Classifications

• • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
  • F23—COMBUSTION APPARATUS; COMBUSTION PROCESSES
  • F23C—METHODS OR APPARATUS FOR COMBUSTION USING FLUID FUEL OR SOLID FUEL SUSPENDED IN  A CARRIER GAS OR AIR 
  • F23C9/00—Combustion apparatus characterised by arrangements for returning combustion products or flue gases to the combustion chamber
  • F23C9/006—Combustion apparatus characterised by arrangements for returning combustion products or flue gases to the combustion chamber the recirculation taking place in the combustion chamber
• • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
  • F02—COMBUSTION ENGINES; HOT-GAS OR COMBUSTION-PRODUCT ENGINE PLANTS
  • F02C—GAS-TURBINE PLANTS; AIR INTAKES FOR JET-PROPULSION PLANTS; CONTROLLING FUEL SUPPLY IN AIR-BREATHING JET-PROPULSION PLANTS
  • F02C3/00—Gas-turbine plants characterised by the use of combustion products as the working fluid
  • F02C3/20—Gas-turbine plants characterised by the use of combustion products as the working fluid using a special fuel, oxidant, or dilution fluid to generate the combustion products
  • F02C3/26—Gas-turbine plants characterised by the use of combustion products as the working fluid using a special fuel, oxidant, or dilution fluid to generate the combustion products the fuel or oxidant being solid or pulverulent, e.g. in slurry or suspension
  • F02C3/28—Gas-turbine plants characterised by the use of combustion products as the working fluid using a special fuel, oxidant, or dilution fluid to generate the combustion products the fuel or oxidant being solid or pulverulent, e.g. in slurry or suspension using a separate gas producer for gasifying the fuel before combustion
• • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
  • F23—COMBUSTION APPARATUS; COMBUSTION PROCESSES
  • F23R—GENERATING COMBUSTION PRODUCTS OF HIGH PRESSURE OR HIGH VELOCITY, e.g. GAS-TURBINE COMBUSTION CHAMBERS
  • F23R3/00—Continuous combustion chambers using liquid or gaseous fuel
  • F23R3/02—Continuous combustion chambers using liquid or gaseous fuel characterised by the air-flow or gas-flow configuration
  • F23R3/16—Continuous combustion chambers using liquid or gaseous fuel characterised by the air-flow or gas-flow configuration with devices inside the flame tube or the combustion chamber to influence the air or gas flow
  • F23R3/18—Flame stabilising means, e.g. flame holders for after-burners of jet-propulsion plants
• • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
  • F23—COMBUSTION APPARATUS; COMBUSTION PROCESSES
  • F23R—GENERATING COMBUSTION PRODUCTS OF HIGH PRESSURE OR HIGH VELOCITY, e.g. GAS-TURBINE COMBUSTION CHAMBERS
  • F23R3/00—Continuous combustion chambers using liquid or gaseous fuel
  • F23R3/02—Continuous combustion chambers using liquid or gaseous fuel characterised by the air-flow or gas-flow configuration
  • F23R3/16—Continuous combustion chambers using liquid or gaseous fuel characterised by the air-flow or gas-flow configuration with devices inside the flame tube or the combustion chamber to influence the air or gas flow
  • F23R3/18—Flame stabilising means, e.g. flame holders for after-burners of jet-propulsion plants
  • F23R3/20—Flame stabilising means, e.g. flame holders for after-burners of jet-propulsion plants incorporating fuel injection means
• • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
  • F23—COMBUSTION APPARATUS; COMBUSTION PROCESSES
  • F23R—GENERATING COMBUSTION PRODUCTS OF HIGH PRESSURE OR HIGH VELOCITY, e.g. GAS-TURBINE COMBUSTION CHAMBERS
  • F23R3/00—Continuous combustion chambers using liquid or gaseous fuel
  • F23R3/28—Continuous combustion chambers using liquid or gaseous fuel characterised by the fuel supply
  • F23R3/34—Feeding into different combustion zones
  • F23R3/343—Pilot flames, i.e. fuel nozzles or injectors using only a very small proportion of the total fuel to insure continuous combustion
• • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
  • F23—COMBUSTION APPARATUS; COMBUSTION PROCESSES
  • F23R—GENERATING COMBUSTION PRODUCTS OF HIGH PRESSURE OR HIGH VELOCITY, e.g. GAS-TURBINE COMBUSTION CHAMBERS
  • F23R3/00—Continuous combustion chambers using liquid or gaseous fuel
  • F23R3/42—Continuous combustion chambers using liquid or gaseous fuel characterised by the arrangement or form of the flame tubes or combustion chambers
• • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
  • F05—INDEXING SCHEMES RELATING TO ENGINES OR PUMPS IN VARIOUS SUBCLASSES OF CLASSES F01-F04
  • F05D—INDEXING SCHEME FOR ASPECTS RELATING TO NON-POSITIVE-DISPLACEMENT MACHINES OR ENGINES, GAS-TURBINES OR JET-PROPULSION PLANTS
  • F05D2220/00—Application
  • F05D2220/70—Application in combination with
  • F05D2220/72—Application in combination with a steam turbine
  • F05D2220/722—Application in combination with a steam turbine as part of an integrated gasification combined cycle
• • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
  • F23—COMBUSTION APPARATUS; COMBUSTION PROCESSES
  • F23R—GENERATING COMBUSTION PRODUCTS OF HIGH PRESSURE OR HIGH VELOCITY, e.g. GAS-TURBINE COMBUSTION CHAMBERS
  • F23R2900/00—Special features of, or arrangements for continuous combustion chambers; Combustion processes therefor
  • F23R2900/00002—Gas turbine combustors adapted for fuels having low heating value [LHV]
• • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
  • F23—COMBUSTION APPARATUS; COMBUSTION PROCESSES
  • F23R—GENERATING COMBUSTION PRODUCTS OF HIGH PRESSURE OR HIGH VELOCITY, e.g. GAS-TURBINE COMBUSTION CHAMBERS
  • F23R2900/00—Special features of, or arrangements for continuous combustion chambers; Combustion processes therefor
  • F23R2900/00015—Trapped vortex combustion chambers
• • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
  • F23—COMBUSTION APPARATUS; COMBUSTION PROCESSES
  • F23R—GENERATING COMBUSTION PRODUCTS OF HIGH PRESSURE OR HIGH VELOCITY, e.g. GAS-TURBINE COMBUSTION CHAMBERS
  • F23R2900/00—Special features of, or arrangements for continuous combustion chambers; Combustion processes therefor
  • F23R2900/03282—High speed injection of air and/or fuel inducing internal recirculation
• • 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
  • Y02E20/00—Combustion technologies with mitigation potential
  • Y02E20/16—Combined cycle power plant [CCPP], or combined cycle gas turbine [CCGT]
• • 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
  • Y02E20/00—Combustion technologies with mitigation potential
  • Y02E20/16—Combined cycle power plant [CCPP], or combined cycle gas turbine [CCGT]
  • Y02E20/18—Integrated gasification combined cycle [IGCC], e.g. combined with carbon capture and storage [CCS]

Definitions

• This invention relates to burners and combustors, including high efficiency combustors for gas turbine engines, as well as to process applications for gas turbine engines utilizing such combustors.
• gas turbines While such gas turbines have been adapted to burn certain syngas fuels, and more specifically fuels with low calorific value often in the range of from about 3.726 MJ/m 3 to about 1 1 .178 MJ/m 3 (about 100 to about 300 BTU/scf), gas turbine combustor design features have not generally been optimized for hydrogen content or low grade gaseous fuel applications.
• Conventional gas turbine engines encounter two basic difficulties when transitioning from natural gas to syngas. First, for the same fuel heat input, the mass flow of a syngas fuel is often four to five times greater than that for natural gas, due to the lower heating value of the syngas fuel.
• DLN dry low NOx
• DLN dry low NOx
• Oxygen oxygen
• DLN combustors can achieve less than 10 ppmvd (10 parts per million by volume, dry, at 15% Oxygen) NOx emissions with a natural gas fuel.
• DLN combustors rely on the premix principle, which reduces the combustion flame temperature, and consequently the NOx emissions.
• DLN combustors are able to achieve much lower NOx emissions than diluted non-premixed combustors because of higher premixing time prior to the combustion zone.
• high hydrogen content fuel such as is found in some syngas mixtures
• the flame speeds may be up to as much as six times faster than the flame speed that is typical in combustion of natural gas. Consequently, such high flame speed mixtures, whether from syngas based fuels or from other hydrogen source fuels, makes the use of a DLN combustion system impossible, because in such a system the flame would flash back into the premix zone, and destroy the fuel injection hardware.
• the diluted non-premixed combustors have a chemical kinetic limit when too much diluent is added for reduction of NOx emissions.
• the increase in diluent causes flame instability in the combustion zone, and eventually, combustor flame-out. Consequently, in the best case, a practical NOx reduction limit for prior art syngas combustors is presently between about 10 and about 20 ppmvd NOx.
• advantageous gas turbine system designs may include the use of a lean premix with high hydrogen content fuels in combination with the use of trapped vortex combustors.
• FIG. 1 provides a plan view of a novel trapped vortex combustor, illustrating the pre-mixing of fuel such as a hydrogen rich fuel and oxidant, as well as the use of laterally extending mixing struts that enable combustion gases from the trapped vortex to mix with the incoming fuel-air premix.
• fuel such as a hydrogen rich fuel and oxidant
• FIG. 2 provides an elevation view of an embodiment of a novel trapped vortex combustor configuration, taken along section 2-2 of FIG. 1 , more clearly showing a first bluff body and a second or aft bluff body, which enables the setup of a stable vortex between the first and second bluff bodies for the combustion of a lean premixed fuel and oxidant mixture, as well as the use of laterally extending struts to promote mixing of the entering premix with hot gases that are escaping from a stable vortex between the first bluff body and a second bluff body.
• FIG. 3 provides a perspective view of an embodiment of a novel trapped vortex combustor, showing a circulating main vortex similar to that first illustrated in FIG. 1 , now showing the use of multiple laterally extending mixing devices, here depicted in the form of partially airfoil shaped outwardly or laterally extending mixing devices extending into the bulk lean premixed fuel and oxidant flow adjacent the dump plane of the combustor.
• FIG. 4 provides a process flow diagram for a prior art Integrated Gasification Combined Cycle (“IGCC”) process, showing the use of a diffusion combustor in a gas turbine, and the feed of compressed air from both the gas turbine compressor and from the motor driven compressor to an air separation unit for the production of oxygen and nitrogen, as well as the use of a selective catalytic reduction hot gas emissions cleanup process subsequent to the gas turbine.
• IGCC Integrated Gasification Combined Cycle
• FIG. 5 provides a process flow diagram for an Integrated Gasification Combined Cycle (“IGCC") process similar to that first described in FIG. 4 above, but compared to the process shown in FIG. 4, now eliminates the use of diluent gas feed to the combustor, and the use of SCR emissions cleanup technology, both of which process steps may be eliminated from an IGCC plant via use of the novel trapped vortex combustor described and taught herein.
• IGCC Integrated Gasification Combined Cycle
• FIG. 6 provides a process flow diagram for a novel Integrated Gasification Combined Cycle ("IGCC") plant, showing the use of a novel trapped vortex combustor in a gas turbine, and also showing the elimination of use of selective catalytic reduction or similar process after the combustion of syngas in the gas turbine for NOx reduction, as well as the elimination of the use of nitrogen diluent to control NOx emissions from the gas turbine engine.
• IGCC Integrated Gasification Combined Cycle
• novel trapped vortex combustor and methods for employing the same in the combustion of high flame speed fuels such as hydrogen rich syngas, may be utilized in order to provide a versatile gas turbine engine with novel trapped vortex combustor for combustion of a fuel-air premix while minimizing emissions of carbon monoxide and oxides of nitrogen.
• a novel trapped vortex combustor 10 design has been developed for operation in a low NOx, lean premixed mode on hydrogen- rich fuels, yet accommodates the high flame speed that is a characteristic of such fuels.
• a combustor 10 can achieve extremely low NOx emissions without the added capital and operating expense of post- combustion treatment of the exhaust gas.
• such a combustor 10 can eliminate the costly requirement for high pressure diluent gas (nitrogen, steam or carbon dioxide) for NOx emissions control. As easily seen in FIG.
• At least one cavity 12 is provided, having a selected size and shape to stabilize the combustion flame for a selected fuel composition. Flame stabilization is accomplished by locating a fore body, hereinafter identified as first bluff body 14, upstream of a second, usually smaller bluff body - commonly referred to as an aft body 16.
• Fuel F such as a hydrogen rich syngas, is provided by fuel outlets 18, and the fuel F is mixed with incoming compressed oxidant containing stream A, which oxidant containing stream A may be a compressed air stream containing both oxygen and nitrogen (or in other embodiments, another inert working fluid, such as steam or carbon dioxide).
• the re-circulation of hot products of combustion into the incoming, lean premixed fuel and oxidant mixture stream 22 may be accomplished by incorporating various features.
• a stable recirculation zone may be generated in on or more vortices, such as vortices 24 and 26, located adjacent to the main fuel-air flow
• the flow of the swirling combustion gases comprise one or more vortices that are stable, at least with respect to the one or more primary trapped vortices, and vortex shedding is substantially avoided
• Each of the one or more stable primary vortices are thus used as a source of heat, or more precisely, a source of hot products of combustion
• heat from the vortex or cavity 12 region must be transported into the main entering lean premix fuel and oxidant mixture stream, and mixed into the main flow As shown in FIG 1 , in one embodiment, this may be done in part by escape of a portion of
• the very stable yet highly energetic primary/core flame zone is very resistant to external flow field perturbations, and therefore yields extended lean and rich blowout limits relative to a dump combustor having a simple bluff body component.
• the unique characteristic of the presently described novel trapped vortex combustor technology provides a fluid dynamic mechanism that can overcome the high flame speed of a hydrogen-rich gas, and thus has the capability to allow combustors to operate with a hydrogen rich gaseous feed stream with a lean fuel-air premix composition.
• the novel trapped vortex combustor design configuration described herein also has a large flame holding surface area, and hence can facilitate the use of a compact primary/core flame zone, which is essential to promoting high combustion efficiency and reduced CO emissions.
• the trapped vortex combustor 10 includes a base 40.
• the first bluff body 14 extends outward from the base 40 for a height or distance of Y-i
• the second bluff body 16 extends outward from the base for a height or distance of Y 2 .
• Yi is equal to Y 2
• the combustor 10 also includes a ceiling 42, so that during operation, a stabilized vortex of mixing and burning gas 12 is trapped between the rear wall 44 of the first bluff body 16 and the front wall 46 of the second bluff body 16, and between base 40 and ceiling 42.
• At least a portion of the gas from each stabilized vortex 24 and 26 of mixing and burning gas moves in the bulk fluid flow direction, i.e., the same direction as the premixed fuel and oxidant mixture stream flow 22 shown in FIG. 1. Also, in one embodiment, as noted in FIG. 3, as noted in FIG. 3, at least a portion of the gas from each stabilized vortex 24 and 26 of mixing and burning gas moves in the bulk fluid flow direction, i.e., the same direction as the premixed fuel and oxidant mixture stream flow 22 shown in FIG. 1. Also, in one embodiment, as noted in FIG.
• each stabilized vortex of mixing and burning gas 24 and 26 moves in a direction opposite the bulk fluid flow direction, i.e., opposite the direction as the premixed fuel and oxidant mixture inflow 22 shown in FIG. 1.
• the novel trapped vortex combustor 10 further comprises one or more outwardly extending structures such as struts 30.
• struts 30 may include a planar rear portion 31.
• the rear planar portion 31 may be substantially co-planar with the rear wall 44 of the first bluff body 14.
• one or more struts 30 may be provided.
• multiple struts 30 may be provided in a configuration where they extend outwardly from adjacent the rear wall 44 of the first bluff body 14.
• the struts 30 may extend transversely with respect to longitudinal axis 50, or may include at least some transverse component, so that circulation of a portion of escaping heat and burning gases flow adjacent struts 30 and are thus mixed with an incoming lean premixed fuel and oxidant mixture. As generally shown in FIGS. 1 through 3, and specifically referenced in
• a novel trapped vortex combustor 10 can be provided wherein the combustor 10 has a central longitudinal axis 50 see FIG. 1 ) defining an axial direction.
• a combustor may include, extending along the longitudinal axis 50, a distance outward toward the ceiling 42 along an outward direction 52, or alternately in an inward, base direction 54 both oriented orthogonal to the axial direction.
• a trapped vortex combustor 10 may include, space extending in a transverse direction 56 or 58, oriented laterally to the axial direction 50.
• a pressurizable plenum 60 is provided having a base 40, an outer wall or ceiling 42, and in some embodiments, combustor first and second sidewalls 64 and 66, respectively.
• the first bluff body 14 includes a nose 70 and opposing first 74 and second 76 bluff body sidewalls, as well as rear 44 noted above.
• the second bluff body 16 is located downstream from the first bluff body 16.
• the second bluff body has an upstream side having a front wall 46, a downstream side having a back wall 78, and first 80 and second 82 opposing sidewalls.
• a mixing zone 84 is provided downstream of the gaseous fuel inlets 18.
• the mixing zone 84 is upstream of the rear wall 44 of the first bluff body 14.
• the mixing zone 84 has a length LM Z along the axial direction 50 sufficient to allow mixing of fuel and oxidant, and particularly gaseous fuel and gaseous oxidant, to form a lean premixed fuel and oxidant stream 22 having an excess of oxidant.
• the pressurizable plenum 60, first bluff body 14, and second bluff body 16 are size and shaped to receive the lean premixed fuel and oxidant mixture stream 22 at a velocity greater than the combustion flame speed in the lean premixed fuel and oxidant mixture 22 composition.
• a primary combustion zone of length LP Z is provided, wherein one or more stabilized vortices 26 and 26 are provided to enhance combustion of the entering fuel.
• combustion burnout zone of length LBz is provided, of sufficient length so that final hot combustion exhaust gases, described below, meet the desired composition, especially with respect to minimizing the presence of carbon monoxide.
• the second bluff body 16 is further configured to provide one or more vortex stabilization jets 90.
• Each of the one or more vortex stabilization jets 90 provides an upstream jet of gas in a direction tending to stabilize vortex 22 and vortex 24 in the cavity 12 between the first bluff body 14 and the second bluff body 16.
• the second bluff body 16 is coupled to a source of fuel, and in such a case, at least one of the vortex stabilization jets provides an injection stream containing a fuel.
• the second bluff body 16 may be coupled to a source of syngas, and in such a case, the fuel comprises a syngas.
• the second bluff body 16 is coupled to a source of oxidant, and in such cases, one or more of the at least one vortex stabilization jets 90 has an injection jet stream containing an oxidant.
• the vortex stabilization jets may include a first jet 90 containing a fuel, and a second jet 92 containing an oxidant.
• the vortex stabilization jets may be used in a process where the second bluff body 16 is coupled to a source of lean premixed fuel and oxidant, and wherein a stream comprising lean premixed fuel and oxidant is injected through at least one of the one or more vortex stabilization jets 90.
• the novel trapped vortex combustor 10 includes first 14 and second 16 bluff bodies that are spaced apart in a manner that when the trapped vortex combustor 10 is in operation, the heat and combustion products produced during combustion of the lean premix are continuously recirculated in a recirculation zone in the cavity 12 between the first 14 and second 16 bluff bodies, and wherein heat and combustion products exit longitudinally (reference direction 50) and laterally (which may include transversely such as in reference directions 56 and 58) from the cavity 12 and are employed to continuously ignite a lean premixed fuel and oxidant mixture entering the tapped vortex combustor
• the lean premixed fuel an oxidant mixture enters adjacent cavity 12, from flow along side of walls 74 and 76 of first bluff body 14.
• High hydrogen content fuels present a particular problem in that the flame speed during the combustion of a premixed stream of pure hydrogen gas and air is approximately six times (6x) that of the flame speed of a premixed stream of natural gas and air.
• the thru-flow velocity needs to be greater, and in some embodiments (depending upon the hydrogen content in the fuel mixture) significantly greater than the flame speed.
• Such problems are compounded in lean pre-mix combustor designs since flashback of the flame into the fuel injector may cause severe damage to the hardware, and has the clear potential, for example, to lead to gas turbine failure. As a result of such factors, in so far as we are aware, presently there are no lean pre-mix gas turbines in operation in industry on high hydrogen content fuels.
• the bulk fluid velocity 20 entering the combustion zone adjacent trapped vortex 12 exceeds the flame speed of combustion occurring in the lean premix composition.
• the bulk fluid velocity entering the novel trapped vortex combustor 10 exceeds the flame speed of combustion occurring in the lean premix by a factor of from about 3 to about 6 or thereabouts.
• fuels containing significant amounts of hydrogen will have turbulent flame speeds from about thirty five (35) meters per second to about fifty (50) meters per second (about 114.83 ft/sec to about 164.04 ft/sec).
• the bulk velocity 20 of lean premix may be provided at about one hundred five (105) meters per second (344.48 ft/sec), and up to as much as about one hundred fifty (150) meters per second (492.12 ft/sec), or more.
• Such bulk pre-mixed fuel velocities allow protection against flash back even when operating on high hydrogen content fuels, and thus are a significant improvement when applied as combustors in gas turbines.
• the novel trapped vortex combustor 10 described and claimed herein can provide a significant benefit in gas turbine designs for high hydrogen content fuels.
• fuels may be found in the syngas from coal gasification technology applications, such as Integrated Gasification Clean Coal ("IGCC") plants, or in Combined Cycle Gasification Technology (“CCGT”) plants.
• IGCC Integrated Gasification Clean Coal
• CCGT Combined Cycle Gasification Technology
• the novel trapped vortex combustor 10 described and claimed herein may provide a significant benefit in the design and operation of equipment for the combustion of hydrogen rich streams in other systems.
• oxygen- blown coal gasifiers 120 are utilized to generate a synthesis gas 122 that is rich in hydrogen and in carbon monoxide.
• Such synthesis gas 122 is typically cleaned in a gas cleanup unit 124, and the clean synthesis gas 126 is used as a fuel in a gas turbine 128.
• the synthesis gas 126 is typically burned in a diffusion combustor 130.
• the production of raw synthesis gas 122 thus requires an oxygen source, which is typically provided by way of a cryogenic air separation unit (“ASU") 131.
• the oxygen source may be a high temperature ion transport membrane (not shown). As is illustrated in FIG.
• a portion 132 of the air 134 for the ASU 131 is provided by the compressor 133 of the gas turbine 128, and a portion 136 of the air 134 for the ASU 131 is provided by a separate motor 140 driven feed air compressor 142.
• the respective contribution of the gas turbine compressor 133 and the supplemental feed air compressor 142 is commonly referred to as the "degree of integration".
• the "degree of integration” varies with the specific plant designs, but the norm is approximately fifty percent (50%) integration, where half of the ASU 131 feed air 134 comes from the gas turbine compressor 133, and half of the ASU 131 feed air 134 comes from separate motor 140 drive (typically electric drive) feed air compressor(s) 142.
• the heating value of typical cleaned synthesis gas (“syngas”) 126 from an IGCC plant is normally below 9.315 MJ/m 3 (250 British Thermal Units per standard cubic foot) which is approximately one-fourth ( 1 A) of the heating value of a typical natural gas supply.
• syngas cleaned synthesis gas
• four (4) times the gaseous volume of clean syngas 126 fuel is required to be fed to a gas turbine 128 in order to generate the same power output that would be generated if the gas turbine 128 were, instead, fueled utilizing a typical natural gas supply.
• diluent gases such as CO 2 (carbon dioxide) and H 2 O (steam) can also used for NOx control, but with the same adverse, efficiency decreasing results.
• nitrogen 144 diluent comes from the ASU 131 as a by-product of the air separation process, there may need to be, at extra capital cost and at extra operating expense, an additional diluent gas compressor (not shown).
• a selective catalytic reduction (“SCR") system 150 may be used to reach a 3 ppm NOx emission value requirement, as is often established by regulation of applicable governmental authorities.
• optimum reaction temperature for the SCR process may be provided by linking the SCR system 150 with the heat recovery steam generator ("HRSG") 152.
• the HRSG 152 may be utilized for recovery of heat and generation of steam 154 for use in a steam turbine 156 for shaft power, such as via shaft 156s to an electric generator 157 (similar to configuration illustrated in FIG. 6) or for process use (not shown).
• condensed steam is collected at a condenser 158 and returned as condensate to the HRSG 152.
• electrical power is generated via shaft 128 S power from gas turbine 128 that is used to turn generator 159. Where utilized, the above mentioned electrical generator 157 is driven by steam turbine 156.
• the total combined gaseous products of combustion flow stream 160 from the added syngas fuel flow volume (up to four times or more by volume, compared to natural gas), and from the added nitrogen 144 diluent flow volume, creates a mass flow mismatch (and thus load mismatch) between the compressor section 133 and the turbine section 162 of a gas turbine 128 designed for use on a typical natural gas fuel.
• a higher mass flow rate through the turbine section 162 may increase the pressure at the compressor section 133 outlet too much, so that the compressor approaches, or if left unaddressed would encroach, a compressor surge region, where such total mass flow would no longer be sustainable.
• such a mismatch is "managed" by adjusting the degree of integration, which usually means removal of at least a portion of the compressed air mass flow 132 to the ASU 131 from the gas turbine compressor 133.
• a gas turbine manufacturer could add a compressor stage to allow higher overall pressure ratio in the compression cycle.
• the high mass flow of syngas as compared to natural gas might approach the mechanical limits of a gas turbine rotor to handle turbine power output.
• uncoupling of the gas turbine 128' compressor 133' with requirement for supply of the ASU 131 also offers the potential for savings in some fuel synthesis plants, by freeing up the compressor 133' so that the parasitic air compression load is reduced.
• Many of the gas turbine compressors currently available operate most efficiently at a pressure ratio of about twenty (20), which means that when compressing atmospheric air, there is about a 2068.43 KPa (three hundred (300) pounds per square inch) absolute discharge pressure.
• KPa three hundred (300) pounds per square inch
• excess compression work may sometimes take place in preparation of compressed air feed 134 for the ASU 131.
• valve 172 is closed and all of the feed air 134 to the ASU 131 is provided using a 4-stage intercooled motor 140' driven compressor 142' operating at 1945.70 KPa (282.2 psia) discharge pressure, the total air compression costs would be less than the costs associated with the case shown in FIG. 4 where valve 172 is open and 50% of supply for the air separation unit 131 is provided via the gas turbine compressor 133 bleed air supply.
• the gas turbine compressor 133' could in such a case be designed to solely handle the oxidant supply requirements to combustor 10 (or to handle compression of an oxidant and an inert working gas such as carbon dioxide or steam where such fluids are used to increase work output from turbine 162' of the gas turbine engine 128'), without regard to any integration requirements with the ASU air supply.
• a novel trapped vortex combustor 10 can be adapted for use in, or in combination with, various types of gas turbines for the combustion of high hydrogen content fuels, especially such fuels from various types of fuel synthesis plants, such as carbonaceous matter gasification plants, including coal or coke gasification plants. In one embodiment, this may be made possible by decreasing the mass flow through the turbine section. Also, in one embodiment, a novel trapped vortex combustor 10 design can improve the overall cycle efficiency of a gas turbine, by decreasing the pressure drop through the trapped vortex combustor 10, as compared with a prior art diffusion combustor 30. And, such a novel trapped vortex combustor 10 design can extend the lean blowout limit while offering greater turndown, (i.e.
• novel trapped vortex combustor 10 design holds tremendous promise for combustion of hydrogen rich fuels in various gas turbine 128' applications. Such a design offers improved efficiency, lower emissions levels, greater flame stability, increased durability, added fuel flexibility, and reduced capital costs, compared to prior art designs.
• the novel trapped vortex combustor 10 described and claimed herein may be utilized in a variety of gaseous fuel synthesis plants that make hydrogen rich fuels. One such plant is an integrated gasification process, as conceptually depicted in FIGS. 5 and 6.
• the gasification unit shown as gasifier 120, produces a raw synthesis gas 122 from a carbonaceous feed 1 19, such as coke or coal, to produce a synthesis gas comprising CO and H 2 , as well as other contaminants that vary according to the feed stock.
• the synthesis gas (“syngas”) provided by the process may have at least fifteen (15) mole percent hydrogen gas.
• the syngas provided by the process may have at least twenty five (25) mole percent hydrogen gas therein.
• a synthesis gas provided by the process may have at least thirty (30) mole percent hydrogen gas.
• the synthesis gas may have at least fifty (50) mole percent hydrogen gas. In still other embodiments, the synthesis gas may have at least sixty five (65) mole percent hydrogen gas. In yet other embodiments, the synthesis gas may have at least seventy five (75) mole percent hydrogen gas, or more than seventy five (75) mole percent hydrogen. In some gaseous fuel synthesis plants, the synthesis gas may be provided at about one hundred (100) mole percent hydrogen.
• a raw synthesis gas may be cleaned at gas cleanup unit 124 to produce a clean synthesis gas 126.
• a gas turbine 128' is provided coupled to an electrical generator 159, for generating electrical power.
• the gas turbine engine 128' includes a compressor section 133', a turbine 162', and a novel trapped vortex combustor 10.
• the novel trapped vortex combustor 10 is sized and shaped for receiving a gaseous fuel F including gas resulting from the cleanup of the raw synthesis gas, via a fuel outlet 18 and a compressed oxidant containing stream A (see FIG.
• the lean premixed fuel and oxidant stream 22 is fed to the novel trapped vortex combustor 10 at a bulk fluid velocity 20 in excess of the speed of a flame front in a premixed fuel and oxidant mixture stream of preselected composition.
• the novel trapped vortex combustor 10 includes a first bluff body 14 and a second bluff body 16.
• the combustion of the synthesis gas occurs at least in part in cavity 12 to produce a stabilized vortex 24 and 26 of mixed oxidant and burning synthesis gas between the first bluff body 14 and the second bluff body 16.
• the bulk premixed velocity 20 may be in the range of from about one hundred five (105) meters per second to about one hundred fifty (150) meters per second (about 344.48 ft/sec to about 492.12 ft/sec).
• the fuel F in the lean premixed stream 22 is combusted in the novel trapped vortex combustor 10, primarily at main vortex 12, to create a hot combustion exhaust gas stream 164.
• the turbine 162' is turned by expansion of the hot combustion exhaust gas stream 164, to produce shaft power, and the shaft 128's turns the electrical generator 159 to produce electrical power.
• an air separation unit 131 is normally provided to separate air into a nitrogen rich stream and an oxygen rich stream.
• the oxygen rich stream is provided as a feed stream to the gasification unit 120.
• a motor 140 driven air compressor 142 may be provided to produce compressed air 134 for feed to the air separation plant 131.
• a compressor 142" having multiple compression stages and an intercooler 176 can be provided, and in such case, the process can be operated to recover the heat of compression from air compressed in the motor driven air compression plant 142".
• nitrogen can be collected from the nitrogen rich stream exiting the air separation plant 131.
• the nitrogen can be stored as compressed gas, or liquefied, and in any event, collected and either used elsewhere on site or sent off-site for sale.
• NOx is expected to be controlled to about 15 ppmvd or lower. In another embodiment, NOx is expected to be controlled to 9 ppmvd or lower. In yet another embodiment, NOx is expected to be controlled to 3 ppmvd or lower. These emissions are stated in parts per million by volume, dry, at fifteen percent (15%) oxygen (“ppmvd").
• the novel trapped vortex combustor 10 described herein is easily adaptable to use in a power generation system.
• the fuel composition may vary widely, depending upon the gasification process selected for use, but broadly, gaseous fuels may have a hydrogen to carbon monoxide mole percent ratio of from about 1/2 to about 1/1.
• the novel trapped vortex combustor 10 described herein may be sized and shaped for operation with a gaseous syngas fuel in a wide range of fuel compositions, and in various embodiments, may be utilized on syngas containing hydrogen, or more broadly, with fuels containing hydrogen in the range of from about fifteen (15) mole percent to about one hundred (100) mole percent.
• the novel trapped vortex combustor 10 design described herein is a unique design which allows use of a gaseous fuel lean pre-mix, and is capable of handling the high velocity through flow necessary with hydrogen-rich fuels.
• the technology has experimentally proven to be very stable and exhibits both low pressure drop and low acoustic coupling throughout its operating range. It is believed that these capabilities can potentially allow a gas turbine combustor to burn hydrogen-rich syngas type fuels in a lean pre-mix mode without flashback. Further such an approach will enable the gas turbine combustor to meet the stringent emissions requirements without after-treatment, and without diluent gas.
• Such a configuration may also allow the retrofit of certain existing natural gas fired power plants to clean coal gasification operations, allowing for productive use of the assets currently considered "stranded" by the high cost of natural gas.

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• 2009
  • 2009-05-06 AU AU2009345819A patent/AU2009345819A1/en not_active Abandoned
  • 2009-05-06 BR BRPI0925016A patent/BRPI0925016A8/pt not_active Application Discontinuation
  • 2009-05-06 WO PCT/US2009/042997 patent/WO2010128964A1/en active Application Filing
  • 2009-05-06 EP EP09789645A patent/EP2427694A1/en not_active Withdrawn
  • 2009-05-06 CA CA2760853A patent/CA2760853A1/en not_active Abandoned
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  • 2009-05-06 CN CN200980160289.0A patent/CN102460015B/zh not_active Expired - Fee Related

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