overshot. For reforming applications upstream of fuel cell stacks, it is likely better to match fuel flow rate to reality and keep the O:C ratio uncorrected, dealing with excess hydrocarbons via internal reforming. For combustion applications, the preference would be to also correct the O:C ratio to guarantee complete combustion.

[0160] In various embodiments, the natural gas fuel comprises hydrogen, which causes steam reforming to occur in a reformer downstream from the fixed volume conduit. In some embodiments, the steam reforming ceases when the partial oxidation reaction is at its operating temperature.

[0161] Reformer simulations performed with a flow rate of 65 seem CH4mixed with air at a 1 to 1 oxygen to carbon ratio and added H2such that there was a 1 to 4 and 1 to 2 ratio of H2to CH4yielding partial pressures of

[0162] Oxygen and steam concentration data were taken at the outlet for average reformer temperatures ranging from about 100 °C to 800 °C, with the physics simulations data plotted in the FIGS. 25 and 26 for each of a methane to hydrogen ratio of 4: 1 and of 2: 1.

[0163] In this temperature range, we see 4 distinct phenomena. First, the region below -200 °C where little oxidation occurs and the catalytic bed is heating up. Little to no water is generated. Second, the region from -200 °C to -480 °C where hydrogen is being oxidized, which oxidation plateaus around 400 °C where the majority of hydrogen is consumed and water is beginning to be generated, which also reaches a plateau. Third, the region from -480 °C to -550 °C where excess steam begins to be produced by CH4oxidation as seen in the sharp rise in water output in FIG. 26. Fourth, the region above -550 °C where all oxygen is consumed (FIG. 25) and steam fraction goes down as the POX reaction mechanism begins to dominate (FIG. 26). Theoretically, the relative chemical potential at the inlet and outlet of the reformer could be measured using a voltage tap at both locations with respect to each other, to a common electrode, or to separate reference electrodes. Using this voltage difference, the amount of oxygen consumed at the plateau in region 2 could be used to accurately measure the hydrogen content of the fuel stream.

[0164] Either in stand alone or in combination with other sensors, the oxygen sensor can be used to measure hydrogen content in relation to other species.

[0165] Global reaction for partial oxidation of methane with hydrogen at 1: 1 O:C ratio

[0166] To fully reform CH4you still need a 1: 1 O:C ratio, but the overall volume ratio of air (21% O2) to fuel will go down with respect to a as:

[0167] For example, if the flow rate of fuel is 1 NLPM, the air needed versus the ratio of hydrogen to methane “a” is shown in FIG. 27.

[0168] Therefore, this sensor could be used to accurately adjust the air flow rate for a natural gas fuel with an uncertain hydrogen concentration by simply measuring the amount of oxygen consumed in Stage II of the temperature curve and applying this simple relation shown above.

[0169] Accordingly in various embodiments of the methods described herein, the present teachings provide a method comprising or further comprising measuring the partial pressure of oxygen at a downstream end of a catalyst bed of the reformer. For example, the downstream end of the catalyst bed of the reformer can comprise a first electrochemical sensor, and measuring the partial pressure of oxygen after the catalyst bed of the reformer comprises measuring a voltage from the first electrochemical sensor. In some embodiments, an initial increase in the voltage from the first electrochemical sensor indicates that the reformer is increasing in heat. In some embodiments, the voltage from the first electrochemical sensor indicates an oxygen to carbon ratio of air and natural gas fuel flowing through the reformer.

[0170] In various embodiments, the present teachings provide methods further comprising measuring the partial pressure of oxygen before the catalyst bed of the reformer. For example, the reformer before the catalyst bed can comprise a second electrochemical sensor, and measuring the partial pressure of oxygen before the catalyst bed of the reformer comprises measuring a voltage from the second electrochemical sensor. In certain embodiments, the voltage of the first electrochemical sensor and the voltage of the second electrochemical sensor are measured in relation to each other, or are measured with respect to a first reference electrode and a second reference electrode, respectively. In some embodiments, measuring the conversion of natural gas fuel to hydrogen can use a measured voltage difference between the first electrochemical sensor and the second electrochemical sensor.

[0171] In various embodiments, the present teachings provide methods further comprising measuring an average temperature of the reformer, to provide an average measured reformer temperature. In some embodiments, the methods include comparing the average measured reformer temperature of the reformer versus the partial pressure of oxygen at the downstream end of a catalyst bed of the reformer to determine when the majority of the hydrogen is consumed. In some embodiments, the partial pressure of oxygen at the downstream end of the catalyst bed substantially forms a plateau when the majority of the hydrogen is being consumed above an average measured temperature of the reformer of about 350 °C. In certain embodiments, the partial pressure of oxygen at the downstream end of the catalyst bed at the plateau and the measured voltage difference between the first electrochemical sensor and the second electrochemical sensor permit determination of the concentration of hydrogen of the natural gas fuel. Accordingly, the methods can include adjusting the flow rate of natural gas fuel and / or a flow rate of air into the reformer based on the concentration of hydrogen in the natural gas fuel to maintain a consistent oxygen to carbon ratio.

[0172] In various embodiments, the partial pressure of oxygen at the downstream end of the catalyst bed substantially forms one or more plateaus below an average measured reformer temperature of 350 °C, wherein the one or more plateaus are indicative of other hydrocarbon species in the natural gas fuel.

[0173] In some embodiments, the methods further comprise identifying the other hydrocarbon species based on the average measured reformer temperature of its respective plateau. In certain embodiments, the methods further comprise determining the concentration of the other hydrocarbon species to determine an adjusted flow rate of natural gas fuel and / or flow rate of air into the reformer based on the concentration of the other hydrocarbon species to maintain a consistent oxygen to carbon ratio. In some embodiments, the partial pressure of oxygen at the downstream end of the catalyst bed of the reformer increases and informs of the decline of the average measured reformer temperature. In certain embodiments, the average measured reformer temperature declines after reaching an operating average measured reformer temperature indicating that the reformer may need to be re-ignited.

[0174] The present teachings also provide a method of determining the concentration of hydrogen in a natural gas fuel comprising: measuring a partial pressure of oxygen exiting a conduit containing a catalytic bed, wherein a natural gas fuel is passed at flow rate through the conduit until the oxygen is substantially consumed by a partial oxidation reaction with the catalytic bed occurring above about 500 °C; wherein a plateau of the partial pressure of oxygen occurs between about 360 °C and about 440 °C, the initial partial pressure of oxygen minus the plateau of partial pressure of oxygen being proportional to the concentration of hydrogen in the natural gas fuel.

[0175] Accordingly, the methods can further comprise adjusting the flow rate of the natural gas fuel and / or a flow rate of air passed through the conduit based on the concentration of hydrogen in the natural gas fuel to maintain a consistent oxygen to carbon ratio.

[0176] In various embodiments, the conduit containing the catalytic bed is a reformer. In some embodiments, the reformer is in fluid communication with a fuel cell stack.

[0177] In various embodiments, the present teachings provide a method of determining the concentration of ethane and hydrogen in a natural gas fuel comprising: measuring a partial pressure of oxygen exiting a conduit containing a catalytic bed, wherein a natural gas fuel is passed at flow rate through the conduit until the oxygen is substantially consumed by a partial oxidation reaction with the catalytic bed occurring above about 550 °C; wherein a plateau of the partial pressure of oxygen occurs between about 280 °C and about 320 °C, the initial partial pressure of oxygen minus the plateau of partial pressure of oxygen being proportional to the concentration of ethane in the natural gas fuel; and wherein a plateau of the partial pressure of oxygen occurs between about 360 °C and about 440 °C, the initial partial pressure of oxygen minus the plateau of partial pressure of oxygen being proportional to the concentration of hydrogen in the natural gas fuel.

[0178] The methods can further include adjusting the flow rate of natural gas fuel and / or a flow rate of air passed through the conduit based on the concentrations of ethane and hydrogen in the natural gas fuel to maintain a consistent oxygen to carbon ratio.

[0179] In various embodiments, the present teachings provide a method of determining the concentration of multiple gas species in a natural gas fuel comprising: measuring a partial pressure of oxygen exiting a conduit containing a catalytic bed, wherein a natural gas fuel is passed at flow rate through the conduit until the oxygen is substantially consumed by a partial oxidation reaction with the catalytic bed occurring above about 550 °C; wherein a first plateau of the partial pressure of oxygen occurs, the initial partial pressure of oxygen minus the first plateau of partial pressure of oxygen being proportional to the concentration of a first gas species in the natural gas fuel; wherein a second plateau of the partial pressure of oxygen occurs, the initial partial pressure of oxygen minus the second plateau of partial pressure of oxygen being proportional to the concentration of a second gas species in the natural gas fuel; and wherein additional plateaus of the partial pressure of oxygen occur, the initial partial pressure of oxygen minus each of the additional plateaus of partial pressure of oxygen being proportional to a respective concentration of additional gas species in the natural gas fuel.

[0180] In some embodiments, the methods further comprise adjusting the flow rate of natural gas fuel and / or a flow rate of air passed through the conduit based on the concentrations of the gas species in the natural gas fuel to maintain a consistent oxygen to carbon ratio.

[0181] In various embodiments described herein, a flow sensor assembly further comprises a first electrochemical sensor located at or near an outlet of the reformer. The flow sensor assembly can further comprise a second electrochemical sensor located at or near an inlet of the reformer. In certain embodiments, the first electrochemical sensor is connected to the second electrochemical sensor, for example, via a reference electrode. In certain embodiments, the first electrochemical sensor is connected to a first reference electrode and the second electrochemical sensor is connected to a second reference electrode.

[0182] In various embodiments described herein, a central processing unit is in electrical communication with the first electrochemical sensor and the second electrochemical sensor, and is adapted to determine the flow rate of the natural gas fuel through the fixed volume conduit based on feedback from the first electrochemical sensor, the second electrochemical sensor and the at least two of the mass flow meter, the differential pressure meter, and the volumetric flow meter.

[0183] In some embodiments, the present teachings provide a voltage sensor assembly comprising a first electrochemical sensor acting as an oxygen sensor located at the outlet of a reformer of a fuel cell unit, wherein the oxygen sensor is in electrical communication with a central processing unit, adapted to determine a flow rate of natural gas fuel and / or a flow rate of air through the reformer based on feedback from the first electrochemical sensor to maintain a consistent oxygen to carbon ratio. In certain embodiments, the voltage sensor assembly comprises a second electrochemical sensor acting as an oxygen sensor located near the inlet of the reformer, wherein the second electrochemical sensor is in electrical communication with the first electrochemical sensor and the central processing unit, adapted to determine a flow rate of natural gas fuel and / or a flow rate of air through the reformer based on feedback from the first electrochemical sensor and the second electrochemical sensor.

[0184] In various embodiments, the present teachings provide a voltage sensor assembly comprising a first electrochemical sensor acting as an oxygen sensor located at the outlet of a conduit containing a catalytic bed, wherein the oxygen sensor is in electrical communication with a central processing unit, adapted to determine a flow rate of natural gas fuel and / or a flow rate of air through the conduit based on feedback from the first electrochemical sensor to maintain a consistent oxygen to carbon ratio. In some embodiments, the voltage sensor assembly comprises a second electrochemical sensor acting as an oxygen sensor located near the inlet of the conduit, wherein the second electrochemical sensor is in electrical communication with the first electrochemical sensor and the central processing unit, adapted to determine a flow rate of natural gas fuel and / or a flow rate of air through the conduit based on feedback from the first electrochemical sensor and the second electrochemical sensor. With reference to FIG. 28A, which is schematic cross-sectional diagram of an embodiment of a voltage sensor assembly 70 associated with a conduit 50’ containing a catalytic bed 82. FIG. 28A shows a first electrochemical sensor 72 having a first voltage tap 73 located at the end of the catalytic bed and a second electrochemical sensor 74 having a second voltage tap

[0185] 75 located at the beginning of the catalytic bed. This diagram depicts a first reference electrode

[0186] 76 and a second reference electrode 78 associated with the first electrochemical sensor 72 and the second electrochemical sensor 74, respectively. The electrochemical sensors 72, 74 and reference electrodes 76, 78 are in electrical communication with a CPU 28”. The voltage sensor assembly 70’ in FIG. 28B is similar at the opposite ends of the catalytic bed 82’ but the electrochemical sensors 72’, 74’ share a common reference electrode 84 which sensors and electrode can be in electrical communications with a CPU (not shown). Finally, the voltage sensor assembly 70” in FIG. 28C also is similar at the opposite ends of the catalytic bed 82” but the electrochemical sensors 72”, 74” have a relative voltage measured across the two voltage taps without the use of a reference electrode. The electrochemical sensors can be in electrical communication with a CPU (not shown).

[0187] It should be understood that a single electrochemical sensor can act as an oxygen sensor, where the oxygen sensor(s) are in electrical communication with a CPU 28”, which is adapted to determine a flow rate of natural gas fuel and / or a flow rate of air through the conduit based on feedback from first electrochemical sensor, or the first electrochemical sensor and the second electrochemical sensor. It should further be understood that the outlet of the conduit can be in fluid communications with a device requiring the flow of a fluid into it such as a fuel cell unit, an internal combustion engine, a water heater, and an HVAC system (not shown).

[0188] EXAMPLE

[0189] In order that the disclosure described herein may be more fully understood, the following example is set forth. The example should not be construed in any way as limiting the scope of the invention.

[0190] Example 1. Methane Diluted with Hydrogen and / or Ethane The following are properties for the three gas species.

[0191] From thermodynamic calculations varying both hydrogen and ethane from 0 to 30% partial pressure, it is found that the following relation of the concentrations of ethane and hydrogen to the error between the heat capacity and density readings is accurate with an uncertainty for the error less than +2%:

[0192] CFD simulations are used to also produce a dataset of viscosity readings verses both the heat capacity and density readings. From those simulations, it is found that the following relation of the error between the heat capacity and viscosity readings and the concentrations of hydrogen and ethane is accurate with an uncertainty for the error of less than +1%:

[0193] Combining these equations, the concentration of either ethane or hydrogen can be expressed only in terms of the errors between the sensor readings:

[0194] The following table shows the calibrated values of the parameters a, b and c : The following are examples of sensor readings and the derived concentrations and real flow rate based on their relative measurements at 25 °C using the above fitted equations and parameters.

[0195] Example 1a. Methane Diluted with Ethane and Hydrogen

[0196] As can be seen reading down the chart starting with the second row where ethane and hydrogen are present, if both density and viscosity read lower than heat capacity, more ethane is present than hydrogen and the flow rate of the natural gas fuel should be increased.

[0197] If both density and viscosity read higher than heat capacity, more hydrogen is present than ethane and flow rate of the natural gas fuel should be decreased.

[0198] If density reads lower but viscosity reads higher than heat capacity, the flow rate of the natural gas fuel may need adjusted higher or lower depending on the relative error.

[0199] When high concentrations of H2and C2H6exist in similar concentrations, the flow rate of the natural gas fuel may need adjusted higher or lower depending on the relative error. In this situation, the flow rate adjustment would benefit from an electrochemical sensor (oxygen sensor) to get accurate measure of the amount of H2present.

[0200] If heat capacity and density are the same but viscosity reads high, there is more hydrogen than ethane and the flow rate of the natural gas fuel should be decreased.

[0201] If heat capacity and viscosity are the same but density reads low, there are equal parts ethane and hydrogen, and flow rate should be increased.

[0202] Note that the relative viscosity reading should always be greater than or equal to relative density reading unless an additional species is present which invalidates this model. Example lb. Methane Diluted with Ethane

[0203] Density and viscosity measurements may not be suitable alone to measure C2H6 concentration because the readings are nearly identical. Here is an example where a voltage sensor assembly (e.g., an oxygen sensor) can be used to determine the relative concentrations of ethane present in each natural gas fuel supply to appropriately adjust the flow rate of the natural gas fuel and / or the flow rate of air through the reformer of a fuel cell unit.

[0204] Example 1c. Methane Diluted with Hydrogen

[0205] Here, any two sensors can be used to estimate hydrogen concentration alone in the absence of C2H6.

[0206] EQUIVALENTS

[0207] The invention may be embodied in other specific forms without departing from the spirit or essential characteristics thereof. The foregoing embodiments are therefore to be considered in all respects illustrative rather than limiting the invention described herein. Scope of the invention is thus indicated by the appended claims rather than by the foregoing description, and all changes that come within the meaning and range of equivalency of the claims are intended to be embraced therein.

Claims

CLAIMS1. A method of operating a fuel cell unit with varying natural gas supplies comprising: flowing a natural gas fuel at a flow rate through a fixed volume conduit comprising an inlet and an outlet; performing at least two of the following after the inlet of the fixed volume conduit: measuring a relative heat capacity of the natural gas fuel flowing past a thermal based mass flow meter in thermal communication with the fixed volume conduit to provide a heat capacity measurement; measuring a relative viscosity of the natural gas fuel flowing through the fixed volume conduit to provide a viscosity measurement, wherein the fixed volume conduit is in fluid communication with a differential pressure meter; and measuring a relative density of the natural gas fuel flowing though the fixed volume conduit to provide a density measurement, wherein the fixed volume conduit is in fluid communication with a volumetric flow meter; wherein the thermal based flow meter, the pressure meter and the volumetric flow meter, when present, are located along the fixed volume conduit in any respective position along the direction of flow of the natural gas fuel; and the heat capacity measurement, the viscosity measurement and the density measurement, when measured, are expressed in normal liter per minute (NLPM) based on the thermal based mass flow meter, the differential pressure meter and the volumetric flow meter, respectively, being calibrated with 100% methane over a range of flow rates; and flowing the natural gas fuel past the outlet of the fixed volume conduit into a reformer of a fuel cell unit; wherein: if a second gas species is present in the natural gas fuel, the second gas species being one of hydrogen or another hydrocarbon, then two of the three measuring steps are required; and using at least two of the heat capacity measurement, the viscosity measurement and the density measurement in relation to the fluid properties of methane and the second gas species to estimate the relative concentrations of methane and the second gas species; estimating the real fluid properties of the natural gas fuel using the relative concentrations of methane and the second gas species; andapplying appropriate corrections to the flow rate of the natural gas fuel through the reformer based on the estimated real fluid properties, wherein: a flow rate of air mixed with the natural gas fuel prior to entering the reformer is decreased proportionally to the concentration of hydrogen to maintain a consistent oxygen to carbon ratio, or a flow rate of air mixed with the natural gas fuel prior to entering the reformer is increased proportionally to the concentration of the other hydrocarbon to maintain a consistent oxygen to carbon ratio.

2. The method of claim 1, wherein if the heat capacity measurement of the natural gas fuel increases relative to the viscosity measurement or the density measurement, then increasing the flow rate of the natural gas fuel into the reformer of the fuel cell unit proportional to the difference between the measurements, or if the heat capacity measurement of the natural gas fuel decreases relative to the viscosity measurement or the density measurement, then decreasing the flow rate of the natural gas fuel into the reformer of the fuel cell unit proportional to the difference between the measurements, or if the density measurement of the natural gas fuel decreases relative to the viscosity measurement and the second gas species is hydrogen, then decreasing the flow rate of the natural gas fuel into the reformer of the fuel cell unit proportional to the difference between the density measurement and the viscosity measurement, or if the density measurement of the natural gas fuel decreases relative to the viscosity measurement and the second gas species is another hydrocarbon, then increasing the flow rate of the natural gas fuel into the reformer of the fuel cell unit proportional to the difference between the density measurement and the viscosity measurement.

3. The method of claim 1 or 2, using two of the three measuring steps to estimate the hydrogen concentration in the natural gas fuel in the absence of another hydrocarbon.

4. The method of claim 1 or 2, wherein when two measuring steps are used, the method further comprises determining the relative concentrations of two gaseous species present in the natural gas fuel.

5. A method of operating a fuel cell unit with varying natural gas supplies comprising: flowing a natural gas fuel at a flow rate through a fixed volume conduit comprising an inlet and an outlet; measuring a relative heat capacity of the natural gas fuel flowing past a thermal based mass flow meter in thermal communication with the fixed volume conduit to provide a heat capacity measurement; measuring a relative viscosity of the natural gas fuel flowing through the fixed volume conduit to provide a viscosity measurement, wherein the fixed volume conduit is in fluid communication with a differential pressure meter; and measuring a relative density of the natural gas fuel flowing though the fixed volume conduit to provide a density measurement, wherein the fixed volume conduit is in fluid communication with a volumetric flow meter; wherein the thermal based flow meter, the pressure meter and the volumetric flow meter are located along the fixed volume conduit in any respective position along the direction of flow of the natural gas fuel; and the heat capacity measurement, the viscosity measurement and the density measurement are expressed in normal liter per minute (NLPM) based on the thermal based mass flow meter, the differential pressure meter and the volumetric flow meter, respectively, being calibrated with 100% methane over a range of flow rates; and flowing the natural gas fuel past the outlet of the fixed volume conduit into a reformer of a fuel cell unit; wherein if a second gas species and a third gas species are present in the natural gas fuel, the second gas species and the third gas species being selected from the group consisting of hydrogen, another hydrocarbon and a third hydrocarbon, using the heat capacity measurement, the viscosity measurement and the density measurement in relation to the fluid properties of methane, the second gas species and the third gas species to estimate the relative concentrations of methane, the second gas species and the third gas species; estimating the real fluid properties of the natural gas fuel using the relative concentrations of methane, the second gas species and the third gas species; andapplying appropriate corrections to the flow rate of natural gas fuel through the reformer based the estimated real fluid properties, wherein: if the concentration of hydrogen is greater than the concentration of the total amount of carbon contained in the third gas species, the flow rate of air mixed with the natural gas fuel prior to entering the reformer is decreased proportionally to the difference between the concentration of hydrogen and the concentration of the third gas species to maintain a consistent oxygen to carbon ratio, or if the concentration of hydrogen is less than the concentration of the total amount of carbon contained in the third gas species, the flow rate of air mixed with the natural gas fuel prior to entering the reformer is increased proportionally to the difference between the concentration of hydrogen and the concentration of the third gas species to maintain a consistent oxygen to carbon ratio, or if no hydrogen is present, the flow rate of air mixed with the natural gas fuel prior to entering the reformer is increased proportionally to the total amount of carbon contained in the second gas species and the third gas species to maintain a consistent oxygen to carbon ratio.

6. The method of claim 5, wherein if the heat capacity measurement of the natural gas fuel increases relative to the viscosity measurement and the density measurements, then increasing the flow rate of the natural gas fuel into the reformer of the fuel cell unit proportional to the difference among the measurements, or if the heat capacity measurement of the natural gas fuel decreases relative to the viscosity measurement and the density measurement, then decreasing the flow rate of the natural gas fuel into the reformer of the fuel cell unit proportional to the difference among the measurements, or if the heat capacity measurement and the density measurement are the same but both decrease relative to the viscosity measurement, then decreasing the flow rate of the natural gas fuel into the reformer, or if the heat capacity measurement and the viscosity measurement are the same but both increase relative to the density measurement, then increasing the flow rate of the natural gas fuel into the reformer, or if the heat capacity measurement increases relative to the density measurement but decreases relative to the viscosity measurement, then a correction of the flow rate of natural gas fuel and / or a flow rate of air is needed dependent on the relative differences among the measurements and the expected constituent properties in the natural gas fuel, orif the viscosity measurement is less than the density measurement regardless of the heat capacity measurement, then the meters need to be recalibrated, or an error has occurred, or an unexpected species has been introduced and the natural gas fuel should be characterized.

7. The method of claim 3 or 4, using the three measuring steps to estimate the concentration of hydrogen and the other hydrocarbon in the natural gas fuel.

8. The method of claim 3 or 4, wherein when three measuring steps are used, the method further comprises determining the relative concentrations of three gaseous species present in the natural gas fuel.

9. The method of any one of claims 1-8, wherein the thermal mass flow meter measures absolute temperature measurements or relative temperature differences.

10. The method of any one of claims 1-9, wherein the differential pressure meter measures absolute pressure measurements, or absolute pressure measurement versus ambient pressure, or relative pressure differences.

11. The method of any one of claims 1-10, wherein the density meter measures absolute pressure measurements, or relative pressures differences, where a second measurement is at a smaller cross-sectional area than a first measurement.

12. The method of any one of claims 1-11, wherein the fixed volume conduit is a single conduit.

13. The method of any one of claims 1-11, wherein the fixed volume conduit comprises a by-pass conduit, wherein an inlet and an outlet of the by-pass conduit is in fluid communication with an interior of the fixed volume conduit.

14. The method of claim 13, wherein the inlet of the by-pass conduit is in fluid communication with the interior of the fixed volume conduit via a manifold.

15. The method of claim 13 or 14, wherein the outlet of the by-pass conduit is in fluid communication with the interior of the fixed volume conduit via a manifold.

16. The method of any one of claims 13-15, wherein the fixed volume conduit comprises a second by-pass conduit, wherein an inlet and an outlet of the second by-pass conduit is in fluid communication with an interior of the fixed volume conduit.

17. The method of any one of claims 1-16, wherein the natural gas fuel comprises hydrogen, which causes steam reforming to occur in a reformer downstream from the fixed volume conduit.

18. The method of claim 17, wherein the steam reforming ceases when the partial oxidation reaction is at its operating temperature.

19. The method of any one of claims 1-18, wherein the consistent oxygen to carbon ratio is a predetermined ratio.

20. The method of any one of claims 1-19, further comprising measuring the partial pressure of oxygen at a downstream end of a catalyst bed of the reformer.

21. The method of claim 20, wherein the downstream end of the catalyst bed of the reformer comprises a first electrochemical sensor, and measuring the partial pressure of oxygen after the catalyst bed of the reformer comprises measuring a voltage from the first electrochemical sensor.

22. The method of claim 21, wherein an initial increase in the voltage from the first electrochemical sensor indicates that the reformer is increasing in heat.

23. The method of claim 21 or 22, wherein the voltage from the first electrochemical sensor indicates an oxygen to carbon ratio of air and natural gas fuel flowing through the reformer.

24. The method of any one of claims 20-23, further comprising measuring the partial pressure of oxygen before the catalyst bed of the reformer.

25. The method of claim 24, wherein the reformer before the catalyst bed comprises a second electrochemical sensor, and measuring the partial pressure of oxygen before the catalyst bed of the reformer comprises measuring a voltage from the second electrochemical sensor.

26. The method of claim 25, wherein the voltage of the first electrochemical sensor and the voltage of the second electrochemical sensor are measured in relation to each other, or are measured with respect to a first reference electrode and a second reference electrode, respectively.

27. The method of claim 26, further comprising measuring the conversion of natural gas fuel to hydrogen using a measured voltage difference between the first electrochemical sensor and the second electrochemical sensor.

28. The method of any one of claim 1-27, further comprising measuring an average temperature of the reformer, to provide an average measured reformer temperature.

29. The method of claim 28, comprising comparing the average measured reformer temperature of the reformer versus the partial pressure of oxygen at the downstream end of a catalyst bed of the reformer to determine when the majority of the hydrogen is consumed.

30. The method of claim 29, wherein the partial pressure of oxygen at the downstream end of the catalyst bed substantially forms a plateau when the majority of the hydrogen is being consumed above an average measured temperature of the reformer of about 350 °C.

31. The method of claim 30, wherein the partial pressure of oxygen at the downstream end of the catalyst bed at the plateau and the measured voltage difference between the first electrochemical sensor and the second electrochemical sensor permit determination of the concentration of hydrogen of the natural gas fuel.

32. The method of claim 31, further comprising adjusting the flow rate of natural gas fuel and / or a flow rate of air into the reformer based on the concentration hydrogen in the natural gas fuel to maintain a consistent oxygen to carbon ratio.

33. The method of claim 28, wherein the partial pressure of oxygen at the downstream end of the catalyst bed substantially forms one or more plateaus below an average measured reformer temperature of 350 °C, wherein the one or more smaller plateaus are indicative of other hydrocarbon species in the natural gas fuel.

34. The method of claim 33, further comprising identifying the other hydrocarbon species based on the average measured reformer temperature of its respective plateau.

35. The method of claim 34, further comprising determining the concentration of the other hydrocarbon species to determine an adjusted flow rate of natural gas fuel and flow rate of air into the reformer based on the concentration of the other hydrocarbon species to maintain a consistent oxygen to carbon ratio.

36. The method of claim 28, wherein the average measured reformer temperature declines after reaching an operating average measured reformer temperature indicating that the reformer may need to be re-ignited.

37. The method of claim 36, wherein the partial pressure of oxygen at the downstream end of the catalyst bed of the reformer increases and informs of the decline of the average measured reformer temperature.

38. A method of determining the concentration of hydrogen in a natural gas fuel comprising: measuring a partial pressure of oxygen exiting a conduit containing a catalytic bed, wherein a natural gas fuel is passed at flow rate through the conduit until the oxygen is substantially consumed by a partial oxidation reaction with the catalytic bed occurring above about 500 °C;wherein a plateau of the partial pressure of oxygen occurs between about 360 °C and about 440 °C, the initial partial pressure of oxygen minus the plateau of partial pressure of oxygen being proportional to the concentration of hydrogen in the natural gas fuel.

39. The method of claim 38, further comprising adjusting the flow rate of the natural gas fuel and / or a flow rate of air passed through the conduit based on the concentration of hydrogen in the natural gas fuel to maintain a consistent oxygen to carbon ratio.

40. The method of claim 38 or 39, wherein the conduit containing the catalytic bed is a reformer.

41. The method of claim 40, wherein the reformer is in fluid communication with a fuel cell stack.

42. A method of determining the concentration of ethane and hydrogen in a natural gas fuel comprising: measuring a partial pressure of oxygen exiting a conduit containing a catalytic bed, wherein a natural gas fuel is passed at flow rate through the conduit until the oxygen is substantially consumed by a partial oxidation reaction with the catalytic bed occurring above about 550 °C; wherein a plateau of the partial pressure of oxygen occurs between about 280 °C and about 320 °C, the initial partial pressure of oxygen minus the plateau of partial pressure of oxygen being proportional to the concentration of ethane in the natural gas fuel; and wherein a plateau of the partial pressure of oxygen occurs between about 360 °C and about 440 °C, the initial partial pressure of oxygen minus the plateau of partial pressure of oxygen being proportional to the concentration of hydrogen in the natural gas fuel.

43. The method of claim 42, further comprising adjusting the flow rate of natural gas fuel and / or a flow rate of air passed through the conduit based on the concentrations of ethane and hydrogen in the natural gas fuel to maintain a consistent oxygen to carbon ratio.

44. A method of determining the concentration of multiple gas species in a natural gas fuel comprising:measuring a partial pressure of oxygen exiting a conduit containing a catalytic bed, wherein a natural gas fuel is passed at flow rate through the conduit until the oxygen is substantially consumed by a partial oxidation reaction with the catalytic bed occurring above about 550 °C; wherein a first plateau of the partial pressure of oxygen occurs, the initial partial pressure of oxygen minus the first plateau of partial pressure of oxygen being proportional to the concentration of a first gas species in the natural gas fuel; wherein a second plateau of the partial pressure of oxygen occurs, the initial partial pressure of oxygen minus the second plateau of partial pressure of oxygen being proportional to the concentration of a second gas species in the natural gas fuel; and wherein additional plateaus of the partial pressure of oxygen occur, the initial partial pressure of oxygen minus each of the additional plateaus of partial pressure of oxygen being proportional to a respective concentration of additional gas species in the natural gas fuel.

45. The method of claim 44, further comprising adjusting the flow rate of natural gas fuel and / or a flow rate of air passed through the conduit based on the concentrations of the gas species in the natural gas fuel to maintain a consistent oxygen to carbon ratio.

46. A flow sensor assembly for a fuel cell unit, comprising a fixed volume conduit positioned upstream of and in fluid communication with a reformer of a fuel cell unit; at least two of the following three meters: a mass flow meter in thermal communication with a flow of a natural gas fuel through the fixed volume conduit; a differential pressure meter tapped into the fixed volume conduit and in fluid communication with the flow of the natural gas fuel through the fixed volume conduit; and a volumetric flow meter tapped into the fixed volume conduit at a first crosssection and at a second cross-section smaller than the first cross-section and in fluid communication with the flow of the natural gas fuel through the fixed volume conduit; wherein the at least two of the mass flow sensor, the differential pressure meter, and the volumetric flow meter are located in any order contiguously along the fixed volume conduit; and a central processing unit in electrical communication with the at least two of the mass flow meter, the differential pressure meter, and the volumetric flow meter, and adapted to controlthe flow rate of the natural gas fuel through the fixed volume conduit based on feedback from the at least two of the mass flow meter, the differential pressure meter, and the volumetric flow meter.

47. The flow sensor assembly of claim 46, further comprising a flow metering device located upstream of or downstream of the least two of the mass flow meter, the differential pressure meter, and the volumetric flow meter, wherein the flow metering device is in electrical communication with the central processing unit and is adapted to control the flow rate of natural gas fuel through the fixed volume conduit based on feedback from the at least two of the mass flow meter, the differential pressure meter, and the volumetric flow meter.

48. The flow sensor assembly of claim 446 or 47, wherein the mass flow meter is adapted to measure absolute temperatures or a relative temperature difference.

49. The flow sensor assembly of any one of claims 46-48, wherein the differential pressure meter is adapted to measure absolute pressures, an absolute pressure versus ambient pressure, or a relative pressure difference.

50. The flow sensor assembly of any one of claims 46-49, wherein the volumetric flow meter is adapted to measure absolute pressures, or a relative pressure difference.

51. The flow sensor assembly of any one of claims 46-50, wherein the mass flow meter is calibrated using 100% methane and a voltage reading of the mass flow meter indicates a relative heat capacity of the natural gas fuel at a measured flow rate.

52. The flow sensor assembly of any one of claims 46-51, wherein the differential pressure meter is calibrated using 100% methane and a voltage reading of the differential pressure meter indicates a relative viscosity of the natural gas fuel at a measured flow rate.

53. The flow sensor assembly of any one of claims 46-52, wherein the volumetric flow meter is calibrated with 100% methane and a voltage reading of the volumetric flow meter indicates a relative density of the natural gas fuel at a measured flow rate.

54. The flow sensor assembly of any one of claims 46-53, wherein the fixed volume conduit is in fluid communication with a fuel / air mixer immediately before the reformer.

55. The flow sensor assembly of any one of claims 46-54, wherein the fixed volume conduit is a single conduit.

56. The flow sensor assembly of any one of claims 46-54, wherein the fixed volume conduit comprises a by-pass conduit, wherein an inlet and an outlet of the by-pass conduit is in fluid communication with an interior of the fixed volume conduit.

57. The flow sensor assembly of claim 56, wherein the flow sensor assembly comprises one or more by-pass conduits.

58. The flow sensor assembly of claim 56 or 57, wherein at least two of the mass flow meter, the differential pressure meter, and the volumetric flow meter are located at any position along the fixed volume conduit and one or more by-pass conduits.

59. The flow sensor assembly of claim 56 or 57, wherein the mass flow meter, the differential pressure meter, and the volumetric flow meter are present and are located at any position along the fixed volume conduit and one or more of the by-pass conduits.

60. The flow sensor assembly of claim 56, wherein the inlet of the by-pass conduit is in fluid communication with the interior of the fixed volume conduit via a first manifold.

61. The flow sensor assembly of claim 60, wherein the flow metering device is in fluid communication with the first manifold.

62. The flow sensor assembly of claim 56, 60 or 61, wherein the outlet of the by-pass conduit is in fluid communication with the interior of the fixed volume conduit via a second manifold.

63. The flow sensor assembly of claim 57, comprising a second by-pass conduit having an inlet and an outlet, wherein an inlet of the second by-pass conduit is in fluidcommunication with the first manifold and an outlet of the second by-pass conduit is in fluid communication with the second manifold.

64. The flow sensor assembly of claim 63, wherein the mass flow meter, the differential pressure meter, and the volumetric flow meter are present and are located at any position along the fixed volume conduit, the by-pass conduit, and the second by-pass conduit.

65. The flow sensor assembly of any one of claims 46-64, further comprising a first electrochemical sensor located near an outlet of the reformer.

66. The flow sensor assembly of claim 65, further comprising a second electrochemical sensor located near an inlet of the reformer.

67. The flow sensor assembly of claim 66, wherein the first electrochemical sensor is connected to the second electrochemical sensor.

68. The flow sensor assembly of claim 66, wherein the first electrochemical sensor is connected to a first reference electrode and the second electrochemical sensor is connected to a second reference electrode.

69. The flow sensor assembly of claim 66, wherein the first electrochemical sensor and the second electrochemical sensor are connected to a common reference electrode.

70. The flow sensor assembly of any one of claims 66-69, wherein the central processing unit is in electrical communication with the first electrochemical sensor and the second electrochemical sensor, and is adapted to determine the flow rate of the natural gas fuel through the fixed volume conduit based on feedback from the first electrochemical sensor, the second electrochemical sensor and the at least two of the mass flow meter, the differential pressure meter, and the volumetric flow meter.

71. A voltage sensor assembly comprising a first electrochemical sensor acting as an oxygen sensor located near an outlet of a reformer of a fuel cell unit, wherein the oxygen sensor is in electrical communication with a central processing unit, adapted to determine a flow rate ofnatural gas fuel and / or a flow rate of air through the reformer based on feedback from the first electrochemical sensor to maintain a consistent oxygen to carbon ratio.

72. The voltage sensor assembly of claim 71, comprising a second electrochemical sensor acting as an oxygen sensor located near an inlet of the reformer, wherein the second electrochemical sensor is in electrical communication with the first electrochemical sensor and the central processing unit, adapted to determine a flow rate of natural gas fuel and / or a flow rate of air through the reformer based on feedback from the first electrochemical sensor and the second electrochemical sensor.

73. A voltage sensor assembly comprising a first electrochemical sensor acting as an oxygen sensor located near an outlet of a conduit containing a catalytic bed, wherein the oxygen sensor is in electrical communication with a central processing unit, adapted to determine a flow rate of natural gas fuel and / or a flow rate of air through the conduit based on feedback from the first electrochemical sensor to maintain a consistent oxygen to carbon ratio.

74. The voltage sensor assembly of claim 73, comprising a second electrochemical sensor acting as an oxygen sensor located near an inlet of the conduit, wherein the second electrochemical sensor is in electrical communication with the first electrochemical sensor and the central processing unit, adapted to determine a flow rate of natural gas fuel and / or a flow rate of air through the conduit based on feedback from the first electrochemical sensor and the second electrochemical sensor.

75. The voltage sensor assembly of any one of claims 71-74, wherein the first electrochemical sensor is connected to the second electrochemical sensor.

76. The flow sensor assembly of any one of claims 71-74, wherein the first electrochemical sensor is connected to a first reference electrode and the second electrochemical sensor is connected to a second reference electrode.

77. The flow sensor assembly of any one of claims 71-74, wherein the first electrochemical senor and the second electrochemical sensor are connected to a common reference electrode.

78. The voltage sensor assembly of any one of claims 73-77, wherein the outlet of the conduit is in fluid communication with a device selected from the group consisting of a fuel cell unit, an internal combustion engine, a water heater, and a heating, ventilation and air conditioning system.

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