Patent Publication Number: US-8992641-B2

Title: Fuel feed system for a gasifier

Description:
CROSS REFERENCE TO RELATED APPLICATIONS 
     This application is a continuation-in-part application of U.S. application Ser. No. 12/209,711 filed Sep. 12, 2008 and entitled “Fuel Feed System for a Gasifier and Method for Gasification System Start-up” which claims priority to and the benefit of the filing date of U.S. Provisional Application No. 60/982,967 filed on Oct. 26, 2007, the disclosures of which are hereby incorporated herein by reference in their entirety. 
    
    
     BACKGROUND 
     The field of the disclosure relates generally to gasification, such as gasification used in Integrated Gasification Combined Cycle (IGCC) power generation systems, and more specifically to systems and methods for supplying high moisture content, solid, carbonaceous fuels to gasifiers, and methods of start up for such systems. 
     At least one known IGCC plant feeds a water-based slurry of bituminous coal to a refractory-lined, entrained flow gasifier to generate the fuel gas used in power generation. Such a slurry feed system may provide an economical and reliable option for feeding higher rank coals, such as bituminous and anthracite coals, to the gasifier. However, such a system is less attractive for lower rank coals, such as sub-bituminous coals, because of the difficulty surrounding the production of low rank coal slurries with a solids concentration and energy content high enough for efficient power production. 
     Inherent moisture is water trapped in the pores of the coal and therefore such moisture may not be available for making the coal slurry. Low rank coals have a relatively higher inherent moisture content (e.g. 22-30 wt %) compared to high rank coals (e.g. &lt;10 wt %). In known IGCC systems, the production of coal-water slurry is a physical process that includes suspending the coal particles in water to facilitate enabling the coal particles to freely move past one another, i.e. enabling slurry flow within the IGCC system. More specifically, in some known IGCC systems, water may be added in an amount sufficient to produce a slurry with a viscosity no higher than about 700 to 1000 Centipoise to enable the slurries to be screened, pumped and sprayed by the feed injectors. Coals with higher inherent moisture content naturally produce slurries with higher total water content. For example, coals with relatively higher inherent moisture content produce slurries with a lower solids content, i.e. lower energy content per unit volume of slurry. While water may be added to particulate sub-bituminous coal to produce a pumpable slurry, the energy content of the resulting dilute slurry may not reach an energy level capable of sustaining an efficient gasification operation. 
     In some known IGCC systems, the quantity of water needed to make a pumpable slurry far exceeds the amount of water needed for the reactions. Although some of the water does react with the coal and convert the coal to syngas, most of this excess slurry water passes through the gasifier, consuming some of the thermal energy in the reactor as the water heats up to reaction temperature, and then degrading that thermal energy produced in the gasifier to lower temperature levels as the product gas is cooled in downstream equipment. The extra energy required for heating the excess water to gasifier reaction temperature comes at the expense of burning some of the CO and H 2  in the product syngas to CO 2  and H 2 O. This requires additional oxygen to be fed to the gasifier, which decreases efficiency and increases capital cost. Also, by converting some of the CO and H 2  in the product syngas to CO 2  and H 2 O in order to heat up the excess water, the amount of CO and H 2  produced per unit of coal gasified decreases. Therefore, in order to fuel the power block with a fixed amount of CO and H 2 , the syngas components with fuel value, a larger amount of coal must be gasified when feeding a coal slurry compared with feeding coal in a much drier state. This increased coal requirement both decreases the plant efficiency and increases its capital cost. 
     Some known combustion turbines must burn a fixed amount of carbon monoxide and hydrogen to achieve their maximum rated power production. To produce the required amount of CO and H 2 , a plant feeding a dilute slurry of sub bituminous coal must gasify significantly more coal than a plant feeding a slurry of bituminous coal. Such a sub-bituminous coal plant may be both less efficient and more costly to construct and operate. 
     Some known IGCC systems feed high moisture content coal to gasifiers using a system known as a dry feed system to overcome the difficulty of producing a high energy content slurry and to avoid the negative impact on overall plant efficiency. In such a dry feed system, lower rank coals may be dried to remove two-thirds, or more, of the inherent moisture present in the coal. The deep drying facilitates improving the flow characteristics of the dried solids in the dry feed system equipment as well as improving the overall efficiency of the gasifier. For instance, high levels of drying are often needed to help reduce the potential consolidation and subsequent flow problems that can result during pressurization of higher moisture content solids in a lock hopper. However, drying the coal may consume a large amount of energy, which reduces the overall power production of the plant as a result. In addition, the dry feed system equipment, which may include a compressor, lock hoppers, lock hopper valves, drying equipment and additional storage capacity, results in a relatively expensive system when compared with slurry-based systems. Furthermore, such systems are limited to relatively modest pressures, on the order of 400 psig or less, because the consumption of gas used for lock hopper pressurization and particle fluidization increases dramatically as system pressures increase. 
     In some known IGCC systems with slurry fed gasifiers, a two-step process may be used for gasifier startup that includes establishing steady flows of all feeds in bypass and/or startup conduits not connected to the gasifier, and redirecting the flows into feed conduits connected to the gasifier feed injector according to a prescribed sequence. Pre-establishing the flows to the gasifier using this two-step process ensures that the correct fuel-oxidant mixture is delivered to the feed injector which, in turn, assures a substantially safe and reliable startup. The startup slurry flow in a slurry feed system is established in a circulation loop that returns to the original slurry storage tank, and the startup oxygen flow may be vented to atmosphere through a silencer. Upon startup, the slurry and oxygen flows are diverted into the gasifier so that the oxygen reaches the feed injector a short time after the slurry. The thermal energy stored in the preheated gasifier refractory brick ignites the reaction mixture and the gasification reactions begin. In contrast, some known IGCC system use a moist feed (or dry feed) system to feed a gasifier. The fuel in a moist feed system is not a storable material like coal-water slurry. Instead, the fuel is manufactured, or “assembled”, prior to introduction into the gasifier by mixing solid fuel particles into a flowing stream of carrier gas. If this mixture is channeled through a conduit but not consumed in the gasifier, such a stream may not be stored for later use, and the carrier gas—fuel particle mixture must be “disassembled” so that the solid fuel particles can be returned to storage for later use. 
     Some known moist feed IGCC systems use a two-step startup method in which nitrogen from the air separation unit may be used as a carrier gas during startup operations. During the first step of the startup method when steady flows of all gasifier feeds are established in bypass and/or startup conduits not connected to the gasifier, the nitrogen carrier gas-fuel particle mixture is returned to the original particulate fuel storage bin via one or more gas-solids separation devices. The gas-fuel solids separation devices facilitate removing a high percentage of the nitrogen from the solid particles before returning the solid particles to a storage bin. The nitrogen is subsequently cleaned to remove moisture and very fine particles so that the nitrogen may be reused in the feed system as carrier gas and/or inert blanketing gas. Some of the nitrogen may be vented to the atmosphere as a purge gas which excludes air from the feed system and facilitates maintaining an inert environment within the feed system. Because nitrogen is used throughout the moist feed system, it may not be necessary for the gas-fuel solids separation devices to be 100% efficient in removing nitrogen from the solid fuel particles. Thus, it is generally acceptable to return the unconsumed solid fuel particles to their original storage bin for later reuse. 
     However, in the case where nitrogen may be unavailable for use as a carrier gas, it may be necessary to use a different carrier gas during startup, such as for example, a process-derived gas such as a sour CO 2 -rich gas and/or syngas. In this case, solid fuel particles may not be returned to their original storage bin. The residual process-gas trapped in the pores of the solid fuel particles, along with any process gas entrained by those particles as they return to the storage bin, may contaminate the feed system with a gas that ultimately cannot be vented directly to the atmosphere. In order to use a process-derived gas, i.e. a “non-ventable” gas, as a startup carrier gas a different startup method and process configuration is needed. 
     SUMMARY 
     In one aspect, a method of startup for a gasification system is provided. The method includes assembling a fuel mixture for use by a gasifier at a fuel mixture assembly point, wherein the fuel mixture includes a quantity of particulate solid fuel and a quantity of non-ventable carrier gas. The method includes channeling the fuel mixture through a first conduit to a fuel mixture disassembly system including a non-ventable carrier gas removal apparatus, establishing a substantially steady flow of the fuel mixture within the first conduit, and redirecting the fuel mixture through a second conduit to the gasifier to facilitate gasifier startup. 
     In another aspect, a gasification system is provided. The gasification system includes a gasifier, a fuel mixture for use by the gasifier, wherein the fuel mixture includes a quantity of particulate solid fuel and a quantity of non-ventable carrier gas. The system includes a pressurization and conveyance section coupled in flow communication upstream from the gasifier, wherein the pressurization and conveyance section includes a fuel mixture disassembly system that includes a non-ventable carrier gas removal apparatus configured to strip the quantity of non-ventable carrier gas from the fuel mixture. 
     In yet another aspect, a fuel feed system for use in a gasification system is provided. The fuel feed system includes a pressurization and conveyance section coupled in flow communication upstream from the gasifier, wherein the pressurization and conveyance section includes a fuel mixture disassembly system including a non-ventable carrier gas removal apparatus configured to strip a quantity of non-ventable carrier gas from a quantity of particulate solid fuel. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  is a block diagram of a portion of an exemplary IGCC power generation plant that includes an exemplary fuel system. 
         FIG. 2  is a process flow diagram of an exemplary feed preparation system used with fuel system shown in  FIG. 1 . 
         FIG. 3  is a process flow diagram of an exemplary feed pressurization and conveyance system used with the fuel system shown in  FIG. 1 . 
         FIG. 4  is a process flow diagram of an exemplary slag additive system used with the fuel system shown in  FIG. 1 . 
         FIG. 5  is a process flow diagram of an alternative startup configuration used with the pressurization and conveyance section shown in  FIG. 3 . 
         FIG. 6  is a process flow diagram of an alternative startup configuration used with the pressurization and conveyance section shown in  FIG. 3 . 
         FIG. 7  is a process flow diagram of an alternative startup configuration used with the pressurization and conveyance section shown in  FIG. 3 . 
     
    
    
     DETAILED DESCRIPTION 
       FIG. 1  is a block diagram of a portion of exemplary IGCC power generation plant  50 . In the exemplary embodiment, plant  50  includes a fuel feed system  110 , an air separation unit  112  coupled in flow communication with fuel feed system  110 , a gasification plant  114  coupled in flow communication with feed system  110 , and a power block  116  coupled in flow communication with gasification plant  114  and IGCC power generation plant  50 . During operation, air separation unit  112  uses compressed air to generate oxygen for use by gasification plant  114 . More specifically, air separation unit  112  separates compressed air received from an external source (not shown) into separate flows of oxygen and a gas by-product, typically nitrogen. In the exemplary embodiment, gasification plant  114  converts solid fuel and oxygen into a clean fuel gas that is burned in power block  116  to produce electrical power, as will be described in more detail herein. It will be clear to those skilled in the art that this diagram is a simplified version of an IGCC power plant block flow diagram and that, for the sake of clarity in explanation, not all of the equipment blocks nor all of the connecting lines found in such a power plant have been shown in the diagram. 
     A solid carbonaceous fuel (not shown) is channeled into a feed preparation section  118  of feed system  110  via a conduit  120 . In the exemplary embodiment, the solid carbonaceous fuel is coal. Alternatively, the fuel may be a petroleum coke, a biomass, or any other solid carbonaceous fuel that will enable IGCC power plant  50  to function as described herein. In another embodiment, a slag additive may be introduced with the solid fuel within conduit  120 . Feed preparation section  118  converts the as-received fuel into a solid particulate gasifier feed with a target particle size distribution and internal moisture content suitable for use in IGCC plant  50 . Low pressure nitrogen from air separation unit  112  enters feed preparation section  118  via conduit  122 , a portion of which is used to convey the solid particulate feed material to a pressurization and conveyance section  124  via conduit  126 . The remaining portion of the low pressure nitrogen is heated in feed preparation section  118  and channeled via conduit  128  to pressurization and conveyance section  124  for use in moisture and fines control within section  124 . Low pressure nitrogen used in the pressurization and conveyance section  124  is channeled back to feed preparation section  118  via conduit  130  to be filtered, which facilitates removing particulate fines, and is then dried to facilitate removing substantially all water therein, so that the low pressure nitrogen may be reused for various purposes throughout feed system  110 . As an alternate to low pressure nitrogen, any gas can be used that allows for the safe and reliable conveyance of the coal in accordance with the feed system described herein. In an alternative configuration, any particle size reduction, control and drying system may be used that reasonably produces the correct particle size and moisture content coal in accordance with the feed system described herein. 
     In the exemplary embodiment, gasification plant  114  includes an acid gas removal section  132  coupled in flow communication with a gasifier  134 . Acid gases, such as H 2 S COS and CO 2 , are removed from a quantity of raw syngas to produce a clean fuel gas that is channeled to a combustor  136  located in power block  116  via conduit  138  for producing electrical power, as described in more detail herein. Acid gas removal section  132  produces a byproduct sulfur stream  140  and a sour, CO 2 -rich gas stream  142  that is compressed and recycled to feed system  110  and that is used as the high pressure conveying gas for transporting the solid particulate fuel into gasifier  134 . The CO 2  recovered from the syngas within acid gas removal section  132  is compressed and channeled to feed preparation section  118  via conduit  142 . This recycled CO 2 -rich gas stream is heated within feed preparation section  118  and then channeled via conduit  144  to pressurization and conveyance section  124  for use as the high pressure pneumatic conveying gas that transports the particulate solid fuel into gasifier  134  via feed conduit  146 . In the exemplary embodiment, high pressure nitrogen from air separation unit  112  is channeled to feed preparation section  118  via conduit  148 . In the preferred embodiment, this nitrogen stream, is only used during startup when recycled CO 2 -rich gas is not yet available (as described in more detail herein), is preheated and then channeled via conduit  144  to pressurization and conveyance section  124  for use as a high pressure pneumatic conveying gas during gasifier startup. Alternatively, any high pressure gas is used during startup that allows for the safe and reliable operation of the gasification system as disclosed herein. Further alternatively, any high pressure gas is used during normal operation that allows for the safe and reliable operation of the gasification system as disclosed herein. 
     In the exemplary embodiment, feed system  110  includes a slag additive handling section  152  that receives a slurry of char (i.e. unconverted solid particulate fuel) and fine slag via conduit  154  from a char and fines handling section  156 . This fine particulate material is recovered as a dilute aqueous slurry from gasification plant  114 . The char fraction of this slurry is the unconverted carbon from gasifier  134 , and is subsequently recycled via conduit  154 . Slag or mineral additive is channeled from an externally located storage section (not shown) to slag additive handling section  152  via conduit  158 . The mineral additive is pulverized in a dry rod or ball mill (not shown in  FIG. 1 ) and mixed with the char and fine slag slurry to make a final additive slurry that is channeled by a positive displacement pump (not shown) into gasifier via conduit  160 . In an alternative embodiment, a secondary water stream  162  may be used to add water to the final additive slurry fed to gasifier  134  to control temperatures and modify reaction chemistry. In a further alternative embodiment, the mineral additive is fed as dry solids to gasifier  134 , in a mixture with the dry particulate fuel or using a separate feed system with a dry solids pump and conveying gas. In a still further alternative embodiment, the mineral matter is fed to gasifier  134  as a separate slurry, separate from the recycle solids slurry. In yet another alternative embodiment, the mineral matter is procured as a preground additive and blended with the recycle solids slurry. In an even further embodiment, the mineral additive is any mineral-containing material that facilitates the operation of the gasification system as described herein. Alternatively, no mineral additive is used and only a quantity of recycled char and fines, or liquid water alone is channeled to gasifier  134  via a separate conduit  165 . 
     During operation, air separation unit  112  separates oxygen from air to produce a relatively high purity (about 95% by volume O 2 ) oxygen feed for use within gasifier  134 . A first portion of air enters the air separation unit  112  directly via conduit  164 . A remaining portion of air is extracted from the combustion turbine air compressor  196  conduit  166 . In the exemplary embodiment, the first portion of air is about 50% of the total quantity of incoming air. Alternatively, the first portion of air may be any percentage of the total quantity of air that enables fuel feed system  110  to function as described herein. In addition to producing the gasifier oxygen feed, air separation unit  112  also produces nitrogen for use within feed system  110 . The remaining nitrogen rich byproduct gas is returned via conduit  168  to the combustion turbine  192  for use as a diluent gas by combustor  136 . 
     In the exemplary embodiment, feeds channeled to gasification plant  114  include pneumatically conveyed particulate solid fuel via conduit  146 , slag additive, char and fine slag slurry via conduit  160 , and high purity oxygen from air separation unit  112  via conduit  170 . During operation, gasifier  134  converts the feeds into raw syngas that is subsequently channeled to acid gas removal section  132  via conduit  172 . A coarse slag (not shown) that is separated from the syngas within gasification plant  114  is recovered as a byproduct slag stream  174 . Any unconverted carbon is recovered along with fine slag as a dilute slurry and channeled via conduit  176  to handling section  156 . High pressure steam generated by the cooling of the hot syngas effluent from gasifier  134  is channeled via conduit  178  to power block  116  wherein the high pressure steam is expanded through a steam turbine  180  to produce electrical power. In the exemplary embodiment, a process water stream (not shown) is channeled as a dilute slurry  182  to a treating section  184  that treats the water to control the concentrations of various contaminants in the circulating process water system, including but not limited to dissolved and suspended solids, and subsequently returns the treated water stream to gasifier  134  for reuse via conduit  186 . A clean stream of water (not shown) is channeled from treating section  184  via conduit  188  to disposal or beneficial use beyond the plant boundary. A dilute slurry (not shown) of fine solids removed from the water stream during cleaning is channeled via conduit  190  to handling section  156 . In an alternative embodiment, the char and fines are not recycled to the gasifier or are only partially recycled to the gasifier. Instead, the portion of char and fines not recycled to the gasifier is channeled from char and fines handling system  156  via a separate conduit, not shown, to disposal or beneficial use. In a further embodiment, all or a portion of the char and fines are dried before recycle to the gasifier and fed to the gasifier in combination with the coal, in combination with the dry slag additive or as a separate stream. In a still further alternative, the char and fines are recovered from the gasification system using dry scrubbing technology, and all or a portion are recycled to the gasifier in combination with the coal, in combination with the dry slag additive or as a separate stream. 
     In the exemplary embodiment, power block  116  includes a combustion turbine  192  and a steam system  194 . Combustion turbine  192  includes an air compressor  196  operatively coupled to a power expansion turbine  198  and an electrical power generator  200  via a single shaft  202 . During operation, the combustion turbine  192  produces power by burning clean fuel gas  138  using, for example, a Brayton Cycle, and steam system  194  produces power by expanding steam through a steam turbine  180  using, for example, a Rankine Cycle. More specifically, clean fuel gas  138  from compressor  196  and diluent nitrogen  168  (used to control NO x  formation) are channeled to combustor  136  and mixed and combusted therein, wherein the exhaust gaseous products of combustion are expanded through expansion turbine  198 , thereby turning shaft  202 , which in turn operates compressor  196  and generator  200  and electrical power is produced therein. Hot exhaust gas from expansion turbine  198  is channeled through a heat recovery steam generator (HRSG)  204 . A high pressure steam generated as the hot exhaust gas cools is combined with high pressure steam  178  generated in syngas cooling section of gasification plant  114 , then superheated in the HRSG  204 , recovering additional energy from the hot exhaust gas, and is then channeled to steam turbine  180  where it is expanded to make additional electrical power via generator  206 . The expanded steam is then condensed within a condenser  208  to produce boiler feed water, which is subsequently channeled to HRSG  204  and the syngas cooler in the gasification plant  114 . 
       FIG. 2  is a process flow diagram of an exemplary feed preparation system  118  used with fuel feed system  110  shown in  FIG. 1 . More specifically,  FIG. 2  illustrates five flow configurations that may be used with fuel feed system  110 . In the exemplary embodiment, a volume of sub-bituminous coal, for example Powder River Basin (PRB) coal, not shown, is channeled to feed preparation section  118  via conduit  120  and is conveyed through an air stripping tube  210  wherein the volume of coal is contacted by a counter-current flow of low pressure nitrogen  212  being channeled thereto from a nitrogen storage drum  214 . Low pressure nitrogen  212  strips residual air from the interstitial spaces between the incoming pieces of coal. In the exemplary embodiment, the coal is maintained in a nitrogen-rich atmosphere in all equipment operatively coupled downstream from tube  210 . Alternatively, any suitable inerting gas, such as CO 2  or vitiated air, may be used to maintain coal in a low oxygen-content environment. The nitrogen and associated particulate matter exiting air stripping tube  210  is filtered in a dust control unit  216  prior to being exhausted to the atmosphere. This exhaust valve point is a main loss point for low pressure nitrogen from system  110 , and the flow of nitrogen exhausting through dust control unit  216  is the major factor determining the makeup rate  218  from air separation unit  112  (shown in  FIG. 1 ). In the exemplary embodiment, air stripping tube  210  includes a plurality of downwardly sloping baffle plates (not shown) positioned within air stripping tube  210  to facilitate creating a counter-current of nitrogen and particles within tube  210 . In an alternate embodiment, air stripping tube  210  may be a featureless column. In another alternate embodiment, air stripping tube  210  may be any configuration that facilitates the stripping of air from the coal in the fuel system disclosed herein, including configurations involving purged air locks. In an alternate embodiment, an air stripping tube  210  may not be used, but instead oxygen concentrations are controlled to safe levels by introducing inert gases at one or more points in the feed preparation system, including but not limited to CO 2  as the result of combusting a fuel. 
     Coal drops through air stripping tube  210  onto a weigh belt feeder  220  that is operatively coupled downstream from tube  210  and that is used to meter the coal into a cage mill  222 . In the exemplary embodiment, cage mill  222  grinds the coal to a desired particle distribution in a single step. Alternatively, a two-step grinding process (not shown) may be used that utilizes a hammer mill followed by a cage mill. In the exemplary embodiment, a target particle size distribution for the coal is about 50% to about 80% filtered through a 100 mesh screen and about 100% filtered through a 10 mesh screen. Alternatively, any appropriate grinding equipment may be used in light of the type of coal feed within fuel feed system  110 , and that enables fuel feed system  110  to function as described herein. 
     In the exemplary embodiment, a low pressure nitrogen gas or other suitably inert gas purge stream  224  maintains a supply of gas purge on the grinding equipment to prevent buildup of coal fines and to remove moisture liberated from the coal by the cleaving of coal particles and evaporated from the coal by the heat of grinding. Purge stream  224  is combined with spent purges from other parts of the system, and the combined stream is channeled through dust filter  226 , compressed in blower  228  and channeled to inert gas drying package  230 . Filter  226  facilitates substantially removing fine coal dust from the purge stream  224 , and drying package  230  substantially removes all moisture from the purge stream  224 . Inert gas is then recycled to storage drum  214  for reuse within system  110 , and condensed water from the inert gas drying package  230  is recycled for use elsewhere in the plant or routed to an externally located wastewater treatment unit (not shown). In an alternative embodiment, condensed water from inert gas drying package  230  may be recycled (not shown) for use elsewhere in gasification system  50 , such as but not limited to the additive slurry tank  406 , described later. In another alternative embodiment, inert gas drying package  230  is not used to substantially dry the inert gas, but is an inert gas humidity and temperature control unit that adjusts the humidity and temperature of the inert gas as needed to help maintain the coal within fuel feed system  110  at a desired moisture level content. 
     In the exemplary embodiment and in one exemplary flow configuration ( 1 ), ground coal particles are channeled via conduits  232 ,  234  and  236  into an inlet  238  of a main coal storage silo  240 . In the exemplary embodiment, silo  240 , and conduits  232 ,  234  and  236  are insulated to substantially prevent cooling of the coal and condensing of any moisture liberated by the grinding process. A stream of low pressure nitrogen or other inert gas  242  is channeled from drum  214  and enters a purge gas inlet  244  in storage silo  240 . During operation, the nitrogen or inert gas flow  242  may be used to fluidize a lower portion  246  of storage silo  240  to enable the solids to flow of out of silo  240 . It also maintains a sufficiently inert environment throughout silo  240  to substantially prevent spontaneous combustion therein. And as it rises upwards through silo  240 , the nitrogen or inert gas flow  242  strips away any excess, residual moisture from the coal solids that may have been liberated during the grinding process and thus substantially prevents moisture from re-condensing as the coal particles cool. 
     In the exemplary embodiment, coal is channeled from an outlet  248  positioned on the bottom  246  of storage silo  240  and is metered into a pneumatic pick-up station  250  where the coal is entrained in a flow of low pressure nitrogen gas  252  channeled from the drum  214 . The nitrogen or other inert gas  252  transports the coal particles via dense phase pneumatic transport in conduit  126  to feed pressurization and conveyance system  124  (shown in  FIG. 1 ). In an alternative embodiment, the coal particles may be transported by any means that facilitates the operation of the fuel feed system  110  as described herein. 
     In the exemplary embodiment, feed preparation section  118  includes equipment for heating gas used in conveying coal and for reducing moisture therein. More specifically, low pressure nitrogen or other inert gas from drum  214  is heated in a low pressure coil  256  of a natural gas-fired heater  258 . Alternatively, a conduit  260  is configured to bypass coil  256  and is used to adjust the final temperature of the heated nitrogen  262 . This heated low pressure nitrogen or other inert gas stream  262  is used for conveying and moisture removal in some of the other flow configurations shown on  FIG. 2  as well as in downstream equipment, as described in more detail herein. Heater  256  includes a high pressure gas heating coil  264  that increases a temperature of a high pressure conveying gas (not shown) for use in the feed pressurization and conveying section  124  (shown in  FIG. 1 ). In the exemplary embodiment, the high pressure conveying gas is recycled sour CO 2    266 . Alternatively, the high pressure conveying gas may be high pressure nitrogen  268  channeled thereto from air separation unit  112 , or the high pressure conveying gas may be natural gas channeled thereto from an external source (not shown). As another alternative, the high pressure conveying gas may be any gas suitable for conveying the coal within fuel feed system  110  and into the gasifier  134 . In a further alternative, fired heater  256  is replaced by other heating means, including, but not limited to, direct heating by the combustion of air and natural gas or indirect heating by heat exchange with steam or other hot process gases available from elsewhere in IGCC plant  50 . 
     In an alternative embodiment and in the second exemplary flow configuration ( 2 ), a steam-jacketed paddle dryer  270  is coupled in flow communication between the cage mill  222  and main storage silo  240 . Paddle dryer  270  is purged with low pressure nitrogen or inert gas stream  272  to remove moisture liberated during the coal drying process. Moisture-laden nitrogen or inert gas  274  then combines with nitrogen or inert gas from cage mill  222  and is processed to remove coal dust and water vapor, as described in more detail herein. Paddle dryer  270  may be incorporated into feed preparation system  118  when a higher degree of moisture removal from the coal particles is desired, or when the feed coal requires additional drying to remove surface moisture. Alternatively, the coal may be dried using other drying methods that facilitate operation of the fuel feed system as described herein. 
     In another alternative embodiment and in the third exemplary flow configuration ( 3 ), coal is channeled through air stripping tube  210  onto a weigh belt feeder  220  and is channeled via conduit  275  through a chute  276  into a pulverizer  278 , e.g. a bowl mill. In the exemplary embodiment, pulverizer  278  is a roller mill. Alternatively, pulverizer  278  may be a bowl mill or a ball mill or any such device used to grind coal to a target particle size including equipment for associated drying requirements, and that enables fuel feed system  110  to function as described herein. Low pressure nitrogen or other inert gas, heated within heater  258  or other heating means not shown, is channeled via conduit  280  to a pulverizer inlet  282  along with coal, where it substantially dries the coal particles to the target moisture level as the coal is being pulverized. For example, the final coal moisture level can be controlled by adjusting the temperature of stream  282 . Other control methods include controlling the humidity and flow rate of the warm nitrogen or other inert gas. The warm nitrogen or other inert gas carries the dried coal particles out of the pulverizer  278  and transports them via conduit  126  to feed pressurization and conveyance section  124  (shown in  FIG. 1 ). 
     In another alternative embodiment and in the fourth exemplary flow configuration ( 4 ), an additional grinding mill  222  is coupled in flow communication between weigh belt feeder  220  and pulverizer  278 . In this embodiment, grinding mill  222  may be a hammer mill or other suitable mill when coupled in conjunction with pulverizer  278  that produces the desired particle size distribution. Coal from the weigh belt feeder  220  is crushed or pre-ground in a first step in mill  222  and then is channeled via conduits  284  and  286  to pulverizer  278 . 
     In another alternative embodiment and in the fifth exemplary flow configuration ( 5 ), coal is channeled from air purge tube  210  onto weigh belt feeder  220  and is directed into cage mill  222  for grinding. The ground coal is then channeled past paddle dryer via conduit  232  and is channeled via insulated conduit  234  to pneumatic transport pickup point  286 . At this point, hot, dry, low pressure nitrogen or other inert conveying gas  288  from heater  258  entrains the ground coal particles and channels the ground coal in dense phase transport via insulated conduit  290  into a cyclone  292 . Alternatively, the coal particles may be transported by any means that facilitates the operation of the fuel feed system as described herein. The temperature of the hot conveying gas and the length of the insulated transport conduit  290  is such that, when combined with the heat of grinding from cage mill  222 , both surface moisture and a portion of the moisture internal to the pores of the coal particles is vaporized and driven into the bulk gas phase. The amount of vaporization is controlled by adjusting the temperature, flow rate and humidity of stream  288 . 
     In the fifth flow configuration, the particulate solids are separated from the conveying gas in cyclone  292  and drop into a moisture stripping column  294 . In this embodiment, moisture stripping column  294  includes a plurality of downwardly sloping baffle plates (not shown) positioned within moisture stripping column  294  to facilitate creating a counter-current of nitrogen or other inert gas and particles therein. Alternatively, moisture stripping column  294  may be a featureless column. The particles then encounter a second, upwardly flowing stream  296  of hot, dry nitrogen or other inert gas from heater  258  therein. This stripping gas stream  296 , which flows counter-current to the downwardly flowing coal particles, strips away residual moisture from the interstitial spaces between coal particles that was liberated during the grinding but that was not removed within the cyclone  292 . Hot, dry coal particles exit stripping column  294  and enter silo  240  at inlet  238 . The coal is channeled via dense phase pneumatic transport within conduit  126  to the feed pressurization and conveyance section  124  (shown in  FIG. 1 ) as described in more detail herein. Moreover, finely ground coal within an overhead flow  299  from cyclone  292  is channeled through a secondary cyclone  300  that returns the coal fines back to stripping column  294  via a conduit  302  to an inlet  304 . Excess gas from secondary cyclone  300  is channeled to dust collection system  226  where, along with the other purges from the system, the combined gas is filtered to remove substantially all remaining coal dust. After compression by blower  228 , the gas is channeled to gas dryer  230  for removal of substantially all of the residual moisture that was present as a result of grinding and drying the coal. The dry, particle free nitrogen or other inert gas exits dryer  230  and may then be recycled to drum  214  for reuse throughout the fuel feed system  110 . 
       FIG. 3  is a process flow diagram of an exemplary feed pressurization and conveyance system  124  used with the fuel feed system  110  shown in  FIG. 1 . Particulate solids with the desired size distribution and moisture content are conveyed from feed preparation section  122  (shown in  FIG. 1 ) via dense phase pneumatic transport in conduit  126 , as described in more detail herein. A storage bin primary inlet cyclone  320  separates solids from the low pressure nitrogen or other inert transport gas and discharges the solids to an inlet  322  of a storage bin inlet stripping tube  324  for further processing. Overhead gas from cyclone  320  is then channeled via conduit  326  through a storage bin secondary inlet cyclone  328  that removes a substantial portion of entrained coal fines from the transport gas and channels the coal fines via conduit  330  to the inlet  322  of stripping tube  324 . Secondary cyclone  330  overhead gas is channeled via conduit  332  to a dust control system  334 . The substantially dust-free gas is then compressed by a blower  336  and channeled to a nitrogen drying package  230  (shown in  FIG. 2 ) for reuse throughout fuel feed system  110 . Alternatively, drying package may be a temperature and humidity control package. 
     The coal particles removed by cyclones  320  and  330  enter inlet  322  and are channeled downwards against a counter-current flow of heated nitrogen or other inert stripping gas  128 . In this embodiment, stripping tube  324  includes a plurality of downwardly sloping baffle plates (not shown) positioned within stripping tube  324  to facilitate creating a counter-current of nitrogen and particles therein. Alternatively, stripping tube  324  may be a featureless column. The stripping gas removes residual moisture that may remain following grinding and drying, as is described in more detail herein. After passing through stripping tube  324 , the coal particles enter a storage device, such as for example, solids pump storage bin  338 . 
     In the exemplary embodiment, storage bin  338  is configured to provide coal feed to two solids pumps  340  that operate in parallel. Alternatively, storage bin  338  may be configured to feed any number of solids pumps  340 . As a further alternative, fuel feed system  110  can be configured to have any number of storage bins  338  and solids pumps  340  that facilitate the operation of the fuel feed system as described herein. In the exemplary embodiment, solids pump  340  is a rotary, converging space Solids Transport and Metering pump utilizing Stamet™ Posimetric® feed technology, otherwise known as a Stamet™ solids pump commercially available from GE Energy, Atlanta, Ga. This pump is capable of transporting solids from atmospheric pressure to pressures well over 1000 psig with a strongly linear relationship between pump rotational speed and solids mass flow. Alternatively, any type of pump or pressurizing conveyance device may be used that handles and pressurizes solids as described herein. 
     In the exemplary embodiment, a suction feed vessel  342  is coupled in flow communication between each outlet conduit  344  from storage bin  338  and each solids pump  340 , wherein each suction feed vessel  342  controls the flow of coal to each solids pump  340 . More specifically, each feed vessel  342 , which is designed to withstand full gasifier system pressure, includes an inlet safety valve  346  that is closed in the event of a pump failure. Alternatively, or in cooperation with inlet safety valve  346 , additional outlet safety valves, not shown, may be located in the discharge line  352  of each solids pump. In the exemplary embodiment, feed vessels  342  are live-bottom vessels configured to ensure that the suction inlet of each respective solids pump  340  is filled with coal thereby ensuring a continuous a flow of particulate solids through each pump. Alternatively, lines  344  are designed to provide a buffer volume, and may incorporate inlet safety valves  346  and other features, such as but not limited to contoured and vibratory surfaces to assist with the flow of solids into the inlet of pumps  340 . 
     In the exemplary embodiment, particulate solid fuel from suction feed vessels  342  is pressurized by solids pumps  340  to a pressure level sufficient to enable the solids to flow through feed injector  348  and into the gasifier  134  (not shown in  FIG. 1 ). A high pressure stream of nitrogen  350  from the air separation unit  112  (shown in  FIG. 1 ), which may or may not be preheated, is coupled to a discharge conduit  352  of each solids pump  340  at two locations, a first connection  354  located adjacent the discharge  356  of solids pump  340 , and a second connection  358  positioned downstream from first connection  354 . First connection  354  provides a flow of seal nitrogen that traverses backwards through the compacted solid particles moving through solids pump  340 . Although gas leakage backwards through solids pump  340  is minimal, the seal nitrogen prevents leakage of conveying gas, oxygen or syngas backwards through the pump. Second connection  358  provides a relatively higher velocity jet of nitrogen directed at the particulate solids emerging from the solids pump discharge  356 . The high speed jet breaks up occasional agglomerations of particles and provides a substantially even distribution of the particulate fuel that exits the solids pump  340  and further enables the solids to transition from the highly compacted condition inside the pump to the free flowing fluidized condition required for high pressure pneumatic transport downstream of solids pumps  340 . In the preferred embodiment, the high pressure pneumatic transport of coal downstream of the solids pump  340  is dilute phase transport. Alternatively, the high pressure pneumatic transport of coal downstream of solids pump  340  is of any type that facilitates operation of the fuel and gasification systems. As an alternative to the high speed jet, any mechanical delumping device may be used at any point on conduit  352  that will enable fuel feed system  110  to function as described herein. Alternatively, the seal nitrogen described herein may be any clean, inert gas that enables the fuel and gasification systems to function as described herein. 
     In the exemplary embodiment, following the delumping operation, the coal particles are channeled via discharge conduit  352  into a pneumatic transport conduit  360 . Therein, a high pressure conveying gas  362  from heater  258  (shown in  FIG. 2 ) entrains the coal solids via dilute phase pneumatic conveyance directly to the gasifier feed injector  348  via conduits  364 ,  366  and  380 . Solids flow control herein is achieved by varying the speed of operation of solids pumps  340  and/or the flow, pressure and temperature of the high pressure conveyance gas. In an alternate embodiment, the high pressure carrier gas is not heated. In a further alternate embodiment, the high pressure carrier gas is processed any way that facilitates operation of the fuel and gasification systems as described herein. 
     In an alternative embodiment, the solids are channeled via conduit  368  into a high pressure feed vessel  370  that serves as a buffer in the conduit between solids pumps  340  and gasifier feed injector  348 . During operation, feed vessel  370  is an alternative flow path that may be used to improve solids flow to gasifier  134  (not shown in  FIG. 1 ). Feed vessel  370  may help minimize the effects of temporary flow variations or interruptions at the solids pumps  340 , or in the alternative embodiment where solids pumps  340  are not Posimetric pumps that may not have the same or substantially the same continuous flow characteristics as the Posimetric technology described herein. 
     During operation of feed vessel  370 , and in one embodiment, a portion of a high pressure conveying gas is diverted via conduit  324  from the solids transports conduit  360  and channeled via conduit  372  to a bottom portion  376  of the feed vessel  370  to fluidize the solids and enhance flow characteristics thereof. A remainder  378  of the high pressure conveying gas is used to channel the solids out of feed vessel  370  and into conduits  366  and  380  towards feed injector  348 . In this embodiment, flow control is achieved by adjusting the operational speed of solids pumps  340  and by adjusting the flow rates of the high pressure conveying gas streams  372  and  378  that are channeled to the bottom  376  of feed vessel  370 . 
     In another alternative embodiment, it may be necessary to recycle more sour CO 2  gas to the gasifier  134  (shown in  FIG. 1 ) than is needed to convey the solids or that can be handled by the solids conveyance conduits. In this embodiment, an additional conduit  382  and  384  is available for feeding gas directly to the feed injector  348 . This additional volume of gas may be used to moderate the temperature within gasifier  134  (not shown in  FIG. 3 ), to modify the spray characteristics of the feed injector  348 , or to modify the chemistry of the gasification reactions. 
       FIG. 4  is a process flow diagram of an exemplary slag additive handling section  152  used with the fuel feed system  110  shown in  FIG. 1 . In the exemplary embodiment, slag additive handling section  152  includes a slag additive mill  402 , such as a rod mill or ball mill, that receives a quantity of slag additive (not shown) from an externally located source (not shown) via a slag additive weight belt feeder  404 . A slag additive/recycle fines mix tank  406  is coupled downstream and in flow communication from mill  402 . More specifically, slag additive is ground to the target particle size distribution within mill  402 , which, in the exemplary embodiment, operates in a dry mode. Alternatively, any type of mill that facilitates operation of the fuel system described herein may be used. Fugitive emissions from mill  402  are captured in a dust collection system  408 . In an alternative embodiment, the slag additive is received as pre-ground material, eliminating a need for mill  402 . 
     In the exemplary embodiment, char and fines slurry is channeled via conduit  154  from handling section  156  (shown in  FIG. 1 ) into the mix tank. Dry particulate additive from the mill  402  is mixed with the char and fines slurry within mix tank  406  by an agitator  410 . A plurality of conduits  412  and  414  form a continuous loop  416  through which a mix tank pump  418  circulates slag additive/recycle fines slurry past the suction of charge pump  420  to ensure that the charge pump always has an adequate supply of slurry and to provide additional mixing in tank  406 . Slurry is withdrawn from the suction recirculation loop  416  into charge pump  420  positioned downstream from mix tank pump  406 . In the exemplary embodiment, charge pump  420  is a high pressure positive displacement pump that feeds the slurry via conduit  422  to gasifier feed injector  348  (shown in  FIG. 3 ). Once the moisture level of the solid fuel being channeled to gasifier  134  (shown in  FIG. 1 ) has been set by the operation of the feed preparation section  118 , the final, total amount of water fed to gasifier  134  can be controlled by adjusting the slurry concentration of the char and fines slurry and/or the amount of fresh water makeup  424  added to mix tank  406 . Alternatively, the slag additive may be ground together with the recycle solids in a wet rod or ball mill rather than grinding the slag additive separately and then blending it with the recycle solids. The product from such a co-grinding operation is screened and then sent to mix tank  406 . In an alternative embodiment, the total amount of water fed to gasifier  134  may be controlled by injecting any additional required water into the recycle solids slurry downstream of charge pump  420 , or as a separate feed to the gasifier  134 . 
     Referring now to  FIG. 1 , and in the exemplary embodiment, prior to ignition of combustion turbine  192  and start up of gasifier  134 , another carrier gas source must be provided until sufficient levels of CO 2  are produced by gasifier  134  and can be recovered to maintain a running fuel feed system  110 . This secondary carrier gas may by necessary because typically CO 2  cannot be recovered from the syngas until the gasifier starts, or, in the case of a multi-train gasification operation, there may not be sufficient CO 2  available to provide the required amount of CO 2  to the operating trains as well as the train undergoing startup. In the exemplary IGCC plant  50 , high pressure nitrogen obtained from the air separation unit  112  is not needed as a clean fuel gas diluent for clean fuel gas  138  until after gasifier  134  has been started and syngas is produced therein. In an alternative embodiment where the gasifier is integrated into an ammonia production plant rather than an IGCC plant, the nitrogen from the air separation unit may not be needed for ammonia synthesis until after the gasifier is started and syngas is produced. 
     Drum  214  is filled with low pressure nitrogen from the air separation unit  112  or from on-site storage, not shown. Coal is introduced into inlet air purge tube  210  (shown in  FIG. 2 ) and is subsequently ground in cage mill  222 , as described herein, and loaded into main coal silo  240  wherein moisture by grinding is purged out by nitrogen  242 . Low pressure conveying gas  252  from drum  314  entrains the coal from silo  240  to storage bin  338 , as shown in  FIGS. 2 and 3 . Once bin  338  is loaded, high pressure nitrogen from the air separation unit  112  is heated in heater  258  and a continuous flow thereof is channeled to cyclone  386  (shown in  FIG. 3 ) via successive conduits  144 ,  362 ,  360 ,  364 ,  366 ,  388  and  390 . Nitrogen is channeled from cyclone  386  through the high efficiency cyclone package  392 , the dust collection system  334 , blower  336 , the N 2  dryer  230  and exhausted through a vent  394  in drum  214 . Once the N 2  conveying gas flow has been established at the correct rate, solids pumps  340  are started and pressurized solids are channeled to the conveying gas transport conduit  360 . The dilute phase flow of solids is direct through conduits  364 ,  366 ,  386 ,  388  and  390  to cyclone  386 . The cyclone  386  sends the solids back into the solids pump storage bin  338 , and the nitrogen passes through nitrogen return system to drum  214 . This off-line operation allows the gas and solids flows to be adjusted to their correct flow rates before introduction to the gasifier. 
     In the exemplary embodiment, a flow rate for the slag additive/char and fines slurry is also established. Referring again to  FIG. 4 , and in the exemplary embodiment, initially there is no recycle char and fines slurry available into which the particulate slag additive may be mixed. Rather, a startup mixture of slag additive is produced with fresh water in mix tank  406 . Slurry circulation pump  418  continuously circulates the startup slurry past the suction of the charge pump  420 , and charge pump  420  circulates pressurized slurry through conduit  428  back to the mix tank  406 . This circulation allows the correct flow rate for the additive slurry to be established off-line prior to startup of gasifier  134 . 
     Following the establishment and stabilization of flow rates for additive slurry, pneumatically-conveyed coal solids and oxygen, a block valve  426  on conduit  428  closes substantially concurrently with the opening of a block valve  430  on conduit  422 , and thus slurry is transferred to gasifier feed injector  348  instead of being recirculated back into mix tank  406 . In the exemplary embodiment, substantially concurrently therewith, block valve  394  on conduit  390  closes and a block valve  396  on conduit  380  substantially concurrently opens. N 2 -conveyed solids therein are transferred to the gasifier feed injector  348 . When oxygen is subsequently introduced to gasifier  134 , the thermal energy stored in the gasifier  134  initiates the reactions, and syngas generation begins. As syngas is channeled downstream from gasifier  134 , CO 2  recovery begins, and the CO 2  stream is compressed and recycled to the front end of the fuel feed system  110  via conduit  142  (as shown in  FIG. 1 ). As more CO 2  becomes available from gasifier  134  within conduit  142 , high pressure nitrogen is progressively replaced with recycled sour CO 2  as the high pressure conveying gas. The high pressure nitrogen then becomes available for use as a clean fuel gas diluent in the combustion turbine combustor  136 . However, until such a time as the full amount of high pressure nitrogen diluent becomes available at combustor  136 , water or steam may be used as a temporary, substitute diluent in the combustor. 
     Following startup, and in the exemplary embodiment, unconverted carbon, i.e. char, along with fine slag begins to accumulate in the gasification plant  114  char and fines handling section  156 . The char and fines are recovered in handling section  156  as a dilute slurry. The slurry is then channeled to the slag additive handling system  152 . As this slurry of char and fines becomes available for recycle to the feed system  110 , the fresh water makeup  424  to mix tank  406  is progressively replaced by this char and fines slurry until all of the char is being recycled to gasifier  134 . The final, total amount of water fed to gasifier  134  is controlled by adjusting the slurry concentration of the char and fines slurry and/or the amount of fresh water makeup added to mix tank  406 . If it is desired to add additional sour CO 2  gas to the gasifier following startup, this may be accomplished by opening block valve  397  on conduit  384 . 
     In an alternative embodiment, high pressure nitrogen from the air separation unit  112  may not be available for use as conveying gas during gasifier startup. In this embodiment, compressed natural gas  267  may be used instead of the high pressure nitrogen. Natural gas may be used as a backup fuel for combustion turbine  192  and sufficient quantities may be available for use as a high pressure conveying gas in place of the high pressure nitrogen. In this embodiment, coal is ground, dried and loaded into the main coal silo  240  and solids pump storage bin  338 . High pressure natural gas is then heated in heater  258  and channeled via conduits  144 ,  360 ,  362 ,  364 ,  366 ,  388 , and  398  to a plant flare (not shown). During startup, this allows the natural gas flow rate to be stabilized at the desired value. Gasifier  134  may then be started using natural gas without the use of any coal solids, since natural gas is a suitable fuel for the gasifier all by itself. Since natural gas has no ash for which a slag modifier is required, the gasifier can be started up on natural gas without having to start the slag additive system  152 . 
     In this embodiment, gasifier  134  is started on natural gas by substantially simultaneously closing block valve  399  in conduit  398  and opening block valve  396  in conduit  380 . Oxygen is then channeled into gasifier  134  through conduit  323 . Thermal energy stored in the gasifier refractory initiates the reactions, and syngas generation begins, as described in more detail herein. In this embodiment, gasifier  134  may operate with natural gas as the sole feed for any practical duration of time. 
     In this alternative embodiment, the introduction of solid particulate fuel begins by activating the solids pumps  340 . Coal particles from the discharge of pumps  340  drop into the solids pickup conduit  360  wherein the coal is entrained by the flow of natural gas to gasifier feed injector  348  via conduit  380 , as described in more detail herein. The addition of coal to the natural gas substantially increases the flow of fuel to gasifier  134 , and a flow rate of oxygen to the gasifier must be increased in order to provide an adequate amount of oxygen to gasify all of the carbon in the feed. The slag additive slurry must also be started up so that slag additive slurry can be fed to the gasifier by closing block valve  426  on conduit  428  and opening block valve  430  on conduit  422 . Gasifier  134  may run on this mixture of natural gas and coal for any practical duration of time. During operation, the natural gas and coal flow rates may not exceed the downstream demand for syngas. More specifically, gasifier  134  may be started up with a low flow rate of natural gas so that, when the coal particles are added, an amount of syngas is produced that satisfies the downstream process demand. Alternatively, if the gasifier operations have already been established at a higher than desirable rate for the transition to coal feed, the natural gas flow may be reduced, together with an appropriate modification of the oxygen flow rate, to allow the introduction of coal particles into the natural gas. As syngas production continues in the gasifier, CO 2  may be recovered from the syngas, compressed and routed to conveying gas heater  258  to progressively replace the natural gas. As the composition of the conveying gas transitions from 100% natural gas to 100% recycled sour CO 2 , the flow rate of solids into the solids pickup conduit  360  is increased to maintain substantially the same level of fuel energy flow into gasifier  134 . The flow rate of slag additive/recycle char and fines slurry is also increased to match the increasing flow rate of coal. Using natural gas during startup operations allows gasifier  134  to be started up using a clean, sulfur-free fuel, which is therefore advantageous for IGCC plants located in regions with process gas flaring restrictions. 
       FIG. 5  is a process flow diagram of an alternative solids recycle configuration for a gasifier startup system  500  used with pressurization and conveyance section  124  shown in  FIG. 3 . Specifically,  FIG. 5  illustrates a configuration that enables the use of a non-ventable carrier gas during an exemplary startup sequence, such as but not limited to a sour CO 2 -rich carrier gas. “Non-ventable carrier gas” as used herein is a gas that may be suitable for use as a carrier gas for the gasification process, but preferably used within only a limited portion of the feed system  110  because of, for example, the potential for equipment corrosion, potential undesirable mixing with or contamination of other gases used within and/or in communication with feed system  110 , and/or preferably not vented to atmosphere without first undergoing some form of treatment, such as, for example, contaminant removal or chemical conversion. 
     In the illustrated embodiment, solids pumps  340  discharge a flow of solid fuel particles via conduit  352  into a stream  362  of non-ventable carrier gas that creates a startup fuel that includes solid fuel particles in non-ventable carrier gas. Carrier gas is substantially prevented from leaking back through solids pumps  340  by controlling the flow rates of seal gas  354  so that the flow rates are equal to or greater than the gas leak rate through each respective solids feed pump  340 . The particle—gas mixture is channeled through a common startup line  502  and through a non-ventable carrier gas startup line  504 . In the illustrated embodiment, a pressure letdown orifice (PLO)  506  is positioned along line  504  that reduces the pressure generated by a non-ventable carrier gas compressor (not shown) and solids pump  340  so that downstream equipment, such as for example cyclone  520  and feed recycle and purge bin  522 , may not need to be designed to handle high pressure, while also ensuring that the flow of the particulate/gas mixture is minimally disturbed when the particulate/gas mixture is diverted to the gasifier injector  348  during startup. Alternatively, an adjustable pressure letdown device may be used in place of PLO  506 . Additionally, and in a further alternative embodiment, multiple pressure letdown devices may be coupled to one another in series in order to distribute the required pressure drop across several devices so that equipment wear may be substantially minimized, wherein the pressure letdown devices may be any type of pressure reducing interfaces that enable feed system  110  to be operated as described herein. 
     In the illustrated embodiment, a cyclone  520  is positioned upstream from a feed recycle and purge bin  522  and separates a substantial portion of the solids from the non-ventable carrier gas and channels the solids into the feed recycle and purge bin  522 . Moreover, finely ground coal within an overhead flow  524  from cyclone  520  is channeled through a secondary cyclone  526  that returns the coal fines back to feed recycle and purge bin  522  via a conduit  528 . Very fine particle removal is accomplished using a filtering device  530 , such as for example a barrier filter, that is positioned downstream of secondary cyclone  526 . Excess gas from secondary cyclone  526  is channeled to filter  530  via conduit  532  where, along with the other purges from the system, the combined gas is filtered to remove substantially all remaining coal dust. 
     During operations and in the exemplary embodiment, gas is periodically blown back to release accumulated solids material from filtering device  530 . The accumulated material is channeled through a rotating valve to meter the material, as well as delump any agglomerations that remain following release from filtering device  530 . The material is then channeled into the filter bottoms discharge line  536  and into the feed recycle and purge bin  522 . The particle free non-ventable gas leaving filtering device  530  is channeled via conduit  538  to a gas treatment system (not shown) to remove contaminates therefrom, and/or a flare (not shown) for disposal, or may be recycled to the sour CO 2 -rich gas storage drum (not shown) for recompression and reuse. In an alternative embodiment, any combination of particulate matter/gas separation and collection devices may be used that facilitate separating the particulate matter from the non-ventable gas as described herein, including subsequent collection of such particulate matter for recycle within the system or disposal. 
     In the illustrated embodiment, the separated solid particles in feed recycle and purge bin  522  may have residual non-ventable gas remaining in the particles and interstitial spaces between the particles. To further remove residual sour CO 2 -rich gas, a stream of N 2  stripping gas is channeled via conduit  540  into a bottom portion  542  of bin  522 . During operations, the stripping gas may both fluidize the solids in the bottom outlet of the bin to facilitate providing a flow rate of the solids through an exit of bin  522 , and facilitates purging the residual non-ventable carrier gas as the gas rises through bin  522 . A mixture of N 2  and residual non-ventable carrier gas exits a top portion  544  of feed recycle and purge bin  522  and is channeled, as needed, to a gas treatment unit and/or flare (both not shown) via conduit  545  for handling prior to discharge. Alternatively, conduit  545  may be joined in combination with conduit  538  upstream or downstream from the gas treatment system (not shown) and/or the flare. Solid fuel particles that are substantially free of residual non-ventable gas exit feed recycle and purge bin  522  are metered from bin  522  by a rotating valve  546 , or alternate metering device, into a flowing stream of low pressure N 2  conveying gas within conduit  548 . The low pressure N 2  conveying gas within conduit  548  transports the non-ventable gas-free separated solids back into the solids pump feed bin  338  via conduit  550  for reuse. A breather line  552  is also provided on the top of the solids pump feed bin to allow the LP N 2  transport gas to escape back into the LP N 2  cleanup system, as described in detail herein. During gasifier startup operations, the startup mixture is diverted from the non-ventable carrier gas startup line  504  to the gasifier feed injector  348 . In an alternate embodiment, the stripping gas is used to facilitate the purging of the residual non-ventable carrier gas from the solids, and the flow of solids out of bin  522  is facilitated by other techniques, such as but not limited to mechanical vibration. In another alternate embodiment, at least a portion of the stripping gas is mixed and purges the solids discharging from bin  522  via the metering device 
     In the exemplary configuration of a gasifier startup system  500  shown in  FIG. 5  and in an alternative embodiment, the transfer of solids from the feed recycle bin  522  may be configured to operate in a batch mode, whereby, for example, solids may be transferred from the feed recycle bin  522  to the solids pump feed bin  338  after the gasifier startup system  500  has been sufficiently depressurized. For example, feed recycle and purge bin  522  may be positioned directly above solids pump feed bin  338  in such a way as to allow solids passing through metering valve  546  to drop directly down into feed recycle and purge bin  522  after the recycle portion of the system has been sufficiently depressurized. In another alternative embodiment, pressurization and conveyance section  124  may be operated in a semi-batch mode by installing a lockhopper (not shown) between the feed recycle bin  522  and the solids pump feed bin  338 . In still another alternative embodiment, pressurization and conveyance section  124  may be configured to operate in a continuous mode by installing one or more pressure let down pumps (not shown) or the equivalent between the feed recycle bin  522  and the solids pump feed bin  338 . In another alternative embodiment, the solids may be conveyed from feed recycle bin  522  by any technique, such as but not limited to mechanical conveyance, such that feed system  110  functions as described herein. 
     The use of a feed system such as the one described above allows the use of a non-ventable carrier gas during gasifier startup because of the active separation that it creates between the non-ventable gas and the rest of the feed system. This active separation occurs at two places within the system, at the point where solids are added to the non-ventable gas at the fuel mixture assembly point and at the point where the solids are removed from the non-ventable gas at the fuel mixture disassembly point. The first location, the fuel mixture assembly point, is between the discharge of the solids pump and the mixing point where the startup fuel mixture is assembled by mixing solid particulate fuel with a flow of non-ventable carrier gas. A flow of seal gas introduced into this first location at a flow rate equal to or greater than the leak rate of gas back through the solids pump prevents the non-ventable gas from leaking backwards through the solids pump and entering the upstream part of the feed system. The second location, the fuel mixture disassembly point, is located on the startup conduit where the fuel mixture is disassembled during the period when a steady flow of the fuel mixture is being established just prior to startup. By separating the solids from the non-ventable gas, including stripping out all residual gas from among the particles, the non-ventable carrier gas is prevented from entering the upstream portion of the feed system along with the solid fuel particles that are returned to the solids feed bin for later reuse. 
       FIG. 6  is a process flow diagram of an alternative solids recycle configuration for a gasifier startup system  600  used with pressurization and conveyance section  124  shown in  FIG. 3 . In the illustrated embodiment, system  600  is substantially similar to system  500  shown in  FIG. 5 . However, feed recycle and purge bin  522 , shown in  FIG. 5 , is replaced with a sour CO 2  stripping column  602 . Solid fuel particles removed from the non-ventable carrier gas are channeled into stripping column  602  where the solid fuel particles encounter an upward moving flow of N 2  stripping gas. The N 2  stripping gas purges the residual non-ventable carrier gas as the stripping gas rises through column  602 . Because of the smaller size of column  602 , the flow of N 2  stripping gas passing through column  602  may be substantially less than the flow of N 2  stripping gas required to operate the feed recycle and purge bin  522 . A mixture of N 2  and residual carrier gas exits a top  604  of column  602  and is channeled, as needed, to a gas treatment unit and/or to a flare (both not shown) via a conduit  606  for handling prior to discharge. Solid fuel particles that are substantially free of residual non-ventable gas exit a bottom  608  of stripping column  602  where the solid fuel particles are metered through a rotating valve  610  and are channeled via conduit  612  into the solids pump feed bin  338 . During operations, this system provides solids separation and stripping equipment that is small enough to be installed above the solids pump feed bin  338 . Although stripping column  602  is shown as a featureless column, in the exemplary embodiment, stripping column  602  may be constructed with a plurality of downward sloping interior baffles to facilitate channeling the solids in a zigzag pattern as the particles descend through stripping tube, thus enhancing contact with the stripping gas, and facilitate further removal of non-ventable gas from the solid fuel particles. Alternatively, stripping column  602  may have any form of internal configuration and gas and solids distribution devices that facilitate such non-ventable gas removal. Further, although a rotating valve  610  is shown connected to the bottom of stripping column  602 , any device suitable for controlling a flowrate of particles via line  612  may be used herein. 
     Alternatively, the equipment in the exemplary configuration shown in  FIG. 6  can be configured to operate at high pressure, and pressure letdown orifice device  506  may be eliminated or adjusted to allow the equipment to operate at the desired higher pressure. In this alternative configuration, N 2  stripping column  602  operates as a pressurized column. A surge bin may be coupled to bottom  608  of column  602  such that solids may be stored at high pressure until controlled depressurization of the solids from the surge bin to the solids pump feed bin  338  may occur. As a further alternative, the surge bin may be replaced by a lock hopper or an adjustable pressure letdown device similar to  506  or any other suitable device or system whereby the solids from the bottom  608  of pressurized column  602  may be depressurized and conveyed in a controlled manner from column  602  to solids pump feed bin  338 . 
       FIG. 7  is a process flow diagram of an alternative solids recycle configuration for a gasifier startup system  700  used with pressurization and conveyance section  124  shown in  FIG. 3 . In the illustrated embodiment, system  700  is substantially similar to system  500  shown in  FIG. 5 . However, feed recycle and purge bin  522 , shown in  FIG. 5 , is replaced with a solids transport system  702 . In the illustrated embodiment, transport system  702  includes a feed recycle bin  704  coupled in flow communication with a solids pump feed vessel  706  that is positioned upstream from a plurality of solids pumps, similar to solids pump  340  shown in  FIG. 3  and described in more detail herein. In the illustrated embodiment, transport system includes a first solids pump  708  and a second solids pump  710 . 
     In the illustrated embodiment, solids that are separated from the startup carrier gas as described herein are channeled to feed recycle bin  704  via conduit  712 . Solids are channeled via conduit  714  to the solids pump feed vessel  706  and into a suction end  716  of solids pump  708  via conduit  718 . Solids pump  708  discharges the solid material into a suction end  720  of the solids pump  710  via conduit  722 , which delivers carrier gas-free particles to solids pump feed bin  322  via conduit  724 . 
     During operations, the removal of the residual non-ventable carrier gas from the interstitial spaces among the separated solid fuel particles is accomplished in solids pump  708 . A small flow  726  of seal N 2  is injected into conduit  722  and the seal N 2  moves upstream through the solids in pump  708 , and strips away substantially all of the residual non-ventable carrier gas and prevents any residual carrier gas from passing through the pump. Solids pump  710  is used to create a sealed, slightly pressurized space between the two pumps  708  and  710  into which the seal N 2  can be injected. Such a configuration forces N 2  upstream through pump  708  while producing stripped solids as the solids pass through solids pumps  708  and  710 . The seal N 2  that moves upstream through pump  708  passes up through the solids pump feed vessel  706  and feed recycle bin  704  and, along with the removed non-ventable gas, is channeled, as needed, to a gas treatment unit and/or to a flare (both not shown) via a conduit  728  for handling prior to discharge, as described in more detail herein. Such a configuration enables the flow requirement for stripping nitrogen to be significantly reduced when compared with the configurations shown in  FIGS. 5 and 6 . In an alternative embodiment, a purge gas may be injected and distributed into solids pump  708  and/or solids pump  710 . In a further alternative embodiment, nitrogen may be injected immediately upstream of solids pump  708 . In another alternative embodiment, one or more of solids pump  708  and solids pump  710  are high pressure solids pumps. In another alternative embodiment, a surge vessel may be coupled in flow communication between solids pump  708  and solids pump  710 . Alternatively, the transport system may include any number of solids pumps, such as for example a single solids pump  708 , that enables pressurization and conveyance section  124  to function as described herein. Alternatively, the seal nitrogen described herein may be any clean, inert gas that enables the fuel and gasification systems to function as described herein. 
     As shown in  FIGS. 5 ,  6  and  7  and described herein, the carrier gas used during startup operations is non-ventable gas, such as sour CO 2 -rich gas. However, such embodiments also may be used with other gases, such as but not limited to sweet CO 2 -rich gas. Such CO 2  rich gases may be recovered from the syngas produced in the gasifier. As described herein, the CO 2 -rich gas may be withdrawn from a number of different sources including, but not limited to: a storage vessel previously filled with a gas recovered from an earlier operation of the gasifier, an additional gasifier train operating in parallel with the gasifier train being started, an underground cavern and/or reservoir previously filled with gas recovered from an earlier operation of the gasifier, a pipeline connected to a suitable source of the gas, and a CO 2 -rich gas generator such as a combustion device capable of producing water-free CO 2 -rich gas, wherein such a combustion device may be coupled to a condenser and knockout system to remove undesirable quantities of water from the CO 2 -rich products of combustion. Alternatively, syngas may be used as the non-ventable carrier gas. 
     Described herein is a fuel feed system that may be utilized in IGCC plants that provides a cost-effective, highly efficient and reliable system for supplying coal to an IGCC plant by integrating coal grinding, moisture control and a solids pump upstream of a gasifier. In each embodiment, the fuel preparation system controls the moisture being channeled to the gasifier to a desired level that is between the moisture content in a dry feed system and the moisture content in a slurry feed system. More specifically, a pulverized PRB coal feed having a well-controlled internal moisture content may be tailored to optimize not only the gasifier performance, but also the performance of the overall system in which the gasifier plays a central role. Further, in each embodiment, the addition of the solids pump upstream of the gasifier facilitates pressurizing the coal from atmospheric pressure at the pump inlet to a pressure above the gasifier operating pressure in order to facilitate pneumatic conveyance of the coal into the gasifier. As a result, a continuous flow of pressurized coal is channeled to the gasifier. Moreover, an improved feed system is disclosed that provides an alternative to conventional dry feed systems for feeding low rank coals, such as sub bituminous coals and lignites, to a refractory-lined, entrained-flow gasifier for the production of syngas for power generation in an IGCC plant. As such, a simpler, more robust method of providing a feed system that is similar to slurry feed systems is disclosed that replaces the expensive lock hoppers, valves and compressors with an alternative method of pressurizing the solids used therein. Accordingly, the costs associated with maintaining a dry feed system and the inefficiencies associated with a slurry feed system are both avoided. 
     Exemplary embodiments of fuel feed systems are described above in detail. The fuel feed system components illustrated are not limited to the specific embodiments described herein, but rather, components of each system may be utilized independently and separately from other components described herein. For example, the fuel system components described above may also be used in combination with different fuel system components. 
     As used herein, an element or step recited in the singular and proceeded with the word “a” or “an” should be understood as not excluding plural elements or steps, unless such exclusion is explicitly recited. Furthermore, references to “one embodiment” of the present invention are not intended to be interpreted as excluding the existence of additional embodiments that also incorporate the recited features. 
     This written description uses examples to disclose the invention, including the best mode, and also to enable any person skilled in the art to practice the invention, including making and using any devices or systems and performing any incorporated methods. The patentable scope of the invention is defined by the claims, and may include other examples that occur to those skilled in the art. Such other examples are intended to be within the scope of the claims if they have structural elements that do not differ from the literal language of the claims, or if they include equivalent structural elements with insubstantial differences from the literal language of the claims.