Patent Publication Number: US-11655421-B2

Title: Method and system for synthesizing fuel from dilute carbon dioxide source

Description:
FIELD 
     This disclosure relates generally to a method and a system for synthesizing a fuel from a dilute carbon dioxide (CO 2 ) source. 
     BACKGROUND 
     Global incentive for reducing CO 2  emissions is gaining momentum. However, emissions reductions in the transportation sector have been acknowledged as being particularly challenging and costly. The vast majority of vehicles, including automobiles, ships, aircraft, and trains, combust high energy density hydrocarbon fuels, and roughly $50 trillion of infrastructure exists globally to produce, distribute, and consume these fuels. 
     Direct synthesis of liquid hydrocarbon fuels presents a promising approach for reducing CO 2  emissions. Also known as “fuel synthesis”, “synfuels”, or “solar fuels”, known fuel synthesis methods involve reacting a source of carbon (such as CO 2 ) with a source of hydrogen to form hydrocarbon molecules. It is an objective of this disclosure to provide a novel method and system for synthesizing fuel from a dilute CO 2  source. 
     SUMMARY 
     According to one aspect of the disclosure, there is provided a method for producing a synthetic fuel from hydrogen and carbon dioxide. The method comprises: extracting hydrogen molecules from hydrogen feedstock to produce a hydrogen containing feed stream; extracting carbon dioxide molecules from a dilute gaseous mixture in a carbon dioxide feedstock to produce a carbon dioxide containing feed stream; 
     and processing the hydrogen and carbon dioxide containing feed streams to produce a synthetic fuel. In some aspects, at least some material used in at least one of the foregoing steps is obtained from material produced in another one of the steps. Alternatively or additionally, at least some energy used for at least one of the steps can be obtained from energy produced by another one of the steps. 
     In the steps of extracting hydrogen molecules and extracting carbon dioxide, the hydrogen feedstock can be water and the dilute gaseous mixture can be air, respectively. 
     In another aspect of the disclosure, the produced material can include water produced during the step of extracting carbon dioxide molecules or the step of processing the hydrogen and carbon dioxide containing feed streams, and at least some of the water is used for at least some of the hydrogen feedstock. The produced water may be steam. In particular, the step of extracting carbon dioxide molecules can comprise: contacting the dilute gaseous mixture with a carbon dioxide capture solution; precipitating at least some of the captured carbon dioxide into CaCO 3  solids; calcining the CaCO 3  solids to produce a calciner product gas stream, and extracting water from the calciner product gas stream to produce at least some of the produced water. Further, the step of processing the hydrogen and carbon dioxide containing feed streams can comprise combining and heating the hydrogen and carbon dioxide containing feed streams, producing a syngas stream, and extracting water from the syngas stream to produce at least some of the produced water. The step of extracting carbon dioxide molecules can also comprise feeding at least a portion of the calciner product gas stream to a solid oxide electrolyzer cell used in the step of extracting hydrogen molecules. 
     The step of extracting carbon dioxide molecules can also comprise using a slaker, wherein the produced material can include water produced during the step of processing the hydrogen and carbon dioxide containing feed streams and at least some of the water produced is used by the slaker. 
     In another aspect of the disclosure, the produced material can include oxygen molecules produced during the step of extracting hydrogen molecules, and the method can further comprise combusting a fuel using at least a portion of the produced oxygen molecules during at least one of the steps of extracting carbon dioxide molecules and processing the hydrogen and carbon dioxide containing feed streams. 
     In a further aspect of the disclosure, the combustion of at least a portion of the produced oxygen molecules and the fuel can produce heat for producing a calciner product gas stream during the step of extracting carbon dioxide molecules. Alternatively or additionally, the heat can be used for producing a syngas stream during the step of processing the hydrogen and carbon dioxide containing feed streams. 
     In yet another aspect of the disclosure, the method can further comprise regenerating a carbon dioxide rich aqueous capture solution during the step of extracting carbon dioxide molecules using at least a portion of the produced oxygen molecules and a fuel. The fuel can be a produced fuel. 
     The produced material can include a fuel produced during the step of processing the hydrogen and carbon dioxide containing feed stream, and the method can further comprise combusting at least a portion of the produced fuel during at least one of the steps of extracting carbon dioxide molecules and processing the hydrogen and carbon dioxide containing feed streams. 
     In another aspect of the disclosure, at least some energy for performing the steps of extracting hydrogen molecules, extracting carbon dioxide molecules, and processing the hydrogen and carbon dioxide containing feed streams can be provided by an electricity source. 
     In a further aspect of the disclosure, the step of extracting carbon dioxide molecules can comprise operating a calciner to produce the carbon dioxide containing feed stream, and wherein the step of processing the hydrogen and carbon dioxide containing feed streams comprises operating a syngas generation reactor (SGR) unit at a pressure selected to enable the SGR unit to receive the carbon dioxide containing feed stream from the calciner without being substantially cooled and compressed between the calciner and the SGR unit. The SGR unit can be operated at a pressure of between 1 and 10 bar and the received carbon dioxide containing feed stream may have a temperature of between 850-900° C. 
     In yet another aspect of the disclosure, the method can further comprise feeding the carbon dioxide containing feed stream and one or more reactant feed streams into the SGR unit. The one or more reactant feed streams can comprise at least one of a hydrogen reactant feed stream, a CH 4  reactant feed stream, a water reactant feed stream, or a Fischer Tropsch light end hydrocarbon reactant feed stream. 
     The SGR unit can be operated to produce a syngas product stream by one or more of a reverse water gas shift (RWGS) reaction, a steam methane reforming (SMR) reaction, and a direct methane reforming (DMR) reaction. 
     In another aspect of the disclosure, the syngas product stream can be treated to produce one or more recycle streams that provide reactant to the SGR unit. At least one or more of the recycle streams and the reactant feed streams can be electrically heated. 
     In yet another aspect of the disclosure, the method can further comprise heating the SGR unit with thermal energy produced by electricity. Alternatively, the SGR unit can be heated with thermal energy produced by combusting an oxidant and a fuel comprising at least one of hydrogen from the hydrogen-containing feed stream, natural gas, or a Fisher Tropsch light end hydrocarbon. 
     The step of extracting carbon dioxide molecules can comprise heating the calciner with thermal energy produced by combusting an oxidant and a fuel comprising at least one of hydrogen from the hydrogen-containing stream, natural gas, or Fischer Tropsch light end hydrocarbons. 
     In another aspect of the disclosure, the step of extracting hydrogen molecules can further comprise producing an oxygen containing stream, at least some of which is used as the oxidant by one or both of the SGR unit and the calciner. 
     In yet another aspect of the disclosure, a CaCO 3  material stream can be heated and used in extracting carbon dioxide molecules with thermal energy from a syngas product stream from the SGR unit. The CaCO 3  material stream can be directly contacted with the syngas product stream and operating the SGR in a RWGS mode, with one or more of an SMR mode, a DMR mode or a combination thereof. 
     In another aspect of the disclosure, the method can further comprise heating the calciner with thermal energy produced by electricity. 
     The step of extracting carbon dioxide molecules can further comprise calcining CaCO 3  material in a fluidized bed reactor vessel of the calciner, and discharging a hot CaO solids stream from the calciner. The CaCO 3  material can be pre-heated prior to entry into the calciner with thermal energy from a calciner product gas stream. In another aspect of the disclosure, the method can comprise extracting water from the calciner product gas stream, boiling the extracted water to produce steam, then fluidizing the fluidized bed reactor vessel with the steam. 
     The step of processing the hydrogen and carbon dioxide containing feed streams can comprise operating an SGR unit, and the method can further comprise preheating one or more SGR reactant feed streams before feeding to the SGR unit, with thermal energy from a syngas product stream discharged from the SGR unit. The SGR reactant feed streams can comprise at least one of a carbon dioxide reactant feed stream, a hydrogen reactant feed stream, a CH 4  reactant feed stream, a water reactant feed stream, or a Fischer Tropsch light end hydrocarbon reactant feed stream, wherein the carbon dioxide reactant feed stream includes at least some of the carbon dioxide feed stream, and the hydrogen reactant feed stream comprises at least some of the hydrogen containing feed stream. 
     In a further aspect of the disclosure, the method can comprise combusting an oxidant and a fuel in an SGR burner of the SGR unit and producing a hot burner exhaust stream, then heating at least one of an oxidant feed stream of the SGR burner and a water reactant feed stream to the SGR unit, using thermal energy from the hot burner exhaust stream. 
     In another aspect of the disclosure, at least a portion of the energy used for extracting the hydrogen molecules, extracting the carbon dioxide molecules, and processing the hydrogen and carbon dioxide containing feed streams is electricity supplied by an external energy source. 
     In yet another aspect of the disclosure, at least some energy is thermal energy used in at least one of the steps of extracting hydrogen molecules, extracting carbon dioxide molecules, and processing the hydrogen and carbon dioxide containing feed streams. 
     At least some of the thermal energy used in processing the hydrogen and carbon dioxide containing feed streams can be produced during a calcination operation in extracting carbon dioxide molecules, and the produced thermal energy can be transferred by the carbon dioxide containing feed stream. 
     In a further aspect of the disclosure, oxygen molecules can be produced during the step of extracting hydrogen molecules, and the method can further comprise heating the oxygen molecules by the thermal energy produced during the step of extracting carbon dioxide molecules. 
     In the step of extracting carbon dioxide molecules, the heated oxygen molecules and a fuel can be combusted in a combustion operation. The combustion operation can provide heat to a calciner, and some thermal energy from calcium oxide material produced in the calciner can be used to heat the oxygen molecules. 
     In another aspect of the disclosure, the method further comprises distilling and refining the synthetic fuel, and at least some of the thermal energy produced during the step of extracting carbon dioxide molecules can be used during the distilling and refining of the synthetic fuel or used to generate power. 
     In yet another aspect of the disclosure, the hydrogen feedstock can comprise water, and the method can further comprise heating at least a portion of the water using at least a portion of the thermal energy produced during the step of extracting carbon dioxide molecules. At least some of the heated water can be produced during the step of extracting carbon dioxide molecules. 
     The method can further comprise heating a material stream produced during the step of extracting carbon dioxide molecules using at least some of the thermal energy produced during the step of processing the hydrogen and carbon dioxide containing feed streams. 
     In another aspect of the disclosure, the method can further comprise preheating a material stream flowing into an SGR unit during the step of processing the hydrogen and carbon dioxide containing feed streams, and using thermal energy produced by the SGR unit. 
     In another aspect of the disclosure, the method further comprises regenerating a sorbent used during the step of extracting carbon dioxide molecules using thermal energy produced during the step of processing the hydrogen and carbon dioxide containing feed streams. 
     According to an aspect of the disclosure, a system is provided for producing a synthetic fuel from hydrogen and carbon dioxide, comprising: a hydrogen production subsystem configured to extract hydrogen molecules from hydrogen compounds in a hydrogen feedstock to produce a hydrogen containing feed stream; a carbon dioxide capture subsystem configured to extract carbon dioxide molecules from a dilute gaseous mixture in a carbon dioxide feedstock to produce a carbon dioxide containing feed stream; and a synthetic fuel production subsystem configured to process the hydrogen and carbon dioxide containing feed streams to produce a synthetic fuel. In some aspects, at least one of the subsystems is physically coupled to at least another one of the subsystems by a material transfer coupling for transferring at least some material produced in one subsystem to at least another one of the subsystems for use therein. 
     Alternatively or additionally, at least one of the subsystems can be thermally coupled to at least another one of the subsystems, such that at least some of the thermal energy produced by one subsystem is transferrable to at least another one of the subsystems. 
     The hydrogen feedstock can be water, the hydrogen production subsystem can comprise an electrolyzer, and the material transfer coupling can comprise an oxidant conduit fluidly coupling the electrolyzer with the carbon dioxide capture subsystem or the synthetic fuel production subsystem, such that oxygen molecules produced by the electrolyzer is transferable via the oxidant conduit to the carbon dioxide capture subsystem or the synthetic fuel production subsystem for use in a combustion operation. 
     The carbon dioxide capture subsystem can comprise a calciner heater coupled to the oxidant conduit such that at least some of the oxygen molecules are used in a combustion operation in the calciner heater. The synthetic fuel production subsystem can comprise an SGR heater fluidly coupled to the oxidant conduit such that at least some of the oxygen molecules are used in a combustion operation in the SGR heater. 
     In another aspect of the disclosure, the material transfer coupling can comprise a first water conduit and the synthetic fuel production subsystem can comprise an SGR unit fluidly coupled to the hydrogen production subsystem via the first water conduit such that water produced by the SGR unit is transferable to the hydrogen production subsystem as hydrogen feedstock. 
     In a further aspect of the disclosure, the material transfer coupling can comprise a second water conduit, the carbon dioxide capture subsystem may comprise a slaker, and the synthetic fuel production subsystem may comprise an SGR unit. The SGR unit can be fluidly coupled to the slaker via the second water conduit such that water produced by the SGR unit is transferable to the slaker. 
     In yet another aspect of the disclosure, the material transfer coupling can comprise a third water conduit and the carbon dioxide capture subsystem comprises a slaker fluidly coupled to the hydrogen production subsystem by the third water conduit such that water output by the slaker is transferable to the hydrogen production subsystem as hydrogen feedstock. 
     In another aspect of the disclosure, the material transfer coupling can comprise a fourth water conduit, the calciner can be fluidly coupled to a high temperature solids removal unit by a calciner product conduit, and the high temperature solids removal unit can be fluidly coupled to the hydrogen production subsystem by the fourth water conduit, such that water produced by the calciner is transferable to the hydrogen production subsystem. 
     In a further aspect of the disclosure, the material transfer coupling can comprise a first fuel conduit, and the carbon dioxide capture subsystem can comprise a calciner fluidly coupled to the synthetic fuel production subsystem by the first fuel conduit such that at least some of the synthetic fuel produced by the synthetic fuel production subsystem is transferable to the calciner for a combustion operation. 
     The high temperature solids removal unit can comprise a water removal membrane in fluid communication with the calciner product conduit and the fourth water conduit, such that water is extracted from a calciner product stream contacting the water removal membrane, the extracted water is directed into the fourth water conduit, and at least some carbon dioxide in the remaining calciner product stream is directed to a syngas generation reactor of the synthetic fuel production subsystem. 
     In yet another aspect of the disclosure, the material transfer coupling can comprise a product conduit, the calciner can be coupled to a high temperature solids removal unit by a calciner product conduit, and the high temperature solids removal unit can be coupled to the hydrogen production subsystem by the product conduit, such that product gases produced by the calciner are transferable to the hydrogen production subsystem. 
     In another aspect of the disclosure, the carbon dioxide capture subsystem can comprise an air contactor and a solution processing unit in fluid communication with the air contactor by a CO 2  aqueous capture solution. The CO 2  aqueous capture solution can be thermally coupled to the synthetic fuel production subsystem such that heat is transferable from the synthetic fuel production subsystem into the CO 2  aqueous capture solution. The carbon dioxide capture system can further comprise a regeneration unit for regenerating a sorbent, and the material transfer conduit can comprise a second fuel conduit that fluidly couples the regeneration unit to a fuel output of the synthetic fuel production subsystem such that at least a portion of the fuel produced by the synthetic fuel production subsystem is transferable to the regeneration unit for a combustion operation. The material transfer conduit can comprise an oxidant conduit that fluidly couples the hydrogen generation subsystem to the regeneration unit such that at least a portion of oxygen molecules produced by the hydrogen generation subsystem is transferable to the regeneration unit for a combustion operation. The synthetic fuel production subsystem can comprise at least one of an SGR unit or a Fischer Tropsch unit fluidly coupled to the regeneration unit such that water produced by at least one of the SGR unit or the Fischer Tropsch unit is transferable to the regeneration unit. 
     According to another aspect of the disclosure, the hydrogen production subsystem can comprise an electrolyzer, the synthetic fuel production subsystem can comprise an SGR unit, and the carbon dioxide capture subsystem can comprise a calciner, and wherein at least one of the electrolyzer, SGR unit, or calciner are electrically driven or heated. The SGR unit can have an operating pressure selected to enable the SGR unit to receive the carbon dioxide containing feed stream without being substantially cooled and compressed between the calciner and the SGR unit. The SGR unit can have an operating pressure of between 1 and 10 bar and the received carbon dioxide containing feed stream can have a temperature of between 850-900° C. The SGR unit can comprise one or more reactant inlets fluidly coupled to one or more reactant feed streams comprising at least one of a carbon dioxide reactant feed stream, a hydrogen reactant feed stream, a CH 4  reactant feed stream, a water reactant feed stream, or a Fischer Tropsch light end hydrocarbon reactant feed stream. 
     The carbon dioxide reactant feed stream can comprise at least some of the produced carbon dioxide containing feed stream. 
     In another aspect of the disclosure, the synthetic fuel production subsystem can further comprise a syngas treatment unit that receives a syngas product stream from the SGR unit and outputs one or more recycle streams, wherein the recycle streams comprise at least one of water, hydrogen, or carbon dioxide for use by the SGR unit. The system can further comprise at least one electric heater thermally coupled to one or more of the recycle streams and the reactant feed streams. The electric heater can comprise of at least one of an inline electric heater, electrical heating tape, resistance heating wire, coils or elements. 
     According to another aspect of the disclosure, the SGR unit can be thermally coupled to an electrical heat source comprising an electrical heater. Alternatively, the SGR unit can comprise an SGR burner and an SGR vessel thermally coupled to the SGR burner, wherein the SGR burner comprises a fuel inlet coupled to the hydrogen containing feed stream to receive hydrogen as fuel for combustion. The SGR burner can produce a hot burner exhaust stream that is thermally coupled to at least one of a heat exchanger for heating an oxidant feed stream of the SGR burner and a boiler for heating a water feed stream to the SGR vessel. 
     In another aspect of the disclosure, the calciner can comprise a calciner burner and a calciner reactor vessel thermally coupled to the calciner burner, wherein the calciner burner comprises a fuel inlet coupled to the hydrogen containing feed stream to receive hydrogen as fuel for combustion. 
     In a further aspect of the disclosure, one or both of the fuel inlets of the SGR burner and the calciner burner can be fluidly coupled to one or more of a natural gas stream and a Fischer Tropsch light end hydrocarbon stream. In yet another aspect of the disclosure, the hydrogen production subsystem can comprise an electrolyzer which produces the hydrogen containing feed stream and an oxygen containing stream from the hydrogen feedstock, and wherein the oxygen containing stream can be fluidly coupled to one or both of the SGR burner and the calciner burner to provide at least some of the oxidant for the combustion. 
     In a further aspect of the disclosure, the carbon dioxide capture subsystem can comprise a calciner, wherein the calciner comprises a fluidized bed reactor vessel. The calciner can comprise a kiln reactor vessel and an electric heating element or a burner thermally coupled to the kiln reactor vessel. 
     In yet another aspect of the disclosure, the synthetic fuel production subsystem can comprise an SGR unit and a heat exchanger thermally coupled to a syngas product stream from the SGR unit and to a CaCO 3  material stream from the carbon dioxide capture subsystem, such that thermal energy is transferrable from the syngas product stream to the CaCO 3  material stream. The heat exchanger can comprise at least one of a bubbling fluidized bed (BFB) heat exchanger or a cyclone heat exchanger. The BFB or cyclone heat exchanger can comprise a refractory or ceramic lined vessel inside which the CaCO 3  material stream and syngas product stream are in direct contact. The SGR unit can be configured to operate in a RWGS mode, with one or more of an SMR mode, a DMR mode or a combination thereof. 
     In another aspect of the disclosure, the carbon dioxide capture subsystem can comprise a calciner, and the calciner can be thermally coupled to an electric heat source. The calciner can comprise a fluidized bed reactor vessel with a solids feed inlet for receiving CaCO 3  material, a fluidizing stream inlet for receiving a calciner fluidizing fluid comprising steam, a product gas stream outlet for discharging a calciner product gas stream, and a solids product outlet for discharging a produced CaO solids stream. The calciner can further comprise an electric heating element thermally coupled to the reactor vessel for heating the fluidizing stream and CaCO 3  material therein. The electric heating element can be encased in a metal sheath extending into a bubbling bed zone of the reactor vessel, or can be thermally coupled to a refractory lined wall of the reactor vessel. 
     In another aspect of the disclosure, the system can further comprise: a water knockout and solids removal unit; a compressor; and a boiler unit. The water knockout and solids removal unit can have an inlet fluidly coupled to the calciner product gas stream, a water outlet for discharging water removed from the product gas stream, a dust outlet for discharging dust removed from the product gas stream, and a CO 2  outlet for discharging a CO 2  product stream. The compressor can have an inlet for receiving the CO 2  product stream and compressing same. The boiler unit can have an inlet for receiving the discharged water, and an outlet for discharging steam for the calciner fluidizing fluid. 
     In yet another aspect of the disclosure, the synthetic fuel production subsystem can comprise an SGR unit and a ceramic heat exchanger thermally coupled to a syngas product stream discharged from the SGR unit and to one or more SGR reactant feed streams fed to the SGR unit, such that the one or more SGR reactant feed streams are preheated by thermal energy from the syngas product stream before being fed to the SGR unit. The SGR reactant feed streams can comprise at least one of a carbon dioxide reactant feed stream, a hydrogen reactant feed stream, a CH 4  reactant feed stream, a water reactant feed stream, or a Fischer Tropsch light end hydrocarbon reactant feed stream. 
     In a further aspect of the disclosure, the carbon dioxide capture subsystem can comprise a calciner, the carbon dioxide reactant feed stream can comprise the carbon dioxide containing feed stream produced by the calciner, and the hydrogen reactant feed stream can comprise the hydrogen containing feed stream produced by the hydrogen production subsystem. 
     In another aspect of the disclosure, the synthetic fuel production subsystem can further comprise a Fischer Tropsch unit having an inlet coupled to the syngas product stream cooled and discharged from the ceramic heat exchanger and at least one outlet for discharging the Fischer Tropsch light end hydrocarbon feed stream and a water stream. 
     In a further aspect of the disclosure, the carbon dioxide capture subsystem can comprise a calciner having a calciner burner, and the hydrogen production subsystem can comprise an electrolyzer which produces the hydrogen containing feed stream and an oxygen containing stream from the hydrogen feedstock, and wherein the oxygen containing stream is fluidly coupled to at least one of the SGR burner or the calciner burner to provide the oxidant. 
     The carbon dioxide capture subsystem can comprise a calciner thermally coupled to the synthetic fuel production subsystem such that thermal energy output by the calciner is transferrable to the synthetic fuel production subsystem. The synthetic fuel production subsystem can comprise an SGR unit thermally and fluidly coupled to the calciner, such that heat energy and carbon dioxide output from the calciner is transferrable to the SGR unit. At least one of the calciner and the SGR unit can be fluidly coupled to an oxygen output of the hydrogen production subsystem such that at least some oxygen produced by the hydrogen production subsystem is usable in a combustion operation to heat the at least one of the calciner and the SGR unit. Alternatively, at least one of the calciner and the SGR unit can be fluidly coupled to a hydrogen fuel source such that hydrogen from the hydrogen fuel source is usable in a combustion operation to heat at least one of the calciner and the SGR unit. 
     In a further aspect of the disclosure, the system can comprise at least one of a distillation and refining unit or a power generation unit fluidly coupled to the system for producing a synthetic fuel from hydrogen and carbon dioxide, wherein the carbon dioxide capture subsystem comprises one or both of a calciner and a slaker, and at least one of the calciner and the slaker is thermally coupled to at least one of the distillation and refining unit or the power generation unit such that thermal energy output by at least one of the calciner and the slaker is transferable to at least one of the distillation and refining unit or the power generation unit. 
     In another aspect of the disclosure, a material stream from the calciner is thermally coupled to an oxygen stream flowing from the hydrogen production subsystem to the calciner, such that thermal energy output by the calciner is transferable to the oxygen stream. 
     In yet another aspect of the disclosure, the carbon dioxide capture subsystem can comprise a calciner thermally and fluidly coupled to the hydrogen production subsystem such that thermal energy and a product fluid output by the calciner are transferrable to the hydrogen production subsystem. In another aspect of the disclosure, the calciner can be thermally coupled to a water source which is fluidly coupled to the hydrogen production subsystem, such that thermal energy output by the calciner is usable to generate steam. 
     In a further aspect of the disclosure, the carbon dioxide capture subsystem can comprise a slaker with a water output that is fluidly and thermally coupled to the hydrogen production subsystem such that water and thermal energy output by the slaker is transferable to the hydrogen production subsystem. 
     In another aspect of the disclosure, the carbon dioxide capture subsystem may comprise a calciner fluidly coupled to a fuel output of the synthetic fuel production subsystem, such that at least some of the synthetic fuel produced by the synthetic fuel production subsystem is combustible by the calciner to generate thermal energy. 
     In a further embodiment of the disclosure, the carbon dioxide capture subsystem can comprise a CaCO 3  material stream, and the synthetic fuel production subsystem comprises an SGR unit producing a syngas stream and a heat exchanger thermally coupled to the syngas stream and to the material stream, wherein thermal energy generated by the SGR unit and carried by the syngas stream is transferable to the CaCO 3  material stream by the heat exchanger. 
     In another aspect of the disclosure, a product gas output from the calciner is fluidly and thermally coupled to the hydrogen production subsystem, such that product gases and thermal energy produced by the calciner are transferable to the hydrogen production subsystem. 
     In yet another aspect of the disclosure, a product stream of the calciner is fluidly and thermally coupled to a high temperature solids removal unit, and the high temperature solids removal unit is fluidly and thermally coupled to the hydrogen production subsystem, such that water and thermal energy produced by the calciner is transferable to the hydrogen production subsystem. 
     The carbon dioxide output of the calciner can be fluidly and thermally coupled to the SGR unit, such that carbon dioxide and heat energy is transferable to the SGR unit. 
     In another aspect of the disclosure, the synthetic fuel production subsystem can comprise a first heat exchanger and a first SGR unit, wherein the first heat exchanger is fluidly coupled to an SGR feed stream comprising a hydrogen feed stream flowing from the hydrogen production subsystem to the first SGR unit, and thermally coupled to a product stream output of the first SGR unit, such that thermal energy produced by the first SGR unit and carried by a product stream from the first SGR unit is transferable by the first heat exchanger to preheat the feed stream. 
     In a further aspect of the disclosure, the carbon dioxide capture subsystem can comprise a slaker and the product stream can be fluidly coupled to the slaker such that at least a portion of the water in the product stream is removed in the slaker. 
     The synthetic fuel production subsystem can further comprise a second heat exchanger fluidly coupled to the product stream, and a second SGR unit fluidly coupled to the product stream and thermally coupled to the heat exchanger such that at least a portion of the thermal energy produced by the second SGR unit is transferable by the second heat exchanger to preheat the product stream upstream of the second SGR unit. 
     In a further aspect of the disclosure, the carbon dioxide capture subsystem can comprise a calciner and the synthetic fuel production subsystem can comprise a multiple-stage SGR assembly having an inlet in fluid communication with a product outlet of the hydrogen production subsystem and comprising at least two SGR units and high-temperature hydrogen unit stages in a sequential fluid coupling, wherein each high-temperature hydrogen unit removes at least a portion of water from a product stream output by each SGR unit. 
     In another aspect of the disclosure, the carbon dioxide capture subsystem can comprise an air contactor and a solution processing unit in fluid communication with the air contactor by a CO 2  aqueous capture solution, wherein the CO 2  aqueous capture solution is thermally coupled to the synthetic fuel production subsystem such that thermal energy is transferable from the synthetic fuel production subsystem into the CO 2  aqueous capture solution. 
     The carbon dioxide capture subsystem can further comprise a regeneration unit comprising a sorbent and is fluidly coupled to the solution processing unit by a rich CO 2  aqueous capture solution, and is thermally coupled to the synthetic fuel production subsystem such that thermal energy from the synthetic fuel production subsystem is transferable to the regeneration unit to regenerate the sorbent. The regeneration unit can be fluidly coupled to a fuel output of the synthetic fuel production subsystem such that at least a portion of fuel produced by the synthetic fuel production subsystem is combustible by the regeneration unit. The regeneration unit can also be thermally coupled to the hydrogen production subsystem such that thermal energy produced by the hydrogen production subsystem is transferable to the regeneration unit to regenerate the sorbent. 
     In a further aspect of the disclosure, at least one of the SGR unit and regeneration unit is thermally coupled to an electrical heat source comprising an electrical heater. 
    
    
     
       BRIEF DESCRIPTION OF DRAWINGS 
         FIG.  1    is a schematic block diagram of a system for producing a synthetic fuel from hydrogen and carbon dioxide including a CO 2  capture subsystem, a hydrogen production sub-system, and a synthetic fuel production subsystem, according to some implementations of the invention. 
         FIG.  2    is a schematic block diagram of a system for producing a synthetic fuel from hydrogen and carbon dioxide, according to a first implementation, wherein oxygen produced by the hydrogen production subsystem and fuel produced by the synthetic fuel production sub-system is used by the CO 2  capture subsystem. 
         FIG.  3    is a schematic block diagram of a system for producing a synthetic fuel from hydrogen and carbon dioxide, according to a second implementation, wherein at least a portion of the energy required in the CO 2  capture subsystem CO 2  is derived from renewable sources CO 2 . 
         FIG.  4    is a schematic block diagram of a system for producing a synthetic fuel from hydrogen and carbon dioxide, according to a third implementation, wherein heat energy produced by the CO 2  capture subsystem is used to heat oxygen produced by the hydrogen production subsystem, and used to generate electrical power. 
         FIG.  5    is a schematic block diagram of a system for producing a synthetic fuel from hydrogen and carbon dioxide, according to a fourth implementation, wherein heat energy produced by the CO 2  capture subsystem is used to produce energy for a distillation and refining unit of the system. 
         FIG.  6    is a schematic block diagram of a system for producing a synthetic fuel from hydrogen and carbon dioxide, according to a fifth implementation, wherein hot product gases and heat energy produced by the CO 2  capture subsystem are sent to the hydrogen production subsystem and water produced by the CO 2  capture subsystem and by the synthetic fuel production subsystem can be used as hydrogen feedstock by the hydrogen production subsystem as well as feedstock to other water consumers within the system. 
         FIG.  7    is a schematic block diagram of a system for producing a synthetic fuel from hydrogen and carbon dioxide, according to a sixth implementation, wherein hot product gases produced by the CO 2  capture subsystem are separated such that the steam can be used as input energy and hydrogen feedstock by the hydrogen production subsystem and the remaining hot product gases are used as input energy and feedstock to the synthetic fuel production subsystem CO 2 . 
         FIG.  8    is a schematic block diagram of a system for producing a synthetic fuel from hydrogen and carbon dioxide, according to a seventh implementation, wherein heat energy in a material flow in the CO 2  capture subsystem is used to heat water used by the hydrogen production subsystem, and water produced by the synthetic fuel production subsystem can be used as hydrogen feedstock by the hydrogen production subsystem or as water input to the CO 2  capture subsystem. 
         FIG.  9    is a schematic block diagram of a system for producing a synthetic fuel from hydrogen and carbon dioxide, according to an eighth implementation, wherein heat energy from the synthetic fuel production subsystem is used to heat a material flow in the CO 2  capture subsystem, heat energy and water produced by the CO 2  capture sub-system can be used by the hydrogen production subsystem and provide hot CO 2  product gases to the synthetic fuel production subsystem. 
         FIG.  10    is a schematic block diagram of a system for producing a synthetic fuel from hydrogen and carbon dioxide, according to a ninth implementation, wherein hot product gases from the CO 2  capture sub-system are fed to the hydrogen production subsystem, heat energy from the synthetic fuel production subsystem is used to heat a material flow in the CO 2  capture subsystem CO 2 . 
         FIG.  11    is a schematic block diagram of a system for producing a synthetic fuel from hydrogen and carbon dioxide, according to a tenth implementation, wherein water in a material stream in the synthetic fuel production subsystem is removed by the CO 2  capture subsystem, and a material stream in the the synthetic fuel production subsystem is preheated using heat from a syngas generation reactor (“SGR”) unit in the synthetic fuel production subsystem. 
         FIG.  12    is a schematic block diagram of a system for producing a synthetic fuel from hydrogen and carbon dioxide, according to an eleventh implementation, wherein water in a material stream in the synthetic fuel production subsystem is removed by the CO 2  capture subsystem, and material streams in the the synthetic fuel production subsystem are preheated using heat from multiple SGR units in the synthetic fuel production subsystem. 
         FIG.  13    is a schematic block diagram of a system for producing a synthetic fuel from hydrogen and carbon dioxide, according to a twelfth implementation, wherein hot product gases from the CO 2  capture subsystem are fed to a first hydrogen production subsystem, the water in the product streams from multiple stages of SGR units within the synthetic fuel production subsystem is removed by multiple stages of high temperature hydrogen units placed in alternating sequence between the SGR stages, the hot O 2  from the the hydrogen production subsystem stages are combined and used for combustion by the CO 2  capture subsystem, and heat energy and water produced by the CO 2  capture subsystem can be used by the hydrogen production subsystem. 
         FIG.  14    is a schematic block diagram of a system for producing a synthetic fuel from hydrogen and carbon dioxide, according to a thirteenth implementation, wherein heat energy from the synthetic fuel production subsystem is used to heat a material stream in the CO 2  capture subsystem, at least a portion of the energy required in the CO 2  capture subsystem is supplied by renewable sources and heat energy produced by the CO 2  capture subsystem is used to provide hot CO 2  for the synthetic fuel production subsystem. 
         FIG.  15    is a schematic block diagram of a system for producing a synthetic fuel from hydrogen and carbon dioxide, according to a fourteenth implementation, including a CO 2  capture subsystem that is different than the CO 2  capture subsystem shown in  FIGS.  2  to  14   . 
         FIG.  16    is a schematic block diagram of a system for producing a synthetic fuel from hydrogen and carbon dioxide, according to a sixteenth implementation, including a CO 2  capture subsystem that is different than the CO 2  capture subsystems shown in  FIGS.  2  to  15   . 
         FIG.  17    is a schematic block diagram of different chemical pathways to produce fuels from CO 2  and hydrogen feedstocks. 
         FIG.  18    is a schematic block diagram of a system producing a synthetic fuel from hydrogen and carbon dioxide, according to a seventeenth implementation, where the synthetic fuel production subsystem includes a low pressure SGR. 
         FIG.  19    is a schematic block diagram of a system producing a synthetic fuel from hydrogen and carbon dioxide, according to an eighteenth implementation, where the synthetic fuel production subsystem includes a low pressure SGR, and where at least a portion of the energy required in the synthetic fuel production subsystem is derived from electric sources. 
         FIG.  20    is a schematic block diagram of a system producing a synthetic fuel from hydrogen and carbon dioxide, according to a nineteenth implementation, where a portion of the energy required in the CO 2  capture subsystem and the synthetic fuel production subsystem is derived from oxy-combustion of a fuel including hydrogen. 
         FIG.  21    is a schematic block diagram of a system producing a synthetic fuel from hydrogen and carbon dioxide, according to a twentieth implementation, where a portion of the energy required in the CO 2  capture subsystem and the synthetic fuel production subsystem is derived from oxy-combustion of a fuel including Fischer-Tropsch light end hydrocarbons. 
         FIG.  22    is a schematic block diagram of a system producing a synthetic fuel from hydrogen and carbon dioxide, according to a twenty-first implementation, illustrating a method of transferring heat energy in a product stream in the synthetic fuel production subsystem to at least a portion of the material flow in the CO 2  capture subsystem. 
         FIG.  23    is a schematic block diagram of a system producing a synthetic fuel from hydrogen and carbon dioxide, according to a twenty-second implementation, illustrating another method of transferring heat energy in a product stream in the synthetic fuel production subsystem to at least a portion of the material flow in the CO 2  capture subsystem. 
         FIG.  24    depicts an illustrative system  2300  for calcining calcium carbonate to produce a CO 2  gas and calcium oxide including an electrically heated calciner system. 
         FIG.  25    depicts an illustrative system  2500  for calcining calcium carbonate to produce a CO 2  gas and calcium oxide including another electrically heated calciner system. 
         FIG.  26    depicts an illustrative system  2600  for calcining calcium carbonate to produce a CO 2  gas and calcium oxide including another electrically heated calciner system. 
         FIG.  27    is a schematic block diagram of a system for producing a synthetic fuel from hydrogen and carbon dioxide, according to a twenty-sixth implementation, illustrating a method of transferring heat energy in a product stream in the synthetic fuel production subsystem to heat at least a portion of a feed stream in the synthetic fuel production subsystem, where at least a portion of the heat required in the synthetic fuel production subsystem is derived from electric sources. 
         FIG.  28    is a schematic block diagram of a system for producing a synthetic fuel from hydrogen and carbon dioxide, according to a twenty-seventh implementation, illustrating a method of transferring heat energy in a product stream in the synthetic fuel production subsystem to heat at least a portion of a feed stream, generate a steam stream or both in the synthetic fuel production subsystem, where at least a portion of the heat required in the synthetic fuel production subsystem is supplied from combustion. 
         FIG.  29    is a schematic block diagram of a system for producing a synthetic fuel from hydrogen and carbon dioxide, according to a twenty-eighth implementation, illustrating a method of transferring heat energy in a product stream in the synthetic fuel production subsystem to heat at least a portion of a feed stream, generate a steam stream or both in the synthetic fuel production subsystem, where at least a portion of the heat required in the synthetic fuel production subsystem is supplied from oxy-combustion. 
         FIG.  30    is a schematic block diagram of a system for producing a synthetic fuel from hydrogen and carbon dioxide, according to a twenty-ninth implementation, including another CO 2  capture subsystem, and where at least a portion of the energy required in the synthetic fuel production subsystem and the CO 2  capture subsystem is derived from electric sources. 
     
    
    
     DETAILED DESCRIPTION 
     Overview 
     Referring to  FIG.  1   , implementations of the invention described herein relates to a method and a system for synthesizing a fuel (“synfuel”) from a dilute CO 2  source, such as from atmospheric air or another gaseous mixture such as gases with less than about 1 vol % CO 2  content, and the like. The system  100  includes three subsystems, namely, a CO 2  capture subsystem  101  for extracting CO 2  molecules from a CO 2  feedstock, a hydrogen production subsystem  103  for extracting hydrogen molecules from a hydrogen feedstock, and a synthetic fuel production subsystem  102  for producing the synfuel using the hydrogen molecules produced by the hydrogen production subsystem  103  and the CO 2  molecules produced by the CO 2  capture subsystem  101 . Furthermore, at least some of the energy (shown as black arrows in  FIG.  1   ) and/or at least some of the fluids (shown as white arrows in  FIG.  1   ) used by one subsystem can be obtained from another subsystem. In some implementations, water produced by the CO 2  capture subsystem  101  and/or by the synthetic fuel production subsystem  102  is used as the hydrogen feedstock by the hydrogen production subsystem  103 . In some other implementations, heat energy produced by the CO 2  capture subsystem  101  is used in a process in the synthetic fuel production subsystem  102  or in the hydrogen production subsystem  103 . In some other implementations, heat energy produced by the synthetic fuel production subsystem  102  is used to preheat a material stream flowing through the CO 2  capture subsystem  101 . In yet some other implementations, reactions occurring within the CO 2  capture subsystem  101  are used to remove water from a material stream in the synthetic fuel production subsystem  102 . In yet some other implementations, heat and oxygen produced by the hydrogen production subsystem  103  are used in a combustion process within the synthetic fuel production subsystem  102  and/or CO 2  capture subsystem  101 . 
     In each of these implementations, it is expected that one or more of the cost effectiveness, operational efficiency, and operational flexibility of the overall system can be improved by having one subsystem use energy and/or fluids produced by another subsystem, rather than obtaining the energy and/or fluids from an external source. Also advantageously, the system can be used in applications where it may be challenging to provide an external source of such energy and/or fluids, such as a location where water is scarce. Furthermore, the system can potentially reduce the carbon intensity of the produced synfuel as compared to conventional fossil fuels. 
     When combined with hydrogen made from renewable electricity, CO 2  capture from atmospheric air, also known as Direct Air Capture (DAC), enables the production of carbon neutral synfuels like gasoline, diesel, and Jet-A that are completely compatible with today&#39;s fuel and transportation infrastructure. These synfuels may also overcome some of the current limitations of fats and biomass based biofuels including for example security of feedstocks, scale limitations, fuel blending constraints, land use, and food crop displacement. Furthermore, synfuels produced through the methods described herein can compare favorably to other renewable diesel options in that they can, for example, have one or more of higher energy content, higher cetane values, lower NO x  emissions, and no sulphur content. The higher cetane synthetic diesel produced through the methods described herein can allow for blending with lower quality fossil stocks. 
     The carbon intensity of the synfuel can be especially reduced when the system uses atmospheric air as the CO 2  feedstock and uses a renewable, zero and/or low carbon power source to operate the system. Using such a low carbon intensity synfuel can be particularly advantageous in those transportation applications where electrical power, biofuel or other low carbon options are not practical, such as powering long-haul vehicles including trucks, aircraft, ships, and trains. Furthermore, the low carbon intensity synfuels produced through the methods described herein will likely qualify for numerous government policy revenues and/or credit schemes, including those from LCFS (California), RIN (D3, US) and RED (EU) programs. 
     The impact of renewable electricity and fuel, used for example in oxy-fired equipment, on the carbon intensity of the synthetic fuel produced has been demonstrated through an example as shown in Table 1. For simplicity, it&#39;s been assumed that the fuel and electricity demand of the synthetic fuel production system are the primary contributors to direct and indirect emissions of the system. Emissions resulting from combustion of fuel used in oxy-fired equipment in the system account for direct emissions, while emissions associated with production, recovery or transportation/distribution of fuel/electricity account for indirect emissions. It&#39;s been assumed that for each Mega Joule (MJ) of synthetic fuel produced, the oxy-combustion process(es) in the synthetic fuel production system utilize 0.4 MJ of energy, and 0.6 KWh electricity is used for other operations in the system. 
     In the case where H 2  is used as a fuel for the burners (case 3), the H 2  is produced onsite using a H 2  production unit (such as an electrolyzer) which utilizes electricity for operation. So, the emissions associated with the production of H 2  have been accounted for in the electricity section of the Table 1. 
     As seen in cases 1 and 2 in Table 1, about 3 g CO 2 e are released for producing 1 MJ of synthetic fuel during the recovery (production) and transportation of natural gas, even though the CO 2  emissions released during combustion of natural gas in the SGR and calciner burners are captured and sent to the SGR reactor along with the CO 2  captured from air to produce synthetic fuel. 
     In the cases where the calciner and SGR use hydrogen for oxy-combustion (Case 3), or are electric (“all electric” case 4 and/or 5), there are no CO 2  emissions from the burners to be captured and this allows for more CO 2  to be captured from air and used to produce the synthetic fuel products. 
     The values in Table 1 clearly indicate that while electricity generation in coal-fired plants is carbon intensive and significantly increases the carbon intensity of the synthetic fuel, using renewables, such as hydroelectricity, solar and wind can significantly reduce the carbon intensity of the fuel, in some cases to below 10 g CO 2 e/MJ fuel. 
     
       
         
           
               
             
               
                 TABLE 1 
               
             
            
               
                   
               
               
                 A case study to show the impact of burner fuel type and source 
               
               
                 of electricity on the carbon intensity of the synthetic fuel 
               
            
           
           
               
               
            
               
                   
                 Source of fuel for oxy-combustion + 
               
               
                   
                 Source of electricity 
               
            
           
           
               
               
               
               
               
               
            
               
                 GHG emissions 
                   
                   
                   
                 4: All 
                 5: All 
               
               
                 (g CO 2 e/MJ 
                 1: NG + 
                 2: NG + 
                 3: H 2  + 
                 electric 
                 electric 
               
               
                 synthetic fuel) 
                 Coal 
                 hydro 
                 hydro 
                 (hydro) 
                 (solar) 
               
               
                   
               
            
           
           
               
               
               
               
               
               
            
               
                 Production and 
                 3 
                 3 
                 0 
                 0 
                 0 
               
               
                 transportation 
               
               
                 of burner fuel 
               
               
                 Generation and 
                 490 
                 6 
                 8.5 
                 8 
                 4 
               
               
                 distribution 
               
               
                 of electricity 
                   
                   
                   
                   
                   
               
               
                 Total emissions 
                 493 
                 9 
                 8.5 
                 8 
                 4 
               
               
                   
               
               
                 CO 2 e: CO 2  equivalent -a term for describing different greenhouse gases in a common unit 
               
               
                 NG: Natural gas; 
               
               
                 hydro: hydroelectricity 
               
            
           
         
       
     
     As indicated in some implementations described herein, the synthetic fuel production subsystem may utilize a modified GTL platform that can convert CO 2  and Hydrogen into syngas through a process known as Reverse Water Gas Shift (RWGS) before sending the syngas to a Fischer Tropsch (FT) reactor to produce synthetic hydrocarbons. This technology pathway allows the integration of a novel DAC technology with industrial FT precedent that already exists in the energy sector, and to scale up the resulting Air-to-Fuel (A2F) process/platform in the transportation sectors that have fewest options to reduce CO 2  emissions (and thus where the value of emissions reductions is the highest). 
     The carbon intensities of alternative biodiesels are in the range of 30-70 g CO 2 e/MJ biodiesel, and as high as 90-100 g CO 2 e/MJ for conventional gasoline and diesel. Synthetic fuels produced as described herein can have a carbon intensity that is less than half that of typical biofuels, meaning that these synthetic fuels get high revenues from market-based emissions programs. 
     When incorporated with renewable energy sources and optimized heat integration, these synthetic fuels can have low or zero carbon intensity. 
     As these synthetic fuels are built from clean feedstock ingredients such as atmospheric CO 2  and Hydrogen, they produce cleaner burning fuel products than fossil fuels, for example they have low to zero sulphur content. 
     Synthetic fuels, for example the diesel and gasoline products, are drop-in compatible with current infrastructure and engines, and can have up to about 30 times higher energy density than batteries, as well as up to about 100 times lower land/water use impact than biofuels. 
     Because of the selection of commercially available equipment for most if not all units described within the synthetic fuel system, these systems can be highly scalable, and thus applicable to a range of markets, including the transportation fuel market. 
     CO 2  capture, H 2  Production and Synfuel Production Subsystems 
     The CO 2  capture subsystem  101  is a machine that extracts CO 2  from dilute sources, such as atmospheric air, and may include equipment such as air contactors such as those described in U.S. Pat. No. 9,095,813 (incorporated by reference herein), or air contactors in the form of gas scrubbers, spray towers, or any other design wherein gas is contacted with the capture solution or a sorbent. As used herein “sorbent” refers to the material that undergoes sorption of a target species. As used herein, “sorption” refers to a process, physical, chemical or a combination of both, by which one substance becomes attached to another for some period of time. Examples of specific categories of sorption may include adsorption (physical adherence or bonding of ions and/or molecules onto the surface of another material), absorption (the incorporation of a substance in one state—gas, liquid, solid—into another substance of a different state) and ion exchange (exchange of ions between electrolytes or between an electrolyte solution and a complex). 
     The CO 2  capture subsystem  101  may function by contacting atmospheric air with an aqueous alkaline solution, an aqueous amine solution, an aqueous carbonate and/or bicarbonate solution, with or without containing catalysts such as carbonic anhydrase, a solid material porous sorbent material including but not limited to non-carbonaceous origin (zeolites, silica, metal-organic frameworks and porous polymers, alkali metal, and metal oxide carbonates) and carbonaceous origin (activated carbons and/or carbon fibers, graphene, ordered porous carbons, fibers), a solid structure with chemical sorbent materials including functional amine-based materials with or without cellulose, a solid polymer based material including polyethyleneimine silica, an aqueous solution combined with an anionic exchange resin, or combinations of any of the above. The CO 2  capture subsystem  101  can be based on known CO 2  capture machines which include, but are not limited to, those described in U.S. Pat. Nos. 9,095,813, 8,119,091, 8,728,428, U.S. Patent application 2014/14281430, U.S. Pat. Nos. 8,871,008, 9,283,510, 8,702,847, 9,387,433, 9,266,051, 8,435,327, 8,999,279, 8,088,197, 8,133,305, 9,266,052, European Patent 2,668,992, U.S. Pat. Nos. 7,833,328, 8,262,774, 8,133,305, 9,227,153, 8,894,747, 8,696,801, 7,699,909, U.S. Patent Application 2015/0283,501, U.S. Patent Application 2015/0273,385, U.S. Pat. No. 8,491,705, International Application number 2015/061807, International Application number 2015/064791, European Patent 2,782,657, U.S. Patent Application 2016/074803, U.S. Application 2014/134088, U.S. Patent Application 2012/076711, and U.S. Pat. No. 9,205,372, the disclosures of which are herein incorporated by references in their entirety. 
     In the implementations as shown in  FIGS.  1  to  14  and  17  to  23  and  27  to  29   , the CO 2  capture subsystem  101  can include one or more of an air contactor, a pellet reactor, a calciner, a slaker, and a solids removal and clean-up unit. In the implementations as shown in  FIGS.  15  and  16   , the CO 2  capture subsystem  101  includes an air contactor, solution processing unit, regeneration reactor unit and a water removal and clean-up unit. 
     The air contactor is a machine that contacts and extracts CO 2  from atmospheric air by contacting the atmospheric air with a CO 2  capture sorbent, such that at least some of the CO 2  in the air is transferred to the capture sorbent. The pellet reactor is a machine which precipitates carbonate out of an aqueous solution, and may include equipment such as a fluidized bed reactive crystallizer, for example as described in U.S. Pat. No. 8,728,428, U.S. application 2014/14281430, or as found in commercially available products provided by Royal Haskoning DHV. The calciner is a device that processes material by calcination, wherein the processing is performed at a high temperature (typically in the range of about 550-1150° C.) within a controlled atmosphere. The slaker is a machine that performs a hydration reaction to convert solid calcium oxide (CaO) into either solid calcium hydroxide (Ca(OH) 2 ) or a slurry of Ca(OH) 2  in solution, and may include equipment such as high temperature hydrators, steam slakers, paste slakers, mixing and diluting tanks, or a combination of any of the above. The solids removal and clean-up unit removes water and impurities from a material stream, and can include a baghouse, electrostatic precipitator, a chiller, a heat exchanger, a condenser, or a combination of these components. 
     The hydrogen production subsystem  103  is a machine that produces hydrogen molecules from a hydrogen containing material, which is typically in a fluid state (hydrogen feedstock). Electrolyzers are one known type of hydrogen production machine that extracts hydrogen molecules from water. A number of known hydrogen production pathways exist for electrolysis, such as alkaline electrolysis, proton exchange membrane (also known as a polymer electrolyte membrane) (PEM), electrolysis hydrogen production and fuel cell technologies, and solid oxide electrolysis cell (SOEC) electrolysis. Examples of hydrogen production technologies are described in U.S. Pat. No. 6,727,012, Canadian Patent 2,396,402, Canadian Patent 2,444,313 U.S. Patent Application 2005/074657, U.S. Pat. No. 6,541,141, Japanese Patent 5,618,485, U.S. Patent Application 2016/222524, European Patent 2,457,635, International Patent Application 2015/180752, European Patent Application 2,491,998, Chinese Patents 105,329,855, U.S. Patent Application 2016/0083251 and 105,163,832 and U.S. Patent Application 2015/0122128, the disclosures of which are herein incorporated by references in their entirety. 
     Extracting water from a stream may include water extraction by one or more of a chemical, or a physical method. Examples of such methods include but are not limited to water extraction from syngas in an SOEC, water extraction from syngas in a slaker, and water removal from calciner product gas. The water extraction may include chemical methods such as interfacing the gaseous stream (e.g. syngas product stream, calciner product gas) with a material that can react with the water, for example CaO, to form another product such as Ca(OH) 2 , or some type of dessicant. Another chemical extraction method could be splitting the water into H 2  and O 2  as part of a hydrogen production unit such as an SOEC. The physical methods may include water removal by cooling, by condensation, filtration or by membrane separation. A water conduit serves as a form of product conduit that includes water, such as steam, and may include additional gaseous species, such as, CO, H 2 , CO 2  and O 2 . The transfer of material produced in one subsystem to another subsystem or between units within a subsystem can serve as material transfer coupling. Examples of material transfer coupling include transfer of material through a water conduit, an oxidant conduit or a fuel conduit. 
     The synthetic fuel production subsystem  102  is a machine which produces a synthetic fuel from hydrogen molecules and carbon molecules, and in particular, from CO 2  gas provided by the CO 2  capture subsystem  101 . As used herein, “synthetic fuel” includes “fuel synthesis products”, “synthetic crude”, “Fischer-Tropsch”, “synfuels”, “air-to-fuels products” and “solar fuels”, and refers to a product that may include light end hydrocarbons, heavy end hydrocarbons, or a combination of these components. Light end hydrocarbons may be considered as hydrocarbons that exist in gas phase under atmospheric pressure and ambient temperatures. Heavy end hydrocarbons may be considered as hydrocarbons that essentially exist in liquid or solid (i.e. wax) phase under atmospheric pressure and ambient temperatures. Examples of synthetic fuel light end hydrocarbons include but are not limited to hydrogen, methane, butane, and propane. The hydrogen component of synthetic fuel product light ends may or may not be separated using a membrane and recycled separately as feedstock to other units, for example an SGR unit within the synthetic fuel production subsystem  102 . Examples of synthetic fuel heavy end hydrocarbons include but are not limited to gasoline, diesel, jet fuel, aviation turbine fuel and waxes. The Fischer Tropsch fuel synthesis products produced in the methods described herein may be further refined to produce specific fuel types as well as plastics, and polymers. 
     The synthetic fuel production subsystem  102  utilizes known fuel synthesis techniques (known as “pathways”) that involve reacting a source of carbon (such as CO 2 ) with a source of hydrogen. A number of pathways are known which use different intermediates such as syngas (a mixture of carbon monoxide (CO) and hydrogen (H 2 )), methanol (MeOH), “Fischer Tropsch Liquids” (or “FTL”) which are similar in composition to light crude oil, and others. In each case, the products can be refined to deliver final marketable fuels such as gasoline, jet fuel, aviation turbine fuel or diesel to be used in existing vehicle engines. Synthetic fuel products such as jet fuel, aviation turbine fuel, diesel or gasoline, in comparison to the equivalent fossil based jet fuel, aviation turbine fuel, diesel or gasoline products, tend to have dramatically reduced content of pollutants such as sulfur, SOx, NOx, aromatic hydrocarbons and particulate matter. Synthetic fuel products have higher levels of purity, making them more desirable as a transportation fuel source. Furthermore, synthetic fuel products derived from an atmospheric source of CO 2  tend to have fewer impurities to deal with during the intermediate stages, as an atmospheric CO 2  source does not tend to have the same impurities as traditional carbon sources such as natural gas, biomass or coal. “Gas-to-Liquid” (or GTL) pathways are known techniques for chemically synthesizing liquid fuels from electricity, water, and a source of carbon, such as natural gas. Examples of GTL technology are described in U.S. Pat. Nos. 9,321,641, 9,062,257, European Patent 2,463,023, Japanese Patent 5,254,278, International Patent Application 2006/044819, U.S. Pat. Nos. 8,062,623, 7,566,441, Canadian Patent 2,936,903, U.S. Patent Application 2015/275097, and U.S. Patent Application 2015/291888, the disclosures of which are herein incorporated by references in their entirety. Examples of syngas reactor systems and components are described in U.S. Pat. Nos. 9,321,641, 9,034,208, 6,818,198, and Chinese patent 102,099,445, the disclosures of which are herein incorporated by references in their entirety. Example of synthetic fuel systems and components are described in U.S. Pat. Nos. 9,358,526, and 9,180,436, the disclosure of which is herein incorporated by reference in its entirety. Examples of reformer exchangers for syngas production are described in U.S. Pat. Nos. 9,126,172, and 9,321,655, the disclosures of which are herein incorporated by references in their entirety. 
     The implementations of the synthetic fuel production subsystem  102  shown in  FIGS.  1  to  23 ,  27 - 30    synthesize fuels from CO 2  and include a syngas generation reactor (“SGR”) unit and a Fischer-Tropsch reactor. The SGR unit is a machine which reacts a variety of feedstocks, including but not limited to hydrogen, CO 2 , methane, natural gas, oxygen, steam, light end hydrocarbons, and biomethane to produce synthetic gas, or “syngas”. As used herein, syngas is a mixture of CO and H 2  gases, with possible minor fractions of CO 2 , methane, and water vapor, and other trace gases depending on production methods. The SGR unit may operate at high temperature, for example above 500° C., may operate at either atmospheric pressure or higher pressures of up to 200 bar depending on the process, may or may not require recycle of product gases, and may incorporate a variety of catalysts to participate in the key reactions. The Fischer-Tropsch reactor is a machine which uses the Fischer-Tropsch process to convert a mixture of carbon monoxide and hydrogen into a range of synthetic fuel products including liquid hydrocarbons. 
     Fischer-Tropsch processes take feedstocks of H 2  and CO and convert them into a multicomponent mixture of linear and branched hydrocarbons and oxygenated products, also known as aliphatic hydrocarbons. In some aspects, a portion of the products may have low aromaticity and low to zero sulfur content. Fischer-Tropsch products may also include linear paraffins and α-olefins, namely: hydrogen and low molecular weight hydrocarbons (C1-C4), medium molecular weight hydrocarbons (C4-C13) and high molecular weight hydrocarbons (C13+). Hydrogen and low molecular weight hydrocarbons can be used to make combustion fuels, polymers, and fine chemicals. Medium molecular weight hydrocarbons having for example similar compositions to gasoline can be used as feedstock for lubricants and diesel fuels. High molecular weight hydrocarbons are waxes or paraffins and can be feedstocks for lubricants and can also be further refined or hydrocracked to diesel fuel. 
     In some implementations, Fischer-Tropsch reactors may operate between 200° C. to 350° C. and from 10 bar to 60 bar. 
     In some implementations, Fischer-Tropsch synthesis may take syngas (from a variety of sources including for example SMR, ATR, POx, RWGS units) and convert it to mostly paraffinic (high molecular weight) hydrocarbon products. In some aspects, the resulting products may include for example two streams; a heavy and a light product. At ambient temperature these heavy and light products may be solid and liquid, respectively. 
     While the implementations of the synthetic fuel production subsystem  102  shown in  FIGS.  1  to  23 ,  27 - 30    use a pathway for synthesizing fuels from CO 2  that involve generating a syngas, the synthetic fuel production subsystem  102  can synthesize fuels using other pathways, including pathways that synthesize fuels from CO 2  using renewable or low carbon energy sources, for example solar, wind, hydro, geothermal, nuclear or a combination of these components. Referring to  FIG.  17   , many of these pathways also utilize syngas as an intermediate component. However, synthetic fuel can also be created using methanol synthesis from syngas followed by methanol-to-gasoline (MTG) conversion. The MTG process uses a zeolite catalyst at around 400° C. and 10-15 bar. Methanol is first converted to di-methyl ether (DME), and then on to a blend of light olefins. These, in turn, are reacted to produce a blend of hydrocarbon molecules. Examples of methods for methanol synthesis are described in Chinese Patent 103,619,790, Chinese Patent 102,770,401, U.S. Patent Application 2014/0323600 and German Patent 102,007,030,440, the disclosures of which are herein incorporated by references in their entirety. Examples of methods of MTG processing are described in Canadian Patent 2,913,061 and U.S. Pat. No. 9,133,074, the disclosures of which are herein incorporated by reference in their entirety. 
     The synthetic fuel production subsystem  102  can also use a pathway wherein synthetic fuel is created using a methanol-to-olefins (MTO) process, which is similar to the MTG process but is optimized to first produce olefins. These are then fed into another zeolite catalyst process, like Mobil&#39;s olefin-to-gasoline and distillate process (MOGD), to produce gasoline. As used herein, the acronym “MTO” refers to the combination of MTO and MOGD. MTG and MTO produce tighter distributions of carbon chain length than Fischer-Tropsch, due to their more selective catalysts. This selectivity reduces the need for post-processing/upgrading and may make for more energy efficient conversion pathways. 
     The synthetic fuel production subsystem  102  can also use a pathway wherein synthetic fuel is created by direct hydrogenation. Here, methanol is synthesized directly from CO 2  and hydrogen followed by MTG conversion. Examples of direct hydrogenation of CO 2  are described in US Patent Application 2014/0316016, the disclosure of which is herein incorporated by reference in its entirety. Examples of CO 2  hydrogenation technology are described in Japanese Patent 2,713,684, Patent 3376380, and European Patent 864,360, the disclosures of which are herein incorporated by references in their entirety. Referring to  FIG.  17   , a flow chart of implementations that could be used to produce synthetic fuels are illustrated. Any combination of the blocks could be used in combination. For example, hydrogen could be produced by electrolysis, such as polymer electrolyte membrane (PEM), alkaline, or solid oxide (SOEC) electrolysis, or could be supplied from other sources such as waste hydrogen from a chlor-alkali plant. Carbon dioxide produced from dilute source CO 2  capture can either be reduced to carbon monoxide using a variety of chemical or electrochemical reduction processes, including but not limited to reverse water gas shift processes. In such cases, the carbon monoxide and hydrogen can be fed into synthetic fuel production processes, including but not limited to Fischer-Tropsch processes, or methanol synthesis processes. Where methanol synthesis processes are used, synthetic fuel can then be produced using processes such as methanol-to-gasoline (MTG) or methanol-to-olefins (MTO). In still further implementations, the carbon dioxide from dilute source capture can be fed directly to a hydrogenation process, combined with hydrogen, and then fed into methanol-based fuel synthesis processes. The above examples are illustrative, rather than prescriptive, examples of implementations of the air to fuels processes described herein. 
     As noted above, the heat energy from one subsystem  101 ,  102 ,  103  can be used as input energy by another subsystem  101 ,  102 ,  103 . For example, the synthetic fuel production subsystem  102  generates medium grade heat while performing fuel synthesis (e.g. Fischer Tropsch  ˜ 250-350° C., Methanol Synthesis  ˜ 200-300° C., Methanol to Gasoline  ˜ 300-400° C., Methanol to Olefins  ˜ 340-540° C.), which can be used by various machines in the system  100 , including the calciner to preheat feed streams, the slaker to produce steam in slaking reactions, the air contactor to regenerate sorbent and release CO 2 , the SGR to preheat boiler feedwater, and the Fischer-Tropsch reactor to preheat the reactor feedstream. 
     Furthermore, the CO 2  capture subsystem  101 , hydrogen production subsystem  103 , and synthetic fuel production subsystem  102  also generate high grade heat during operation (e.g. Calciner- ˜ 850-950° C., SOEC electrolysis  ˜ 800° C., SGR  ˜ 800° C.-900° C.) which can be used by various machines in the system  100 , including the calciner, the SOEC electrolyzer, and the SGR. This medium and high-grade heat can also be used to generate power, as well as to provide steam heat for downstream refining and distillation systems. 
     Similarly, fluids produced or discharged by one subsystem  101 ,  102 ,  103  can be used as feedstock or for other processes in another subsystem. For example, the synthetic fuel production subsystem  102  generates steam (both by the SGR and the Fischer-Tropsch reactor) and the CO 2  capture subsystem  101  generates water (e.g. by combustion reaction in the calciner and the air contactor ingesting water during times of precipitation), which can be used by various machines in the system  100 , including in the air contactor to replace water loss due to evaporation, and the slaker to produce lime slurry, to wash pellets to remove alkali content prior to feeding into the calciner, to regenerate sorbent and release CO 2  in the sorbent regeneration unit, and to serve as hydrogen feedstock in the hydrogen production subsystem  103 . 
     Table 2 illustrates some of the key chemical reactions in CO 2  capture processes, H 2  production processes, and syngas or synfuel production processes that may be involved in air to fuel pathways along with approximate heats of reaction. As will be discussed further with reference to  FIGS.  1  to  30    these pathways suggest how heat energy and/or materials can be advantageously exchanged between the subsystems  101 ,  102  and  103  which perform these processes. 
     
       
         
           
               
             
               
                 TABLE 2 
               
             
            
               
                   
               
               
                 Chemical Reactions and Approximate Heats Associated with Air to Fuels Processes 
               
            
           
           
               
               
               
               
            
               
                   
                 Location of Reaction 
                   
                 Approximate ΔH 
               
               
                 Process 
                 in the Process 
                 Chemical Reaction(s) 
                 (kJ/mol product) 
               
               
                   
               
               
                 CO 2  Capture 
                 Air contactor; 
                 CO 2 (g) + 2KOH(aq) → K 2 CO 3 (aq) + H 2 O(I); 
                  −96; 
               
               
                   
                 Pellet reactor; 
                 K 2 CO 3 (aq) + Ca(OH) 2 (aq) → 2KOH(aq) + CaCO 3 (s); 
                  −6; 
               
               
                 CO 2  Capture 
                 Calciner 
                 CH 4 (g) + O 2 (g) → 2H 2 O(g) + CO 2 (g); 
                 −165; 
               
               
                 (Oxy-fired 
                   
                 CaCO 3 (s) + Heat ← → CaO(s) + CO 2 (g); 
                 +165; 
               
               
                 Calcination) 
               
               
                 CO 2  Capture 
                 Lime Hydrator, 
                 CaO(s) + H 2 O(g/l) → Ca(OH) 2 (s); 
                  −64; 
               
               
                 (Lime Slaking or 
                 paste slaker or steam 
               
               
                 Hydration) 
                 slaker 
               
               
                 H 2  Production 
                 Water electrolyzer 
                 2H 2 O(I) + electricity → H 2 (g) + O 2 (g); 
                 +286; 
               
               
                   
                   
                 2H 2 O(g) + electricity → H 2 (g) + O 2 (g); 
                 +242; 
               
               
                 Syngas Production 
                 Steam Methane Reformer 
                 CH 4 (g) + H 2 O(g) ← → CO(g) + 3H 2 (g); 
                 +206; 
               
               
                 Syngas Production 
                 Partial Oxidation Reformer 
                 CH 4 (g) + 1/2O 2 (g) ← → CO(g) + 2H 2 (g); 
                  −36; 
               
               
                 Syngas Production 
                 Dry Methane Reformer 
                 CH 4 (g) + CO 2 (g) ← → 2CO(g) + 2H 2 (g); 
                 +247; 
               
               
                 Syngas Production 
                 Autothermal Reformer 
                 CH 4 (g) + 1/2xO 2 (g) + yCO 2 (g) + (1 − x − y)H 2 O(g) ← → 
                  ~0; 
               
               
                   
                   
                 (y + 1)CO(g) + (3 − x − y)H 2 (g); 
               
               
                 Syngas Production 
                 Syngas electrolyzer unit 
                 2CO 2 (g) + electricity ← → 2CO(g) + O 2 (g) 
                 +283; 
               
               
                 Syngas Production 
                 RWGS Reactor 
                 H 2 (g) + CO 2 (g) ← → CO(g) + H 2 O(g); 
                  +41; 
               
               
                   
                   
                 CO 2 (g) + 4H 2 (g) ← → CH 4 (g) + 2H 2 O(g); 
                 −165; 
               
               
                   
                   
                 CO(g) + 3H 2 (g) ← → CH 4 (g) + H 2 O(g); 
                 −206; 
               
               
                 Syngas Production 
                 Syngas unit 
                 CH 4 (g) ← → C(s) + 2H 2 (g); 
                  +75; 
               
               
                   
                   
                 2CO(g) ← → C(s) + CO 2 (g); 
                 −172; 
               
               
                   
                   
                 CO 2 (g) + 2H 2 (g) ← → C(s) + 2H 2 O(g); 
                  −90; 
               
               
                   
                   
                 H 2 (g) + CO(g) ← → H 2 O(g) + C(s); 
                 −131; 
               
               
                 Synthetic Fuel 
                 Fischer-Tropsch Unit 
                 CO(g) + 2H 2 (g) ← → (—CH 2 —) + H 2 O(g); 
                 −152; 
               
               
                 Production 
               
               
                 Synthetic Fuel 
                 Methanol 
                 CO(g) + 2H 2 (g) ← → CH 3 OH(I); 
                  −91; 
               
               
                 Production 
                 Production unit 
                 CO 2 (g) + 3H 2 (g) ← → CH 3 OH(I) + H 2 O(I); 
                  −49; 
               
               
                 Synthetic Fuel 
                 Methanol-to-Gasoline unit 
                 2CH 3 OH(I) ← → CH 3 OCH 3  + H 2 O; 
                  −37; 
               
               
                 Production 
               
               
                 Synthetic Fuel 
                 Methanol-to-Olefin unit 
                 2CH 3 OH(I) ← → CH 3 OCH 3  + H 2 O; 
                  −37; 
               
               
                 Production 
               
               
                   
               
            
           
         
       
     
     Implementations 
     According to a first implementation, and referring to  FIG.  2   , the synthetic fuel production system  100  includes the CO 2  capture subsystem  101 , the hydrogen production subsystem  103  and the synthetic fuel production subsystem  102 . In the CO 2  capture subsystem  101 , an air contactor  104  takes in atmospheric air (including for example CO 2 , O 2 , N 2  and impurities)  120  and contacts it with a CO 2  capture solution (including for example K 2 CO 3 , H 2 O, KOH, trace CaCO 3 )  124 . The CO 2 -rich capture solution  122  is then sent to a pellet reactor  105 , which takes a Ca(OH) 2  slurry  128  and reacts it with the CO 2 -rich capture solution  122  to precipitate the CO 2  as carbonate onto calcium carbonate pellets, which are part of a stream  126  including wet CaCO 3  and trace amount of K 2 CO 3 , H 2 O and KOH at about 10° C. The CO 2 -lean stream leaves the pellet reactor  105  and goes back to the air contactor  104  as the CO 2  capture solution  124 . The calcium carbonate pellets are processed, dried and preheated through a slaker  106  and are eventually sent to a hot oxy-fired calciner  107  via pellet stream  130 . Due to the high temperature in the calciner  107 , the pellets calcine, releasing the CO 2  in a gaseous stream  132  that may also include one or more of H 2 O, O 2 , impurities and the like (calciner gaseous product gas stream). The hot calcium oxide (CaO) solids  131  are returned to the slaker  106 , where the heat from the hot CaO can be used to dry and preheat the calcium carbonate pellets, and the CaO is reacted (hydrated) with water to reform the Ca(OH) 2  slurry  128 . The heat produced from the hydration reaction is thus exchanged. The resulting Ca(OH) 2  slurry  128  is sent back into the pellet reactor  105  to grow more pellets. The reaction taking place in the slaker  106  is slightly exothermic, and waste heat generated in this unit can be recycled to an optional power generation unit  117  via a steam/water stream  140 . The power generation unit  117  may include waste heat boilers, steam turbines, steam superheaters or a combination of these components. In addition to calcium carbonate pellets, the oxy-fired calciner  107  is fed oxygen, which may be partially or wholly provided by the oxygen by-product stream  143  of the hydrogen production subsystem  103 . The transfer of material produced in one subsystem to another subsystem or between units within a subsystem can serve as material transfer coupling. Examples of material transfer coupling include transfer of material through a conduit. In this sense, the oxygen by-product stream  143  serves as an oxidant conduit that transfers material from one subsystem (hydrogen production subsystem) to another subsystem (CO 2  capture subsystem). 
     The calciner  107  also requires fuel to combust with the oxygen to provide the approximately 900° C. temperature for calcination. The fuel can be provided by a natural gas stream  152  from an external supply and/or by a light end by-products stream  154  from a Fischer Tropsch unit  112  within the synthetic fuel production subsystem  102 . Calcination is a highly endothermic reaction, and for this process occurs at high temperatures, and both the calcium oxide solids and calciner gaseous product streams leaving the unit have temperatures of approximately 900° C. The hot calciner gaseous product stream  132  is cooled and sent through a solids removal and clean-up unit  108 , which may include a baghouse, electrostatic precipitator, a chiller, a heat exchanger, a condenser, or a combination of these components, where any water and impurities such as dust can be removed as streams  134  and  138 , respectively, prior to a CO 2  product stream  150  being sent over to a SGR unit  111  within the synthetic fuel production subsystem  102 . Water  134  from the solids removal and clean-up unit  108  is sent over to a water treatment and source unit  109  where it is cleaned up and recycled back into the overall system  100 . Make-up or supplemental water can be supplied to the water treatment and source unit  109  via an external source  136 . Water from the water treatment and source unit  109  may be provided to other units within system  100 , for example as water  163  to the slaker unit  106  and/or water  142  to the hydrogen generation unit  110 . 
     The hydrogen production subsystem  103  includes a hydrogen generation unit  110  such as a water electrolyser, and is powered by a power supply such as a renewable source of electricity. This hydrogen generation unit  110  produces a hydrogen product stream  146  and a by-product oxygen stream  143  from a hydrogen feedstock stream  144  (e.g. water). At least a portion of the by-product oxygen stream  143  is sent to the oxy-fired calciner  107 , and the hydrogen product stream  146  can be sent to both the SGR unit  111  and the Fischer Tropsch unit  112  within the synthetic fuel production subsystem  102 , as either separate streams  1764  and  1753  respectively, or as a single stream fed first to the SGR unit  111 , where any unreacted hydrogen leaves the SGR unit  111  with the product SGR gases in stream  148  and is then sent to the Fischer-Tropsch unit  112 . The hydrogen product stream  146  is heated to approximately 800° C. by a heat exchanger  116  before being fed into the SGR unit  111 . The hydrogen production stream  146  is reacted with the CO 2  product stream  150  in the SGR unit  111  to produce a product gas stream  148  called syngas which can include, for example, CO, H 2 O, H 2 , CH 4  and CO 2 . Water produced in the SGR unit  111  by the reaction can be fed to the hydrogen generation unit  110  via stream  156  for use as hydrogen feedstock; this water can be cooled by a heat exchanger  115 . In this sense, stream  156  serves as a water conduit that transfers material from one subsystem (synthesis gas production subsystem) to another subsystem (H 2  production subsystem). The syngas  148  is cooled down in a heat exchanger  114  before entering the Fischer-Tropsch unit  112 . 
     The hydrogen product stream  146  and the syngas  148  are reacted within the Fischer-Tropsch unit  112  to produce hydrocarbon products. Lighter hydrocarbons produced by the Fischer-Tropsch unit  112  and any unreacted hydrogen are sent back within the system  100 , for example to the oxy-fired calciner  107  via stream  154  to be used as fuel. 
     In some implementations, the lighter hydrocarbons produced by the synthetic fuel production subsystem  102 , for example by the Fischer-Tropsch unit  112 , may be recycled back within the synthetic fuel production subsystem  102 , for example to the SGR unit  111  (not shown). Heavier hydrocarbons are sent downstream for further processing or final product as stream  160 . Water in the product stream is knocked out by the Fischer Tropsch unit  112  and is sent via water stream  158  for clean up in a clean-up unit  113 ; this water can be recycled back to the hydrogen production subsystem  110  via stream  157  or to elsewhere in the system  100  via stream  162 . 
     The heat exchangers ( 114 ,  115  and  116 ) may or may not incorporate waste heat from elsewhere in the overall system to heat up  116  or cool down  114 ,  115  the process streams pass therethrough. 
     In some implementations, the CO 2  capture subsystem  101  may incorporate a high temperature hydrator or steam slaker (not shown) within the slaker unit  106 . In other implementations the SGR unit  111  of synthetic fuel production subsystem  102  may be a reverse gas shift (RWGS) reactor, or include a different syngas generation reactor (SGR) unit instead of or in combination with the SGR unit  111 , such as an auto-thermal reformer (ATR), a partial oxidation reactor, dry methane reformer (DMR) or a steam methane reformer (SMR). In some implementations, the hydrogen feedstock to the synthetic fuel production system  102  may at least be partially provided by products from the SGR unit. (not shown). 
     Referring now to  FIG.  3    and according to a second implementation, a synthetic fuel production system  200  includes the capture subsystem  101 , the hydrogen production subsystem  103  and the synthetic fuel production subsystem  102 . All the components of the system  200  are substantially the same as in the first implementation of the system  100  illustrated in  FIG.  1   , with the exceptions being that within the CO 2  capture subsystem  101 , the calciner  207  is now heated with a renewable energy source  252  instead of natural gas or light end products from the Fischer Tropsch unit  112 ; examples of such renewable energy sources  252  include one or more of hydroelectricity, solar thermal energy, wind, geothermal or nuclear heat sources (e.g. molten salt reactors). Using a renewable energy source to provide the heat for calciner unit  207  means that the hot CO 2  product stream  132  does not contain the usual oxy-combustion products (H 2 O, CO 2 , trace O 2 ); instead it contains mostly calcination products such as CO 2  and trace impurities. In this sense, the hot CO 2  product stream  132  serves as a calciner product conduit that transfers the product stream from the calciner to the solids removal unit. This eliminates the need for water removal prior to sending to downstream units, for example the SGR  111 . Also, in this implementation the solids removal and clean up unit  208  operates at higher temperatures than the unit  108  in the first implementation, for example up to approximately 800° C.-950° C., and as such incorporates filter materials that can handle higher temperatures, such as ceramic fiber elements, refractory material, ceramic wollastonite, ceramic fibres of an alumino-silicate composition such as are described in Norwegian Patent 960,955, the disclosure of which is herein incorporated by reference in its entirety, or the like. In this implementation, the solids removal and clean-up unit  208  does not need water removal componentry. 
     The hot CO 2  product stream  150  leaving the high temperature solids removal and clean up unit  208  can then be directly fed into the SGR unit  111  without needing preheating exchangers and/or with less heat needing to be supplied to the SGR unit  111 , so long as the SGR unit  111  is operating at low pressur. 
     The SGR unit  111  is operating at a low pressure, for example slightly above atmospheric, so that the hot CO 2  product stream  150  coming from the calciner unit  105 , which is also operating near atmospheric pressure, can properly feed into the SGR unit  111 . Any significant compression required to feed into the SGR unit  111  would involve cooling the stream  150  down, which would take away the advantage of having the hot product stream  150  feed directly into the SGR unit  111 . The gas streams may be moved between units using low pressure, high temperature blowers if required/as needed. 
     In some aspects, the hot CO 2  product stream  150  is transferred with minimal heat loss so that a substantial amount of the stream&#39;s heat can be retained, thus reducing the need for external heat energy to the SGR unit. Said in another way, the hot CO 2  product stream  150  is transferred to the SGR unit  111  in a way to avoid substantially cooling the stream; while there may be some cooling/heat loss due to the need to transfer through pipes for example, care would be taken to minimize heat loss and the stream  150  would not be intentionally cooled to the point where a significant amount of the thermal energy is removed. 
     In some aspects, the calciner units may be operated at slightly higher than atmospheric pressures, ie up to a few bars of pressure, in order to mitigate compression between the calciner and SGR units, while still maintaining higher temperatures gas exchange between the two units. In these cases, however it is noted that the required temperature of calcination rises exponentially as the pressure rises, therefore operating the calciner at even up to 2 bars of pressure would require a significant increase in calciner operating temperature, which quickly impacts the energy input to the system. Additionally, there are practical upper limits on calciner operating temperature due to melting temperatures and fouling from impurities. Implementations of low pressure SGR units and how they interface are described in more detail in  FIGS.  18  and  19   . The by-product oxygen stream  143  from the hydrogen production subsystem  103  is not sent to the calciner unit  207  and instead can be used to oxy-fire turbines for power, oxy-fire the heating needs for the SGR unit  111  or can be sent out of the system for other purposes (not shown). The SGR unit  111  can be a modified RWGS unit to handle the oxy-firing (not shown). 
     Referring now to  FIG.  4    and according to a third implementation, a synthetic fuel production system  300  includes the CO 2  capture subsystem  101 , the hydrogen production subsystem  103  and the synthetic fuel production subsystem  102 . All components in the system  300  are substantially the same as in the first implementation of the system  100  illustrated in  FIG.  1   , with the exceptions being that within the CO 2  capture subsystem  101 , the hot calciner gases  332  are passed through a first heat exchanger  301  to extract excess heat and provide it to a power generation system  317  via heat exchanger fluid  333  to generate power. Additionally or alternatively, excess heat from the slaker unit  106  is extracted and sent to the power generation system  317  in the form of steam  334  to generate power. 
     Furthermore, the CO 2  capture subsystem  101  includes a second heat exchanger  302  which is used in a heat recovery process to heat the oxygen product gas stream  143  from about 20° C. to about 600° C. using heat from hot calcium oxide (CaO) solids  131  (thereby causing the solids to drop in temperature from about 950° C. to about 550° C.). The heated oxygen product gas stream  143  is then fed into the calciner  107  for use in combustion. 
     Referring now to  FIG.  5    and according to a fourth implementation, a synthetic fuel production system  400  includes the CO 2  capture subsystem  101 , the hydrogen production subsystem  103  and the synthetic fuel production subsystem  102 . All components in the system  400  are substantially the same as in the first implementation of the system  100  illustrated in  FIG.  1   , with the exceptions being that within the CO 2  capture subsystem  101  the hot calciner gases  132  are passed through a heat exchanger  401  to extract excess heat and provide it to a waste heat collection system  417  via a first heat transfer fluid  403 . The waste heat is collected and sent to a downstream distillation and refining unit  402  via a second heat transfer fluid  405 . The distillation and refining unit  402  may also accept the liquid products stream  160  from the Fischer Tropsch unit  112  within the synthetic fuel production subsystem  102 . 
     Referring now to  FIG.  6    and according to a fifth implementation, a synthetic fuel production system  500  includes the CO 2  capture subsystem  101 , the hydrogen production subsystem  103  and the synthetic fuel production subsystem  102 . All components in the system  500  are substantially the same as in the first implementation of the system  100  illustrated in  FIG.  1   , with the exceptions being that within the CO 2  capture subsystem  101 , the calciner hot product gases  132 , including CO 2 , H 2 O and O 2 , are sent through a high temperature solids removal and clean up unit  508 , which is similar to the second implementation of the unit  208  but which removes particles only as particles stream  509 , after which all gases  511  (including CO 2 , H 2 O, O 2 ) are sent directly to the hydrogen production subsystem  103  within which they are fed into a high temperature solid oxide electrolyser cell (SOEC) unit  510  for use as hydrogen feedstock. In this sense, the hot product stream  132  serves as a calciner product conduit that transfers material from the calciner to the solids removal unit (unit  508  in this case), while the stream  511  serves as a product conduit that transfers material from one subsystem (CO 2  capture subsystem) to another subsystem (H 2  production subsystem). The heat energy in the hot gas stream  511  can be used as input energy by the SOEC unit  510 . Energy from an external source can also be provided to power the SOEC unit  510 , which can be provided for example by a renewable energy source. If needed, the steam supply to the hydrogen production subsystem  103  can be supplemented with steam  512  generated in the slaker unit  106 , water  142  from the water treatment and source unit  109 , or a combination of these sources. In this sense, the streams  512  and  142  serve as water conduits that transfer material from one subsystem (CO 2  capture subsystem) to another subsystem (H 2  production subsystem). 
     The SOEC unit  510  operates to produce a product stream  546  that contains CO 2 , H 2  and CO which is then sent to the SGR unit  111  (which in this implementation can be a RWGS reactor), and an oxygen by-product stream  143 . At least a portion of the by-product oxygen stream  143  is sent to the oxy-fired calciner  107 . Water  156  is removed in the SGR unit  111  and is cooled in a heat exchanger unit  515  before going through a clean-up unit  113  and is then recycled as part of the water stream  550  to the water treatment and source unit  109  for use as needed in the system  500 . Alternatively or additionally, at least a portion of the water stream  557  can be diverted directly to the SOEC unit  510  upstream of the heat exchanger  515 , to provide heat energy and hydrogen feedstock. 
     Referring now to  FIG.  7    and according to a sixth implementation, a synthetic fuel production system  600  includes the CO 2  capture subsystem  101 , the hydrogen production subsystem  103  and the synthetic fuel production subsystem  102 . All components in the system  600  are substantially the same as in the first implementation of the system  100  illustrated in  FIG.  1   , with the exceptions being that within the CO 2  capture subsystem  101 , the calciner hot product gases  132 , including CO 2 , H 2 O and O 2 , are sent through a high temperature solids removal and clean up unit  608 , where any solids particles are removed as stream  509  and water (steam) is separated as stream  609  using a high temperature water removal membrane. The steam  609  is sent over to an SOEC unit  610  within the hydrogen production system  103  and the other hot product gases  611  (including for example CO 2 , O 2 ) are sent to the SGR unit  111  within the synthetic fuel system  102 . In this sense, the stream  609  serves as a water conduit that transfers material from one subsystem (CO 2  capture subsystem) to another subsystem (H 2  production subsystem). Similar to the second implementation, the SGR unit  111  in this implementation must be operating at a low pressure of slightly above atmospheric, as the hot CO 2  product stream  132  coming from the calciner unit  107  is at near atmospheric pressure, and any compression required to feed into a higher pressure SGR unit  111  would involve cooling the stream  611  down significantly, taking away the advantage of having the hot product stream  611  feed directly into the SGR unit  111 . This direct feeding method is done in such a way to avoid substantially cooling the stream  611 . If needed, the steam supply to the hydrogen production subsystem  103  can be supplemented with steam  512  generated in the slaker unit  106 , the water  142  from the water treatment and source unit  109 , or a combination of the two sources. The hydrogen production subsystem  103  produces a hydrogen stream  146  and an oxygen stream  143 . At least a portion of the oxygen stream  143  gets fed to the calciner  107  and the hydrogen stream  146  gets fed directly to the SGR unit  111 , where enough surplus is fed such that there is hydrogen in the syngas product stream  148  that is then cooled and proceeds to the Fischer Tropsch unit  112 . Water  156  is removed in the SGR unit  111  and is cooled in a heat exchanger unit  615  before going through a clean-up unit  113  and is then recycled as part of water stream  550  to the water treatment and source unit  109  for use as needed in the system  600 . Alternatively or additionally, at least a portion of the water can be diverted as stream  657  directly to the SOEC unit  610  upstream of the heat exchanger  615 , to provide heat energy and hydrogen feedstock. 
     Referring now to  FIG.  8    and according to a seventh implementation, a synthetic fuel production system  700  includes the CO 2  capture subsystem  101 , the hydrogen production subsystem  103  and the synthetic fuel production subsystem  102 . All components in the system  700  are substantially the same as in the first implementation of the system  100  illustrated in  FIG.  1   , with the exceptions being that within the CO 2  capture system  101 , the hot calciner gaseous product stream  132  is sent through a heat exchanger unit  701 , wherein heat is transferred to a heat transfer fluid  703  which in turn flows to a steam unit  717 ; consequently the calciner gaseous product stream is cooled from about 950° C. to less than about 450° C. Steam  140  from the slaker  106  is also sent to the steam unit  717  and the resulting steam  702  can be sent to a SOEC unit  710  to provide heat energy and the hydrogen feedstock. If needed, the steam unit  717  can be supplemented with water  705  from the water treatment and source unit  109 . 
     Once through the heat exchanger unit  701 , the cooled calciner gaseous product stream  132  is then sent to the solids removal and clean-up unit  108  and processed in the same manner as in the first implementation. The hydrogen production subsystem  103  produces a hydrogen stream  146  and an oxygen stream  143 . At least a portion of the oxygen stream  143  gets fed to the calciner  107  and the hydrogen product stream  146  is split; a portion  1764  goes to the SGR unit  111  and a portion  1753  gets sent downstream, to mix with the syngas  148  before being cooled in a heat exchanger unit  114  and sent to the Fischer-Tropsch unit  112 . Water  156  is removed in the SGR unit  111  and is cooled in a heat exchanger  715  before being recycled, along with any excess water from Fischer-Tropsch unit  112 , as water  850  to the H 2 O source unit  109  for use as needed in the system  700 , e.g. for use in the slaker  106  and the hydrogen production subsystem  103 . Alternatively or additionally, the water  157  can be diverted directly to the SOEC unit  710  upstream of the heat exchanger  715 , to provide heat energy and hydrogen feedstock. 
     Referring now to  FIG.  9    and according to an eighth implementation, a synthetic fuel production system  800  includes the CO 2  capture subsystem  101 , the hydrogen production subsystem  103  and the synthetic fuel production subsystem  102 . All components in the system  800  are substantially the same as in the first implementation system  100  illustrated in  FIG.  1   , with the exceptions being that within the CO 2  capture subsystem  101 , the calciner gaseous product stream  132  is sent through a high temperature solids removal and clean up unit  808 , where any solids particles are removed  809  and water (steam) is separated using a high temperature water removal membrane. The steam  811  is sent over to an SOEC unit  810  within the hydrogen production subsystem  103  to provide heat energy and hydrogen feedstock. In this sense, the stream  811  serves as a water conduit that transfers material from one subsystem (CO 2  capture subsystem) to another subsystem (H 2  production subsystem). The other hot product gases  813  (CO 2 , trace O 2 ) are sent to the SGR unit  111  within the synthetic fuel system  102 , for use as heat energy, and CO 2  feedstock. Similar to the second and sixth implementations, the SGR unit  111  in this implementation must be operating at a low pressure of slightly above atmospheric, as the hot CO 2  product stream  132  coming from the calciner unit  107  is operated at near atmospheric conditions, and any compression required to feed into a higher pressure SGR unit  111  would involve cooling the stream  813  down significantly, taking away the advantage of having the hot product stream  813  feed directly into the SGR unit  111 . This direct feeding method is done in such a way to avoid substantially cooling the stream  813 . If needed, the steam supply to the hydrogen production subsystem  103  can be supplemented with steam  512  generated in the slaker unit  106 , water  142  from the water treatment and source unit  109 , or a combination of these two sources. The supplied steam provides heat energy and at least a portion of the hydrogen feedstock, and the supplied water can provide at least a portion of the hydrogen feedstock. 
     The hydrogen production subsystem  103  produces a hydrogen stream  146  and an oxygen stream  143 . At least a portion of the oxygen stream  143  gets fed to the calciner  107  and the hydrogen stream  146  is split; a portion is fed directly to the SGR unit  111  as stream  1764 , and the rest bypasses the SGR unit  111  as stream  1753 , and joins the syngas stream  148  upstream of a heat exchanger unit  814 , wherein heat is transferred from the syngas stream  148  to the CaCO 3  pellet stream  130 , such that the combined syngas and hydrogen stream  821  is cooled from about 800° C. to about 350° C., and the pellet stream  130  is preheated from about 350° C. to about 750° C. before being fed into the calciner  107 . Examples of a few types of heat exchange designs that may be used to accomplish this form of process heat exchange without incurring metal dusting issues commonly encountered with syngas are described in  FIGS.  22 , 23 , 27 - 29   . The combined syngas and hydrogen stream  821  proceeds to the Fischer Tropsch unit  112 . Water  156  is removed in the SGR unit  111  and is cooled in a heat exchanger unit  815  before going through a clean-up unit  113  and is then recycled as water  550  to the water treatment and source unit  109  for use as needed in the system  800 . Alternatively or additionally, the water  157  can be diverted directly to the SOEC unit  810  upstream of the heat exchanger  815 , to provide heat energy and hydrogen feedstock. 
     Referring now to  FIG.  10    and according to a ninth implementation, a synthetic fuel production system  900  includes the CO 2  capture subsystem  101 , the hydrogen production subsystem  103  and the synthetic fuel production subsystem  102 . All components in the system  900  are substantially the same as in the first implementation of the system  100  illustrated in  FIG.  1   , with the exceptions being that within the CO 2  capture subsystem  101 , the hot calciner gaseous product stream  132  is sent through a high temperature solids removal and clean up unit  908 , similar to that of the second and fifth implementations, which removes particles  909  only, after which a hot gas stream  911  (including CO 2 , H 2 O, O 2 ) is sent directly to the hydrogen production subsystem  103  within which the gas stream is fed into a high temperature SOEC unit  910 , for use as input energy and hydrogen feedstock. Additional energy  1052  can be provided to the SOEC unit  910  by an external source, such as a renewable energy source. If needed, the steam supply to the hydrogen production subsystem  103  can be supplemented with steam  512  generated in the slaker unit  106 , water  142  from the water treatment and source unit  109 , or a combination of these two sources. 
     At least a portion of the by-product oxygen stream  143  from the SOEC unit  910  is sent to the oxy-fired calciner  107  and another product stream  913  containing CO 2 , H 2  and CO, is sent to the SGR unit  111 . The water by-product stream  156  from the SGR unit  111  is cooled in a heat exchanger unit  915 , and is then cleaned up in clean up unit  113  and sent back to the H 2 O source unit  109  as part of stream  917  for reuse within the overall system  100 . Additionally, at least a portion of the by-product water stream  157  can be diverted upstream of the heat exchanger unit  915  and fed directly to the SOEC unit  910 . The syngas product stream  148  from the SGR unit  111  is sent to a heat exchanger unit  901  where it exchanges heat to the CaCO 3  pellet stream  130  from the slaker unit  106 , causing the syngas product stream  148  to cool from about 800° C. to about 350° C., and causing the pellet stream to be preheated from about 350° C. to about 750° C. The cooled product gas stream  948  may get further cooled in a heat exchanger unit  902  before being sent to the Fischer Tropsch unit  112 , while the heated pellet stream  130  is fed into the calciner  107 . 
     Referring now to  FIG.  11    and according to a tenth implementation, a synthetic fuel production system  1000  includes the CO 2  capture subsystem  101 , the hydrogen production subsystem  103  and the synthetic fuel production subsystem  102 . All components in the system  1000  are substantially the same as in the first implementation of the system  100  illustrated in  FIG.  1   , with the exceptions being that some of the hydrogen product stream  146  from the hydrogen production subsystem  103  is combined with a cooled product stream  1002  including CO 2 , O 2  from the solids removal and clean up unit  108  to produce a combined product stream (“SGR feed stream”)  1004 , including gas species such as H 2 , CO 2 , O 2 , that is then sent through a preheat exchanger unit  1001  and then into the SGR unit  111  which in this implementation includes an RWGS reactor. The SGR unit  111  outputs a hot SGR product stream  1005  (including gas species such as CO, H 2 , H 2 O and CO 2 ) which is then fed into the preheat exchanger unit  1001 , wherein heat is transferred from the SGR product stream  1005  to the SGR feed stream  1004 , thereby preheating the SGR feed stream  1004  from about 350° C. to about 750° C. and cooling the SGR product stream  1005  from about 800° C. to 300° C. 
     After the SGR product stream  1005  leaves the heat exchanger unit  1001 , it flows through a slaker  1006  within the CO 2  capture subsystem  101  where water is removed therefrom; this water may be used by the slaker  1006  in a hydrating reaction to form the Ca(OH) 2  slurry  128 . In this sense, the SGR product stream  1005  serves as a water conduit that transfers material from one subsystem (synthesis gas production subsystem) to another subsystem (CO 2  capture subsystem). The steam slaker unit  1006  sends any excess steam  140  to a steam unit  1017  which can be used to generate power or provide input energy, water or a combination of both, to other parts of the system  1000 . The dewatered SGR product stream  1014  leaves the steam slaker and heads back to the synthetic fuel production subsystem  102  where it combines with the rest of the hydrogen stream  1753  from the hydrogen production subsystem  103  and the combined stream then feeds into the Fischer Tropsch unit  112 . 
     Referring now to  FIG.  12    and according to an eleventh implementation, a synthetic fuel production system  1100  includes the CO 2  capture subsystem  101 , the hydrogen production subsystem  103  and the synthetic fuel production subsystem  102 . All components in the system  1100  are substantially the same as in first implementation of the system  100  illustrated in  FIG.  1   , with the exceptions being that the hydrogen product stream  146  from the hydrogen production subsystem  103  is combined with a product stream  1102  including gas species such as CO 2 , O 2  from the solids removal and clean up unit  108  to produce a combined gas product stream (“first SGR feed stream”)  1104  (including gas species such as Hz, CO 2 , O 2 ) that is then sent through a first preheat exchanger unit  1103 . This first preheat exchanger unit  1103  takes the hot product gas stream (including gas species such as H 2 O, CO, CO 2 )  1105  from a first stage SGR unit  1101  (“first SGR product stream”) and uses it to preheat the first feed stream  1104  from about 350° C. to about 750° C. After the first SGR product stream  1105  leaves the first preheat exchanger unit  1103  and is cooled from about 800° C. to 350° C., it is then sent to a steam slaker unit  1106  within the CO 2  capture subsystem  101  where water is removed therefrom and may be used in the hydrating reaction to form the Ca(OH) 2  slurry  128 . The steam slaker unit  1106  sends any excess steam  1107  to a steam unit  1117 , which can generate power or provide input energy, water or both to other parts of the system  1100 . The dewatered first SGR product stream  1115  leaves the steam slaker unit  1106  and heads back to the synthetic fuel production subsystem  102  where it serves as a feed stream for a second preheat exchanger unit  1114 , which has the same function as the first heat exchanger unit  1103 . The preheated feed stream  1115  enters a second stage SGR unit  1102 , and the resulting second SGR product stream  1108  heads through the preheat exchanger unit  1114  and then is fed into the Fischer Tropsch unit  112 . 
     While a two stage SGR/heat exchanger arrangement, which can serve as a multiple-stage SGR assembly, is shown in  FIG.  12   , in alternative implementations more or less SGR stages and intercooling or preheating exchangers can be provided. 
     Referring now to  FIG.  13    and according to a twelfth implementation, a synthetic fuel production system  1200  includes the CO 2  capture subsystem  101 , the hydrogen production subsystem  103  and the synthetic fuel production subsystem  102 . All components in the system  1200  are substantially the same as in the system  100  illustrated in  FIG.  1   , with the exceptions being that within the CO 2  capture subsystem  101 , the hot calciner gaseous product stream  132  is sent through a high temperature solids removal and clean up unit  1208 , similar to that described in the second, fifth and ninth implementations, after which a product gas stream  1211  (including for example CO 2 , H 2 O, trace O 2 ) is sent directly to the hydrogen production subsystem  103  within which it is fed into a first high temperature SOEC unit  1210 . The hot product stream  1211  provides input energy and the hydrogen feedstock for the SOEC unit  1210 . Additional energy can be provided by an external source  1220 , such as from a renewable energy source. If needed, the steam supply to the hydrogen production subsystem  103  can be supplemented with steam  512  generated in the slaker unit  106 , water  142  from the water treatment and source unit  109 , or a combination of both. 
     At least a portion of the by-product oxygen stream  143  is sent to the oxy-fired calciner  107  and the other product gas stream  1213  (first SOEC product stream), including for example CO 2 , H 2  and CO, is sent to a first stage SGR unit  1201  which in this implementation includes an RWGS reactor. The resulting first SGR product gas stream  1215  (including, for example, H 2 O, CO, CO 2 , O 2 , H 2 ) is then sent through a second high temperature SOEC unit  1203  to convert the water into H 2  and O 2 , thereby producing a second SOEC product gas stream  1217  including species such as CO, CO 2 , H 2  and O 2 . At least a portion of the by-product oxygen stream  1219  from the SOEC unit  1203  is sent to the calciner unit  107  while the second SOEC product stream  1217  is sent to a second stage RWGS unit  1202 . The product gas stream  1221  from the second stage RWGS unit  1202  (“second SGR product stream”) including, for example, H 2 O, CO H 2  may be sent to a third high temperature SOEC unit  1204 . At least a portion of the resulting by-product oxygen stream  1223  may be sent to the calciner unit  107  and the remaining syngas  1225  is sent to a heat exchanger unit  1205  where it exchanges heat with the CaCO 3  pellets stream  130  from the slaker unit  106  within the CO 2  capture subsystem  101 . The cooled syngas stream  1225  heads from the heat exchanger unit  1205  to the Fischer Tropsch unit  112  and the heated pellet stream  130  heads to the calciner unit  107 . 
     While a three stage SGR/heat exchanger arrangement, which can serve as a multiple-stage SGR assembly, is shown in  FIG.  13   , in alternative implementations more or less SGR stages and intercooling or preheating exchangers can be provided. 
     Referring now to  FIG.  14    and according to a thirteenth implementation, a synthetic fuel production system  1300  includes the CO 2  capture subsystem  101 , the hydrogen production subsystem  103  and the synthetic fuel production subsystem  102 . All components in the system  1300  are substantially the same as in the first implementation of the system  100  illustrated in  FIG.  1   , with the exceptions being that within the CO 2  capture subsystem  101 , the second implementation of the calciner  207  and the solids removal and clean up unit  208  are used. As noted previously the calciner  207  is powered by renewable energy, and the solids removal and clean up unit  208  operates at much higher temperatures than the unit of the first implementation, and as such incorporates filter materials that can handle higher temperatures, such as ceramic fiber elements, refractory material, ceramic wollastonite, or ceramic fibres of an alumino-silicate composition. The hot CO 2  product stream  150  leaving the solids removal and clean up unit  208  can then be directly fed into the SGR unit  111  without needing preheating exchangers and/or with less heat needing to be supplied to the SGR unit  111 . The hydrogen stream  146  from the H 2  production unit  103  is split; a portion can be fed directly to the SGR unit  111  as stream  1764 , and a portion can bypass the SGR unit  111  as stream  1753 , combining with the product gas stream  148  from the SGR unit  111  upstream of a heat exchanger unit  1314 . The gas mixture is then sent through a heat exchange unit  1314  which exchanges heat between the gas stream and a CaCO 3  pellet stream  126  from the pellet reactor unit  105 . The cooled mix of hydrogen and syngas stream  1301  heads from the heat exchanger unit  1314  to the Fischer Tropsch unit  112  and the heated pellet stream  126  then heads to the slaker unit  106 . The by-product oxygen stream  143  from the hydrogen production subsystem  103  is not sent to the calciner unit and instead can be used to oxy-fire turbines for power, oxy-fire the heating needs for the SGR  111 , sent to an external end user, or a combination of these options. 
     In some implementations, the CaCO 3  pellets are first sent to the slaker and then sent to a heat exchanger unit  1314 . In other implementations, the synthetic fuel production subsystem  102  may include a different SGR unit instead of or in combination with the SGR unit  111 , such as an ATR, a partial oxidation reactor, DMR, a SMR or a modified RWGS unit to properly handle oxy-firing. 
     Referring to  FIG.  15    and according to a fourteenth implementation, a synthetic fuel production system  1500  includes the same hydrogen production subsystem  103  and synthetic fuel production subsystem  102  as in the previous implementations, but a different type of CO 2  capture subsystem  1501 . More particularly, the CO 2  capture subsystem  1501  uses a different liquid chemistry process and equipment to extract the CO 2  molecules form the air, namely CO 2  lean aqueous capture solution  1503 . CO 2  is extracted from the air using an air contactor  1504 , which outputs a CO 2  rich aqueous capture solution  1510  to a solution processing unit  1505 . A processed CO 2  rich aqueous capture solution  1514  is then fed to a DAC regeneration unit  1507 , which produces a regenerated capture solution  1513  and a product stream  1515  including CO 2  and H 2 O, which is then fed to a water recovery unit  1508 , to extract water and a dry CO 2  product stream  1517 . The water is fed to the water treatment and source unit  109  via water stream  1534  for use as needed in the overall system, such as water  1519  to the solution processing unit  1505  and/or as feedstock for the hydrogen production subsystem  103 . The CO 2  product stream  1517  is sent to a SGR  1511  of the synthetic fuel production subsystem  102  for use in the same manner as in previous implementations. 
     The DAC regeneration unit  1507  may include stripper reactors, heat recovery steam generators, boilers, reboilers, condensate treatment units, heat exchangers and makeup chemicals. The solution processing unit  1505  may include one or more of electrically powered membrane units, including for example electrodialysis, reverse osmosis and nanofiltration units, thermally driven evaporators and filtration units. Steam  1521  generated in the synthetic fuel production subsystem  102  may be used to strip CO 2  and regenerate sorbent in CO 2  capture subsystem  1501  (e.g. from one or more of the Fischer-Tropsch unit  1512  and the SGR  1511 ). Also, light end hydrocarbon byproducts  1523  produced by the Fischer-Tropsch unit  1512  can be used as fuel by the regeneration unit  1507 . In this sense, the stream  1523  serves as a fuel conduit that transfers the fuel from the synthetic fuel production subsystem to the regeneration unit  1507 . Additionally or alternatively, some of the H 2  and O 2  produced by the hydrogen production subsystem  103  may be used to heat the regeneration unit  1507  via combustion of H 2  stream  1525  and O 2  stream  1527 . 
     Fuel synthesis machines, such as Fischer-Tropsch reactors, may be used directly as reboilers in the DAC regeneration unit  1507 . The regeneration unit  1507  may be oxy-fired, electrically heated or may use waste heat and/or steam from other sub systems. Additionally, the CO 2  rich aqueous capture solution  1510  may be used as a cooling liquid for the synthetic fuel production subsystem  102  e.g. by the Fischer-Tropsch unit  1512  (not shown). Referring to  FIG.  16    and according to a fifteenth implementation, a synthetic fuel production system  1600  includes the same hydrogen production subsystem  103  and synthetic fuel production subsystem  102  as in the previous implementations, but a different type of CO 2  capture subsystem  1601 . More particularly, the CO 2  capture subsystem  1601  uses solid sorbent technology, and includes a solid sorbent air contactor  1604 , a steam generation unit  1607  and a water removal unit  1608 . The CO 2  capture subsystem  1601  still sends a CO 2  stream  1617  to the synthetic fuel production subsystem  102  as in the previous implementations. In this CO 2  capture subsystem  1601 , steam  1609  is used as a heat source to release the CO 2  and regenerate the solid sorbent. The steam may be generated via heat recovery steam generators, boilers, reboilers, directly via steam from fuel synthesis unit and/or may include condensate treatment units, heat exchangers and makeup chemicals. In particular, steam  1621  generated in the synthetic fuel production subsystem  102  (e.g. from Fischer-Tropsch unit  1612  and from the SGR  1611 ) can be supplied to the steam generation unit  1607  for this purpose. 
     The steam generation unit  1607  can be oxy-fired, electrically heated or use waste heat/steam from other sub systems. Also, light end hydrocarbon byproducts  1623  produced by the Fischer-Tropsch unit  1612  can be used as fuel by the steam generator unit  1607 . Additionally or alternatively, some of the H 2  and O 2  produced by the hydrogen the production subsystem  103  may be used to heat the steam generation unit  1607  via H 2  stream  1625  and O 2  stream  1627 . 
     A product stream  1615  including CO 2  and H 2 O, which is then fed to a water removal unit  1608 , to extract water and a dry CO 2  product stream  1617 . The water is fed to the water treatment and source unit  109  via water stream  1634  for use as needed in the overall system, such as water  1619  to the steam generation unit  1607  and/or as feedstock for the hydrogen production subsystem  103 . 
     Referring now to  FIG.  18    and according to a seventeenth implementation, a synthetic fuel production system  1700  includes the CO 2  capture subsystem  101 , the hydrogen production subsystem  103  and the synthetic fuel production subsystem  102 . Within the CO 2  capture subsystem  101 , there is a calciner unit  1707 , and the hot product gas stream  132  from calciner unit  1707  is sent to a high temperature solids removal and clean up unit  208 . The high temperature solids removal unit  208  is similar to the high temperature solids removal units described in  FIGS.  3 , 7 ,  9  and  14    with the essential feature being the unit is able to transfer hot calciner product gases from the CO 2  capture subsystem  101  to the SGR unit  1711 . 
     In this implementation, the SGR unit  1711  is a low pressure SGR unit, operating at pressures slightly above atmospheric. In this implementation, the synthetic fuel production subsystem  102  further includes a syngas treatment unit  1745 , a compression unit  1737 , and a Fischer Tropsch unit  112 . 
     In some aspects, the hot calciner product stream  150  leaves the CO 2  capture subsystem  101  at approximately 850° C.-900° C. and can then be directly fed into an SGR unit  1711  that is operating at low pressure of slightly above atmospheric, without the need for cooling and compression, preheat exchangers and/or with less heat needing to be supplied to the SGR unit  1711 . The method of directly feeding the hot calciner product stream  150  to the SGR unit  1711  is done in such a way to avoid substantially cooling the stream being fed to the SGR unit  1711 . 
     In some aspects, operating the SGR unit  1711  at lower pressures, for example pressures at or below about 10 bar, may also enable methanation suppression within the SGR unit  1711 . In addition, operating at lower pressures can reduce the operating temperature of the SGR unit  1711  from about 900° C. to about 850° C., which can enable a larger choice of materials for vessel construction, which in turn provides for more cost competitive capital cost of the SGR unit  1711 . 
     In some cases, the SGR hot syngas product stream  148  leaving SGR unit  1711  is sent to a syngas treatment unit  1745  where the gaseous composition is adjusted by removing a portion of one or more of the H 2 O, CO 2  and H 2  components such that the syngas stream  1735  leaving the syngas treatment unit  1745  has the desired ratio of H 2 :CO for feeding the downstream Fischer Tropsch unit  112 . In some aspects the syngas treatment unit can include common gas separation equipment, such as membranes, molecular sieves, pressure swing adsorption, thermal swing adsorption and the like. 
     In some cases, the treated syngas product syngas stream  1735  can then be sent to a compression unit  1737  where it is compressed up to the feed pressure for the Fischer Tropsch unit  112 , of approximately 20 to 30 bar. Water produced as a by-product during compression leaves the compressor as stream  1741 . 
     The components separated from the syngas stream  148  within the syngas treatment unit  1745 , for example CO 2  stream  1749 , H 2  stream  1751 , H 2 O stream  1747  or a combination of these components, may be sent back, either separately or mixed, to the SGR unit  1711  as recycle stream(s). 
     The H 2  stream  146  produced by the H 2  generation unit  110  may be split into one or more hydrogen feed streams, for example streams  1764  and  1753 , which can be sent to the SGR unit  1711  and the Fischer-Tropsch unit  112 , respectively. 
     In some implementations, a portion of the necessary heat stream  1729  required for the SGR unit  1711  may come from a combustion operation, for example from one or more of air or oxy-combustion of a fuel source  1761 . The fuel source stream  1761  may include components such as hydrogen, natural gas, light end hydrocarbons from the Fischer Tropsch unit  112  or a combination of the above. 
     In some cases, the heat stream  1729  required for the SGR unit  1711  might be electrically generated, for example through use of commercially available electric elements or heaters, including for example inline pipe electric preheaters. 
     In some aspects, in addition to the hot CO 2  feed stream  150  from the capture subsystem  101 , the SGR unit  1711  may be fed one or more additional feed streams, including for example H 2  split stream  1764 , recycled streams from the syngas treatment unit  1745 , reactant feed streams such as a CH 4  stream  1759 , a steam stream  1755 , the Fischer-Tropsch light end hydrocarbon stream  1754  or a combination of these components. Furthermore, one or more of these feed streams may be used as the hydrogen source for the synthetic production subsystem  101 , additionally or alternatively the use of one or more alternate feedstock streams may enable a reduction or elimination of the use of the hydrogen stream  1764  from the hydrogen generation unit  110 . 
     In some implementations the CH 4  stream  1759  may be available as a less expensive reactant feed stream, and when the CH 4  stream  1759 , the steam stream  1755 , the light end hydrocarbon stream  1754  or any combination of these streams are fed to the SGR unit  1711 , the SGR unit  1711  would then include at least a portion of RWGS, SMR reactions, DMR reactions or a combination of these reactions, to produce the syngas product stream  148 . In some aspects using the CH 4  stream  1759  may be more economic than using the H 2  stream  1764 , for example when renewable electricity is unavailable or expensive and using a CH 4  or Fischer Tropsch light end hydrocarbon source for reactant feedstock to the SGR unit  1711  (and operating the SGR unit  1711  at least in part as an SMR or DMR unit) is more cost effective than running the electrically driven hydrogen production subunit  110  and feeding the resulting H 2  stream  146  as feedstock to the synthetic fuel production subsystem  102 . 
     In some aspects the low pressure SGR unit  1711  described within this implementation may be incorporated into any of the other implementations described in  FIGS.  3 , 7 ,  9 ,  14 ,  19 ,  22  and  23    where hot calciner product gases are sent directly (with or without being first transferred through a high temperature solids removal unit) to the SGR unit  1711  (ie without being cooled, compressed and reheated in between the calciner unit and SGR units). 
     In the implementation shown in  FIG.  18   , one or more of the SGR unit  1711  and calciner unit  1707  may require fuel to combust with the respective oxygen split-streams  1765  and  1766  to provide the operating heat for syngas production and calcination, respectively. In this sense, the oxygen split streams  1765  and  1766  serve as oxidant conduits that transfer material from the hydrogen production subsystem to the synthetic fuel production subsystem and the CO 2  capture subsystem, respectively. The fuel can be provided by an offsite hydrogen supply, hydrogen sourced from the hydrogen production subsystem  110 , natural gas, Fischer Tropsch light end hydrocarbons from the Fischer Tropsch unit  112  or a combination of these components as stream  1761 . 
     In the implementation shown in  FIG.  18   , the calciner unit  1707  may alternatively be heated electrically as is described in  FIGS.  3 ,  14 , and  24  through  26   . In these cases, the CO 2  feed stream  132  going from the calciner  1707  to the SGR unit  1711  may have substantially less or no water content than when the calciner unit  1707  is heated using combustion of a fuel source, and as a result, the calciner product gas stream  132  may not require the same downstream components, for example water removal, prior to being sent to the SGR unit  1711 . 
     Referring now to  FIG.  19    and according to an eighteenth implementation, a synthetic fuel production system  1800  includes the CO 2  capture subsystem  101 , the hydrogen production subsystem  103  and the synthetic fuel production subsystem  102 . All the components of the system  1800  are substantially the same as in the seventeenth implementation of the system  1700  illustrated in  FIG.  18   , with the exception being that the low pressure SGR unit  1711  utilizes electricity to generate all necessary process heat. The synthetic fuel production subsystem  102  includes an electric indirect heater unit  1818  which provides heat stream  1729  to the SGR unit  1711 . 
     In some aspects, one or more of the feed streams to the low pressure SGR unit  1711  are heated using high temperature electric heating components  1863 , for example inline electric heaters, electrical heating tape or resistance heating wire, coils or elements, in some cases constructed from, for example a nickel chromium alloy. In some aspects, these types of electric heating components can operate at temperatures up to approximately 900° C. In some cases some types of heating wires can operate at higher temperatures in order to maintain flowing gas temperatures of about 900° C. 
     One example of commercially available types of inline electric heating products for heating gaseous feed streams may include a heater body constructed of stainless steel, provides heat up to approximately 900° C. and operate up to 4 bar gas pressure, utilizing a range of wattages up to 36 kW and 380 or 480 voltage in either single or three phase. 
     In some aspects, inline electrical heaters can be placed in parallel within the feed stream piping to enable more than one heater to share the heating load. Alternatively, and depending on the heat load, a longer overall length of the heater element can be used. 
     The energy requirement for the electric heater(s) can be calculated by the following simple formula:
 
 E   h =( Q*ΔT )/2500
         Where E h =Heater energy requirement (kW)   Q=gas flow rate (SCFM)   ΔT=change in temperature (° F.)       

     In some aspects, when the SGR unit  1711  operates at lower pressure and temperatures (of up to approximately 10 bar and 850° C., respectively), the above mentioned methods of inline electrical heating of the feed streams are possible. In addition to inline heating of the SGR unit  1711  feed streams, the lower operating pressure of the SGR unit  1711  enables the SGR unit  1711  to operate at a lower operating temperature, for example when the SGR unit  1711  is operating as an RWGS reactor, which can then enable the RWGS reaction to proceed adiabatically to form syngas (for example by using the sensible heat in the inlet feed streams to drive the reaction). In some aspects this can result in a lower product outlet temperature of about 700° C. In some cases, this method of heating (electrically) is done instead of providing heat directly to the SGR unit  1711  by a burner unit combusting fuel in a radiant heat transfer zone. 
     When operated at a lower pressure the SGR unit  1711  can then operate at a lower temp without lowering the selectivity of the target syngas product. 
     Additionally, when the SGR unit  1711  operates at lower pressures, this enables operating at lower temperatures without risking a lower selectivity of the target syngas products. For example, some of the typical side reactions that take place in SGR units, such as the methanation side reaction, are reduced at lower temperatures when operating at lower pressures. 
     In some implementations, these indirect and electrically sourced heating methods may not work as well at higher temperatures, encountered for example with SGR units operating at higher pressures of between 20 bar to 40 bar, due to the temperature limitations of the electrical heating equipment. 
     In this implementation, the hot calciner product stream  150  leaves the CO 2  capture subsystem  101  at approximately 850° C.-900° C. and can then be directly fed into an SGR unit  1711  that is operating at low pressure of slightly above atmospheric, without the need for cooling and compression, preheat exchangers and in some cases with less external heat needing to be supplied to the SGR unit  1711 . The method of directly feeding the hot calciner product stream  150  to the SGR unit  1711  is done in such a way to avoid substantially cooling the stream being fed to the SGR unit  1711 . 
     In addition, operating at lower pressures can reduce the operating temperature of the SGR unit  1711  from about 900° C. to about 700° C., which can also enable a larger choice of materials for vessel construction, which in turn provides for more cost competitive capital cost of the SGR unit  1711 . 
     In some aspects the low pressure electrically heated SGR unit  1711  described within this implementation may be incorporated into any of the other implementations described in  FIGS.  3 , 7 ,  9 ,  14 ,  18 ,  22  and  23    where hot calciner product gases are sent (with or without being transferred through a high temperature solids removal unit  208  first) directly to the SGR unit  1711  ( ie  without being cooled, compressed and reheated in between the calciner unit and SGR units). 
     In the implementation shown in  FIG.  19   , the calciner unit  1707  may require fuel to combust with the oxygen source stream  1766  to provide the operating temperature for calcination. The fuel can be provided by an offsite hydrogen supply, hydrogen sourced from the hydrogen production subsystem  110 , natural gas, Fischer Tropsch light end hydrocarbons from the Fischer Tropsch unit  112  or a combination of these components as stream  1761 . 
     In some aspects, the low pressure electrically heated SGR unit  1711  described herein may be incorporated into any of the other implementations containing an electrically heated calciner, for example  FIGS.  3 ,  14   , and  24  through  26 , such that most if not all external thermal heating requirements for the synthetic fuel production system  100  are supplied from an electric source, rather than from combustion of fuel. In some aspects, this can lower the carbon intensity of the Fischer Tropsch product stream  160 , particularly when the electric source is derived from renewable energy such as hydro, solar, wind, nuclear, geothermal or a combination of these sources. 
     According to a nineteenth implementation, and referring to  FIG.  20   , the synthetic fuel production system  1900  includes the CO 2  capture subsystem  101 , the hydrogen production subsystem  103  and the synthetic fuel production subsystem  102 . The CO 2  capture subsystem  101  has an oxy-fired calciner  1907 , solids removal and clean-up unit  108  and a water treatment unit  109 , and the synthetic fuel production system  102  has an oxy-fired SGR unit  1911 , a Fischer Tropsch unit  1912  and a compression and clean-up unit  1970 . The oxy-fired calciner  1907  has a calciner burner unit  1972  and a calciner reactor vessel  1971 . The SGR  1911  has an SGR burner unit  1968  and an SGR reactor vessel  1969 . 
     The calciner  1907  requires fuel to combust with the oxygen stream  1766  to provide the 900° C. temperature for calcination within the calciner reactor  1971  and the SGR  1911  also requires fuel to combust with the oxygen stream  1765  to provide up to 900° C. temperature for the heat of reaction required for syngas production within the SGR vessel  1969 . The calciner  1907  operates at atmospheric pressure while the SGR unit  1911  may operate at either low or high pressure depending on the application. 
     In some aspects, the oxy-fired calciner burner unit  1972  and SGR burner unit  1968  are fed oxygen, which may be partially or wholly provided by the oxygen by-product stream  143  of the hydrogen production subsystem  110 , as streams  1766  and  1765 , respectively. The fuel for both the calciner burner  1972  and 
     SGR burner  1968  can be provided by a natural gas stream  1952  from an external supply, a hydrogen stream  146  from the H 2  production unit  110  within the hydrogen production subsystem  103 , Fischer Tropsch light end hydrocarbons stream  1954 , or a combination of these streams. The burner design for the calciner burner unit  1972  and the SGR burner unit  1968  can be selected to handle the different types of fuel used—for example, hydrogen fuel requires a burner design that can handle the combustion of hydrogen and its physical properties. These burner designs can be found in a variety of industrial applications. 
     In some aspects, both the fuel and the oxygen are supplied to the calciner burner unit  1972  and SGR burner unit  1968 , which handle the combustion reaction and provide the resulting heat to the calciner reactor vessel  1971  and SGR reactor vessel  1969 , respectively. The combustion reaction products will include H 2 O, and for applications when at least one of the natural gas stream  1952  or Fischer Tropsch light ends hydrocarbon stream  1954  is in use, CO 2 . The combustion reaction products will include a range of concentrations of H 2 O and CO 2 , depending on the composition of the fuel source(s) used. For example, combustion of the natural gas fuel stream  1952  alone will produce slightly different products than when mixed with or replaced completely by the hydrogen fuel stream  146  from the H 2  Production unit  103 . 
     The calciner burner unit  1972  is internal to the calciner reactor and, in fluid bed designs, is located in the solids bed zone, near the bottom of the reactor. In a calciner kiln design, the burner is located at the lower end near where the calcined material exits to a cooler. As a result of the burners being internal to the calciner reactor  1971 , the hot combustion products stream  1967  is mixed and leaves with the calcination reaction products as stream  1932 . 
     The SGR burner  1968  is, with the exception of an SGR configured for autothermal reforming (ATR), located externally to the SGR vessel  1969  and as such provides heat via stream  1973  to one or more SGR vessels  1969 , from burners that can be located within in a furnace box  1999  that encases the one or more SGR vessel tubes (which contain the catalyst bed and through which the feed streams move). In an ATR design, the burners are located in a combustion zone located within the SGR vessel  1969  but upstream of the catalytic zones (not shown). 
     When the SGR burner  1968  is external to the SGR vessel  1969 , the burner&#39;s combustion products, including for example H 2 O, and CO 2  in applications when at least a portion of the natural gas stream  1952  is used for combustion, can be sent via stream  1974  to the compression and clean-up unit  1970 , where any water present is removed as stream  1975  and the CO 2  gas stream  1976 , if present, is compressed before being sent to the SGR vessel  1969  as a feed stream for the syngas reactions. 
     Both the calcium oxide solids stream  131  and calciner gaseous product stream  132  leaving the unit have temperatures of approximately 900° C. 
     In some aspects, the hot calciner gaseous product stream  132  is sent through a high temperature solids removal unit, similar to those in earlier implementations as described in  FIGS.  3 , 7 , 9 , 18 , 19 , 22 , and  23   , so that the resulting solids-free, hot CO 2  product gas stream  150  can be sent directly to the SGR unit  1911 , and in this case, the SGR unit  1911  would be operating at lower pressures, for example between atmospheric to about 10-12 bar, such that the stream  132  would not require cooling or compression prior to being fed into the SGR unit  1911 . 
     In some aspects, the hot calciner gaseous product stream  132  is sent through a solids removal and clean-up unit  108 , which may include a baghouse, electrostatic precipitator, a chiller, a heat exchanger, a condenser, or a combination of these components, where any water and impurities are removed as streams  134  and  138 , respectively, prior to a cooled, compressed CO 2  product stream  150  being sent over to an SGR unit  1911  within the synthetic fuel production subsystem  102 . 
     In some aspects, water streams  134 ,  1975 ,  156 , water streams from other water removal units within the synthetic fuel production system  1900 , or a combination of any of these streams can be sent to a water treatment and source unit  109  where they are cleaned up and recycled back into the overall system  1900 . Make-up or supplemental water can be supplied to the water treatment and source unit  109  via an external source  136 . Water from the water treatment and source unit  109  may be provided to other units within system  1900 . 
     In some cases, the hydrogen production subsystem  103  includes a hydrogen generation unit  110  such as a water electrolyser, and is powered by a power supply such as a renewable source of electricity. This hydrogen generation unit  110  produces a hydrogen product stream  146  and a by-product oxygen stream  143  from a hydrogen feedstock stream  144  (for example water). At least a portion of the by-product oxygen stream  143  is sent to one or more of the oxy-fired calciner  1907  and the oxy-fired SGR  1911  as streams  1766  and  1765  respectively. At least a portion of the hydrogen product stream  146  can be sent as a fuel stream  1979  to the calciner burner  1972 , as a fuel stream  1978  to the SGR burner  1968 , or a combination of thereof. In addition to or instead of use as a fuel source, at least a portion of the hydrogen product stream  146  can be sent as a feed stream  1764  to the SGR unit  1911 , as a feed stream  1753  to the Fischer Tropsch unit  1912  or a combination of these units, as either separate streams, or as a single stream fed first to the SGR unit  1911 , where any unreacted hydrogen leaves the SGR unit  1911  with the product SGR gases in stream  148  and is then sent to the Fischer-Tropsch unit  1912 . The syngas stream  148  is cooled down (not shown) before entering the Fischer-Tropsch unit  1912 . 
     The hydrogen product stream  1753  and the syngas stream  148  are reacted within the Fischer-Tropsch unit  1912  to produce hydrocarbon products. Light end hydrocarbons stream  1954  produced by the Fischer-Tropsch unit  1912  can be sent back within the system  1900 , for example to the oxy-fired calciner burner  2072  via split-stream  1980 , to the oxy-fired SGR burner  2068  via split-stream  1981 , or a combination thereof, to be used as fuel. In this sense, light end hydrocarbons split streams  1980  and  1981  serve as fuel conduits that transfer fuel from the synthetic fuel production subsystem to the calciner and the SGR respectively. Additionally or alternatively, at least a portion of the Fischer Tropsch light ends stream  1954  can be sent to the SGR vessel  1969  as a reactant feed (not shown). Heavier hydrocarbons are sent downstream for further processing or final product as stream  160 . 
     According to a twentieth implementation, and referring to  FIG.  21   , the synthetic fuel production system  2000  includes the CO 2  capture subsystem  101 , the hydrogen production subsystem  103  and the synthetic fuel production subsystem  102 . The components within the synthetic fuel production system  2000  are similar to those described in the nineteenth implementation shown in  FIG.  20   , with the exceptions being that the SGR unit  2011  and calciner unit  2072  are oxy-fired with fuel sources other than hydrogen. 
     The calciner  2007  requires fuel to combust with the oxygen stream  1766  to provide the 900° C. temperature for calcination within the calciner reactor  1971  and the SGR  2011  also requires fuel to combust with the oxygen stream  1765  to provide up to 900° C. temperature for the heat of reaction required for syngas production within the SGR vessel  1969 . The calciner  2007  operates at atmospheric pressure while the SGR unit  2011  may operate at either low or high pressure depending on the application. 
     In some aspects, the oxy-fired calciner burner unit  2072  and SGR burner unit  2068  are fed oxygen, which may be partially or wholly provided by the oxygen by-product stream  143  of the hydrogen production subsystem  103 . In this sense, the calciner burner unit  2072  and the SGR burner unit  2068  serve as heaters, where they produce and transfer heat to the calciner reactor  1971  and the SGR vessel  1969 , respectively. 
     The fuel for both the calciner burner  2072  and SGR burner  2068  can be provided by a natural gas stream  1952  from an external supply, a light end hydrocarbon by-products stream  1954  from a Fischer Tropsch unit  1912  within the synthetic fuel production subsystem  102 , or a combination of these streams. 
     Both the fuel and the oxygen are supplied to the calciner burner unit  2072  and SGR burner unit  2068 , which handle the combustion reaction and provide the resulting heat to the calciner reactor vessel  1971  and SGR reactor vessel  1969 , respectively. The combustion reaction products will include H 2 O and CO 2 , in a range of concentrations depending on the composition of the fuel source(s) used. For example, combustion of the natural gas fuel stream  1952  alone will produce slightly different products than when mixed with or replaced completely by the light end hydrocarbon by-product fuel stream  1954  from the Fischer Tropsch unit  1912 . 
     The hydrogen production subsystem  103  includes a hydrogen generation unit  110  such as a water electrolyser, and is powered by a power supply such as a renewable source of electricity. This hydrogen generation unit  110  produces a hydrogen product stream  146  and a by-product oxygen stream  143  from a hydrogen feedstock stream  144  (e.g. water). At least a portion of the by-product oxygen stream  143  is sent to one or more of the oxy-fired calciner  2007  and the oxy-fired SGR  2011  as streams  1766  and  1765  respectively. The hydrogen product stream  146  can be sent as a feed stream  1764  to the SGR vessel  1969 , as a feed stream  1753  to the Fischer Tropsch unit  1912  or a combination of these units, as either separate streams, or as a single stream fed first to the SGR vessel  1969 , where any unreacted hydrogen leaves the SGR vessel  1969  with the product SGR gases in stream  148  and is then sent to the Fischer-Tropsch unit  1912 . The syngas  148  is cooled down (not shown) before entering the Fischer-Tropsch unit  112 . 
     The hydrogen product stream  1753  and the syngas stream  148  are reacted within the Fischer-Tropsch unit  1912  to produce hydrocarbon products. Light end hydrocarbons stream  1954  produced by the Fischer-Tropsch unit  1912  can be sent back within the system  1900 , for example to the oxy-fired calciner burner  2072  via stream  1980 , to the oxy-fired SGR burner  2068  via stream  1981 , or a combination thereof, to be used as fuel. Additionally or alternatively, light end hydrocarbons stream  1954  can be sent to the SGR reactor vessel  1969  as a reactant feedstock (not shown), for example in the cases where the SGR reactor vessel is operating at least as a partial SMR or DMR. 
     In some implementations, the lighter hydrocarbons produced by the synthetic fuel production subsystem  102 , for example by the Fischer-Tropsch unit  1912 , may be recycled back within the synthetic fuel production subsystem  102 . Heavier hydrocarbons are sent downstream for further processing or final product as stream  160 . 
     According to a twenty-first implementation, and referring to  FIG.  22   , a synthetic fuel production system  2100  includes the CO 2  capture subsystem  101 , the hydrogen production subsystem  103  and the synthetic fuel production subsystem  102 . All the components of the system  2100  are substantially the same as in the first implementation of the system  100  illustrated in  FIG.  1   , with the exceptions being that the synthetic fuel production subsystem  102  in this implementation includes componentry such as a bubbling fluidized bed (BFB) preheat exchanger  2114 , and a water knockout and compression unit  2187 . The SGR unit  1711  is configured to operate as an RWGS reactor with the option of including one or more of SMR reactions, DMR reactions and the like, by taking in, in addition to CO 2  stream  2150 , one or more feed streams including for example steam stream  1755 , methane stream  1759 , H 2  stream  1764 , Fischer Tropsch light ends stream  1754 , fuel stream  1761 , depending on the mode of SGR operation required. 
     In some cases, the calcium carbonate pellet stream  2130 , which could be coming for example from an upstream slaker unit or pellet reactor unit within the CO 2  capture subsystem  101 , is preheated through the BFB preheating exchanger unit  2114 . The BFB preheating unit  2114  can include components such as a distributor plate  2186 , an outer vessel  2183 , a refractory or ceramic lining  2184 , and a bubbling bed zone  2182 . 
     In this implementation, the SGR unit  1711  is configured as a low pressure SGR, operating at pressures slightly above atmospheric. 
     In some aspects, at least a portion of the hydrogen stream  146  can be sent directly to the Fischer Tropsch unit  2112  as stream  1753 , and the SGR hot gaseous product stream  2148  is sent to the BFB preheating unit  2114 , wherein it fluidizes the solid CaCO 3  material and heat is transferred from the hot syngas stream  2148  to the solid CaCO 3  material as they mix in the bubbling bed zone  2182 . In some aspects, the syngas stream  2148  is cooled from about 900° C. to about 420° C. if, for example the pellet stream  2130  was preheated in an upstream slaker unit (not shown) and as such was then fed to the preheat exchanger  2114  at a higher temperature of about 300-350° C. In some aspects, the syngas stream  2148  is cooled from about 900° C. to about 150° C. if for example the pellet stream  2130  was not preheated in an upstream unit prior to entering the BFB preheating unit  2114 , and as such was fed to the preheat exchanger  2114  at a lower, near ambient temperature, of about 10-25° C. The CaCO 3  material stream  2130  is heated in the BFB preheat exchanger  2114  from as low as ambient up to a maximum of about 800° C. before being fed into the calciner  1707 . In some aspects, the hydrogen stream  2183  can be combined with the hot SGR stream  2148  upstream of the bubbling bed heat exchanger  2114 . The cooled syngas stream  2121  leaves the BFB preheating unit  2114  and proceeds to a water knockout and compression unit  2187 , where the moisture present in cooled syngas exits the unit  2187  as stream  2158 . The cooled dry syngas is then compressed up to about 30 bar and leaves unit  2187  as stream  2188  and is sent to the Fischer Tropsch unit  2112 . The heated CaCO 3  material stream  130  is transferred to the calciner unit  1707  for calcining. 
     BFB heat exchange equipment is frequently used in calcination processes, and can be constructed of refractory or ceramic lined vessels, with the external vessel  2183  being constructed out of inexpensive materials, for example including but not limited to carbon steel, as the external vessel is protected by the refractory lining from the high temperatures operating conditions. Using this type of direct heat exchange equipment enables direct heat transfer between the CaCO 3  pellets and hot fluid streams, and due to the nature of the materials interfacing within the unit, (ie the CaCO 3  pellets mix with syngas in a refractory lined vessel) there is no risk of metal dusting, which can be a common problem in equipment/facilities working with syngas streams. 
     The SGR unit  1711  as shown in this implementation can operate as an RWGS reactor with one or more of SMR, DMR reactions. This SGR unit  1711  as shown in this implementation can use feed streams for syngas reactants including for example the calciner gaseous product stream  2150  which contains at least a portion of CO 2  and may also contain H 2 O. The SGR unit  1711  may also be fed a portion of CH 4  from stream  1759 , Fischer Tropsch light ends stream  1754 , or a combination of both, and a portion of steam from stream  1755 . These streams may be provided as reactant feedstock to the SGR unit  1711  in order to reduce or eliminate the need for the hydrogen stream  1764  supplied from the hydrogen production subunit  110 . For example, the SGR unit  1711  may be operated wholly or partially as an SMR, taking in feedstocks including CH 4  stream  1759 , optionally or additionally Fischer Tropsch light ends stream  1754 , and steam stream  1755 , in order to produce syngas for the Fischer Tropsch unit  2112 . 
     In some implementations, the H 2  product stream  146  from the H 2  generation unit  110  can be split, and fed into the system at a variety of points, such as streams  1753 ,  1764  and  2183 , that are fed as H 2  feedstock to the Fischer Tropsch unit  2112 , feedstock to the SGR unit  1711  and fed upstream of BFB preheat exchanger  2114  to mix with the hot syngas stream  2148 , respectively. In some implementations the CH 4  stream  1759 , the Fischer Tropsch light ends stream  1754 , or a combination of the two may be available as less expensive/readily available sources of hydrogen, and when one or more of the CH 4  stream  1759 , FT light ends stream  1754  and steam stream  1755  are fed to the SGR unit  1711 , the SGR unit  1711  would then, in addition to RWGS reactions, include at least a portion of SMR reactions, DMR reactions or a combination of any of the above, to produce a syngas product stream  2148 . 
     In some aspects using CH 4  as feedstock to the SGR unit  1711  may be more economic, for example when renewable electricity is unavailable or expensive and using a CH 4  source for hydrogen in the synthetic fuel production subsystem  102  is more cost effective than running the electrically driven hydrogen production subunit  110 . 
     In the implementation shown in  FIG.  22   , one or more of the SGR unit  1711  and calciner unit  1707  may be oxy-fired and as such may require a fuel source to combust with an oxygen source. In some cases, oxygen streams  1765  and  1766  from the hydrogen production unit  110  can be combusted with the fuel source to provide heat for syngas production and calcination, respectively. The fuel to one or both SGR unit  1711  and calciner unit  1707  can be provided by an offsite hydrogen supply, hydrogen sourced from the hydrogen production subsystem  110 , natural gas, Fischer Tropsch light end hydrocarbons from the Fischer Tropsch unit  2112  or a combination of any of the above as fuel stream  1761 . In this case, the combustion products from heating the SGR unit  1711  can be treated and used within another subsystem, for example the CO 2  can be isolated and incorporated into the SGR unit  1711  feed stream  2150 . 
     Both the calcium oxide solids stream  131  and calciner gaseous product stream  132  leaving the unit have temperatures of approximately 900° C. The hot calciner gaseous product stream  132  is sent through a high temperature solids removal and clean-up unit  2108 . In some aspects, water may optionally be removed as stream  2134 , and impurities are removed as stream  2138 , prior to sending the hot CO 2  product stream  2150  over to the SGR unit  1711  within the synthetic fuel production subsystem  102 . 
     In the implementation shown in  FIG.  22   , one or more of the SGR unit  1711  and calciner unit  1707  may be heated electrically as is described in  FIGS.  19  and  27    for electrically heated SGR units, and  FIGS.  3 , 14 , 24  to  26    for electrically heated calciners, respectively, instead of using combustion of fuel for process heat. In some aspects, the CO 2  feed stream  132  going from the calciner  1707  to the SGR unit  1711  may have substantially less or no water content than when the calciner unit  1707  is heated using combustion of a fuel source. As a result, the downstream high temperature solids removal unit  2108  may not require water removal equipment, as there would be no combustion products, only dust  2138  and calcination products  2150  (ie the stream would be mostly CO 2 ). 
     In the implementation shown in  FIG.  22   , the low pressure SGR unit  1711  may be replaced by a high pressure SGR unit (not shown). A high pressure SGR unit  1711  may be configured to operate at pressures up to about 30 bar. For cases using a high pressure SGR, a standard solids removal and cleanup unit  108  may be used instead of the high temperature solids removal and cleanup unit  2108  to remove impurities and water from the calciner product stream  132 . Additionally, the water knockout and compression unit  2187  would no longer require compression equipment to feed stream  2188  into the Fischer Tropsch operating pressure. 
     The BFB preheat unit  2114  as described in this implementation and shown in  FIG.  22    may also be used in implementations similar to those shown in  FIG.  10   , in place of the heat exchange unit  901 . 
     According to a twenty-second implementation, and referring to  FIG.  23   , a synthetic fuel production system  2200  includes the CO 2  capture subsystem  101 , the hydrogen production subsystem  103  and the synthetic fuel production subsystem  102 . All the components of the system  2200  are substantially the same as in the twenty-first implementation illustrated in  FIG.  22   , with the exceptions being that the calcium carbonate pellets are preheated through a cyclone preheating unit  2214  located within the synthetic fuel production subsystem  102 . 
     Cyclone gas-solid separation equipment is common in calcining processes, and cyclones can be constructed of refractory or ceramic materials, or a combination of these materials. In some aspects, the diameter of the cyclone preheating unit  2214  may be enlarged to promote longer residence times for the solid CaCO 3  material of stream  2130  to be in contact with the hot syngas stream  2148  within the cyclone preheat unit  2214  before dropping out of the bottom and transferring to the calcination unit  1707 . Using this type of equipment for direct heat exchange enables heat transfer between the CaCO 3  pellet stream  2130  and hot fluid stream  2148 , and due to the nature of the materials interfacing within the unit, (ie the CaCO 3  pellets mix with hot syngas in a refractory lined vessel) there is no risk of metal dusting, which can be a common problem in other syngas generation heat exchange systems. 
     The cyclone preheat unit  2214  as described in this implementation and shown in  FIG.  23    may also be used in implementations similar to those shown in  FIG.  10   , in place of the heat exchange unit  901 . 
     According to a twenty-third implementation, and referring to  FIG.  24   , an electric calcining subsystem  2300  is shown and includes an electric bubbling fluidized bed (BFB) calciner unit  2307 , and can also include components such as one or more staged preheat cyclones  2301 , a water knockout, heat recovery and solids removal unit  108 , a compression unit  2391 , a boiler unit  2317 , or combinations of any of these units. This calcining subsystem  2300  can be used in whole or in part where an electric calciner is suggested (as described in  FIGS.  3 , 14 ,  18 ,  19 ,  22 ,  23 ,  25  to  29   ) or in some cases, can be optionally substituted in for an oxy-fired calciner unit without changing the key features of the implementation, for example those implementations shown in  FIGS.  5 , 11 , 12   . 
     The electric BFB calciner unit  2307 , which is a type of fluidized bed reactor vessel, has componentry such as an insulation or refractory lining  2384  that is encased in an outer vessel  2383 . The outer vessel provides structural support to the unit and may be constructed of inexpensive material such as carbon steel for example, due to being shielded from most of the calciner operating temperature by the insulation or refractory lining  2384 . The BFB calciner  2307  also has a distributor plate  2386 , a bubbling bed calcination zone  2382 , electric heating elements  2389 , which may or may not be sheathed in a protective casing, and a controlled discharge device  2390 . 
     In some aspects, a CaCO 3  material feed stream  2130  may be preheated, for example by feeding directly into the electric BFB calciner product gas stream  132  upstream of a preheat cyclone  2301 . In some aspects, the solid feed stream  2130  may additionally or alternatively be heated indirectly by a process waste heat exchange unit (not shown), prior to entering the BFB calciner  2307  as preheated CaCO 3  stream  130 . Within the electric BFB calciner  2307 , the CaCO 3  material fluidizes in the bubbling bed calcination zone  2382 , which mixes the gases and solids together similar to a continuously stirred tank reactor (CSTR) vessel. The solid material including CaCO 3  moves through the bed towards the exit, and as it does, it interfaces with the high temperature fluidizing gases and heat from the electric heating elements  2389 . During this process, the CaCO 3  material calcines causing the CaCO 3  to release gaseous CO 2  and form solid calcium oxide, or CaO. Both the calcium oxide solid stream  131  and calciner gaseous product stream  132  leaving the electric fluidized bed calciner unit  2307  can have temperatures of up to approximately 900° C., which makes recovering and using the high-grade heat in these streams (eg within other units) desirable. 
     The hot calcium oxide solid stream  131  leaves the electric BFB calciner  2307  by overflowing into the end zone portion  2385  where it then drops into a controlled discharge device  2390 , such as a loop seal, for example a fluoseal, or similar device after which it can be pneumatically or mechanically conveyed to downstream processes. In some aspects, the hot CaO can be sent through a heat exchange unit, in order to transfer at least a portion of the heat to one or more feed streams or intermediated streams within the process, for example to superheat the fluidization gases for the electric BFB calciner  2307 . In some aspects, the fluidized bed calciner  2307  is physically located in close proximity to the heat exchange unit, such that the hot CaO stream  131  can drop by gravitational means from the fluidized bed calciner  2307  directly into the heat exchange unit without need for pneumatic or mechanical conveyance. 
     In some implementations, the bubbling bed calcination zone  2382  is fluidized with a gaseous stream  2334 , which may include hot gases such as steam. This fluidization stream  2334  enters the electric BFB calciner  2307  near the bottom portion of the vessel, through a distributor plate  2386  and flows up through the calcination bubbling bed zone  2382 , mixing with the solid bubbling bed material and the gaseous CO 2  product stream. 
     The mixed gaseous stream, including a mix of fluidizing gas (for example steam), CO 2 , and any fluidized impurities and dust present exits the top of the electric BFB calciner  2307  as stream  132 , where it moves counter currently through one or more cyclones  2301  to preheat the solid feed CaCO 3  pellets stream  2130  before leaving as cooled gaseous product stream  2332 . This cooled stream may then be sent to a water knockout heat recovery &amp; solids removal unit  108  where any dust present in the stream  2332  is removed as stream  138 . In some aspects, most of the heat in gas stream  132  is recovered in one or more cyclone units  2301  (eg transferred to the feed CaCO 3  stream  2130 ), so that the water knockout, heat recovery &amp; solids removal unit  108  can include a simple direct contact cooler (ie it does not need further heat recovery). In some aspects, where there is enough heat left in stream  2332  after using it to preheat the CaCO 3  stream  2130 , the remaining heat could be extracted using another heat exchanger, for example to preheat boiler feed water for the boiler and desuperheater unit  2317 . In some aspects, where the stream  2332  temperature is below about 150° C., further heat recovery may not be required and instead the stream could be cooled with a direct contact cooler to knockout the water and remove dust as part of the water knockout, heat recovery &amp; solids removal unit  108 . 
     In some aspects, dust stream  138  can be sent with the cooled CaO material stream  131  to downstream processes, such as a slaker unit, or offsite disposal (not shown) or combination of both. Water from the water knockout heat recovery &amp; solids removal unit  108  is condensed and sent as stream  134  to a boiler unit  2317  where it is converted back to steam and sent back into the electric BFB calciner  2307  as stream  2334  to continue fluidizing the bed. In some aspects, a portion of available steam from units within other subsystems, for example excess steam from the slaker unit  106 , the Fischer Tropsch unit  112 , or a combination of the these units (not shown) may be combined with water in the boiler and desuperheater  2317  to produce LP steam stream  2334  that is then fed into the BFB calciner  2307  with or without additional heating. Optionally, the stream  2334  may be superheated using a heat exchange equipment (not shown), before being sent to the BFB calciner  2307 . 
     The concentrated gaseous CO 2  stream leaves the water knockout &amp; solids removal unit  108  as stream  150  and can optionally be sent to a compression unit  2391 , where it can be compressed if necessary to meet the operating conditions for downstream processes. In some aspects, downstream processes can, for example, include an SGR unit within the synthetic fuel production subsystem  102  as described in  FIG.  2 - 5 , 11 , 12 , 14 , 18 - 23 , 27 - 29   , an off-site user or combinations of both. The compressed CO 2  gas exits the compression unit  2391  as stream  2350 . 
     The electric BFB calciner  2307  is heated with electric elements  2389  which can be encased in a metal sheath through which the generated heat can be conducted, can be coupled to the refractory lined walls  2384 , can extend into the fluidized bed zone  2382 , or can include a combination of any of these aspects. These electric elements  2389  and their surroundings act to generate and distribute heat into the calcination bubbling bed zone  2382  to maintain the operating temperature of up to 900° C. Due to the fluidization nature of this BFB calciner design, the heat is transferred efficiently from the elements throughout the bed to the CaCO 3  material, maximizing the bed-side heat transfer coefficient while minimizing both the risk of hot spots as well as build-up of CaO on the walls. Additionally, this design can allow for the bubbling bed calcination zone  2382  to operate, in some cases, at slightly lower temperatures, for example within the range of between 850° C.-870° C. In some cases, the fluidization velocity of the steam stream  2334  can maximize the bed-side heat transfer film coefficient in the BFB calciner  2307 . 
     Electrically heated calciner as described in  FIG.  24    can be incorporated into many of the other implementations described herein, in whole or in part where an electric calciner is suggested (as described in  FIGS.  3 , 14 ,  18 , 19 ,  22 ,  23 ,  27  to  29   ) or in some cases, can be optionally substituted in for an oxy-fired calciner unit without changing the key features of the implementation, for example those implementations shown in  FIGS.  5 , 11 , 12   . By doing so, those implementations can take further advantage of renewable energy sources instead of fossil fuel energy sources, and the resulting process can have one or more of a lower carbon intensity product, lower capital costs, lower operating costs or a combination of these advantages. Furthermore, electrically heated calciners can be incorporated within systems operating an electric SGR as suggested in  FIGS.  19 ,  22 ,  23  and  27   , taking further advantage of renewable energy sources instead of fossil fuel energy sources for the overall system thermal heat requirements. 
     According to a twenty-fourth implementation, and referring to  FIG.  25    the synthetic fuel production system  100  includes the CO 2  capture subsystem  101 , the hydrogen production subsystem  103  and the synthetic fuel production subsystem  102 . The CO 2  capture subsystem  101  has a calciner unit  2500  that includes an electric bubbling fluidized bed (BFB) calciner  2507 , coupled with one or more preheat cyclone units  2501 , a water knockout and solids removal unit  108 , a compression unit  2391  and a boiler unit  2317 . The BFB calciner  2507 , which is a type of fluidized bed reactor vessel, includes an internal process vessel  2585  which is wrapped in an insulation or refractory lining  2584  and encased in an outer vessel  2583 . The BFB calciner  2507  also includes a distributor plate  2586 , a solids discharge device  2390 , and electric elements  2589  that can be housed in an element housing zone  2592  between the refractory lining  2584  and the internal process vessel  2585 . 
     In some aspects, the outer vessel provides structural support to the unit and may be constructed of inexpensive material such as carbon steel for example, due to being shielded from the high calciner operating temperature by the insulation or refractory lining  2584 . The internal process vessel may be constructed of heat resistant materials such as 253MA, Inconells, hastelloy, or any other material with similar properties that can maintain structural integrity under high temperature operating conditions. 
     In some aspects, the electric elements  2589 , which may or may not be sheathed in a protective metal casing, are located in a housing zone, or gap, between the refractory lining  2584  and the internal process vessel  2585 . These elements generate heat that radiates through the housing zone  2592  and is then conducted through the internal process vessel walls  2585  and into the calcination bubbling bed zone and internal head space  2593  to maintain the calciner operating temperature of up to 900° C. Both the calcium oxide solid stream  131  and calciner gaseous product stream  132  leaving the electric BFB calciner unit  2507  can have temperatures of up to approximately 900° C., which makes recovering and using the high grade heat in these streams (eg within other units) desirable. 
     In some aspects, the cool CaCO 3  material stream  2130  is first mixed with the hot calciner product gas stream  132  prior to entering one or more cyclone preheat stages  2501 , in order to transfer at least a portion of the sensible heat within the hot calciner product gas stream  132  to the feed CaCO 3  material stream  2130 , as well as to help convey the solids into the preheat cyclones  2501 . The preheated CaCO 3  material stream  130  then enters the BFB calciner internal process vessel  2585  and is fluidized in the bubbling bed zone  2582 . Due to the high temperature in the BFB calciner  2507 , the CaCO 3  solids calcine causing the CaCO 3  to release gaseous CO 2  as it calcines to solid calcium oxide. The hot calcium oxide solid stream  131  leaves the BFB calciner  2507  near the bottom of the vessel, through a controlled discharge device  2390  such as loop seal, fluoseal or the like. In some aspects, electric BFB calciner  2507  may be physically located in close proximity to a heat exchange unit (not shown) such that the hot CaO stream  131  can drop by gravitational means from the electric BFB calciner  2507  directly into the heat exchange unit without need for pneumatic or mechanical conveyance. 
     The BFB calciner  2507  is fluidized with a steam stream  2334  that enters the BFB internal process vessel  2585  near the bottom through a distributer plate  2586 , and flows up through the calcination bubbling bed zone  2582 , mixing with the solid bubbling bed material and the gaseous CO 2  product stream. The mixed gaseous stream of H 2 O, CO 2 , impurities and trace amounts of dust exits the top of the BFB calciner and through the cyclone  2501  where at least a portion of the dust is separated and sent back into the calciner  2507  while the remaining gases exit as stream  2532  and then move to a water knockout, heat recovery &amp; solids removal unit  108 . Here, any remaining heat can optionally be removed and exchanged with other process streams, or a direct contact cooler, as appropriate. In some aspects, where there is enough heat left in stream  2532  after using it to preheat the CaCO 3  stream  2130 , the remaining heat could be extracted using another heat exchanger, for example to preheat boiler feed water for the boiler and desuperheater unit  2317 . In some aspects, where the stream  2532  temperature is below about 150° C., further heat recovery may not be required and instead the stream could be cooled with a direct contact cooler to knockout the water and remove dust as part of the water knockout, heat recovery &amp; solids removal unit  108 . 
     Also in some cases, any remaining dust present is removed in unit  108  and leaves as stream  134 , where it can be combined with the solid calcium oxide stream  131  and sent to downstream process units, for example a waste heat recovery unit, and then on to a slaker unit (not shown), or offsite disposal (not shown), or a combination of both. 
     In some aspects, water is condensed in unit  108  and sent to a boiler  2317  as stream  134  where it can be converted to steam and sent back into the BFB calciner  2507  as stream  2334  to continue fluidizing the bed. In some aspects, the boiler  2317  is heated at least in part using waste process heat, electric heat or a combination of these heat sources. In some aspects, a portion of available steam from units within other subsystems, for example excess steam from the slaker unit  106 , the Fischer Tropsch unit  112 , or a combination of the these units (not shown) may be combined with water in the boiler and desuperheater  2317  to produce LP steam stream  2334  that is then fed into the BFB calciner  2307  with or without additional heating. Optionally, the stream  2334  may be superheated using a heat exchange equipment (not shown), before being sent to the BFB calciner  2307 . 
     In some aspects, the concentrated gaseous CO 2  stream  150  leaves the water knockout &amp; solids removal unit  108  and is sent to a compression unit  2391 . After compression, the CO 2  stream  2550  can be sent to downstream processing, for example to the synthetic fuel production subsystem  102 , and in some cases, to an SGR unit (not shown). Both the calcium oxide solid stream  131  and calciner hot gaseous product stream  132  leaving the BFB calciner unit  2507  can have temperatures of up to approximately 900° C., and as such, methods by which their sensible heat is recycled or transferred to other process streams are employed in this implementation to reduce waste heat and improve overall process energy use. 
     Due to the fluidization nature of this calciner design, the heat generated by the electric elements  2589  can be transferred efficiently from the elements throughout the bed, minimizing both the risk of hot spots as well as build-up of CaO on the walls, and can allow for the unit to operate, in some cases, at slightly lower temperatures, for example within the range of between 850° C.-870° C. 
     This type of electrically heated calciner can be incorporated into many of the other implementations described herein, for example implementations as shown in  FIGS.  3 , 14 ,  18 , 19 ,  22 ,  23 ,  27  to  29   . This type of electric calciner can be substituted for the oxy-fired calciner units in implementations described in  FIGS.  5 , 11 , 12   , without harming the features already described in those figures, and by doing so, those implementations can take further advantage of renewable energy sources. Furthermore, this electric calciner can be incorporated within systems operating an electric SGR as described in  FIGS.  19 ,  22 ,  23  and  27   , further taking advantage of renewable energy sources instead of fossil fuel energy sources for the overall system thermal heat requirements, and the resulting process can have one or more of a lower carbon intensity product, lower capital costs, lower operating costs or a combination of these advantages. 
     In some aspects, the electric elements  2589  are sheathed and as such act more like an electric heater, such that they can be coupled to other metal surfaces within the unit without causing the elements to fail or burn out. In other cases, the electric elements  2589  are exposed, and as such must be surrounded in a housing zone  2592  or the like, such that a gap exists between any conductive surfaces/material and the element itself. 
     According to a twenty-fifth implementation, and referring to  FIG.  26    the calciner unit  2600  includes an electric kiln calciner  2607 , which is coupled with a solids removal unit  108  and a compression unit  2391 . 
     The electric kiln calciner  2607 , that serves as a kiln reactor vessel, has an internal process vessel  2685  which is wrapped in an insulation or refractory lining  2684  and encased in an outer vessel  2683 . The outer vessel provides structural support to the unit and may be constructed of inexpensive carbon steel due to being shielded from the calciner operating temperature by the insulation or refractory lining  2684 . The internal process vessel may be constructed of heat resistant materials such as 253MA, Inconells, hastelloy, or any other material with similar properties that can maintain structural integrity under high temperature operating conditions. The electric heating elements  2689  can be housed in an element housing zone  2692  which provides a gap between the elements and the internal process vessel wall  2685 , through which heat can be conducted. 
     In some aspects, the electric kiln calciner  2607  can be heated with an electric element  2689  that is located in the element housing zone  2692 . Optionally or additionally, the wall of the internal process vessel  2685  is coupled to the metal heat fins  2693 , and the heating elements can generate heat which then conducts through the walls of the internal process vessel  2685 , the metal fins  2693  or a combination of the two components into the calcination zone  2682  and solid bed material to maintain the operating temperature of up to 1000° C., for example when operating with 100% CO 2  atmosphere in the kiln. In some aspects, the heating elements are configured similar to electric pottery kilns. 
     The electric kiln calciner  2607  is fed CaCO 3  material stream  130  which, as it travels through the calcination zone  2682 , calcines to release gaseous CO 2  and solid CaO. The solid CaO moves towards the bottom of the kiln  2607  and exits via the controlled discharge device  2390  as stream  131 . In some aspects where stream  131  leaves the process vessel  2685  at a high temperature, for example up to 900° C., it will be discharged through a controlled discharge device  2390  such as a loop seal fluoseal, or the like. In some aspects where cooling of stream  131  is possible between the electric kiln calciner vessel  2685  and the controlled discharge device  2390 , The controlled discharge device  2390  can include a wider range of discharge devices, for example a mechanical discharge device including a lock hopper, rotary valve or the like. 
     While the solid material moves toward the bottom portion of the internal process vessel  2685 , The gaseous CO 2  moves up through the calcination zone  2682 , as it does it also moves through and heats the solid material. In some cases, prior to exiting the electric kiln calciner, the hot calcination gases move through a bed of CaCO 3  material that is entering the calciner, acting to preheat these feed solids, similar to the configuration of a shaft kiln. 
     The cooled gas stream leaves the top portion of the electric kiln calciner via stream  2632 , where it is then transferred to a solids removal unit  108 . Once substantially free of any dust (stream  138 ), the gaseous CO 2  stream  150  can be transferred to a compression unit  2391  before being sent as stream  2650  to other processing units, for example an SGR unit (not shown). 
     In some aspects, where the electric heating elements  2689  are configured so that they can operate under direct contact with the hot CaCO 3 /CaO material in the calcination zone  2682  without significant fouling, corrosion or the like, then inserting the elements  2689  directly into the bed would be another option for electrically heating the calciner kiln unit  2607 . 
     In some aspects, the heat produced by the electric heating elements  2689  moves out from the exposed electric heating elements  2689 , the metal fins  2693 , the internal process walls  2685 , or a combination of any of the above, in a radial direction towards the center of the calcination zone  2682 . This electric energy can see several types of heat transfer resistance between the heating element and the targeted CaCO 3  material, including for example the element material itself, any solid CaO lining the internal process vessel wall or fins, the gaseous environment within the calcination zone  2682  and finally, the CaCO 3  material itself. The heat transfer through these layers of resistance can be slow, and therefore there is a preferred diameter range for the internal process vessel  2685  of between 6 to 18 inches internal diameter, such that sufficient heat can extend throughout the calcination zone and heat the CaCO 3  up to a calcination temperature of about 900° C. 
     This type of electrically heated kiln calciner  2607  can be incorporated into many of the other implementations described herein, for example implementations as shown in  FIGS.  3 , 14 ,  18 , 19 ,  22 ,  23 ,  27  to  29   . This type of electric kiln calciner  2607  can be substituted for the oxy-fired calciner units in implementations described in  FIGS.  5 , 11 , 12   , without harming the features already described in those figures, and by doing so, those implementations can take further advantage of renewable energy sources. 
     Furthermore, this electric calciner can be incorporated within systems operating an electric SGR as described in  FIGS.  19 ,  22 ,  23  and  27   , further taking advantage of renewable energy sources instead of fossil fuel energy sources for the overall system thermal heat requirements. 
     According to a twenty-sixth implementation, and referring to  FIG.  27    a synthetic fuel production system  2700  includes the CO 2  capture subsystem  101 , the hydrogen production subsystem  103  and the synthetic fuel production subsystem  102 . The CO 2  capture subsystem includes a calciner unit  1707 . The synthetic fuel production subsystem  102  has an SGR unit  2711  coupled to a ceramic heat exchanger  2714  and a Fischer Tropsch unit  2712 . The SGR unit  2711  includes a boiler  2717 , the SGR reactor vessel  2769  and the electric elements  2718  that produce the heat stream  2773  required for the syngas process occurring in the SGR reactor vessel  2769 . 
     Ceramic heat exchangers are used in various high temperatures and corrosive industrial applications, including for example heat exchange units such as furnaces, boilers, and the like. Ceramic heat exchangers are capable of gas-gas heat exchange at high temperatures such as those used in the SGR unit, up to about 1100° C. in cases where for example the SGR unit  2711  is operated under ATR conditions. Ceramic heat exchangers can be made of various ceramic materials such as for example silicon carbide or alumina. Silica carbide can be less expensive than alumina but more prone to corrosion under high temperature water vapour environments. In addition to the ceramic material, ceramic heat exchangers can have metal shells and components. 
     In the implementation shown in  FIG.  27   , the ceramic heat exchanger  2714  is used to exchange heat between the SGR unit  2711  hot syngas product stream  148  and one or more of the SGR unit  2711  gaseous feed streams (including components such as CO 2 , H 2 O, CH 4 , H 2 , Fischer Tropsch light ends and the like, resulting in a hot SGR feed stream  2750  for the SGR vessel  2711  and a cooled syngas product stream  2748  that is sent as feed to the Fischer Tropsch unit  2712 . In some aspects, the gaseous feed streams may enter the ceramic heat exchanger  2714  as separate streams or in a combined stream. The ceramic heat exchanger  2714  is required for this application, as common metal and alloy heat exchangers exposed to the hot SGR product gas stream conditions and temperatures would be prone to metal dusting issues, where as ceramic heat exchange materials are not prone to metal dusting. Metal dusting is a common problem in syngas and reforming processes when metal or alloy surfaces, for example mild steel, stainless steel, iron and nickel based alloys, are exposed to the process operating conditions. The result is a deterioration in the metal material, ultimately requiring replacement. Industry typically reduces metal dusting issues by cooling the gas streams to temperatures where metal dusting does not occur—this results in wasted energy and low process efficiencies. 
     The ceramic heat exchanger can be used in all applications where the SGR unit product gas stream  148  is used to preheat one or more of the SGR unit  2711  feed streams. 
     The SGR unit  2711  as shown in this implementation can use feed streams for syngas reactants including for example the calciner  1707  gaseous product stream  150  which contains at least a portion of CO 2  and may also contain H 2 O. The SGR unit  2711  may also be fed a portion of CH 4  from stream  1759 , a portion of steam stream  2755  from the boiler  2717  that is fed water from stream  2762 , a portion of steam stream  2758  from the Fischer Tropsch unit  2712 , or a combination of any of the above as reactants to the SGR. These streams may be provided as feedstock to the SGR unit  2711 , in part to reduce or eliminate the need for the hydrogen stream  1764  supplied from the hydrogen production subunit  110 . 
     In some implementations, a portion of the H 2  in stream  2748  may be separated, using for example a membrane separation unit, and recycled back to the SGR vessel  2769 , via the ceramic heat exchanger  2714  (not shown). In this case, the CH 4  stream  1759  may be available as a less expensive reactant to the SGR vessel  2969 , and when one or more of the CH 4  stream  1759 , Fischer Tropsch light ends stream  1981  are fed with one or more of steam streams  2755  and  2758  as feedstock to the SGR reactor vessel  2769 , the SGR vessel  2769  would then, in addition to RWGS reactions, include at least a portion of SMR reactions, DMR reactions or a combination of these reactions, to produce the syngas product stream  148 . 
     In some implementations the CH 4  stream  1759  may be available as a less expensive reactant, and when one or both of the CH 4  stream  1759  and steam streams  2755  and  2758  are fed to the SGR unit  2711 , the SGR unit  2711  would then, in addition to RWGS reactions, include at least a portion of SMR reactions, DMR reactions or a combination of these reactions, to produce the syngas product stream  148 . 
     In some aspects, using CH 4  as feedstock for the SGR unit  2769  may be more economic, for example when renewable electricity is unavailable or expensive and using a CH 4  source for SGR reactor  2769  feedstock (and operating the SGR unit  2711  in for example SMR mode) is more cost effective than running the electrically driven hydrogen production subunit  110 . Additionally or alternatively, this method of operation could be used when the CO 2  capture subsystem  101  is offline or at reduced capacity. 
     In the implementation shown in  FIG.  27   , the calciner unit  1707  may require fuel to combust with the oxygen source to provide the operating temperature for calcination. The fuel can be provided by an offsite hydrogen supply, hydrogen sourced from the hydrogen production subsystem  110 , natural gas, Fischer Tropsch light end hydrocarbons from the Fischer Tropsch unit  2712  or a combination of these components as stream  1761 . 
     In the implementation shown in  FIG.  27   , the calciner unit  1707  may be heated electrically as is described in  FIGS.  3 ,  24 - 26   . In these cases, the CO 2  feed stream  150  going from the calciner  1707  to the SGR unit  2711  may have substantially less or no water content than when the calciner unit  1707  is heated using combustion of a fuel source, and as a result, the calciner product gas stream  150  may not require the same downstream components, for example water removal, prior to being sent to the SGR unit  2711 . 
     According to a twenty-seventh implementation, and referring to  FIG.  28   , a synthetic fuel production system  2800  includes the capture subsystem  101 , the hydrogen production subsystem  103  and the synthetic fuel production subsystem  102 . The synthetic fuel production subsystem  102  has an SGR unit  2811  coupled to a ceramic heat exchanger  2714 , and a Fischer Tropsch unit  2712 . The SGR unit  2811  includes an SGR burner system  2867  that is air fired with a fuel source stream  1761 , which may include fuel such as natural gas, hydrogen, Fischer Tropsch light end hydrocarbons or a combination of any of the above. The SGR burner system  2867  is coupled to a heat exchanger  2816  and a boiler unit  2717 . The combustion air stream  2865  is preheated by feeding through the heat exchanger  2816 , before being sent to the SGR burner system  2867  as stream  2866 . The SGR burner system hot exhaust gas stream  2874  is used to preheat the air and, in some cases where steam is required as a reactant for the SGR unit  2811 , the SGR burner system hot exhaust gas stream  2874  is also used to produce steam  2755  in boiler unit  2717 . The hot exhaust stream  2874  can be split into stream  2815  that is directed to the boiler unit  2717  and stream  2835  that is directed to the heat exchanger  2816 . The split ratio of feed stream  2815  to the boiler unit  2717  and stream  2835  to the heat exchanger  2816  can be varied depending on how much heat is required for producing steam versus air preheating via heat exchanger  2816 . The cooled exhaust gas leaves the boiler unit  2717  and heat exchanger  2816  as flue gas streams  2899  and  2876 , respectively. In some cases, one or both of the flue gas streams  2876  and  2899  can be used as a feed stream into another subsystem process unit within the synthetic fuel production system  2800 , as both streams can contain CO 2  and H 2 O. 
     Ceramic heat exchangers are used in in various high temperatures and corrosive industrial applications, including for example heat exchange units such as furnaces, boilers, and the like. Ceramic heat exchangers are capable of gas-gas heat exchange at high temperatures such as those used in the SGR unit, ie up to 1100° C. in cases where for example the SGR unit  2811  is operated under ATR conditions. Ceramic heat exchangers can be made of various ceramic materials such as for example silicon carbide or alumina. Silica carbide can be less expensive than alumina but more prone to corrosion under high temperature water vapour environments. In addition to the ceramic material, ceramic heat exchangers can have metal shells and components. 
     In the implementation shown in  FIG.  28   , the ceramic heat exchanger  2714  is used to exchange heat between the SGR vessel  2869  hot syngas product stream  148  and one or more of the SGR unit  2811  feed streams including components such as CO 2 , H 2 O, CH 4 , H 2 , Fischer Tropsch light ends and the like, resulting in a hot SGR feed stream  2750  for the SGR vessel  2869  and a cooled syngas product stream  2748  that is sent as feed to the Fischer Tropsch unit  2712 . In some aspects, the gaseous feed streams may enter the ceramic heat exchanger  2714  as separate streams or in a combined stream. The ceramic heat exchanger  2714  is required for this application, as common metal and alloy heat exchangers exposed to the hot SGR product gas stream conditions and temperatures would be prone to metal dusting issues, where as ceramic heat exchange materials are not prone to metal dusting. Metal dusting is a common problem in syngas and reforming processes when metal or alloy surfaces, for example mild steel, stainless steel, iron and nickel based alloys, are exposed to the process operating conditions. The result is a deterioration in the metal material, ultimately requiring replacement. Industry typically reduces metal dusting issues by cooling the gas streams to temperatures where metal dusting does not occur—this results in wasted energy and low process efficiencies. 
     The ceramic heat exchanger  2714  can be used in all applications where the SGR unit product gas stream  148  is used to preheat one or more of the SGR reactor unit  2869  feed streams. In this implementation, the SGR unit  2811  is configured to handle RWGS reactions, DMR reactions, SMR reactions or combination of these reactions. Having a single unit configured to handle these SGR reactions is more cost effective than having a separate SMR unit and RWGS unit, for example. Also in this implementation, the ceramic heat exchanger  2714  is recycling most of the required heat of reaction by using the SGR unit  2869  hot product gas stream  148  to preheat the reactant feed gases, so that in the cases where the SGR unit  2811  is undergoing mostly an RWGS reaction, ie where feed steam is not needed and where the RWGS reaction enthalpy (+41 kJ/mol CO) is much lower than reaction enthalpies associated with SMR (+206 kJ/mol CO) and DMR (+247 kJ/mol CO) reactions, the ceramic heat exchanger  2714  can provide sensible heat while the heat of reaction can be provided by the SGR unit  2811  primary heat source, which in this case is the heat stream  2873  generated by the SGR burner system  2867 . This configuration is better at heat recovery than if the same RWGS process was attempted in a standard SMR unit. In some aspects, the ceramic heat exchanger  2714  enables improved thermal efficiency of the SGR, as It is the only way to recover process heat in an SGR system where a high steam feed is not required. In a standard SMR unit, the heat from the hot syngas product is used to produce steam for the SMR feed. This configuration is not required for a RWGS reaction and thus having the hot syngas product hard piped through a boiler unit would be inefficient for an RWGS process. In the implementation shown in  FIG.  28   , during times when the SGR unit  2811  is in SMR operation, the steam can instead be produced from the SGR burner system hot exhaust gas  2874  if needed, and if it is not needed, as in the case where the SGR unit  2811  is used for an RWGS process, the SGR burner system hot exhaust gas stream  2874  can put the unused heat (previously used to make steam during SMR operation) into preheating the SGR burner system combustion reactants (ie air and fuel stream) instead. 
     The SGR unit  2811  as shown in this implementation can use feed streams for syngas reactants including for example the calciner  1707  gaseous product stream  150  which contains at least a portion of CO 2  and may also contain H 2 O. The SGR unit  2811  may also be fed a portion of CH 4  from stream  1759 , a portion of steam stream  2755  from the boiler  2717  that is fed water from stream  2762 , and a portion of steam stream  2758  from the Fischer Tropsch unit  2712  as reactants. These streams may be provided as feedstock to the SGR vessel  2869 , in part to reduce or eliminate the need for the hydrogen stream  1764  supplied from the hydrogen production subunit  110 . 
     In some implementations, a portion of the H 2  in stream  2748  may be separated, using for example a membrane separation unit, and recycled back to the SGR reactor vessel  2869 , via the ceramic heat exchanger  2714  (not shown). In this case, the CH 4  stream  1759  may be available as a less reactant to the SGR vessel  2869 , and when one or more of the CH 4  stream  1759 , Fischer Tropsch light ends stream  1981  are fed with one or more of steam streams  2755  and  2758  as feedstock to the SGR reactor vessel  2869 , the SGR vessel  2869  would then, in addition to RWGS reactions, include at least a portion of SMR reactions, DMR reactions or a combination of these reactions, to produce the syngas product stream  148 . 
     In some aspects, using CH 4  as a feedstock for the SGR reactor vessel  2869  may be more economic, for example when renewable electricity is unavailable or expensive and using a CH 4  source for SGR reactor vessel  2869  feedstock (and operating the SGR unit  2811  in for example SMR mode) is more cost effective than running the electrically driven hydrogen production subunit  110 . Additionally or alternatively, this method of operation could be used when the CO 2  capture subsystem  101  is offline or at reduced capacity. 
     The calciner gaseous product stream  132  is sent through a solids removal and clean-up unit  108 , where water is removed as stream  134  and the dust/particles are removed as stream  138 . The gaseous product stream containing CO 2  and some H 2 O gets sent to the ceramic heat exchanger  2714 . 
     In the implementation shown in  FIG.  28   , the calciner unit  1707  may require fuel to combust with the oxygen source  1766  to provide the operating temperature for calcination. The fuel can be provided by an offsite hydrogen supply, hydrogen sourced from the hydrogen production subsystem  110 , natural gas, Fischer Tropsch light end hydrocarbons from the Fischer Tropsch unit  2712  or a combination of these components as stream  1761 . 
     In the implementation shown in  FIG.  28   , the calciner unit  1707  may be heated electrically as is described in  FIGS.  3 , 24 - 27   . In this case, the CO 2  feed stream  132  going from the calciner  1707  to the SGR unit  2811  may have substantially less or no water content than when the calciner unit  1707  is heated using combustion of a fuel source, and as a result, the calciner product gas stream  132  may not require the same downstream components, for example water removal prior to being sent to the ceramic heat exchange unit  2714 . 
     According to a twenty-eighth implementation, and referring to  FIG.  29    a synthetic fuel production system  2900  includes the capture subsystem  101 , the hydrogen production subsystem  103  and the synthetic fuel production subsystem  102 . The synthetic fuel production subsystem  102  has an SGR unit  2911  coupled to a ceramic heat exchanger  2714  and a Fischer Tropsch unit  2712 . The SGR unit includes a SGR burner system  2967  that is oxy-fired with a fuel source stream  1761 , which may include fuel such as natural gas, hydrogen, Fischer Tropsch light end hydrocarbons or a combination of any of the above. The SGR burner system  2967  is coupled to a heat exchanger  2916 , and a boiler unit  2717 . The combustion oxygen stream  1765  is preheated by feeding through the heat exchanger  2916 , before being sent to the SGR burner system  2967 . The SGR burner system hot exhaust gas stream  2974  is used to preheat the oxygen stream  1765 , any recycled flue gas from stream  2976 , and in some cases where steam is required as a reactant for the SGR unit  2911 , the SGR burner system hot exhaust gas stream  2974  is used to produce steam in boiler unit  2717 . The hot exhaust stream  2974  can be split into stream  2915  that is directed to the boiler unit  2717  and stream  2935  that is directed to the heat exchanger  2916 . The split ratio of exhaust gas stream  2915  to the boiler unit  2717  and stream  2935  to the heat exchanger  2916  can be varied depending on how much heat is required for producing steam versus oxygen preheating via heat exchanger  2916 . The cooled exhaust gas leaves the boiler unit  2717  and heat exchanger  2916  as flue gas streams  2986  and  2976 , respectively. In some cases, at least a portion of the flue gas stream  2976  can be recycled back through to the SGR burner system  2967  along with the combustion oxygen stream  1765 , and a portion of it can be sent as stream  2989  to a compression and clean-up unit  1970  where the water is removed as stream  2975 . The resulting compressed gas stream  2999  is then sent through the ceramic heat exchanger  2714  and can then be used as a feed stream for the SGR Reactor vessel  2969 . In some cases, one or both of the flue gas streams  2976  and  2986  can be used as feed streams into another subsystem process unit within the synthetic fuel production system  2900 , as both streams can contain CO 2  and H 2 O. 
     Ceramic heat exchangers are used in in various high temperatures and corrosive industrial applications, including for example heat exchange units such as furnaces, boilers, and the like. Ceramic heat exchangers are capable of gas-gas heat exchange at high temperatures such as those used in the SGR unit, ie up to 1100° C. in cases where for example the SGR unit  2811  is operated under ATR conditions. Ceramic heat exchangers can be made of various ceramic materials such as for example silicon carbide or alumina. Silica carbide can be less expensive than alumina but more prone to corrosion under high temperature water vapour environments. In addition to the ceramic material, ceramic heat exchangers can have metal shells and components. 
     In the implementation shown in  FIG.  29   , the ceramic heat exchanger  2714  is used to exchange heat between the SGR vessel  2969  hot syngas product stream  148  and one or more of the SGR unit  2911  feed streams including components such as, H 2 O, CH 4 , H 2 , Fischer Tropsch light ends and the like, resulting in a hot SGR feed stream  2750  for the SGR vessel  2969  and a cooled syngas product stream  2748  that is sent as feed to the Fischer Tropsch unit  2712 . In some aspects, the gaseous feed streams may enter the ceramic heat exchanger  2714  as separate streams or in a combined stream. The ceramic heat exchanger  2714  is required for this application, as common metal and alloy heat exchangers exposed to the hot SGR product gas stream conditions and temperatures would be prone to metal dusting issues, where as ceramic heat exchange materials are not prone to metal dusting. Metal dusting is a common problem in syngas and reforming processes when metal or alloy surfaces, for example mild steel, stainless steel, iron and nickel based alloys, are exposed to the process operating conditions. The result is a deterioration in the metal material, ultimately requiring replacement. Industry typically reduces metal dusting issues by cooling the gas streams to temperatures where metal dusting does not occur—this results in wasted energy and low process efficiencies. 
     The ceramic heat exchanger  2714  can be used in all applications where the SGR unit product gas stream  148  is used to preheat one or more of the SGR reactor unit  2969  feed streams. In this implementation, the SGR unit  2911  is configured to handle RWGS reactions, DMR reactions, SMR reactions or combination of these reactions. Having a single unit configured to handle these SGR reactions is more cost effective than having a separate SMR unit and RWGS unit, for example. Also in this implementation, the ceramic heat exchanger is recycling most of the required heat of reaction by using the SGR vessel  2969  hot product gas stream  148  to preheat the reactant feed gases, so that in the cases where the syngas production subsystem  2911  is forming syngas by undergoing mostly an RWGS reaction, ie where feed steam is not needed and where the RWGS reaction enthalpy (+41 Id/mol CO) is much lower than reaction enthalpies associated with SMR (+206 Id/mol CO) and DMR (+247 kJ/mol CO) reactions the ceramic heat exchanger  2714  can provide sensible heat while the heat of reaction can be provided by the SGR unit  2911  primary heat source, which in this case is the heat stream  2963  generated by the SGR burner system  2967 . This configuration is better at heat recovery than if the same RWGS process was attempted in a standard SMR unit. In some aspects, the ceramic heat exchanger  2714  enables improved thermal efficiency of the SGR, as It is the only way to recover process heat in an SGR system where a high steam feed is not required. In a standard SMR unit, the heat from the hot syngas product is used to produce steam for the SMR feed. This configuration is not required for a RWGS reaction and thus having the hot syngas product hard piped through a boiler unit would be inefficient for an RWGS process. In the implementation shown in  FIG.  29   , during times when the SGR unit  2911  is in SMR operation, the steam can instead be produced from the SGR burner system hot exhaust gas  2974  if needed, and if it is not needed, as in the case where the SGR unit  2911  is used for an RWGS process, the SGR burner system hot exhaust gas stream  2974  can put the unused heat (previously used to make steam during SMR operation) into preheating the SGR burner system combustion reactants (ie oxygen and fuel stream) instead. 
     The SGR unit  2911  as shown in this implementation can use feed streams for syngas reactants including for example the calciner  1707  gaseous product stream  150  which contains at least a portion of CO 2  and may also contain H 2 O. The SGR unit  2911  may also be fed a portion of CH 4  from stream  1759 , a portion of steam stream  2755  from the boiler  2717  that is fed water from stream  2762 , and a portion of steam stream  2758  from the Fischer Tropsch unit  2712  as reactants. These streams may be provided as feedstock to the SGR vessel  2969  in part to reduce or eliminate the need for the hydrogen stream  1764  supplied from the hydrogen production subunit  110 . 
     In some implementations, a portion of the H 2  in stream  2748  may be separated, using for example a membrane separation unit, and recycled back to the SGR vessel  2969 , via the ceramic heat exchanger  2714  (not shown). In this case, the CH 4  stream  1759  may be available as a less expensive reactant to the SGR vessel  2969 , and when one or more of the CH 4  stream  1759 , Fischer Tropsch light ends stream  1981  are fed with one or more of steam streams  2755  and  2758  as feedstock to the SGR reactor vessel  2969 , the SGR vessel  2969  would then, in addition to RWGS reactions, include at least a portion of SMR reactions, DMR reactions or a combination of these reactions, to produce the syngas product stream  148 . 
     In some aspects using CH 4  as the hydrogen source for the SGR vessel  2969  may be more economic, for example when renewable electricity is unavailable or expensive and using a CH 4  source SGR reactor vessel  2969  feedstock (and operating the SGR unit  2911  in for example SMR mode) is more cost effective than running the electrically driven hydrogen production subunit  110 . Additionally or alternatively, this method of operation could be used when the CO 2  capture subsystem  101  is offline or at reduced capacity. 
     The calciner gaseous product stream  132  is sent through a solids removal and clean-up unit  108 , where water is removed as stream  134  and the dust/particles are removed as stream  138 . The gaseous product stream containing CO 2  and some H 2 O gets sent to the ceramic heat exchanger  2714 . 
     In the implementation shown in  FIG.  29   , one or more of the SGR unit  2911  and calciner unit  1707  may require fuel to combust with the oxygen source to provide the operating temperature for syngas production and calcination, respectively. The fuel can be provided by an offsite hydrogen supply, hydrogen sourced from the hydrogen production subsystem  110 , natural gas, Fischer Tropsch light end hydrocarbons from the Fischer Tropsch unit  2712  or a combination of these components as stream  1761 . 
     In the implementation shown in  FIG.  29   , the calciner unit  1707  may be heated electrically as is described in  FIGS.  3 ,  24 - 26   . In this case, the CO 2  feed stream  132  going from the calciner  1707  to the SGR unit  2911  may have substantially less or no water content than when the calciner unit  1707  is heated using combustion of a fuel source, and as a result, the calciner product gas stream  132  may not require the same downstream components, for example water removal, prior to being sent to the ceramic heat exchange unit  2714 . 
     Referring to  FIG.  30    and according to a twenty-ninth implementation, a synthetic fuel production system  3000  includes a hydrogen production subsystem  103 , a synthetic fuel production subsystem  102 , and the CO 2  capture subsystem  1501  as described in  FIG.  15   . 
     In this implementation, the energy required for one or more of the regeneration unit  1507  and the SGR unit  1511  may be derived at least in part from oxy-combustion of a fuel source including hydrogen, Fischer Tropsch light ends, natural gas or a combination of these components. For example, light end hydrocarbon byproducts stream  1523  produced by the Fischer-Tropsch unit  1512  can be used as fuel for combustion to generate heat for one or more of the regeneration unit  1507  and the SGR unit  1511 . Additionally or alternatively, some of the H 2  and O 2  produced by the hydrogen the production subsystem  103  may be used to heat one or more of the regeneration unit  1507  and the SGR unit  1511  via combustion of a portion of H 2  stream  1525  and a portion of the O 2  stream  1527 . 
     In some aspects, one or more of the regeneration unit  1507  and the SGR unit  1511  may be electrically driven processes, where electrical source  1518  provides the input heat  1529  for the regeneration unit  1507  and electrical source  1552  provides the input heat  1551  required by the SGR unit  1511 . For example, equipment such as boilers in the regeneration unit  1507  can be configured to generate heat from electricity, and the SGR unit  1511  can be electrically configured at least in part as described in implementations  18  ( FIG.  19   ) and  26  ( FIG.  27   ) for example. In some cases, the electrical energy could be provided by a renewable source. 
     In the implementations described herein, oxygen produced within the system (for example in the hydrogen production system) could be used to oxy-fire any combustion process within the plant for example within any on-site power generation systems, within the SGR, in particular the RWGS reactor, in addition to or instead of the calciner. In some aspects, the oxidant used for combustion processes within the plant may be sourced from more dilute forms, such as air or more concentrated forms such as O 2  produced in an electrolyzer. 
     As discussed in the implementations above, the CO 2  capture subsystems  101 ,  1501 ,  1601 , can capture CO 2  from large volumes of gas in a way that is decoupled from industrial (point emission) sources, can be located on non-agricultural or inexpensive land, and can provide a source of cooling medium (process solution), a source of high grade waste heat (calciner and slaker outputs), may have the ability to remove water from gas streams (slaker) and it may have the ability to consume intermediate or byproduct streams from the hydrogen production system and the synthetic fuel production system, for example, oxygen, hydrogen and lighter end fuels may be consumed in equipment such as the oxy-fired calciner, in the heating and/or feedstock requirements of SGR units, and in power generation systems where combustion is used, such as combustion turbines, and/or boilers. 
     Furthermore, the oxygen demands of the oxy-fired calciner can be significantly less than the total oxygen byproduct stream produced in the electrolysis process, in particular when the electrolysis process is sized to provide all the hydrogen demands of the synthetic fuel system. In scenarios where hydrogen electrolysis is used to produce hydrogen for a fuel synthesis system including RWGS and FT units, and where Fischer-Tropsch reactor feedstock requires an H 2 :CO ratio of  ˜2 , and where the CO 2  source is from a CO 2  capture subsystem including an oxy-fired calciner where some CO 2  is captured from the calciner combustion as well as from the air, the stoichiometric amount of oxygen byproduct produced from the hydrogen unit can be approximately 2-3 times greater than what is needed in the calciner. This leads to the potential of utilizing the excess oxygen byproduct in other units/areas where oxy-firing could be employed. For example, in the heating requirements of SGR units, and in particular RWGS units, in power generation systems where combustion is used, such as combustion turbines, and/or boilers. 
     In some implementations, the produced synthetic fuel can be blended into existing fossil fuel inventory such that transitioning a hydrocarbon production system, such as a refinery and distribution system, from fossil fuel feedstock to completely synthetic fuel feedstock can be timed in accordance with the demand for low carbon intensity fuels, with no blending restrictions like those that exist with most biofuels. 
     Biofuels in large scale production include Biodiesels or “FAME” (fatty acid methyl ester) and Renewable Diesel or “HVO” (hydrotreated vegetable oil). Emerging pathways include biomass and waste based Fischer-Tropsch “BFT” diesel and jet fuel created through the pyrolysis, hydrolysis/catalysis, or fermentation of materials such as municipal waste, energy crops, and crop residues. FAME, HVO and BFT fuels work at small penetration but social, chemical and environmental limits can drive up their costs steeply. Specific issues include the following:
         FAME fuels based on rendered animal fat, waste cooking oils, and vegetable oils may only be blended 5-10% with fossil diesel, can have a lower energy density and cannot be distributed through pipelines due to corrosion issues. The feedstocks are commodities with alternative uses and their costs are tightly correlated with the cost of crude oil.   Biomass feedstocks such as crop and forest wastes have low energy density, high collection/transport cost, require very large crop areas and compete with food uses.   FAME, HVO, and BFT diesel fuels all have carbon intensities in the range of 20-70 gCO 2 e/MJ (with the exception of site specific small sources in the 10-20 gCO 2 e/MJ).       

     In some implementations, the production of synthetic fuels can be designed to support an economical means of transitioning from fossil fuel based systems, such as GTL processes, to air-to-fuels systems, and in so doing, the resulting overall process energy requirements, capital cost, carbon intensity or a combination of the above may be reduced. In these implementations, the SGR unit can be operated, for example, as an SMR or DMR, taking in feedstocks such as methane and steam (in addition to CO 2  as applicable), to produce syngas for downstream processes, such as Fischer Tropsch liquid fuels production. 
     This mode of operation can be carried out for a period of time, after which the SGR unit can operate, for example as an RWGS reactor, taking in CO 2  and H 2  feedstocks, to produce syngas for downstream processes. These different modes of operation can be alternated, depending on the need and availability to process certain feedstocks. In some implementations, separate RWGS, SMR and DMR units are not necessary—these reactions can be carried out in the same catalyzed SGR reactor, simply by changing the feedstock streams. 
     In some implementations, the system may be designed to facilitate a dynamic transition from GTL to air to fuels, or to facilitate operation as a hybrid GTL and air to fuels system, utilizing a combination of fossil fuels as well as dilute source carbon dioxide and a hydrogen source. The system may be designed to shift back and forth between GTL inputs and air to fuels inputs depending on a number of conditions. In some of these implementations, the existing challenges of the fossil fuel based processes like the GTL processes mentioned herein can be alleviated using the byproducts from the on-site air-to-fuels system. For example, GTL systems have challenges in producing favorable hydrogen to carbon (H:C) ratios in their synthetic gas product for downstream users such as Fischer-Tropsch and methanol systems. Dry methane reforming (DMR) tends to produce a low H:C ratio ( ˜ 1:1), steam methane reforming tends to produce a high H:C ratio ( ˜ 3:1), and while autothermal reforming can achieve something in between ( ˜ 2:1), the O 2  feed source from an air separation unit (ASU,) can be prohibitively expensive at smaller scales. If the GTL process is on a site that also houses air-to-fuels system componentry, such as electrolysis and DAC systems (capable of producing additional feedstocks of hydrogen, oxygen and CO 2 ), the GTL hydrogen-to-carbon ratio issues could be alleviated, and use of additional (and expensive) ASU equipment could be avoided. 
     Furthermore, the carbon intensity of the resulting fuel may be reduced relative to a GTL fuel that only utilizes natural gas as an input. 
     A system such as this could shift the balance between inputs from fossil fuels to dilute source carbon dioxide and hydrogen in response to a number of factors, for example, the price and availability of electricity: in an example implementation, a system could be operated in air to fuels mode at times when excess or affordable electricity is available, such as in a case where electricity is intermittently produced by renewable energy sources and excess electricity is not required by the grid. Similarly, the system could transition to operate in GTL mode, or in a mode where the majority of fuel is produced using fossil fuel, at times when electricity is not available, or is in high demand elsewhere, effectively allowing the air to fuels production system to act as an arbitrage to absorb excess electricity capacity through production and use of hydrogen for air to fuels. 
     In some of these GTL transitional implementations, the transition of the GTL unit may, for example, involve changing the catalyst material within some or all of the reactors, changing the operation regime within some or all of the reactors, adding or removing equipment around the reactors, rerouting streams within the plant, and possibly changing the quantities of feedstocks. 
     In some implementations, the system  100  can include components such as air contactor units, fluidized bed reactive crystallizers, slakers, oxy-fired calciners, hydrogen production systems such as a high temperature SOEC cell, a proton exchange membrane (PEM), an alkaline electrolyzer, synthetic fuel production components such as syngas generation reactors (SGRs), for example dry methane reformers (DMRs), steam methane reformers (SMRs), auto thermal reformers (ATRs), RWGS reactors, and partial oxidation reactors, as well as synthetic fuel processing units including Fischer-Tropsch reactors, methanol to gasoline (MTG) units, methanol to olefin (MTO) units, methanol synthesis units, CO 2  hydrogenation to hydrocarbon units, power cycles, or a combination of these components. 
     In some of these implementations, the reactors can include an external combustion zone, whereby the combustion process is kept separate from the internal reaction process, thereby allowing for the combustion components to be collected separately from the reaction products without impacting the reaction environment or composition within the reactor. 
     In some implementations, heat exchanger means used in the system  100  can include shell and tube heat exchangers, plate and frame heat exchangers, tube bundle heat exchangers, heat recovery systems, boilers, reboilers, cooling towers, cooling fins, baffles, microchannel heat exchangers, coils, radiator coils, spiral heat exchangers, fluidized beds, spray towers, bubbling columns, gas sparging, counter current, co-current or cross flow heat exchangers or a combination of these components. In some implementations, steam is used as a heat exchange medium and the incorporation of steam desuperheater equipment can be employed. 
     In some implementations, the total capacity of the hydrogen production subsystem  103  is sized so as to meet the feedstock requirements of the downstream fuel synthesis subsystem  102  (such as the Fischer-Tropsch or methanol synthesis units). The required hydrogen production capacity depends on both the production capacity of the fuel synthesis subsystem  102 , and on the ratio of H 2 :CO that the process requires. In implementations where water electrolyzers are used for producing all of the hydrogen and the CO 2  capture subsystem supplies all of the CO, the quantity of oxygen co-produced by the water electrolyzers is about three times the oxygen demand of the calciner. 
     In some implementations, all or part of the system&#39;s heat requirements are met with oxy-fired combustion, air fired combustion with post CO 2  capture, electric heating, or a combination of these methods. 
     In yet some other implementations, fuel used in the combustion processes may include hydrogen, methane, biomethane, pyrolysis oil, natural gas, syngas, products from a Fischer-Tropsh process, or a combination of these components. 
     In some of the implementations, water from the clean-up unit can be fed to the water treatment and source unit. 
     In some of the implementations, the CO 2  capture subsystem may incorporate a high temperature hydrator or steam slaker within the slaker unit. 
     The term “couple” and variants of it such as “coupled”, “couples”, and “coupling” as used in this description is intended to include indirect and direct connections unless otherwise indicated. For example, if a first device is coupled to a second device, that coupling may be through a direct connection or through an indirect connection via other devices and connections. Similarly, if the first device is communicatively coupled to the second device, communication may be through a direct connection or through an indirect connection via other devices and connections. In particular, a fluid coupling means that a direct or indirect pathway is provided for a fluid to flow between two fluidly coupled devices. Also, a thermal coupling means that a direct or indirect pathway is provided for heat energy to flow between to thermally coupled devices. 
     A number of implementations of the invention have been described. Nevertheless, it will be understood that various modifications may be made without departing from the spirit and scope of the invention. 
     Accordingly, other implementations are within the scope of the following claims. Further modifications and alternative implementations of various aspects will be apparent to those skilled in the art in view of this description. Accordingly, this description is to be construed as illustrative only. It is to be understood that the forms shown and described herein are to be taken as examples of implementations. Elements and materials may be substituted for those illustrated and described herein, parts and processes may be reversed, and certain features may be utilized independently, all as would be apparent to one skilled in the art after having the benefit of this description. Changes may be made in the elements described herein without departing from the spirit and scope as described in the following claims.