Patent Publication Number: US-2009239960-A1

Title: Methods and systems for fischer tropsch reactor low product variation

Description:
BACKGROUND OF THE INVENTION 
     This invention relates generally to carbon to liquids systems, and more specifically to methods and systems for minimizing liquid product variation from a Fischer-Tropsch reactor portion of the system. 
     The terms C5+ and “liquid hydrocarbons” are used synonymously and refer to hydrocarbons or oxygenated compounds having five (5) or greater numbers of carbons, including for example pentane, hexane, heptane, pentanol, pentene, and which are liquid at normal atmospheric conditions. 
     The terms C4− and “gaseous hydrocarbons” are used synonymously and refer to hydrocarbons or oxygenated compounds having four (4) or fewer numbers of carbons, including for example methane, ethane, propane, butane, butanol, butene, propene, and which are gaseous at normal atmospheric conditions. 
     Modern Fischer-Tropsch (FT) units have been optimized for synthesis gas (syngas) production from natural gas, also known as Gas-to-Liquids process (GTL). Generally, syngas refers to a mixture of mainly H 2  and CO, plus some CO 2 , all at various proportions. The FT reactor is operated at relatively high residence times, high per pass conversion, and H 2 /CO ratios below the consumption ratio to improve C5+ selectivity and minimize C4− selectivity, i.e. natural gas and liquefied petroleum gas (LPG) production. The remote location of most carbon to liquids plants makes natural gas and (LPG) co-production economically unattractive, due to high transportation costs. 
     Minimizing natural gas and LPG production result in a significant fraction (30-40%) of the FT liquids being converted to wax. This wax must then be converted back to diesel range products (generally C10-C20 range) using a separate hydrocracking reactor. Also, the high per pass conversion that is used to maximize C5+ production limits the pressure of the FT reactor and byproduct water partial pressure increases with conversion and total pressure. Such high water partial pressure may cause deactivation of the catalyst by oxidizing the active catalyst sites, while low water partial pressure may cause competitive adsorption among water, CO and H 2  molecules on the catalyst active site thus reducing (CO+H 2 ) conversion. Iron-based FT catalysts, in particular, can be greatly affected by water, while cobalt-based FT catalysts tend to be more resistant to oxidation by water Generally, the water volume % in the reaction media should be under the range of 15-25%, beyond which the catalyst deactivation effect is known to be quite extensive. 
     Other carbonaceous fuels may also be used to provide the syngas input to the FT process. However, undesirable product variation is caused by the characteristics of modern FT gas to liquids systems described above. 
     BRIEF DESCRIPTION OF THE INVENTION 
     In one embodiment, a method for operating a carbon to liquids system includes receiving a flow of syngas, shifting the syngas to increase an H 2 /CO ratio of the syngas, mixing hydrogen with the shifted syngas to increase the H 2 /CO ratio, reacting the hydrogen/shifted syngas mixture with a catalyst in a vessel at a pressure of approximately 600 psia such that approximately 40% of the hydrogen/shifted syngas mixture is converted, and recycling an un-reacted hydrogen/shifted syngas mixture to the vessel. 
     In another embodiment, a carbon to liquids system includes a source of syngas, a vessel configured to shift the syngas to increase an H 2 /CO ratio of the syngas, the vessel coupled in flow communication downstream of the source of syngas, a source of gas including hydrogen coupled in flow communication with the shifted syngas, the source of gas configured to be mixed with the shifted syngas to increase the H 2 /CO ratio of the shifted syngas, a vessel including an inlet and an outlet, the inlet configured to receive the gas and shifted syngas mixture, the vessel including a catalyst configured to facilitate a Fischer-Tropsch synthesis reaction at a pressure of approximately 600 psia such that approximately 40% of the hydrogen/shifted syngas mixture is converted, and a recycle path communicatively coupled between the outlet and inlet configured to channel an un-reacted hydrogen/shifted syngas mixture to the vessel inlet. 
     In yet another embodiment, a system for generating liquid hydrocarbons from gaseous reactants includes a source of syngas including hydrogen and carbon monoxide in a ratio of between approximately 1.4 and approximately 1.8, a shift reactor configured to shift the syngas to increase an H 2 /CO ratio of the syngas, the vessel coupled in flow communication downstream of the source of syngas, a source of gas including hydrogen coupled in flow communication with the shifted syngas, the source of gas configured to be mixed with the shifted syngas to increase the H 2 /CO ratio of the shifted syngas to between approximately 1.9 to approximately 2.3, a vessel including an inlet and an outlet, the inlet configured to receive the gas and shifted syngas mixture, the vessel including a catalyst configured to facilitate a Fischer-Tropsch synthesis reaction at a pressure of approximately 600 psia such that approximately 40% of the hydrogen/shifted syngas mixture is converted, and a recycle path communicatively coupled between the outlet and inlet, the recycle path configured to channel an un-reacted hydrogen/shifted syngas mixture to the vessel inlet. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  is a schematic diagram of an exemplary known integrated gasification combined-cycle (IGCC) power generation system; and 
         FIG. 2  is a schematic diagram of a portion of an exemplary coal to liquids processing system in accordance with an embodiment of the present invention. 
     
    
    
     DETAILED DESCRIPTION OF THE INVENTION 
       FIG. 1  is a schematic diagram of an exemplary known integrated gasification combined-cycle (IGCC) power generation system  50 . IGCC system  50  generally includes a main air compressor  52 , an air separation unit  54  coupled in flow communication to compressor  52 , a gasifier  56  coupled in flow communication to air separation unit  54 , a gas turbine engine  10 , coupled in flow communication to gasifier  56 , and a steam turbine  58 . In operation, compressor  52  compresses ambient air. The compressed air is channeled to air separation unit  54 . In some embodiments, in addition or alternative to compressor  52 , compressed air from gas turbine engine compressor  12  is supplied to air separation unit  54 . Air separation unit  54  uses the compressed air to generate oxygen for use by gasifier  56 . More specifically, air separation unit  54  separates the compressed air into separate flows of oxygen and a gas by-product, sometimes referred to as a “process gas”. The process gas generated by air separation unit  54  includes nitrogen and will be referred to herein as “nitrogen process gas” (NPG). The nitrogen process gas may also include other gases such as, but not limited to, oxygen and/or argon. For example, in some embodiments, the nitrogen process gas includes between about 95% and about 100% nitrogen. The oxygen flow is channeled to gasifier  56  for use in generating partially combusted gases, referred to herein as “syngas” for use by gas turbine engine  10  as fuel, as described below in more detail. In some known IGCC systems  50 , at least some of the nitrogen process gas flow, a by-product of air separation unit  54 , is vented to the atmosphere. Moreover, in some known IGCC systems  50 , some of the nitrogen process gas flow is injected into a combustion zone (not shown) within gas turbine engine combustor  14  to facilitate controlling emissions of engine  10 , and more specifically to facilitate reducing the combustion temperature and reducing nitrous oxide emissions from engine  10 . IGCC system  50  may include a compressor  60  for compressing the nitrogen process gas flow before being injected into the combustion zone. 
     Gasifier  56  converts a mixture of fuel, a carbonaceous substance, the oxygen supplied by air separation unit  54 , steam, and/or limestone into an output of syngas for use by gas turbine engine  10  as fuel. Although gasifier  56  may use any fuel, in some known IGCC systems  50 , gasifier  56  uses coal, petroleum coke, residual oil, oil emulsions, tar sands, and/or other similar fuels. In some known IGCC systems  50 , the syngas generated by gasifier  56  includes carbon dioxide. The syngas generated by gasifier  56  may be cleaned in a clean-up device  62  before being channeled to gas turbine engine combustor  14  for combustion thereof or may be channeled to other systems for further processing, for example, to a Fischer-Tropsch synthesis reaction system for conversion to liquid hydrocarbons. Alternatively, a portion of the cleaned syngas after clean-up device  62 , may be channeled to gas turbine engine combustor  14 , while another portion may be channeled to a Fischer-Tropsch synthesis reaction system for conversion to liquid hydrocarbons. The portion ratio is dependant on the particular application. Carbon dioxide may be separated from the syngas during clean-up and, in some known IGCC systems  50 , vented to the atmosphere, recycled to injection nozzle  70  of gasifier  56  (not shown), compressed and sequestered for geological storage (not shown), and/or processed to industrial use gases (not shown). The power output from gas turbine engine  10  drives a generator  64  that supplies electrical power to a power grid (not shown). Exhaust gas from gas turbine engine  10  is supplied to a heat recovery steam generator  66  that generates steam for driving steam turbine  58 . Power generated by steam turbine  58  drives an electrical generator  68  that provides electrical power to the power grid. In some known IGCC systems  50 , steam from heat recovery steam generator  66  is supplied to gasifier  56  for generating the syngas. 
     In the exemplary embodiment, gasifier  56  includes an injection nozzle  70  extending through gasifier  56 . Injection nozzle  70  includes a nozzle tip  72  at a distal end  74  of injection nozzle  70 . Injection nozzle  70  further includes a port (not shown in  FIG. 1 ) that is configured to direct a stream of fluid proximate nozzle tip  72  such that the stream of fluid facilitates reducing a temperature of at least a portion of nozzle tip  72 . In the exemplary embodiment, injection nozzle  70  is configured to direct a stream of ammonia proximate nozzle tip  72  such that the stream of ammonia facilitates reducing a temperature of at least a portion of nozzle tip  72 . 
     In the exemplary embodiment, IGCC system  50  includes a syngas condensate stripper configured to receive condensate from a stream of syngas discharged from gasifier  56 . The condensate typically includes a quantity of ammonia dissolved in the condensate. At least a portion of the dissolved ammonia is formed in gasifier  56  from a combination nitrogen gas and hydrogen in gasifier  56 . To remove the dissolved ammonia from the condensate the condensate is raised to a temperature sufficient to induce boiling in the condensate. The stripped ammonia is discharged from stripper  76  and returned to gasifier  56  at a pressure higher than that of the gasifier, to be decomposed in the relatively high temperature region of the gasifier proximate nozzle tip  72 . 
       FIG. 2  is a schematic diagram of a portion of an exemplary coal to liquids processing system  200  in accordance with an embodiment of the present invention. Known commercial GTL reactors are generally operated at H 2 /CO ratios of approximately 1.6 to optimize the C5+ selectivity. The kinetics of the FT reaction is improved at higher H 2 /CO ratios. In the exemplary embodiment, using an H 2 /CO ratio of 2.1 (FT consumption ratio), approximately one third less catalyst and reaction volume are used compared to an H 2 /CO ratio of 1.6. 
     A flow of syngas  202  from a gasification process such as but, not limited to a coal gasification process, is prepared to an H 2 /CO ratio of approximately 1.85 by shifting at least a portion of the syngas in a shift reactor  204  and removing essentially all of the CO 2 , H 2 S, and COS using, for example, a solvent and absorbent based system  206 . The CO 2 , H 2 S, and COS removed streams in system  206  are not shown. Recycle hydrogen from a flow of tail gas  208  increases an H 2 /CO ratio of a flow of feed gas  210  to approximately 2.10. 
     The flow of feed gas  210  is mixed with a flow of recycle gas  212  and a flow of mixed feed gas  214  is channeled to the bottom of a Fischer-Tropsch synthesis reactor  216 . In the exemplary embodiment, Fischer-Tropsch (FT) synthesis reactor  216  comprises a slurry bubble column reactor (SBCR) type. Approximately 40% of the CO and hydrogen are converted into FT distillates and water in vapor form and FT wax in liquid form in SBCR  216 . 
     The Fischer-Tropsch reaction for converting syngas, which is composed primarily of carbon monoxide (CO) and hydrogen gas (H 2 ), is characterized by the two following general reactions, which produce paraffinic hydrocarbons (reaction 1) and olefinic hydrocarbons (reaction 2): 
       (2 n+ 1)H 2   +n CO→C n H 2n+2   +n H 2 O  (1) 
       2 n H 2   +n CO→C n H 2n   +n H 2 O  (2) 
     Mixed feed gas  214  is fed to the bottom of SBCR  216  and distributed into a slurry  218  comprising liquid wax and catalyst particles. As the gas bubbles upwards through slurry  218 , it is diffused and converted into more wax by the FT reaction, which is exothermic. The heat generated by the FT reaction is removed through cooling coils (not shown) where steam is generated for use elsewhere in system  200 . SBCR  216  operates at a relatively high pressure of approximately 600 psia, but with a low per pass conversion of approximately 40% such that the water partial pressure is low enough to substantially reduce oxidizing and deactivating the catalyst. Generally, the water partial pressure in the mixture should be such that volume % content is less than 15-25%, depending on catalyst type. 
     A flow of FT distillates and water vapor  220  are condensed in a pump around condenser  222 . A chimney tray  224  positioned internally to condenser  222  collects the condensed water and FT distillate and includes baffles (not shown) to provide gravity separation of the FT distillate from the water phases. 
     A flow of hot condensed water  226  from the baffles is channeled to a stripper  228  for separation of oxygenates and other organics. A flow of hot FT distillate  230  is channeled to a distillate stripper  232  for removal of dissolved gases, water, and lighter hydrocarbons. A flow of the dissolved gases, water, and lighter hydrocarbons  234  is condensed in a condenser  236  and a flow of remaining vapor  238  is compressed in a compressor  240  and combined with a FT tail gas stream  242  and a flow of the mixture  244  is channeled to a gas separation system  246 . Recycled rich-hydrogen stream  208  from gas separation system  246  is channeled to feed gas  210 . 
     A flow of stripped distillate  248  and a flow of hydrocarbon condensate  250  are channeled to an atmospheric distillation column  252  for fractionation to a flow of finished products  254  in an atmospheric distillation column. 
     A flow of condensed water  256  is routed to a stripper  258 . A flow of syngas and hydrocarbon vapor from a water condensing section (not shown) of stripper  258  is contacted with a cooled high boiling product stream (lean oil)  260 . Lean oil  260  absorbs any remaining light naphtha fraction in the FT reactor product gas and cools the gas stream. A flow of naphtha  262  is then routed to the FT distillate stripper  232  and atmospheric distillation column  252  for lean oil recovery and recycle. A majority of gas  212  from the lean oil absorber section is recycled back to the syngas feed line  210  and the remainder is removed as tail gas  242 . 
     Alternatively, all or a portion of the naphta stream  262  is pumped to near 600 psia and routed to catalyst recovery system  268 . Under these conditions, naphta (C5-C8 paraffinic hydrocarbons) becomes a supercritical solvent and will enhance solubility and removal of heavy waxes filling the pores of the catalyst particles, thus providing more efficient catalyst recovery. This will enable higher probability of chain growth since it will promote the reappearance of vacant sites on the catalyst surface, thereby providing accessibility for the re-adsorption of olefins and subsequent chain growth towards the desired C5+ selectivity range. 
     Accordingly, in operation a bubble column reaction section  264  of Fischer-Tropsch synthesis reactor  216  includes a reduced liquid height requirement and pump around condenser  222  has a relatively low pressure drop permitting a relatively high recycle gas flow rate and relatively high overall conversion of approximately eighty-five percent while maintaining a relatively low power requirement for recycle compressor  240 . In the exemplary embodiment, the low per pass conversion and high recycle rate enables a lower height of reactor  216 , which provides a more uniform top to bottom gas composition, a more uniform flow distribution with less channeling, a more uniform catalyst distribution, and a more uniform temperature profile across reactor  216 . 
     More uniform FT reactor  216  conditions facilitate reducing FT product variation from the desired kero and diesel range (C10 to C20). Wax production is minimized allowing a small base lube oil hydrocracker (pipe reactor) to be added to a return wax stream  266  from an FT catalyst recovery system  268 , where waxy products that accumulate in the catalyst pores are separated. Return wax stream  266 , including un-reacted hydrogen and light hydrocarbons, is channeled to FT distillate stripper  232  and atmospheric distillation column  252 . FT distillate stripper  232  separates out the light components (H 2 , C1-C4), which are combined with FT tail gas stream  242  and routed to gas separation system  246 . The heavier components are fractionated to finished products stream  254  (including lube oil base stock) in atmospheric distillation column  252 . 
     Exemplary embodiments of carbon to liquids systems and methods of minimizing liquid product variation from the Fischer-Tropsch reactor are described above in detail. The carbon to liquids 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 carbon to liquids system components described above may also be used in combination with different carbon to liquids system components. 
     The above-described carbon to liquids systems and methods are cost-effective and highly reliable. The method permits a reduced of variation of FT liquids product boiling point and carbon number and facilitates minimizing wax production. The method also provides improved diesel selectivity over naphtha due to higher operating pressure, a relatively high catalyst activity due to low water vapor concentration and substantially eliminates a need for external knockout and water separation drums. The carbon to liquids system provides a reduced FT reactor height and catalyst volume, a reduced FT liquids product boiling point (carbon number) variation, a significantly reduced wax production, which permits wax removal to be integrated into the catalyst regeneration system thereby eliminating a separate hydrocracker upgrading unit. Accordingly, the systems and methods described herein facilitate the operation of carbon to liquids systems in a cost-effective and reliable manner. 
     While the invention has been described in terms of various specific embodiments, those skilled in the art will recognize that the invention can be practiced with modification within the spirit and scope of the claims.