WO2010120309A1 - Détection de fuite de gaz d'un empilement de piles à combustible - Google Patents

Détection de fuite de gaz d'un empilement de piles à combustible Download PDF

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Publication number
WO2010120309A1
WO2010120309A1 PCT/US2009/040989 US2009040989W WO2010120309A1 WO 2010120309 A1 WO2010120309 A1 WO 2010120309A1 US 2009040989 W US2009040989 W US 2009040989W WO 2010120309 A1 WO2010120309 A1 WO 2010120309A1
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WO
WIPO (PCT)
Prior art keywords
flow field
gas
conductivity
liquid
fuel cell
Prior art date
Application number
PCT/US2009/040989
Other languages
English (en)
Inventor
Sitaram Ramaswamy
Bryan F. Dufner
Adam J. Hathaway
Original Assignee
Utc Power Corporation
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Utc Power Corporation filed Critical Utc Power Corporation
Priority to PCT/US2009/040989 priority Critical patent/WO2010120309A1/fr
Publication of WO2010120309A1 publication Critical patent/WO2010120309A1/fr

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Classifications

    • H—ELECTRICITY
    • H01—ELECTRIC ELEMENTS
    • H01M—PROCESSES OR MEANS, e.g. BATTERIES, FOR THE DIRECT CONVERSION OF CHEMICAL ENERGY INTO ELECTRICAL ENERGY
    • H01M8/00—Fuel cells; Manufacture thereof
    • H01M8/04—Auxiliary arrangements, e.g. for control of pressure or for circulation of fluids
    • H01M8/04298—Processes for controlling fuel cells or fuel cell systems
    • H01M8/04313—Processes for controlling fuel cells or fuel cell systems characterised by the detection or assessment of variables; characterised by the detection or assessment of failure or abnormal function
    • H01M8/04664—Failure or abnormal function
    • H01M8/04679—Failure or abnormal function of fuel cell stacks
    • H—ELECTRICITY
    • H01—ELECTRIC ELEMENTS
    • H01M—PROCESSES OR MEANS, e.g. BATTERIES, FOR THE DIRECT CONVERSION OF CHEMICAL ENERGY INTO ELECTRICAL ENERGY
    • H01M8/00—Fuel cells; Manufacture thereof
    • H01M8/04—Auxiliary arrangements, e.g. for control of pressure or for circulation of fluids
    • H01M8/04082—Arrangements for control of reactant parameters, e.g. pressure or concentration
    • H01M8/04197—Preventing means for fuel crossover
    • H—ELECTRICITY
    • H01—ELECTRIC ELEMENTS
    • H01M—PROCESSES OR MEANS, e.g. BATTERIES, FOR THE DIRECT CONVERSION OF CHEMICAL ENERGY INTO ELECTRICAL ENERGY
    • H01M8/00—Fuel cells; Manufacture thereof
    • H01M8/06—Combination of fuel cells with means for production of reactants or for treatment of residues
    • H01M8/0606—Combination of fuel cells with means for production of reactants or for treatment of residues with means for production of gaseous reactants
    • H01M8/0612—Combination of fuel cells with means for production of reactants or for treatment of residues with means for production of gaseous reactants from carbon-containing material
    • H—ELECTRICITY
    • H01—ELECTRIC ELEMENTS
    • H01M—PROCESSES OR MEANS, e.g. BATTERIES, FOR THE DIRECT CONVERSION OF CHEMICAL ENERGY INTO ELECTRICAL ENERGY
    • H01M8/00—Fuel cells; Manufacture thereof
    • H01M8/24—Grouping of fuel cells, e.g. stacking of fuel cells
    • H01M8/249—Grouping of fuel cells, e.g. stacking of fuel cells comprising two or more groupings of fuel cells, e.g. modular assemblies
    • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
    • Y02E—REDUCTION OF GREENHOUSE GAS [GHG] EMISSIONS, RELATED TO ENERGY GENERATION, TRANSMISSION OR DISTRIBUTION
    • Y02E60/00—Enabling technologies; Technologies with a potential or indirect contribution to GHG emissions mitigation
    • Y02E60/30—Hydrogen technology
    • Y02E60/50—Fuel cells

Definitions

  • the present disclosure relates in general to fuel cell power plants, and more particularly, to a system and method for detecting leakage of reactant gases from a fuel cell stack.
  • Fuel cell power plants are well known for converting chemical energy into usable electrical power. Fuel cell power plants usually comprise multiple fuel cells arranged in a repeating fashion to form a cell stack assembly ("CSA"), including internal ports or external manifolds connecting coolant fluid and reactant gas flow passages or channels. Each individual fuel cell in a CSA typically includes a proton exchange membrane (“PEM”) sandwiched between an anode electrode and a cathode electrode to form a membrane electrode assembly (“MEA").
  • PEM proton exchange membrane
  • bipolar plates On either side of the MEA are electrically conductive bipolar plates (also referred to as separator plates) that comprise gas flow fields for supplying a reactant fuel (e.g., hydrogen) to the anode, and a reactant oxidant (e.g., oxygen or air) to the cathode.
  • a reactant fuel e.g., hydrogen
  • a reactant oxidant e.g., oxygen or air
  • one or more of the bipolar plates also include a coolant flow field on an opposing side that circulates water to maintain each fuel cell at a desired operating temperature.
  • the reactant gases are typically supplied at desirable gas pressures relative to a pressure of the liquid, such as coolant water. However, if the pressures are not maintained within a desired range, the reactant gases may overcome the coolant water pressure and escape from the flow fields into the coolant. Additionally, for porous or solid bipolar plates, the reactant gases may also escape through leak paths formed between the bipolar plates and the PEM, or generally through seals and junctions between plates and other CSA components.
  • Leaks and other conditions causing reactant gas to pass into fuel cell liquids must be detected so that necessary corrective actions and/or repairs may take place. It is also desirable to determine the extent of leakage of gas into the liquid in order to distinguish between those situations that may be dangerous versus those that may be small enough to not warrant any immediate corrective action. As an example, if hydrogen gas is allowed to leak into coolant liquid, it can escape into an air space within an accumulator, and at certain concentrations, may result in a potentially flammable mixture warranting immediate corrective action.
  • a system and method provide an output representative of a gas leakage from a gas flow field of a fuel cell stack into a liquid flow field.
  • the output is a function of a measured conductivity in the liquid flow field.
  • FIG. 1 is a schematic diagram showing a gas leak detection system for a cell stack assembly.
  • FIG. 2 is a schematic diagram showing a gas leak detection system for a plurality of cell stack assemblies.
  • FIG. 3 is a flowchart showing a method for detecting gas leakage in a cell stack assembly and initiating corrective actions.
  • FIG. 4 shows a curve of the percentage of the lower flammability limit for hydrogen gas in an accumulator exhaust flow field as a function of water conductivity in a liquid flow field due to gas leakage of a cell stack assembly having porous flow fields and carbon dioxide impurities.
  • FIG. 5 shows a curve of the percentage of the lower flammability limit for hydrogen gas in an accumulator exhaust flow field as a function of water conductivity in a liquid flow field due to gas leakage of a cell stack assembly having solid flow fields and carbon dioxide impurities.
  • FIG. 6 shows a curve of the percentage of the lower flammability limit for hydrogen gas in an accumulator exhaust flow field as a function of water conductivity in a liquid flow field due to gas leakage of a cell stack assembly having solid flow fields and no carbon dioxide impurities in the liquid entering the liquid flow field.
  • a gas leak detection system includes detecting the leakage of gas from a gas flow field of a CSA to a liquid flow field by measuring a conductivity of the liquid to indicate the leakage of gas. More specifically, a constituent of the leaked gas, such as carbon dioxide, functions to increase the conductivity of liquid that captures the leaked gas, thereby allowing gas leaks to be detected based upon a measured conductivity of liquid in liquid flow fields of the CSA. For example, conductivity of liquid exiting a healthy CSA having no gas leaks may be used to establish a threshold conductivity value, with conductivity measurements exceeding this value used to indicate the leakage of gas. Alternatively, as described in more detail below, other threshold values may be established to identify those leaks excessive enough to warrant corrective actions and eventual shutdown of the CSA so that flammable conditions are not established, for example.
  • FIG. 1 is a schematic diagram of gas leak detection system 10, which may include CSA 12 (having anodes 14, cathodes 16 and coolers 18); accumulator 20 (having air space 22 and liquid 24); gas leak detector 26; fuel source F; oxidant source O; liquid source L; gas flow fields including fuel inlet flow field Fl, fuel flow field F2, fuel outlet flow field F3, oxidant inlet flow field 01, oxidant flow field 02, oxidant outlet flow field 03, accumulator oxidant flow field 04, and accumulator exhaust flow field E; liquid flow fields including liquid inlet flow field Ll, liquid flow field L2, liquid outlet flow field L3, accumulator liquid outlet flow field L4, moat inlet flow field Ml, moat flow field M2, and moat outlet flow field M3; gas leak Gl, G2, and G3; and conductivity sensors Cl and C2.
  • An output signal from gas leak detector 26 is labeled S.
  • gas flow fields including Fl, F2, F3, 01, 02, 03, and 04
  • liquid is directed through liquid flow fields Ll, L2, L3, and L4, and optionally Ml, M2, and M3.
  • gas flow fields and liquid flow fields may comprise various channels, internal ports and external manifolds.
  • hydrogen rich gas fuel from fuel source F is supplied to fuel flow field F2 via fuel inlet flow field Fl, electrochemically reacts with an anode 12 catalyst on each PEM (not shown) of each fuel cell in CSA 12, and is exhausted via fuel outlet flow field F3.
  • gaseous oxidant from oxidant source O is supplied to oxidant flow field 02 via oxidant inlet flow field 01, electrochemically reacts with a cathode 14 catalyst on each PEM (not shown) of each fuel cell in CSA 12, and is exhausted via oxidant outlet flow field 03.
  • the electrochemical reaction across each PEM produced by anode 14 catalysts and cathode 16 catalysts creates heat that can exceed a healthy operating temperature of fuel cells in CSA 12. Therefore, coolers or water transport plates 18 are provided to cool CSA 12.
  • Coolers 18 comprise liquid flow field L2.
  • Liquid contained in liquid flow field L2 may be utilized for absorbing heat to cool CSA 12, or in the case of porous bipolar plates, may also function to humidify reactant gases contained in fuel flow field F2, for example.
  • Liquid used for both cooling and humidifying purposes is typically deionized water, however, glycol based coolants may also be used in the case of a closed coolant loop system.
  • moat flow field M2 is utilized as a liquid seal to limit overboard leakage of gases from CSA 12, it may either rely on liquid inlet flow field Ll for a source of liquid via moat inlet flow field Ml as shown in FIG. 1, or may utilize an independent liquid source not shown.
  • FIG. 1 shows that moat flow field M2 may be used to capture leaked gas from gas leak Gl coming from fuel flow field F2 as well as gas leak G2 coming from oxidant flow field 02, and then carry it away from CSA 12 via moat outlet flow field M3 and liquid outlet flow field L3. These leaks may occur, for example, when leak paths form between the bipolar plates (solid or porous) and a PEM, or generally through seals and junctions between plates and other CSA 12 components. In systems not employing moat flow field M2, liquid flow field L2 may in some circumstances capture gas leaked from gas leak G3 originating from fuel flow field F2 and/or oxidant flow field 02.
  • Gas directed through fuel flow field F2 comprises hydrogen, which can leak via gas leak Gl and/or G3 into liquid flow fields of CSA 12, such as M2 and/or L2 respectively. This leaked hydrogen is then carried away from CSA 12 with liquid carried by outlet flow field L3.
  • liquid from outlet flow field L3 is directed to accumulator 20 and accumulates as liquid 24.
  • Accumulator oxidant flow field 04 directs air or pure oxygen into accumulator 20 such that oxidant bubbles up through liquid 24 to remove dissolved carbon dioxide in liquid 24. Carbon dioxide gas removed from liquid 24 collects in air space 22 and is exhausted away from accumulator 20 in accumulator exhaust flow field E.
  • Liquid 24 is typically directed away in accumulator liquid outlet flow field L4 to a water treatment system, for example, prior to joining back with liquid source L.
  • hydrogen contained in liquid 24 will rise with oxidant and carbon dioxide gas into air space 22. If hydrogen gas is allowed to accumulate in air space 22 for too long, it can create a flammable and potentially dangerous condition in air space 22.
  • hydrogen has a lower flammability limit (LFL) of about 4% hydrogen in air. Therefore, in the case of a hydrogen gas leak, corrective action must take place prior to reaching the LFL.
  • LFL lower flammability limit
  • FIG. 1 shows a system and method 10 for detecting the leakage of gas into moat flow field M2 and/or liquid flow field L2.
  • fuel source F comprises a hydrocarbon fuel
  • reformer to produce hydrogen rich reformate gas prior to being fed to fuel flow field F2 via fuel inlet flow field Fl.
  • Reformate typically comprises a large percentage of carbon dioxide along with the hydrogen, with the remainder comprising small amounts of water, methane, and trace amounts of carbon monoxide. Therefore, when reformate fuel from fuel flow field F2 leaks via gas leak Gl and/or G3 into liquid contained in moat flow field M2 and/or liquid flow field L2, respectively, the carbon dioxide in the reformate will be captured in the liquid along with the hydrogen at a fixed ratio.
  • an output representative of gas leakage via gas leak Gl and/or G3 into moat flow field M2 and/or liquid flow field L2 may be provided as a function of conductivity measured in liquid that has captured the leaked gas.
  • the amount of hydrogen leakage may be quantified based on a known ratio of carbon dioxide to hydrogen in the reformate, along with other CSA 12 operating variables that may exist, in order to signal at what point corrective actions should take place, for example, to prevent hydrogen gas from reaching its LFL in accumulator 20.
  • the system and method of the present disclosure may also work for non- reformate fuel cell power plant systems by adding an amount of carbon dioxide to fuel source F sufficient to result in a detectable rise in conductivity of liquid that captures leaked gas.
  • carbon dioxide could similarly be added to oxidant source O for the detection of oxidant leaking via gas leak G2 and/or G3.
  • purposefully adding carbon dioxide is not the preferred method due to the negative impact on efficiency of CSA 12 having less available reactant for carrying out an electrochemical reaction. It may be appreciated that other gases having an effect on liquid conductivity could similarly be used instead of carbon dioxide.
  • Gas leak detector 26 may be used to measure a rise in conductivity of the liquid and indicate a gas leak with signal S.
  • Gas leak detector 26 may include conductivity sensor Cl for measuring a first conductivity of liquid in liquid inlet flow field Ll upstream of CSA 12, and conductivity sensor C2 for measuring a second conductivity of liquid in liquid outlet flow field L3 downstream of CSA 12.
  • Gas leak detector 26 may then provide an output signal S representative of gas leakage Gl, G2, and/or G3 from a gas flow field such as F2 and/or 02 into moat flow field M2 and/or liquid flow field L2 as a function of the first measured conductivity and the second measured conductivity.
  • gas leak detector 26 may determine if a difference in conductivity measured by conductivity sensor Cl and C2 exists, and indicate a gas leak with signal S as a function of the difference.
  • a rise in conductivity could indicate leakage of gas into the liquid flow field upstream of conductivity sensor C2 and downstream of sensor Cl.
  • gas leak detector 26 may include only one conductivity sensor, for example, C2, for measuring a conductivity of liquid in liquid outlet flow field L3 downstream of CSA 12 to indicate a gas leak with signal S. In such a case, conductivity of liquid in the liquid flow fields could be established for healthy, no-leak operating conditions, with a rise beyond this conductivity level used as an indicator of leakage. As described in more detail with reference to FIG.
  • the difference in measured conductivity between sensors Cl and C2 and/or the measured conductivity at sensor C2 may also be compared to a threshold value, for example, indicating an excessive amount of gas leakage.
  • Conductivity sensors such as Cl and C2 may also be placed internal to CSA 12, for example, at a position in liquid flow field F2, and it may be appreciated that more than two conductivity sensors can be used to increase the sensitivity of conductivity measurements taken at various locations of liquid flow fields Ll, L2, L3.
  • FIG. 2 is a schematic diagram of gas leak detection system 1OA, including a plurality of cell stack assemblies, for example, CSA 12A, 12B, 12C, 12D, 12E, and 12F, having conductivity sensor C3, C4, C5, C6, C7, and C8 on the liquid outlet flow field of each CSA, respectively.
  • Each CSA 12A-F is fed by common liquid source L, and has a liquid flow field and gas flow field configuration as described with reference to FIG. 1 (gas flow fields not shown for sake of clarity).
  • gas leak detector 26 receives a liquid outlet flow field conductivity measurement for each CSA 12A-F, and can identify a CSA among the plurality having a gas leak as a function of measured conductivity at C3-C8, respectively.
  • conductivity of liquid at the liquid outlet flow field of each CSA 12A-12F could be established for healthy, no-leak operating conditions, with a rise in conductivity at any one of the sensors C3-C8 indicating a gas leak for the corresponding CSA 12A-12F.
  • the standard deviation of liquid conductivity at sensors C3- C8 can be calculated under healthy, no-leak operating conditions, and used as a threshold value for identifying a CSA among the plurality having gas leakage causing conductivity for that CSA to exceed the threshold value.
  • Gas leak detector 26 may then indicate the gas leakage with signal S.
  • the following example illustrates the use of standard deviation measure for identifying a CSA with a high or abnormal leakage potential within a plurality of cell stacks:
  • the CSA would be considered an outlier, for example, any one of CSA 12A-12F of FIG. 2.
  • the "3" times standard deviation is used as an example.
  • the expected number may be established as higher or lower depending on what constitutes abnormal conductivity for a particular stack. As one example, abnormal conductivity could correspond to a particular percentage of the %LFL for hydrogen, explained further with reference to FIGS. 3-6.
  • Variations of this approach could also be used in conjunction with this method.
  • other methods like the upper quartile method, or the Q test method (which compares how far out the outlier is to the total range of the data) could also be used to identify a CSA suspected of having leakage.
  • any number of CSAs may be used with the gas leak detection system and method of the present disclosure.
  • FIG. 3 is a flow chart showing a method for indicating a gas leakage with gas leak detector 26 and responding to that leakage with appropriate corrective action, and may be used, for example, with either the gas leak detection system 10 or 1OA described with reference to FIG. 1 or FIG. 2, respectively.
  • Gas leak detector 26 measures a conductivity of liquid in a liquid flow field (step 28) and the measured conductivity is then compared to a first threshold value (step 30).
  • the first threshold value may represent a level of conductivity indicating an excessive but not yet potentially dangerous leakage of gas, for example, a conductivity indicating about 25% of the LFL for hydrogen as explained with reference to FIGS. 4-6. If the measured conductivity does not exceed the first threshold value, measurement of conductivity of the liquid (step 28) resumes.
  • step 32 If the measured conductivity does exceed the first threshold, an alarm is triggered (step 32) so that appropriate corrective action may take place. Such corrective action may include changing the flow rates of gas through gas flow fields in CSA 12, changing relative gas pressures in CSA 12, or derating CSA 12 to minimize the leakage of gas.
  • Measured conductivity is then compared to a second threshold value (step 34). This second threshold value may represent a level of conductivity indicating a potentially more dangerous leakage of gas, for example, a conductivity indicating 50% of the LFL for hydrogen as explained with reference to FIGS. 4-6. If the measured conductivity does not exceed the second threshold value, measurement of conductivity of the liquid (step 28) resumes. If the measured conductivity does exceed the second threshold, shutdown of CSA 12 is initiated (step 36) to prevent dangerous levels of leaked gas, for example hydrogen, from continuing to leak and/or accumulate.
  • a second threshold value may represent a level of conductivity indicating a potentially more dangerous leakage of gas, for example, a conductivity indicating 50%
  • FIG. 4 shows a curve of %LFL in accumulator exhaust flow field E as a function of deionized water conductivity at conductivity sensor C2 due to a gas leak from fuel flow field F2 (shown in FIG. 1) in a CSA 12 having porous flow fields.
  • the LFL for hydrogen gas is 4% hydrogen in air, and thus 100% LFL on the ordinate axis of FIG. 4 equals 4% hydrogen gas in accumulator exhaust flow field E.
  • the curve generated for FIG. 4 assumes a reformate fuel gas composition of 67% hydrogen and 24% carbon dioxide in fuel flow field F2, and a CSA 12 utilizing porous flow fields.
  • This conductivity is primarily set by dissolved carbon dioxide from recycle of water and only a partial removal of carbon dioxide by accumulator 20.
  • Water conductivity increases further from 1.8 ⁇ S at liquid inlet flow field Ll to 2.4 ⁇ S at liquid exit flow field L3 due to marginal carbon dioxide diffusion through the porous gas flow fields of CSA 12 into liquid flow field L2.
  • These sources of carbon dioxide have a predictable rate of transfer and have no appreciable hydrogen gas associated with their transfer mechanisms. Bulk gas cross-over into the liquid flow fields will also occur if there are gas leaks Gl, G3, for example. This bulk gas cross-over transfers both hydrogen gas and carbon dioxide gas.
  • FIG. 4 Based on the specific ratio of hydrogen to carbon dioxide entering gas flow field F2, the ratio of reactant fuel gas flow in flow field F2 to water flow entering CSA 12, and the ratio of water flow to oxidant flow through accumulator oxidant flow field 04 in accumulator 20, the curve shown in FIG. 4 is generated, allowing measured water conductivity to be used to determine what the current LFL is for an operating CSA 12 having porous flow fields. More specifically, FIG. 4 defines an exit water conductivity of 2.4 ⁇ S as having no appreciable hydrogen gas present.
  • the slope illustrates the %LFL for the system given the following three ratios; 2.8 moles-H2/mol-CO2 in fuel gas, 5.8 moles-reactant/1000 moles-water, 113 moles-water/mol-oxidant purge gas in degasifier. 100% LFL is observed for a measured conductivity of 8.8 ⁇ S at conductivity sensor C2. Based on the method described with reference to FIG. 3, an alarm can be triggered at a measured conductivity of 4.8 ⁇ S (about 25% LFL), and the plant will shutdown at a measured conductivity of 6.4 ⁇ S (about 50% LFL), for example.
  • the curve is nonlinear due to the three dissociations constants of carbon dioxide in water.
  • FIG. 5 shows a curve of %LFL in accumulator exhaust flow field E as a function of deionized water conductivity at conductivity sensor C2 due to a gas leak from fuel flow field F2 in CSA 12 (shown in FIG. 1) for a CSA 12 having solid flow fields.
  • the LFL for hydrogen gas is 4% hydrogen in air, and thus 100% LFL on the ordinate axis of FIG. 4 equals 4% hydrogen gas in accumulator exhaust flow field E.
  • the curve generated for FIG. 4 assumes a reformate fuel gas composition of 67% hydrogen and 24% carbon dioxide in fuel flow field F2.
  • FIG. 5 defines an exit water conductivity of 1.8 ⁇ S as having no appreciable hydrogen gas present.
  • the slope illustrates the %LFL for the system given the following three ratios; 2.8 moles-H2/mol-CO2 in fuel gas , 5.8 moles-reactant/1000 moles-water, 113 moles-water/mol-oxidant purge gas in degasifier.
  • FIG. 6 shows a curve of %LFL in accumulator exhaust flow field E as a function of deionized water conductivity at conductivity sensor C2 due to a gas leak from fuel flow field F2 in CSA 12 (shown in FIG. 1) for a CSA 12 having no carbon dioxide impurities transferring to water in liquid flow field L2 (i.e., solid flow fields), and perfect carbon dioxide removal with accumulator 20 such that no carbon dioxide enters CSA 12 in liquid inlet flow field Ll. Water conductivity under healthy CSA 12 operation conditions will remain constant from liquid inlet flow field Ll to liquid outlet flow field L3 at 0.055 ⁇ S.
  • FIG. 6 Based on the specific ratio of hydrogen to carbon dioxide entering gas flow field F2, the ratio of reactant fuel gas flow in flow field F2 to water flow entering CSA 12, and the ratio of water flow to oxidant flow through accumulator oxidant flow field 04 in accumulator 20, the curve shown in FIG. 6 is generated, allowing measured water conductivity to be used to determine what the current LFL is for an operating CSA 12 having no natural carbon dioxide impurity in the water. More specifically, FIG. 6 defines an exit water conductivity of 0.055 ⁇ S as having no appreciable hydrogen gas present.
  • the slope illustrates the %LFL for the system given the following three ratios; 2.8 moles-H2/mol-CO2 in fuel gas, 5.8 moles-reactant/1000 moles-water, 113 moles- water/mol-oxidant purge gas in degasifier. 100% LFL is observed for a measured conductivity of about 8.4 ⁇ S at conductivity sensor C2. Based on the method described with reference to FIG. 3, an alarm can be triggered at a measured conductivity of about 4.2 ⁇ S (about 25% LFL), and the plant will shutdown at a measured conductivity of about 5.9 ⁇ S (about 50% LFL), for example.
  • the curve is nonlinear due to the three dissociations constants of carbon dioxide in water.
  • each of the examples described with reference to FIGS. 4-6 may be used as a nominal curve, allowing a measured conductivity of liquid in a liquid flow field of a CSA 12 to prove as a reliable indicator of gas leakage for any fuel cell system.
  • the conductivity of water entering CSA 12 in liquid inlet flow field Ll may be determined by measuring conductivity with conductivity sensor Cl, for example, to generate plots of water conductivity to %LFL for any fuel cell system.

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Abstract

L'invention concerne un système et un procédé de détection de fuites de gaz (G1, G2, G3) dans un système de piles à combustible empilées (CSA) (12), qui comprennent un détecteur de fuite de gaz (26) destiné à mesurer une conductivité de liquide dans un champ de flux, tel qu'un champ de flux de sortie de liquide (L3), pour indiquer une fuite de gaz à partir du champ de flux de gaz tel que F2 et/ou O2 dans un champ de flux de liquide tel que L2 et/ou M2 en fonction de la conductivité mesurée.
PCT/US2009/040989 2009-04-17 2009-04-17 Détection de fuite de gaz d'un empilement de piles à combustible WO2010120309A1 (fr)

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PCT/US2009/040989 WO2010120309A1 (fr) 2009-04-17 2009-04-17 Détection de fuite de gaz d'un empilement de piles à combustible

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Cited By (1)

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Publication number Priority date Publication date Assignee Title
US11539058B1 (en) 2021-07-12 2022-12-27 Hamilton Sundstrand Corporation Fuel cell hydrogen detection

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KR20060072665A (ko) * 2004-12-23 2006-06-28 현대자동차주식회사 연료 전지 차량의 수소 가스 누출 검지 장치 및 방법
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Publication number Priority date Publication date Assignee Title
JPH08329965A (ja) * 1995-05-29 1996-12-13 Matsushita Electric Ind Co Ltd 燃料電池発電システム
US20040197919A1 (en) * 2003-04-01 2004-10-07 Herman Gregory S. Fuel cell leak detection
KR20060072707A (ko) * 2004-12-23 2006-06-28 현대자동차주식회사 연료전지 차량용 수소누출 감시장치
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* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US11539058B1 (en) 2021-07-12 2022-12-27 Hamilton Sundstrand Corporation Fuel cell hydrogen detection
EP4120405A1 (fr) * 2021-07-12 2023-01-18 Hamilton Sundstrand Corporation Détection d'hydrogène de pile à combustible

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