Patent Application
20110120012
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.
Gasification was first used to produce “town gas” for light and heat. Additionally, coal and other hydrocarbons have been gasified in the past to produce various chemicals and synthetic fuels. More recently gasification technology has been employed to generate electricity in an IGCC complex wherein coal or another hydrocarbon is gasified by partial oxidation using oxygen or air to syngas. Typically, this syngas is then cleaned of particulates, sulfur compounds and nitrogen compounds such as NOx compounds and then subsequently passed to gas turbine where it is fired. Additionally the hot exhaust gas from the gas turbine is usually passed to a heat recovery steam generator where steam is produced to drive a steam turbine. Electrical power is then produced from the gas turbine and the steam turbine. These IGCC complexes can also be designed to produce hydrogen and capture CO2 thereby reducing greenhouse gas emissions. Because the emission-forming components are removed from the syngas prior to combustion an IGCC complex produces very low levels of air contaminants, such as NOx, SO2, particulate matter and volatile mercury.
As mentioned above 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. Generally the 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° C. to about 1400° C. and in excess of 1,600° 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. There are three basic types of gasifiers that are either air or oxygen fed gasifiers. Specifically, 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. Briefly, 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. In the entrained flow gasifier 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. Finally, in the fluidized-bed gasifier 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. The ASU is used to separate air such that a pure oxygen stream can be sent to the gasifier.
In order to convert syngas produced by the gasifier to hydrogen fuel for both power generation and/or hydrogen sales, the syngas from the gasification block or gasifier must be shifted to convert the CO and water in the syngas to CO2 and hydrogen. The water gas shift reaction is:
CO+H2O→CO2+H2
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.
As set out above this “shift reaction” is practiced widely in the refining and petrochemical industries. Examples of gasification plants utilizing sour shift technology include the Convent Hydrogen Plant in Louisiana, the Dakota Gasification Plant in North Dakota, and the petcoke gasification plant in Coffeyville, Kans. The Coffeyville plant uses gasification technology for ammonia and CO2 production.
Where an IGCC complex is used to capture CO2, the CO2 captured must meet purity standards for compression and injection if the CO2 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 CO2 in the resultant syngas within a downstream AGR unit.
In an IGCC complex as contemplated herein, 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 Rectisol 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 CO2 stream that is suitable for enhanced oil recovery (“EOR”) applications. Ultra-low sulfur content in gas turbine (“GT”) fuel is necessary to allow use of catalysts for CO and NOx 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 H2S. The deep sulfur removal achieved by the Rectisol unit for H2-rich syngas coupled with the use of CO oxidation catalysts and SCR allow the power block to achieve NOx, CO and SO2 emission levels that are comparable to those for a natural gas-fired combined cycle power plants, but with much lower CO2 emissions.
As mentioned above the Rectisol is a purely physical absorption process, which is carried out at low temperatures and benefits from high operating pressure. 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 compounds absorbed are removed from the solvent by flashing (desorption) and additional thermal regeneration, so that the solvent is ready for new absorption. The relative ease of removing CO2 from high pressure synthesis gas as compared to removing it from atmospheric pressure, nitrogen-diluted flue gas is widely recognized as one of the principal benefits of gasification when compared to combustion technologies.
CO2 produced by such an IGCC complex, depending on the process unit integration, is between 97 to 99%+pure with only small traces of other compounds present. This level of purity is required for several reasons. First, it is essential for the product to be very low in water content to minimize or alleviate the formation of carbonic acid (water+CO2=carbonic acid) which is very corrosive to the steel used in the compression equipment, pipeline, injection/re-injection equipment and the actual wells themselves. Second, 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, Third, 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 CO2.
The Rectisol unit can be used to produce high purity CO2 at two pressure levels, atmospheric pressure and about three atmospheres. EOR operations require a CO2 pressure of 2,000 psig (13.79 MPa), so CO2 compression above this level is required. CO2 enters a dense, supercritical phase at about 1,100 psig (7.58 MPa), therefore it remains in a single phase throughout a CO2 pipeline. The Rectisol acid gas removal unit also produces an acid gas stream containing H2S.
The sulfur recovery unit (“SRU”) used in the IGCC complex contemplated herein can be a conventional oxygen-blown Claus technology to convert the H2S 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).
While 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.
A conventional selective catalytic reduction process (“SCR”) can be used for post-combustion treatment of effluent gases to reduce NOx content down to acceptable levels.
In a conventional start-up of a partial oxidation gas generating process the gas generator is started at atmospheric pressure after preheating to at least 950° C. Until the gasifier is pressurized and downstream processes are brought on-stream the resulting effluent, comprising syngas, is typically burned in a flare. As is well known to those skilled in the art, this results in higher than normal emissions of contaminants such as sulfur. See, for example, U.S. Pat. No. 4,385,906 (Estabrook) and U.S. Pat. No. 3,816,332 (Marion).
Accordingly, the start-up of a partial oxidation gas generator presents special challenges, including dealing with the contaminant emissions. For example, U.S. Pat. No. 4,378,974 (Petit et al.) discloses a start-up method for a coal gasification plant, in particular a refractory lined rotary kiln. The method of Petit et al. focuses on the problems that arise from coal having a high chlorine content. Petit et al. discloses a reactor where the lining is made of materials susceptible to chlorine-induced cracking in the presence of oxygen. Petit et al. teaches starting the reactor up in stages while maintaining an oxygen content in the reactor at a sufficiently low level to prevent chlorine-induced cracking of the refractory lining.
Additionally, U.S. Pat. No. 4,385,906 (Estabrook) discloses a start-up method for a gasification system comprising a gas generator and a gas purification train. In the method disclosed by Estabrook 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.
U.S. Pat. No. 6,033,447 (Moock et al.) discloses a start-up method for a gasification system with a sulfur-free organic liquid, such as propanol. The reference claims that air contaminants, such as sulfur, which are characteristic of start-up, may be eliminated by starting the gasifier with a sulfur-free, liquid organic fuel. Once the gasifier is started up using a sulfur-free liquid organic fuel and reaches the appropriate temperature and pressure conditions the burner is transitioned to a carbonaceous fossil fuel slurry. Only sulfur-free gas is flared.
The present invention deals with the start-up of a gasifier or an IGCC complex with no sour gas flaring. 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° C.).
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, CO2, sulfur compounds can be recovered. 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
The sour reducing streams generated during gasifier startups which contain sulfur are first passed through a low pressure scrubber containing a solvent that absorbs H2S such as either amine based or caustic-based solvent before such streams are flared. During normal operations, 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 H2S acid gas containing stream typically contains greater than about 10% H2S. 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 H2S prior to flaring.
Further objects, features, and advantages of the present invention will become apparent from consideration of the following description and the appended claims when taken in connection with the accompanying drawings.
Broadly, in accordance with the present invention 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. When the downstream acid gas removal unit and the sulfur recovery unit and the tail gas treatment unit are commissioned, the clean fuel is switched to a high sulfur solid fuel. After the AGR is fully commissioned, the acid gas (H2S and other contaminants) are concentrated and sent to a sulfur recovery unit e.g. Claus unit to make elemental sulfur. If the acid gas concentration is less than 25% vol H2S in the acid gas during the start-up, such acid gas is routed to a sour gas scrubber such as an emergency caustic scrubber. Once the SRU is operational, the small amount of unconverted H2S 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 CO2 product stream recovered from the AGR unit for export.
The sulfur-free syngas is combusted in the flare
When the gasifier is shutdown, sour (sulfur-containing gas) gas is trapped inside the gasifier. This sour gas can be depressured in a controlled manner though a low low pressure (LLP) scrubber to remove the sulfur contaminants. The substantially sulfur-free depressuring gas is then sent to the flare.
Generally, all emissions containing contaminants during start-up and shut down and if desired, during operation of the IGCC complex are collected in four different headers by an eductor or compressor type collection system also known as the Vapor Recovery Unit (VRU). The gas is either scrubbed free of sulfur and then sent to the flare, or can be recycled back to an upstream unit such as the AGR or SRU for further product (H2, CO2, and 8) recovery
In one embodiment of the present invention where petroleum coke is used as the hydrocarbon containing feedstock, 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:
In one embodiment of the present invention 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. As the gasification or syngas production zone is being started up 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.
When the feed rate to the syngas production zone reaches a predetermined rate at predetermined conditions including a predetermined pressure and temperature, 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. The gases passing through the shift conversion zone and the low temperature gas cooling zone and exiting the low temperature gas cooling zone and are characterized as a sweet reducing stream effluent. This sweet reducing stream effluent is then passed to a blow down conduit to a flare.
Prior to, subsequent to, or contemporaneously with the gasifier start up, the acid gas removal zone is started up with nitrogen or any other inert gas. When the acid gas removal zone has reached predetermined operating conditions including temperature and pressure 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 combusted in the same manner as described above.
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. 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.
Subsequently 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.
When the sulfur concentration of the acid gas removal effluent stream passing to the sour gas scrubber reaches a predetermined value of about 25 volume percent H2S, 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.
Finally, the 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 CO2 recovery.
Additionally in accordance with the present invention 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.
By following the above start up procedure in accordance with this invention 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.
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.
Subsequently, 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.
Finally the fuel to the turbines in the power block zone is switched from hydrogen to natural gas.
In another embodiment 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.
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.
Subsequently, 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.
Finally the fuel to the turbines in the power block zone is switched from hydrogen to natural gas.
In another embodiment 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.
In yet another embodiment the 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.
For the purposes of this invention the tail gas treating unit comprises of the following components and operates as described below.
In this invention, 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 H2S in the TGTU feed. The H2S is absorbed in the amine and the rich amine (H2S laden amine solvent) is regenerated to an essentially sulfur free amine by stripping the rich amine with steam in the stripping column or regenerator. This regenerated amine is reused in the TGTU process and the H2S from the stripping process is recycled back to the sulfur recovery unit for further sulfur removal. 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.
For the purposes of this invention, the flare header system can contain the following components and operates as described below.
The flare header system as shown in
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.
For instance, when the methanol and oxygen mixture is first ignited in the gasifier, 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. As mentioned in one embodiment, the blow down gas is sent to the flare. In order to keep the gasification system gas velocity roughly constant during start-up, an example of the ramp up schedule of the gasifier start-up can be as follows:
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 valve can be gradually opened to introduce more syngas to the shift zone and downstream. Simultaneously, 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 H2 rich syngas in the AGR. Any CO2 stream from the AGR unit can be vented to the atmosphere using a CO2 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 H2S. 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 CO2 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.
After switching the fuel from clean sulfur-free natural gas or hydrocarbon liquid to coke slurry feed, the AGR acid gas H2S concentration will steadily increase. The SRU operation is then adjusted to normal operating conditions by feeding H2S acid gas from the AGR and NH3 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. When the H2S content in the scrubbed TGTU overhead gas is verified to be acceptable, i.e., less than ppmv 10 ppmv, the tail gas compressor can then be started up in order to route the tail gas to the product CO2 stream or alternatively, if the H2S content is too high, it can be routed to a point upstream of the AGR. The CO2 stream from the AGR is routed to the CO2 pipeline for sales or EOR.
The clean H2 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.
For a planned shutdown, 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. After switching the fuel to the gasifier, 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.
When the gasifier shutdown sequence is 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. After the syngas depressuring, the system can be nitrogen purged. The shutdown nitrogen purge is also sent to the flare as well via the gasifier blowdown conduit.
The pollution control equipment includes all equipment and flow schemes shown in
When pollution-control equipment is all operating properly, the sour gas coming from in the SRU tailgas is scrubbed and the clean TGTU tail gas is recycled back to upstream of the CO2 compressors.
While the present invention has been described in terms of preferred embodiments, it will be understood, of course, that the invention is not limited thereto since modifications may be made by these skilled in the art, particularly in light of the foregoing teachings.
This application claims benefit of provisional application Ser. No. 61/084,774 filed Jul. 30, 2008, which is incorporated herein by reference in its entirety.
| Filing Document | Filing Date | Country | Kind | 371c Date |
|---|---|---|---|---|
| PCT/US09/51206 | 7/21/2009 | WO | 00 | 1/27/2011 |
| Number | Date | Country | |
|---|---|---|---|
| 61084774 | Jul 2008 | US |
