Classifications

• • C—CHEMISTRY; METALLURGY
  • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
  • C10J—PRODUCTION OF PRODUCER GAS, WATER-GAS, SYNTHESIS GAS FROM SOLID CARBONACEOUS MATERIAL, OR MIXTURES CONTAINING THESE GASES; CARBURETTING AIR OR OTHER GASES
  • C10J3/00—Production of combustible gases containing carbon monoxide from solid carbonaceous fuels
• • C—CHEMISTRY; METALLURGY
  • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
  • C10J—PRODUCTION OF PRODUCER GAS, WATER-GAS, SYNTHESIS GAS FROM SOLID CARBONACEOUS MATERIAL, OR MIXTURES CONTAINING THESE GASES; CARBURETTING AIR OR OTHER GASES
  • C10J3/00—Production of combustible gases containing carbon monoxide from solid carbonaceous fuels
  • C10J3/72—Other features
  • C10J3/726—Start-up
• • C—CHEMISTRY; METALLURGY
  • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
  • C10J—PRODUCTION OF PRODUCER GAS, WATER-GAS, SYNTHESIS GAS FROM SOLID CARBONACEOUS MATERIAL, OR MIXTURES CONTAINING THESE GASES; CARBURETTING AIR OR OTHER GASES
  • C10J3/00—Production of combustible gases containing carbon monoxide from solid carbonaceous fuels
  • C10J3/72—Other features
  • C10J3/728—Shut down
• • C—CHEMISTRY; METALLURGY
  • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
  • C10K—PURIFYING OR MODIFYING THE CHEMICAL COMPOSITION OF COMBUSTIBLE GASES CONTAINING CARBON MONOXIDE
  • C10K1/00—Purifying combustible gases containing carbon monoxide
  • C10K1/002—Removal of contaminants
  • C10K1/003—Removal of contaminants of acid contaminants, e.g. acid gas removal
• • C—CHEMISTRY; METALLURGY
  • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
  • C10K—PURIFYING OR MODIFYING THE CHEMICAL COMPOSITION OF COMBUSTIBLE GASES CONTAINING CARBON MONOXIDE
  • C10K1/00—Purifying combustible gases containing carbon monoxide
  • C10K1/002—Removal of contaminants
  • C10K1/003—Removal of contaminants of acid contaminants, e.g. acid gas removal
  • C10K1/004—Sulfur containing contaminants, e.g. hydrogen sulfide
• • C—CHEMISTRY; METALLURGY
  • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
  • C10K—PURIFYING OR MODIFYING THE CHEMICAL COMPOSITION OF COMBUSTIBLE GASES CONTAINING CARBON MONOXIDE
  • C10K1/00—Purifying combustible gases containing carbon monoxide
  • C10K1/08—Purifying combustible gases containing carbon monoxide by washing with liquids; Reviving the used wash liquors
  • C10K1/10—Purifying combustible gases containing carbon monoxide by washing with liquids; Reviving the used wash liquors with aqueous liquids
  • C10K1/101—Purifying combustible gases containing carbon monoxide by washing with liquids; Reviving the used wash liquors with aqueous liquids with water only
• • C—CHEMISTRY; METALLURGY
  • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
  • C10K—PURIFYING OR MODIFYING THE CHEMICAL COMPOSITION OF COMBUSTIBLE GASES CONTAINING CARBON MONOXIDE
  • C10K1/00—Purifying combustible gases containing carbon monoxide
  • C10K1/08—Purifying combustible gases containing carbon monoxide by washing with liquids; Reviving the used wash liquors
  • C10K1/10—Purifying combustible gases containing carbon monoxide by washing with liquids; Reviving the used wash liquors with aqueous liquids
  • C10K1/12—Purifying combustible gases containing carbon monoxide by washing with liquids; Reviving the used wash liquors with aqueous liquids alkaline-reacting including the revival of the used wash liquors
  • C10K1/14—Purifying combustible gases containing carbon monoxide by washing with liquids; Reviving the used wash liquors with aqueous liquids alkaline-reacting including the revival of the used wash liquors organic
  • C10K1/143—Purifying combustible gases containing carbon monoxide by washing with liquids; Reviving the used wash liquors with aqueous liquids alkaline-reacting including the revival of the used wash liquors organic containing amino groups
• • C—CHEMISTRY; METALLURGY
  • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
  • C10J—PRODUCTION OF PRODUCER GAS, WATER-GAS, SYNTHESIS GAS FROM SOLID CARBONACEOUS MATERIAL, OR MIXTURES CONTAINING THESE GASES; CARBURETTING AIR OR OTHER GASES
  • C10J2300/00—Details of gasification processes
  • C10J2300/09—Details of the feed, e.g. feeding of spent catalyst, inert gas or halogens
  • C10J2300/0983—Additives
  • C10J2300/0989—Hydrocarbons as additives to gasifying agents to improve caloric properties
• • C—CHEMISTRY; METALLURGY
  • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
  • C10J—PRODUCTION OF PRODUCER GAS, WATER-GAS, SYNTHESIS GAS FROM SOLID CARBONACEOUS MATERIAL, OR MIXTURES CONTAINING THESE GASES; CARBURETTING AIR OR OTHER GASES
  • C10J2300/00—Details of gasification processes
  • C10J2300/16—Integration of gasification processes with another plant or parts within the plant
  • C10J2300/164—Integration of gasification processes with another plant or parts within the plant with conversion of synthesis gas
  • C10J2300/1643—Conversion of synthesis gas to energy
  • C10J2300/1653—Conversion of synthesis gas to energy integrated in a gasification combined cycle [IGCC]
• • 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
• • 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

• the present invention relates to systems and methods of starting up, operating and shutting down a gasification reactor and an integrated gasification combined cycle (“IGCC") complex.
• IGCC integrated gasification combined cycle
• any hydrocarbon can be gasified, i.e. partially combusted, in contradistinction to combustion, by using less than the stoichiometric amount of oxygen required to combust the solid.
• oxygen supply is limited to about 20 to 70 percent of the oxygen required for complete combustion.
• the reaction of the hydrocarbon-containing feedstock with limited amounts of oxygen results in the formation of hydrogen, carbon monoxide and some water and carbon dioxide.
• Solids such as coal, biomass, oil refinery bottoms, digester sludge and other carbon-containing materials can be used as feedstocks to gasifiers. Recently petroleum coke has been used as the solid hydrocarbon feed stock for IGCC.
• a typical gasifier operates at very high temperatures such as temperatures ranging from about 1000 0 C to about 14OfJ 0 C and in excess of 1 ,600 0 C. At such high temperatures any inert material in the feedstock is melted and flows to the bottom of the gasification vessel where it forms an inert slag.
• gasifiers can be characterized as a moving bed, an entrained flow, or a fluidized bed. Moving bed gasifiers generally contact the fuel in countercurrent fashion.
• the carbon-containing fuel is fed into the top of a reactor where it contacts oxygen, steam and/or air in counter-current fashion until it has reacted to form syngas
• the fuel or hydrocarbon-containing feedstock contacts the oxidizing gas in co- current fashion until syngas is produced which exists the top of the reactor while slag flows to the bottom of the reactor.
• the hydrocarbon-containing fuel or feedstock is passed upwards with a steam/oxygen gas where it is suspended until the gasification reaction takes place.
• the gasifier in an IGCC complex is integrated with an air separation unit ("ASU"), a gas purification or clean up system such as an acid gas removal (“AGR”) process, and a combined cycle power plant or "power block” which is the gas turbine unit.
• ASU air separation unit
• AGR acid gas removal
• power block combined cycle power plant or "power block” which is the gas turbine unit.
• the ASU is used to separate air such that a pure oxygen stream can be sent to the gasifier.
• CO shift technology is commonly used in conventional hydrogen and ammonia plants. Where the syngas is derived from gasification, the CO shift unit is typically located upstream of a sulfur removal unit and therefore uses "sour" shift catalysts. Shift catalysts can be cobalt-molybdenum-based catalysts which are readily commercially available from a number of suppliers. The catalyst life is typically three years. For a high degree of CO2 capture additional stages of shift may be required. The heat from the highly exothermic shift reaction can be effectively utilized by generating steam for internal plant consumption.
• an IGCC complex is used to capture CO 2
• the CO 2 captured must meet purity standards for compression and injection if the CO 2 is to be injected into oil fields for enhanced oil recovery.
• An extremely high degree of carbon capture can be achieved by shifting almost all the CO in the raw sour synthesis gas to carbon dioxide and hydrogen, and then recovering nearly all of the CO 2 in the resultant syngas within a downstream AGR unit.
• shifted syngas effluent from the shift reactor is passed to an acid gas removal unit.
• a suitable acid gas removal unit could be the Rectisol process licensed by Lurgi AG or Linde AG.
• the Rectisoi Process uses a physical solvent, unlike amine based acid removal solvents that rely on a chemical reaction with the acid gases. While any acid gas removal process can be utilized the Rectisol Process is preferably utilized due to (1) the high syngas pressure and (2) the proven ability of the process to (i) achieve very low ( ⁇ 2 ppmv) sulfur levels in treated fuel gas effluents, ⁇ ii) simultaneously produce an acid gas that is suitable for a Claus sulfur recovery unit (“SRU”) and (iii) a CO 2 stream that is suitable for enhanced oil recovery (“EOR”) applications.
• SRU Claus sulfur recovery unit
• EOR enhanced oil recovery
• Ultra-low sulfur content in gas turbine (“GT”) fuel is necessary to allow use of catalysts for CO and NO x reduction in the GT exhaust because sulfur compounds react with ammonia used in the selective catalytic reduction (SCR) process to form sticky particulates that adhere to catalyst and heat recovery steam generator (“HRSG”) tube surfaces. Rectisol can also remove nearly all COS from the syngas, thus eliminating the need for an upstream hydrolysis reactor that would otherwise be needed to convert COS in the syngas to H 2 S.
• SCR selective catalytic reduction
• the deep sulfur removal achieved by the Rectisol unit for H 2 -rich syngas coupled with the use of CO oxidation catalysts and SCR allow the power block to achieve NO x , CO and SO 2 emission levels that are comparable to those for a natural gas-fired combined cycle power plants, but with much lower CO 2 emissions.
• the absorption medium is methanol. Mass transfer from the gas into the methanol solvent is driven by the concentration gradient of the respective component between the gas and the surface of the solvent, the latter being dictated by the absorption equilibrium of the solvent with regard to this component.
• the product is essential for the product to be very low in water content to minimize or alleviate the formation of carbonic acid (water + CO 2 - carbonic acid) which is very corrosive to the steel used in the compression equipment, pipeline, injection/re-injection equipment and the actual wells themselves.
• the total sulfur content is limited to 30 ppmv or less to further minimize corrosion issues and to mitigate any health concerns to workers or the public in the event of a mechanical failure or release.
• nitrogen in the product is limited to less than about 2 vol % since excessive amounts of nitrogen may significantly inhibit EOR and permanent sequestration of CO 2 .
• the Rectisol unit can be used to produce high purity CO 2 at two pressure levels, atmospheric pressure and about three atmospheres.
• the sulfur recovery unit (“SRU") used in the IGCC complex contemplated herein can be a conventional oxygen-blown Claus technology to convert the H 2 S to liquid elemental sulfur.
• the tail gas from the Claus unit can be recycled to the AGR unit to avoid any venting of sulfurous compounds to the atmosphere or routed to a conventional Tail Gas Treating Unit (TGTU).
• TGTU Tail Gas Treating Unit
• the hydrogen produced in the present IGCC complex is generally used for power production, during off peak demand a portion of such hydrogen can be directed to petroleum refineries after suitable purification using, for instance, conventionally available pressure swing adsorption technology.
• the combustion of the hydrogen fuel to produce power can be carried out by any conventional gas turbines. These turbines can each exhaust into a heat recovery and steam generator ("HRSG"). Steam can be generated at three pressure levels and is used to generate additional electrical energy in a steam turbine.
• HRSG heat recovery and steam generator
• a conventional selective catalytic reduction process can be used for post-combustion treatment of effluent gases to reduce NO x content down to acceptable levels.
• SCR selective catalytic reduction process
• the gas generator is started at atmospheric pressure after preheating to at least 950 0 C.
• the gasifier is pressurized and downstream processes are brought on-stream the resulting effluent, comprising syngas, is typically burned in a flare.
• U.S. Pat. No. 4,385,906 discloses a start-up method for a gasification system comprising a gas generator and a gas purification train.
• the gas purification train is isolated and prepressurized to 50% of its normal operating pressure.
• the gas generator is then started, and its pressure increased before establishing communication between the generator and the purifier.
• Purified gases from the purifier may then be burned in a flare until all parts of the process reach appropriate temperature and pressure.
• Flaring is an uncontrolled combustion of flammable gas at the flare tip. Flare flames are visible from substantial distances. The combustion is carried outside the flare tip at the adiabatic flame temperature of the flammable gas, typically as high as 3,000° F (1649 0 C). BRIEF SUMMARY OF THE INVENTION
• the present invention involves a process of collecting all the potential contaminants or pollutants in blow down conduits associated with the process units that comprise an IGCC complex, during start-up, shutdown and normal operation and treating streams containing these contaminants or pollutants such that the IGCC complex does not flare any streams containing such contaminants or otherwise emit the contaminants into the atmosphere.
• These potential contaminant or pollutant streams are first treated for sulfur removal, if necessary.
• the sulfur-free potentially contaminant or contaminant- containing streams are then segregated into either an oxidizing stream or a reducing stream in a flare header system. These streams are then passed to a flare having several burner stages such that oxidizing and reducing streams are not co-mingled.
• the flare header system can also be equipped with a Vapor Recovery Unit (VRU) where any usable gas products such as H2, CO 2 , sulfur compounds can be recovered.
• VRU Vapor Recovery Unit
• a simplified process block diagram of an IGCC plant with the no sour gas flaring scheme in accordance with the present invention is given in Figure 6.
• the sour reducing streams generated during gasifier startups which contain sulfur are first passed through a low pressure scrubber containing a solvent that absorbs H 2 S such as either amine based or caustic- based solvent before such streams are flared.
• gas products from the sour reducing streams can be recovered in a tail gas treatment unit and/or an acid gas removal unit via a vapor recovery unit.
• the sour oxidizing stream typically contains only a trace amount of flammable gas, and can contain an oxygen content of greater than about 1.0 vol %. This sour oxidizing stream is passed to a point downstream of the main reactor furnace burner in the Sulfur Recovery Unit Tail Gas Treating Unit.
• the sweet reducing stream typically contains flammable gas with high heating value which can be greater than about 50 BTU/SCF (1869 kilojoules/scm) and oxygen content of less than about 1.0 vol %, is then passed to a vapor recovery unit where the stream is subsequently routed to the feedstream to the Acid Gas Recovery Unit.
• the sweet oxidizing gas typically contains only a trace amount of flammable gas, and can contain an oxygen content of greater than about 1.0 vol %. This sweet oxidizing stream is passed to a point downstream of the flare burner tip
• the rich acid gas or high H 2 S acid gas containing stream typically contains greater than about 10% H 2 S.
• This stream is passed from the AGR to the SRU during startup. In the case of an unplanned SRU shutdown this stream can be routed to an emergency caustic scrubber to remove the H 2 S prior to flaring.
• Figure 1 is a schematic diagram of an IGCC complex flow diagram in accordance with one embodiment of the present invention, where at least one blowdown conduit is present for the syngas production zone, the shift conversion and low temperature gas cooling zones, the acid gas removal zone, and clean hydrogen expander/heating zone.
• Figure 2 is another schematic diagram of a blowdown system in accordance with one embodiment of the present invention.
• Figure 2 shows the blowdown gases from the gasification zone, shift zone and low temperature gas cooling zone, acid gas recovery zone, gas turbine blow down system and blow down systems for other fugitive emission sources such as the solid handling system.
• Figure 2 shows the routing of these gases depending on either the H 2 S or oxygen contents.
• Figure 3 is a schematic diagram of flare system suitable for use in accordance with the present invention.
• Figure 3 also shows the flare vapor recovery unit integrated within the various streams in the flare header system.
• Figure 4 is a schematic diagram of an IGCC complex flow diagram in accordance with one embodiment of the present invention, in which at least one blowdown conduit is present for the shift conversion and low temperature gas cooling zones and the acid gas removal zone, and in which there is no blowdown conduit for the syngas production zone.
• Figure 5 is a schematic diagram of an IGCC complex flow diagram in accordance with one embodiment of the present invention, in which at least one blowdown conduit is present for the acid gas removal zone, and in which there are no blow down conduits for the syngas production zone and for the shift conversion and low temperature gas cooling zones.
• FIG. 6 is a schematic diagram of an IGCC complex flow diagram in accordance with the embodiment of the present invention, where an LP (low pressure) amine scrubber is used for gasification startup (sour reducing gas) gases and a LLP (low low pressure) caustic scrubber is used for SRU (sulfur recovery unit) startup and for emergency acid gas release.
• LP low pressure
• LLP low low pressure
• SRU sulfur recovery unit
• the syngas production zone or gasifier in an IGCC complex is started up with a clean, sulfur-free, containing less than about 10 ppmv sulfur hydrocarbon-containing feedstock such as natural gas or a light hydrocarbon liquid such as methanol.
• the sulfur-free syngas produced in the gasifier, a sweet reducing gas is then sent to a flare.
• the clean fuel is switched to a high sulfur solid fuel.
• the acid gas H 2 S and other contaminants
• a sulfur recovery unit e.g. Claus unit to make elemental sulfur.
• the acid gas concentration is less than 25% vol H 2 S in the acid gas during the start-up, such acid gas is routed to a sour gas scrubber such as an emergency caustic scrubber.
• a sour gas scrubber such as an emergency caustic scrubber.
• the small amount of unconverted H 2 S in the effluent stream of the SRU is sent to the Tail Gas Treating Unit ("TGTU"), where the small amount of sulfur is removed, and the clean tail gas is recycled back to the AGR or to a CO 2 product stream recovered from the AGR unit for export.
• TGTU Tail Gas Treating Unit
• the suifur-free syngas is combusted in the flare
• sour sulfur-containing gas
• LLP low low pressure
• VRU Vapor Recovery Unit
• the IGCC complex nominally designed to procure 500 Mega Watts of power, can have three coke grinding trains, three operating plus one additional spare gasifier trains, two shift/low temperature gas cooling trains, two AGR/SRU trains, one TGTU train, one syngas expander and optionally a pressure swing absorption unit for hydrogen export offsite and two combined cycle power block trains.
• Contaminant or pollutant emissions in accordance with the invention can be characterized as follows:
• Sour oxidizing gas stream e.g., having a possible oxygen content greater than about 1 vol % and an H 2 S content of a greater than about
• High H 2 S acid gas stream - containing greater than about 10% H 2 S such as the feed to the SRU, or AGR zone.
• a feedstock that does not contain contaminants such as sulfur-containing compounds i.e., in amounts of about less than about 10 ppmv sulfur is used to carry out the start up of the integrated gasification combined cycle complex.
• the sulfur-free feedstock which can be a hydrocarbon feedstock is passed to the syngas production zone which then produces a sweet reducing syngas effluent stream.
• This sweet reducing syngas stream is passed to a blow down conduit.
• the sweet reducing syngas effluent stream is then passed via the blow down conduit to a flare.
• the syngas zone sweet reducing effluent is diverted from the blow down conduit to the shift conversion zone which typically has a low temperature gas cooling zone disposed downstream thereof.
• This sweet reducing stream effluent is then passed to a blow down conduit to a flare.
• the acid gas removal zone is started up with nitrogen or any other inert gas.
• the sweet reducing gas from the blow down conduit associated with the low temperature gas cooling zone is diverted to the acid gas removal zone.
• the effluent from the acid gas removal zone is also characterized as a sweet reducing effluent stream. This sweet reducing stream is then passed through a blow down conduit to a flare and and combusted in the same manner as described above.
• the sulfur recovery zone Prior to, subsequent to, or contemporaneously with the start-up of the upstream zones the sulfur recovery zone is started up with a start-up gas such as natural gas such that when the sulfur recovery zone has reached operating conditions.
• a start-up gas such as natural gas such that when the sulfur recovery zone has reached operating conditions.
• the sweet reducing effluent stream from the acid gas removal zone is then diverted from the blow down conduit to the sulfur recovery zone to produce another sweet reducing effluent stream.
• This sulfur recovery zone sweet reducing effluent stream is then passed to a tail gas treatment unit to produce a tail gas treatment unit sweet reducing effluent.
• the effluent from the tail gas treatment unit is then passed through a blow down conduit to a flare and combusted in the same manner as described above.
• the amount of sulfur-free containing feedstock to the syngas production zone is reduced and the amount of sulfur-containing hydrocarbon feed stock to the syngas production zone is increased.
• the acid gas removal zone sweet reducing effluent stream is diverted from the sulfur recovery zone and passed to a sour gas scrubber.
• the effluent from the sour gas scrubber is then passed to a flare.
• the sulfur concentration of the acid gas removal effluent stream passing to the sour gas scrubber reaches a pretermined value of about 25 volume percent HbS, this stream is diverted back to the sulfur recovery zone while simultaneously reducing start-up gas to the sulfur recovery zone and increasing the sulfur laden hydrocarbon feedstock to the desired operating feed rate.
• tail gas treatment unit effluent presently flowing to the flare is diverted to a point either upstream or down stream of the acid gas removal zone for additional CO 2 recovery.
• various sweet oxidizing gases collected from sumps, tanks, instrument vents, bridles, and pressure safety valves associated with the various zones in the IGCC complex can be passed to the flare or a thermal oxidizer or incinerator such as those commonly found in some conventional tail gas treating units.
• the IGCC complex can be started up with mitigated releases of all noxious contaminants.
• Another embodiment of the above start up procedure in accordance with the present invention involves passing the sulfur-free start up feedstock through the syngas production and the shift conversion zone including the low temperature gas cooling zone prior sending it to a blow down conduit for flaring.
• Figure 4 depicts a schematic process flow diagram that would permit this type of start up.
• the sulfur free start up feedstock is passed through the syngas production zone, the shift conversion zone, low temperature gas cooling zone and the acid gas removal zone prior to sending it to a blow down conduit for flaring.
• Figure 5 depicts a schematic process flow diagram that would permit this type of start up.
• Another embodiment of the present invention provides for a process for shutting down an integrated gasification combined cycle complex with mitigating the release of noxious contaminants such as sulfur. More specifically in the shut down procedure the feedstock to the syngas production zone is switched to a sulfur-free, i.e. about less than 10 ppmv sulfur, feedstock. Once the syngas stream using the sulfur laden hydrocarbon feedstock is displaced by the syngas using the sulfur free feedstock, the effluent from the syngas production zone now a sweet reducing gas is diverting from the shift conversion zone and depressurized to a blow down conduit associated with the syngas production zone. The effluent from the syngas production zone is then passed to a flare.
• a sulfur-free i.e. about less than 10 ppmv sulfur
• the effluent from the low temperature gas cooling zone associated with the shift conversion zone is diverted from the acid gas removal zone and depressurized to a blow down conduit associated with the shift conversion zone. This effluent stream is then passed to a flare.
• the effluent from the acid gas reduction zone is then depressurized. Specifically the hydrogen rich syngas is passed to a flare. The acid gas is depressurized to the sulfur recovery zone.
• the gaseous effluent from the sulfur recovery zone is depressurized to a tail gas treating unit.
• the effluent from the tail gas treating unit is diverted from its recycle to the acid gas removal zone and is depressurized to a flare in accordance with the present invention.
• the fuel to the turbines in the power block zone is switched from hydrogen to natural gas.
• the gasifier and shift zone can both be depressurized by diverting the sweet reducing effluent stream from the low temperature cooling zone to the flare, with the remainder of the IGCC complex being shut down as described above.
• [0060] in another embodiment of the present invention is to provide for a process for shutting down an integrated gasification combined cycle complex while mitigating the release of noxious contaminants such as sulfur in a manner that does not use a sulfur-free feedstock as described above.
• the effluent from the syngas production zone now a sour reducing gas is diverted from the shift conversion zone and depressurized to a blow down conduit associated with the syngas production zone.
• the effluent from the syngas production zone is then slowly discharged to a low pressure sour gas scrubber (such as an amine scrubber) for sulfur removal by throttling one or more pressure control valves.
• the effluent from the sour gas scrubber is passed to a flare for combustion as described above.
• the effluent from the low temperature gas cooling zone associated with the shift conversion zone is diverted from the acid gas removal zone and depressurized to a blow down conduit associated with the shift conversion zone.
• This sour reducing effluent stream is then slowly discharged to a low pressure scrubber by throttling one or more pressure control valves.
• the effluent from the low pressure scrubber is passed to a flare in accordance with the present invention.
• the effluent from the acid gas reduction zone is then depressurized. Specifically the hydrogen-rich syngas is passed to a flare to be combusted and treated in accordance with the present invention.
• the acid gas effluent is depressurized to the sulfur recovery zone.
• the gaseous effluent from the sulfur recovery zone is depressurized to a tail gas treating unit.
• the effluent from the tail gas treating unit is diverted from its recycle to the acid gas removal zone and is depressurized to a flare in accordance with the present invention. [0065] Finally the fuel to the turbines in the power block zone is switched from hydrogen to natural gas.
• the gasifier and shift zone can both be depressurized by diverting the sour reducing effluent stream from the low temperature cooling zone to a low pressure scrubber and then to a flare, with the remainder of the IGCC complex being shut down as described above.
• gasifier, shift and acid gas removal zones can be depressurized by commencing the acid removal zone shut down as described above and not depressurizing the gasifier and shift individually prior to the depressurization of the acid gas removal zone as described above.
• the tail gas treating unit comprises of the following components and operates as described below.
• the tail gas treatment unit can contain either one standard amine absorber for both normal operations and gasifier shutdown operations or two amine absorbers one dedicated for gasifier shutdown and the other for normal operating conditions.
• the TGTU unit also contains several exchangers, pumps, filters and a stripping column.
• the TGTU amine absorber is used to remove the H 2 S in the TGTU feed.
• the H 2 S is absorbed in the amine and the rich amine (H 2 S laden amine solvent) is regenerated to an essentially sulfur free amine by stripping the rich amine with steam in the stripping column or regenerator.
• the TGTU also contains a thermal oxidizer or incinerator for the combustion of tail gas effluent, SRU startup gases, fugitive emissions, and gases from the sulfur pits, sulfur storage tanks and sulfur loading docks.
• the flare header system can contain the following components and operates as described below.
• the flare header system as shown in Figure 3 is divided in to several streams depending on the H 2 S and/or oxygen content. These streams are separated into: sour reducing gas, sour oxidizing gas, sweet reducing gas, sour reducing gas and high acid or H 2 S gas streams.
• a vapor recovery unit of the eductor or compressor type is used to recover any usable or saleable gases from the header system.
• Included in the flare system is an emergency caustic scrubber for the removal of H 2 S from high acid gas streams in the event of an emergency shut down or during the startup of the sulfur recovery unit.
• Separate flare knock out drums are required to remove any water from the gases before they are combusted in the flare.
• the start-up hydrocarbon-containing feedstock or fuel that is free of sulfur can be natural gas or light hydrocarbon liquid such as methanol.
• the start-up fuel rate can be less than or, for instance, about 10% to more than 50% of the normal operating condition ("NOC") of one gasifier throughput. As the gasifier pressure is increased, the rest of the gasification system is commissioned..
• the pressure will rapidly increase to 50-150 psig (345 - 1034 kPa) within minutes after the lightoff with a pressure control valve opened and adjusted to produce such a backpressure.
• the blow down syngas is routed to the sweet reducing gas header to the flare.
• a water knockout drum at the inlet of the flare is necessary to remove any condensed moisture from the wet syngas mixture at start-up.
• the gasifier pressure is gradually increased by throttling the pressure control valve to the blowdown stream.
• the water in the syngas includes the equilibrium water at the gasifier operating pressure and any water physically entrained by the syngas flow.
• the blow down gas is sent to the flare.
• an example of the ramp up schedule of the gasifier start-up can be as follows:
• the pressure can be increased until the gasifier pressure reaches the NOC operating pressure (e.g. about 1000 psig (6895 KPa); ⁇
• the gasifier pressure and throughput can be ramped up to only about 40% NOC throughput at about 400 psig (2758 KPa) for the AGR start-up to save start-up fuel and oxygen. This 40% minimum turndown is based on the constraints provided by a typical AGR column design;
• the syngas from the gasification zone is introduced to the shift section and the low temperature gas cooling ("LTGC") section.
• the syngas from the gasification zone syngas scrubber overhead is diverted from the flare and introduced to the shift zone and the LTGC zone by first opening the small equalizing valve at the inlet of the shift zone gradually to equalize the upstream and downstream pressure. After the pressure is equalized, then a control vaive can be gradually opened to introduce more syngas to the shift zone and downstream.
• the pressure control valve controlling the venting of the sweet syngas to the blowdown conduit passing to the flare can be gradually closed as more syngas is introduced to downstream section.
• the introduction of syngas to the acid gas removal is performed similar to the introduction of syngas to the shift/LTGC zones.
• the scrubbed and shifted syngas passing through the AGR zone should be routed to the flare at a blow down conduit located at the outlet of the H 2 rich syngas in the AGR.
• Any CO 2 stream from the AGR unit can be vented to the atmosphere using a CO 2 vent stack.
• the AGR sweet acid gas is then sent to the Sulfur Recovery Unit ("SRU").
• the SRU can be started up with supplementary firing using natural gas because the sweet acid gas contains practically no H 2 S.
• the SRU refractory heat up is estimated to take at least about 16 to about 24 hours to complete.
• the SRU should reach steady-state operation such that it is ready to receive sour acid gas.
• the effluent from the TGTU low pressure amine scrubber contains mainly CO 2 and is vented to a location downstream of the flare combustor burner during this start-up period.
• the switching of the sulfur-free startup fuel to coke slurry feed can be performed after the AGR/SRU have reached steady-state operation.
• the composition of the vented syngas at the AGR will change slightly after the fuel switching. However, the switching of the sweet to sour acid gas to the SRU can be done over about a 30 minute to about one hour period.
• the sour acid reducing gas coming from the AGR is first routed to a low low pressure ("LLP") scrubber and then to a flare and then switched gradually to the SRU burner. Such switching of flow to the SRU burner is carried out while simultaneously reducing the start-up natural gas supply to the SRU.
• LLP low low pressure
• the AGR acid gas H 2 S concentration will steadily increase.
• the SRU operation is then adjusted to normal operating conditions by feeding H 2 S acid gas from the AGR and NH 3 from a sour water stripper to the SRU.
• the SRU tailgas is sent to the TGTU amine scrubber.
• the TGTU amine scrubber overhead is first sent to the thermal oxidizer or flare.
• the tail gas compressor can then be started up in order to route the tail gas to the product CO 2 stream or alternatively, if the H 2 S content is too high, it can be routed to a point upstream of the AGR.
• the CO 2 stream from the AGR is routed to the CO 2 pipeline for sales or EOR.
• the clean H 2 rich syngas can also be routed downstream using the expander bypass line to vent at the gas turbine inlet after the gasifier lightoff.
• the pressure control valve on an expander bypass can be used to automatically control the expander upstream pressure and the pressure control valve on the blowdown conduit to the flare can be used to automatically control the expander downstream pressure to the gas turbine.
• the shutdown actions can generally be carried out by reversing the steps of the start-up procedure.
• the gasifier throughput is reduced, e.g., from about 100% to about 70% at its normal operating pressure, and the fuel can be switched from coke slurry to a sulfur- free feedstock such as methanol.
• the gas turbine can be backed down commensurately.
• the syngas scrubber overhead control valve can be gradually closed, with the pressure control valve opened gradually to vent to the sweet reducing gas blowdown header passing to the flare. As the syngas is vented, the gasifier throughput is reduced simultaneously to minimize venting. When the syngas scrubber overhead control valves are completely closed, the clean syngas is 100% routed to the flare.
• the pressure and the throughput of the gasifier operating on the clean fuel can be gradually reduced until an arbitrary low throughput is achieved and a reduced gasifier pressure (for example, 50% NOC at 500 psig (3447 KPa) gasifier pressure) is established.
• the gasifier shutdown sequence is then initiated to shutdown the gasifier in a controlled manner.
• the syngas system is bottled up at operating pressure.
• the gasifier will be depressured gradually through the gasifier blowdown conduit to the flare.
• the flow rate of the syngas to the flare due to depressurizing can be calculated by the reduction of inventory accordingly.
• the system can be nitrogen purged.
• the shutdown nitrogen purge is also sent to the flare as we!! via the gasifier blowdown conduit.
• the pollution control equipment includes all equipment and flow schemes shown in Figures 2 and 3.
• the relief or blow down gases are segregated into various relief headers according to whether the gases contain H 2 S and oxygen, as described previously.
• a recovery system is included to recover any usable gases such as H 2 , CO 2 or sulfur for sales.
• a ground or elevated flare is used for emergency safety relief, shutdown and start-up operations.
• the sour gas scrubbers are used for H 2 S removal in the startup/shutdown cases and in emergency acid gas release.
• the following is a non-exclusive example list of the pollution control equipment that may be used in an IGCC complex to carry out an embodiment of the present invention:

Landscapes

• Chemical & Material Sciences (AREA)
• Engineering & Computer Science (AREA)
• Combustion & Propulsion (AREA)
• Oil, Petroleum & Natural Gas (AREA)
• Organic Chemistry (AREA)
• Chemical Kinetics & Catalysis (AREA)
• General Chemical & Material Sciences (AREA)
• Industrial Gases (AREA)

Priority Applications (4)

Applications Claiming Priority (2)

Publications (2)

Family

ID=41610915

Family Applications (1)

Country Status (5)

Cited By (1)

Families Citing this family (10)

Citations (5)

• 2009
  • 2009-07-21 CN CN2009801304923A patent/CN102124082A/zh active Pending
  • 2009-07-21 AU AU2009276876A patent/AU2009276876A1/en not_active Abandoned
  • 2009-07-21 CA CA2731953A patent/CA2731953A1/en not_active Abandoned
  • 2009-07-21 US US13/056,138 patent/US20110120012A1/en not_active Abandoned
  • 2009-07-21 WO PCT/US2009/051206 patent/WO2010014456A2/en active Application Filing

Patent Citations (5)

Also Published As

Similar Documents

Legal Events