Patent Publication Number: US-2023159835-A1

Title: Integrated Process for the Manufacture of Renewable Diesel

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application claims the benefit of U.S. Provisional Application No. 63/264,379, filed on Nov. 22, 2021, the entire contents of which are incorporated herein by reference. 
    
    
     FIELD 
     This application relates to hydroprocessing of biofeedstocks to produce a renewable diesel product. 
     BACKGROUND 
     Renewable diesel is a hydrocarbon fuel made from vegetable oils, fats, greases, or other suitable biofeedstocks. In contrast to biodiesels, renewable diesels are not esters and are chemically similar to petroleum diesels. In some instances, renewable diesel can be used as a blendstock for blending with petroleum diesel. While a number of different techniques can be used for renewable diesel production, an example process includes hydrodeoxygenation of a biofeedstock followed by isomerization. Since hydrodeoxygenation generates a number of components, including water, carbon monoxide and carbon dioxide, to which the isomerization catalyst can be sensitive, the feed to the isomerization reactor from hydrotreatment is typically stripped in a stripper. In addition, the product from the isomerization is also typically cooled and stripped in a separate column. Unfortunately, conversion of the biofeedstocks to renewable diesel in conventional processing equipment can be expensive. 
     SUMMARY 
     Disclosed herein is an example method of processing a biofeedstock, including: hydrotreating the biofeedstock by reaction with hydrogen in the presence of a hydrodeoxygenation catalyst to form at least a hydrotreated effluent stream; cooling the hydrotreated effluent stream; separating a gas-phase portion from at least the cooled hydrotreated effluent stream to form at least a gas-phase stream and a hydrotreated stream; stripping at least a portion of the hydrotreated stream to remove isomerization contaminants and form at least an isomerization feed stream and a first gas stream; contacting at least a portion of the isomerization feed stream with an isomerization catalyst to form an isomerization effluent stream; separating at least the isomerization effluent stream to form at least a first gas stream and an isomerization reactor effluent; contacting at least a portion of the isomerization reactor effluent with the first gas stream such that the isomerization reactor effluent adsorbs at least hydrocarbons having 4 carbons are more from the first gas stream; and stripping at least a portion of the isomerization effluent stream to form at least a product stream and a second gas stream, wherein the product stream comprises renewable diesel and has a minimum flash point of about 35° C. to about 60° C. as determined in accordance with ATSTM D93. 
     Disclosed herein is an example method of method for integration of product separation in renewable diesel production, including: stripping a hydrotreated effluent stream comprising hydrotreated biofeedstock to remove isomerization contaminants and form at least an isomerization feed stream and a first gas stream; contacting an isomerization effluent with the first gas stream such that the isomerization effluent adsorbs at least C4+ hydrocarbons from the first gas stream; and stripping at least a portion of an isomerization effluent in an integrated stripper while separated from the stripping the hydrocarbon stream by a dividing wall to remove hydrocarbons having 10 carbons or less and form at least a product stream and a second gas stream, wherein the product stream comprises renewable diesel. 
     These and other features and attributes of the disclosed methods, systems, and apparatus of the present disclosure and their advantageous applications and/or uses will be apparent from the detailed description which follows 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       To assist those of ordinary skill in the relevant art in making and using the subject matter hereof, reference is made to the appended drawings, wherein: 
         FIG.  1    is a schematic illustration of an example renewable diesel production system in accordance with one or more illustrative embodiments; 
         FIG.  2    is a schematic illustration of an integrated stripper in accordance with one or more illustrative embodiments; 
         FIG.  3    is a schematic illustration of an integrated stripper in accordance with one or more illustrative embodiments; 
         FIG.  4    is a schematic illustration of an integrated stripper in accordance with one or more illustrative embodiments; 
         FIG.  5    is a schematic illustration of an integrated stripper in accordance with one or more illustrative embodiments; and 
         FIG.  6    is a schematic illustration of an integrated stripper in accordance with one or more illustrative embodiments. 
     
    
    
     DETAILED DESCRIPTION 
     In various embodiments, methods and systems are provided for producing renewable diesel. Renewable diesel is a hydrocarbon made from biofeedstocks, including vegetable oils, fats, greases, or other sources of triglycerides, which can include various crops, waste oil, used cooking oil or other animal fats. As used herein, the term “renewable diesel” refers to a hydrocarbon liquid produced from a biofeedstock and with paraffins (e.g., iso and normal) as a major component. Because renewable diesel is chemically similar to petroleum diesel, renewable diesel is capable of use in diesel engines without engine modification. In one example, a renewable diesel includes between 50% to 99% by weight of paraffins. A 100% renewable diesel should meet the ASTM D975 specification for diesel fuel. 
     Example embodiments for renewable diesel production include hydrodeoxygenation (“HDO”) stage and an isomerization stage. In example embodiments of the HDO stage, a biofeedstock is converted by reaction with hydrogen to form, for example, paraffin products with removal of oxygen. Particular embodiments for renewable diesel production further include an isomerization stage that receives hydrotreated biofeedstock from the HDO stage. In example embodiments of the isomerization stage, the hydrotreated biofeedstock is catalytically isomerized, for example, by isomerization of long chain paraffinic molecules, such as molecules ranging from 10 carbons long to 24 carbons long or from 10 carbons long to 19 carbons long or from 15 carbons long to 19 carbons long. 
     However, the processing equipment needed for producing renewable diesel is typically capital intensive due to the particular process requirements, thus making it challenging to economically produce renewable diesel. For example, components such as water, carbon monoxide and carbon dioxide generated in the HDO stage are removed from the feed to the isomerization reactor as these components can be poisons to the isomerization catalyst. In addition, the product from the isomerization reactor can also be stripped to provide a renewable diesel with desired specifications. By integration of the product separation schemes into an integrated stripper, example embodiments reduce the amount of equipment required to produce renewable diesel. For example, both a hydrocarbon stream from the HDO stage and an isomerization effluent stream are fed to an integrated stripper. In some embodiments, the integrated stripper includes a divided wall column. In example embodiments, the hydrocarbon stream from the HDO stage is stripped in the integrated stripper, for example, to meet constraints of the isomerization reactor, such as carbon monoxide, carbon dioxide, and/or water constraints. In example embodiments, the isomerization effluent stream is also stripped in the integrated stripper, for example, to remove lighter hydrocarbons (e.g., 10 hydrocarbons or less) to meet a flash point requirement of the renewable diesel. For example, the renewable diesel can have a minimum flash point of 35° C. to 60° C. or from 38° C. to 55° C. As used herein, flash point is determined in accordance with ATSTM D93. Before stripping, examples include contacting the isomerization effluent stream with gas from stripping the hydrocarbon stream such that higher value molecules (e.g., hydrocarbons ranging from C10 to C15) are absorbed. To further reduce equipment requirements, the integrated stripper has certain design features in accordance with present embodiments. In some embodiments, the integrated stripper includes a condenser (e.g., spiral condenser) mounted in the top of the column, reducing need for reflux drum and associated pumps. 
     Another challenge posed by the production of renewable diesel is due to the cooling requirements of the HDO reactor. By way of further example, removal of oxygen from biofeedstocks typically results in a large, localized heat release. As a result, conventional methods for deoxygenation include a substantial amount of product recycle with corresponding increases in equipment sizes (e.g., reactor, compressors, pumps, etc.). However, by splitting the biofeedstock across the catalyst beds instead of introducing the feedstock into the HDO reactor above the initial catalyst bed, example embodiments assist in maintaining a desired temperature profile across the HDO reactor. Example embodiments further control temperature in the HDO reactor by use of product recycle to provide cooling between catalyst beds, thus reducing or minimizing hydrogen circulation relative to embodiments where a hydrogen quench gas may be used for cooling between catalyst beds. 
     Yet another challenge posed by production of renewable diesel is the desulfidation of the catalyst used in the HDO reactor due the low sulfur content of biofeedstocks as compared to feedstocks conventionally used in conventional hydroprocessing reactors. In accordance with present embodiments, the biofeedstocks are hydrodeoxygenated while maintaining the HDO catalyst in a sulfided state. In some embodiments, the hydrogen gas used for hydrodeoxygenation is formed at least in part from hydrogen that has been used as a stripping gas for removing H 2 S from a rich amine stream. In such embodiments, the hydrogen recycle loop for the HDO stage can be integrated with the amine absorber loop for one or more associated processes. In some embodiments, the resulting hydrogen-containing stream includes sufficient H 2 S to substantially maintain the catalyst in the hydrodeoxygenation stage in a sulfided state. 
     Example Configurations 
       FIG.  1    is a schematic illustration of a system  100  for renewable diesel production in accordance with some embodiments. In the illustrated embodiment, the system  100  includes the following stages: (i) an HDO stage  102  in which a feed stream  104  containing a biofeedstock is reacted with hydrogen to reduce oxygen in the biofeedstock; and (ii) an isomerization stage  106  that receives an isomerization feed stream  108  containing hydrocarbons from the HDO stage  102  and isomerizes the hydrocarbons to improve the cold flow properties of a distillate boiling range portion of the hydrocarbons. In some embodiments, the HDO stage  102  includes an HDO reactor  110 , an HDO separator  112 , and amine unit  114 , and a hydrogen recycle compressor  116 . In some embodiments, the isomerization stage  106  includes an isomerization reactor  118  and an isomerization reactor effluent separator  120 . As illustrated, the system  100  includes an integrated stripper  122  for an integrated scheme for the HDO stage  102  and the isomerization stage  106 . 
     In the illustrated embodiment, a feed stream  104  including a biofeedstock is introduced into the HDO reactor  110 . As illustrated, hydrogen treat gas stream  124  including hydrogen is also be introduced into the HDO reactor  110 . While not shown on  FIG.  1   , example embodiments include make-up hydrogen (e.g., make-up hydrogen gas  648  on  FIG.  6   ) to provide additional hydrogen for the HDO reactor  110 . While  FIG.  1    illustrates separate addition of the feed stream  104  and the hydrogen treat gas stream  124  to the HDO reactor  110 , some embodiments include combination of the feed stream  104  and the hydrogen treat gas stream  124  prior to the HDO reactor  110 . In accordance with example embodiments, the biofeedstock is exposed to hydrodeoxygenation conditions in the HDO reactor  110  in the presence of one or more catalyst beds that contain hydrodeoxygenation catalyst such that the biofeedstock reacts with the hydrogen to reduce oxygen in the biofeedstock. The reaction in the HDO reactor  110  should produce hydrotreated biofeedstock, including paraffins, reaction intermediates (if any), and unreacted biofeedstock (if any) and hydrogen. The paraffins include, for example, long chain paraffinic molecules, such as molecules ranging from 10 carbons long to 24 carbons long or from 10 carbons long to 19 carbons long or from 15 carbons long to 19 carbons long. Lighter hydrocarbons having 9 or few carbons are also produced in the HDO reactor  110 , including methane, ethane, and propane, for example. The hydrodeoxygenation can be used to substantially deoxygenate the biofeedstock. This corresponds to removing 90% or more, for example, 95% or more, 98% or more, 99% or more, 99.5% or more, 99.9% or more, or completely (measurably) all the oxygen present in the biofeedstock. Alternately, substantially deoxygenating the biofeedstock can correspond to reducing the oxygenate level of the hydrotreated biofeedstock to 0.1 wt. % or less, for example, 0.05 wt. % or less, 0.03 wt. % or less, 0.02 wt. % or less, 0.01 wt. % or less, 0.005 wt. % or less, 0.003 wt. % or less, 0.002 wt. % or less, or 0.001 wt. % or less. 
     In the illustrated embodiments, a hydrotreated effluent stream  126  including hydrotreated biofeedstock is withdrawn from the HDO reactor  110  and flowed to an HDO separator  112 , where a gas-phase portion is separated from liquid-phase products. While not shown, some embodiments include cooling the hydrotreated effluent stream  126  prior to separation. In the illustrated embodiment, the HDO separator  112  produces a hydrotreated stream  128  including hydrocarbons (e.g., C1+ paraffins) and a gas-phase stream  129 . The particular components in the hydrotreated stream  128  and gas-phase stream  129  will depend on number of factors, including the operating conditions of the HDO separator  112  and the pressure and temperature of the isomerization reactor effluent separator  120 . In some embodiments, the HDO separator  112  operates at a temperature of 1° C. to 100° C. (e.g., 35° C. to 80° C., 45° C. to 75° C.) and a pressure of 3000 kPa to 8500 kPa (e.g., 4000 kPa to 5000 kPa). In some embodiments, the hydrocarbons in the hydrotreated stream  128  include long chain hydrocarbons (e.g., paraffins) from 10 carbons long to 24 carbons long or from 10 carbons long to 19 carbons long or from 15 carbons long to 19 carbons long. In some embodiments, the hydrotreated stream also includes lighter hydrocarbons having 9 or few carbons, including methane, ethane, or propane, for example. 
     The gas-phase stream  129  can contain hydrogen, for example, that can be recycled to the HDO reactor  110 . As illustrated, some embodiments include passing the gas-phase stream  129  to an amine unit  114 . In some embodiments of the amine unit  114 , hydrogen sulfide is incorporated into the gas-phase stream  129  to provide a hydrogen treat gas stream  124  that contains hydrogen and hydrogen sulfide. In accordance with example embodiments, the amine unit  114  also removes contaminant gases from the gas-phase stream  129 , such as ammonia, H 2 S, carbon monoxide, and/or carbon dioxide, that were generated in the HDO reactor  110 . In some embodiments, the hydrogen treat gas stream  124  from the amine unit  114  is compressed by hydrogen recycle compressor  116  and then recycled to the HDO reactor  110 . By incorporation of hydrogen sulfide into the hydrogen treat gas stream  124 , the hydrogen treat gas stream  124 , for example, contains sufficient hydrogen sulfide to substantially maintain the catalysts in the HDO reactor  110  in a sulfided state. 
     In the illustrated embodiment, the hydrotreated stream  128  including hydrocarbons is passed to the integrated stripper  122 . While the hydrotreated stream  128  is liquid, in some embodiments, when separated in the HDO separator  112 , example embodiments include at least a portion of the hydrotreated stream  128  being gas as when passed to the integrated stripper  122 . In  FIG.  1   , the integrated stripper  122  includes a first separate volume  130  and a second separate volume  132 . A dividing wall  134  separates the first separate volume  130  and the second separate volume  132 . The integrated stripper  122  further includes a common volume  136 . The hydrotreated stream  128  from the HDO stage  102  can enter the first separate volume  130 . A liquid output from the first separate volume  130  can be passed to the isomerization stage  106  as the isomerization feed stream  108 . In the first separate volume  130 , the hydrocarbons in the hydrotreated stream  128  can be stripped to remove isomerization contaminants to form the isomerization feed stream  108  and the first gas stream  131  using a first stripping medium  212  (e.g.,  FIG.  2   ). In some embodiments, the hydrotreated stream  128  is stripped to form an isomerization feed stream  108  with reduced isomerization contaminants, such as carbon monoxide, carbon dioxide, and water. For example, the hydrotreated stream  128  can be stripped to provide an isomerization feed stream  108  with a total oxygen content of 0.4 wt. % or less. In some embodiments, the total oxygen content of the isomerization feed stream  108  is 0.1 wt. % or less. In some embodiments, the total oxygen content of the isomerization feed stream  108  ranges from 0.001 wt. % to 0.1 wt. %. The total-oxygen content includes oxygen from oxygen-containing compounds. 
     The isomerization feed stream  108  can then be passed to the isomerization reactor  118 . In the isomerization reactor, catalytic isomerization can be performed by exposing the stripped hydrocarbon in the isomerization feed stream  108  to an isomerization catalyst under effective isomerization conditions. While not shown, some embodiments include adding hydrogen to the isomerization reactor  118  such that the isomerization takes place in the presence of hydrogen. In the illustrated embodiment, an isomerization reactor product stream  138  is withdrawn from the isomerization reactor  118  and passed to the isomerization reactor effluent separator  120 . While not shown, embodiments include cooling the isomerization reactor product stream  138  prior to separation. In some embodiments, the isomerization reactor product stream  138  contains paraffins (e.g., normal and iso), hydrogen, and light hydrocarbons (e.g., C1-C4 hydrocarbons). In the isomerization reactor effluent separator  120 , some embodiments include separating the liquid-phase products in the isomerization reactor product stream  138  from the gas-phase products to form a gas stream  140  and an isomerization reactor effluent  142 . The particular composition of the gas stream  140  and isomerization reactor effluent  142  depend, for example, on the conditions of the isomerization reactor effluent separator  120 . In some embodiments, the isomerization reactor effluent separator  120  operates at a temperature of 100° C. to 350° C. (e.g., 175° C. to 275° C., 200° C. to 250° C.) and a pressure of 2500 kPa to 7000 kPa (e.g., 3000 kPa to 5500 kPa, 4000 kPa to 5000 kPa). In the illustrated embodiment, the gas stream  140  including hydrogen and light hydrocarbons (e.g., C1-C4+ hydrocarbons) is combined with the hydrotreated effluent stream  126  with the combined stream passed to the HDO separator  112 . 
     In the illustrated embodiment, the isomerization reactor effluent  142  is passed to the integrated stripper  122 . In  FIG.  1   , the isomerization reactor effluent  142  from the isomerization stage  106  enters the common volume  136  where it contacts the first gas stream  131  from the first separate volume  130 . The isomerization reactor effluent  142  absorbs, for example, C4+ hydrocarbons from the first gas stream  131 . In some embodiments, the common volume  136  also receives a second gas stream  133  from the second separate volume  132 . In the illustrated embodiment, the common volume  136  produces a light ends stream  144  and a naphtha product stream  146 . In some embodiments, the light ends stream  144  include hydrocarbons, for example, from 1 carbon long to 6 carbons long. In some embodiments, the naphtha product stream  146  include hydrocarbons, for example, from 4 carbons long to 12 carbons long. In the illustrated embodiment, the isomerization reactor effluent  142  with the absorbed C4+ hydrocarbons is passed to the second separate volume  132  of the integrated stripper  122 . In the second separate volume  132 , for example, the isomerization reactor effluent  142  is stripped to remove lighter components and provide a renewable diesel with a desirable flash point. For example, liquid isomerization effluent can be stripped of lighter component to provide a product stream  148  including renewable diesel with a desirable flash point, such as a minimum flash point of 35° C. to 60° C. or from 38° C. to 55° C. As illustrated, the product stream  148  including renewable diesel is withdrawn from the integrated stripper  122 . In accordance with present embodiments, the renewable diesel includes, for example, long chain hydrocarbons, such as long chain hydrocarbons (e.g., paraffins and iso-paraffins) ranging from 10 carbons long to 24 carbons long or from 10 carbons long to 19 carbons long or from 15 carbons long to 19 carbons long. 
       FIG.  2    is a schematic illustration of an integrated stripper  122  in accordance with one or more embodiments. The integrated stripper  122  is used, for example, in a process for renewable diesel production to integrate product separation schemes. Integration of product separation into an integrated stripper  122  reduces, for example, capital requirements for renewable diesel production by reducing the amount and type of process equipment that may be needed. It should be understood that the illustration of  FIG.  2    is an example configuration of the integrated stripper  122  and that other configurations can be used that are suitable for integration of the product separation schemes. 
     In the illustrated embodiment, the integrated stripper  122  includes a column  123 , including a first separate volume  130 , a second separate volume  132 , and a common volume  136 . In some embodiments, the first separate volume  130  and the second separate volume  132  are separated by a dividing wall  134  that prevents intermixing of fluids in each section. As illustrated, tray  200  is positioned at the top of the first and second separate volumes  130 ,  132  to separate them from the common volume that allows gas flow to the common volume but does not allow downward liquid flow into first separate volume  130 . While  FIG.  2    illustrates, a single tray  200  extending across both the first and second separate volumes  130 ,  132 , some embodiments include multiple trays. Tray  200  can be any of a variety of suitable designs for preferentially allowing gas flow, including, but not limited to, chimney tray or bubble cap trays and valve trays. In some embodiments, the second separate volume  132  includes a downcomer  202  to allow downward liquid flow from the common volume  136  to the second separate volume  132 . In some embodiments, the first and second separate volumes  130 ,  132  include equipment disposed therein to promote vapor-liquid mass transfer. Examples of suitable equipment include trays and packing. For example, first separate volume  130  may include first packing section  204 , and the second separate volume  132  may include second packing section  206 . 
     In the illustrated embodiment, the integrated stripper  122  further includes a condenser  208 . In the illustrated embodiment, the common volume  136  includes an upper section  207  and a lower section  209 . In some embodiments, a tray  210  is positioned between the upper section  207  and the lower section  209  of the common volume  136 . Any suitable tray  210  can be used, including, but not limited to a chimney tray or bubble cap trays and valve trays. As illustrated, the condenser  208 , in some embodiments, is positioned in the upper section  207  of the common volume  136 . The condenser  208  may include any suitable heat transfer device, such as coil and spiral condensers. In the illustrated embodiment, the condenser  208  is in the form of a spiral condenser. 
     In operation, the integrated stripper  122  receives various inputs. In example embodiments, one input is the hydrotreated stream  128  including predominantly long chain hydrocarbons (e.g., long chain hydro C10 hydrocarbons) from the HDO stage  102  (e.g., shown on  FIG.  1   ). In example embodiments, hydrotreated stream  128  also includes the absorbed light end molecules (e.g., C9 hydrocarbons or lighter). In some embodiments, the hydrotreated stream  128  is introduced into the first separate volume  130  of the column  123 . In some embodiments, a first stripping medium  212  is also introduced into the first separate volume  130  of the column  123 . The first stripping medium  212  can include any of a variety of suitable stripping agents, including, but not limited to, steam, nitrogen, inert gases, and hydrocarbon gases. In some embodiments, the first stripping medium  212  includes natural gas. The hydrotreated stream  128  is stripped by the first stripping medium  212 , for example, to remove isomerization contaminants, such as carbon monoxide, carbon dioxide, and water. For example, the hydrotreated stream  128  and the first stripping medium  212  are contacted in a countercurrent manner, for example, across the first packing section  204 . This results in formation of at least a first gas stream  131  and an isomerization feed stream  108  with reduced (or minimized) contaminants. In the illustrated embodiment, the isomerization feed stream  108  is withdrawn from the column  123  and passed to the isomerization stage  106  (e.g., shown on  FIG.  1   ). In the illustrated embodiment, the first gas stream  131  passes through tray  200  to the common volume  136 . 
     In the illustrated embodiment, an additional input to the integrated stripper  122  is the isomerization reactor effluent  142  from the isomerization stage  106  (e.g., shown on  FIG.  1   ). As illustrated, the isomerization reactor effluent  142  can be introduced into the common volume  136  of the column  123 . In the common volume, some embodiments contact the isomerization reactor effluent  142  and the first gas stream  131  from the first separate volume  130  in a countercurrent manner. This results in absorption of C4+ hydrocarbons from the first gas stream  131  into the isomerization reactor effluent  142 . In the illustrated embodiment, the common volume  136  also receives a second gas stream  133  from the second separate volume  132 . Vapor in the common volume  136  flows upward through tray  210  into the condenser  208 . In some embodiments, a coolant is introduced into the condenser  208 . In the illustrated embodiment, the condenser  208  includes a cooling water inlet  214  and a cooling water outlet  216  connection through which an inlet cooling water stream  218  is fed to the condenser  208  and outlet cooling water stream  220  is removed from it. From the condenser  208 , a light ends stream  144 , a water-hydrocarbon mixture  222 , and a naphtha product stream  146  is withdrawn in accordance with example embodiments. In the illustrated embodiments, the water-hydrocarbon mixture  222  are passed to a separator  224  to produce a water stream  226  and a hydrocarbon stream  228 , wherein the hydrocarbon stream  228  is returned to the column  123  above the tray  210 . 
     In the illustrated embodiment, the isomerization reactor effluent  142  from the common volume  136  with the absorbed C4+ hydrocarbons is passed to the second separate volume  132  of the column  123 . A second stripping medium  230  can also be introduced into the second separate volume  132 . The second stripping medium  230  can include any of a variety of suitable stripping agents, including, but not limited to, steam, nitrogen, inert gases, and hydrocarbon gases. In the illustrated embodiment, the isomerization reactor effluent  142  is stripped by the second stripping medium  230  to remove lighter components, such as hydrocarbons having less than 10 carbons. For example, example embodiments include contacting the isomerization reactor effluent  142  and the second stripping medium  230  in a countercurrent manner, for example, across the second packing section  206 . This results in formation of at least a second gas stream  133  and a product stream  148 . In the illustrated embodiment, the second gas stream  133  is passed to the common volume  136 , while the product stream  148  is withdrawn from the column  123 . In accordance with present embodiments, the product stream  148  includes renewable diesel. 
       FIG.  3    is a schematic illustration of an alternative configuration of the integrated stripper  122  in accordance with one or more embodiments. In  FIG.  3   , the integrated stripper  122  includes a reflux system  300  that includes an external condenser  302  that cools an overhead gas stream  304  from the column  123 . The reflux system  300  also includes a reflux drum  306  that receives the cooled overhead stream  308  and a reflux pump  310  that pressurizes a liquefied hydrocarbon reflux  312  from the reflux drum  306  for return to the column  123 . 
     In operation, example embodiments include introducing the hydrotreated stream  128  into the first separate volume  130  of the column  123 . In some embodiments, the hydrotreated stream  128  is stripped in the first separate volume  130  by the first stripping medium  212  to remove contaminants that impact the run length of the isomerization catalyst and form an isomerization feed stream  108  and a first gas stream  131 . In the illustrated embodiment, the isomerization feed stream  108  is withdrawn from the column  123  and passed to the isomerization stage  106  (e.g., shown on  FIG.  1   ). As illustrated, the first gas stream  131  passes through tray  200  to the common volume  136 . As illustrated, example embodiments also include introducing the isomerization reactor effluent  142  into the common volume  136  of the column  123 . In the common volume  136 , example embodiments include contacting the isomerization reactor effluent  142  and the first gas stream  131  from the first separate volume  130  in a countercurrent manner. This results in absorption of C4+ hydrocarbons from the first gas stream  131  into the isomerization reactor effluent  142 . In the illustrated embodiment, the isomerization reactor effluent  142  from the common volume  136  with the absorbed C4+ hydrocarbons are passed to the second separate volume  132  of the column  123  where it is stripped by the second stripping medium  230  to remove lighter components and form the second gas stream  133  and the product stream  148  including renewable diesel. In some embodiments, the second gas stream  133  is passed through tray  200  to the common volume  136 . 
     In the illustrated embodiment, an overhead gas stream  304  is withdrawn from the column  123  and passed to the external condenser  302  of the reflux system  300 . In accordance with example embodiments, the external condenser  302  cools and at least partially condenses the overhead gas stream  304 . In the illustrated embodiment, the cooled overhead gas stream  308  is passed to the reflux drum  306 . In accordance with present embodiments, the reflux drum  306  functions as gas-liquid separator to separate lighter hydrocarbons and other gases from water and heavier hydrocarbons in the cooled overhead gas stream  308 . From the reflux drum  306 , in the illustrated embodiment, a light ends stream  144  and produced water stream  226  are withdrawn. In some embodiments, the remainder liquid in the reflux drum  306  is a hydrocarbon liquid that is pressurized by reflux pump  310  and returned to the column as liquefied hydrocarbon reflux  312 . In the illustrated embodiment, a portion of the liquefied hydrocarbon reflux  312  is recovered as naphtha product stream  146 . 
       FIG.  4    is a schematic illustration of an alternative configuration of the integrated stripper  122  in accordance with one or more embodiments. In  FIG.  4   , the integrated stripper  122  includes first stripping reboiler  400  and second stripping reboiler  402 . The integrated stripper  122  uses heat from the first and second stripping reboilers  400 ,  402  for separation instead of separate stripping gases. 
     In operation, example embodiments include introducing the hydrotreated stream  128  into the first separate volume  130  of the column  123 . In accordance with present embodiments, the hydrotreated stream  128  is stripped in the first separate volume  130  by heat from the first stripping reboiler  400  to remove isomerization contaminants and form an isomerization feed stream  108  and a first gas stream  131 . Similar levels of the isomerization contaminants can be stripped from the hydrotreated stream  128  as described previously. In some embodiments, the first gas stream  131  passes through tray  200  to the common volume  136 . In the illustrated embodiment, a first bottoms stream  404  is withdrawn from the first separate volume  130 . In some embodiments, the pressure of the first bottoms stream  404  is increased using a pump (not shown). In the illustrated embodiment, a portion of the first bottoms stream  404  is recovered as the isomerization feed stream  108  and passed to the isomerization stage  106  (e.g., shown on  FIG.  1   ). Example embodiments include passing another portion of the first bottoms stream  404  to the first stripping reboiler  400  as first reboiler feed stream  406 . In some embodiments, the pressure of the first reboiler feed stream  406  is increased using a pump (not shown). From the first stripping reboiler  400 , example embodiments include passing a first reboiler return stream  408  back to the first separate volume  130  where it contacts the hydrotreated stream  128 , for example, in a countercurrent manner. 
     In the illustrated embodiment, the isomerization reactor effluent  142  is introduced into the common volume  136  of the column  123 . In some embodiments, the common volume, the isomerization reactor effluent  142  and the first gas stream  131  from the first separate volume  130  is contacted in a countercurrent manner. This results in absorption of hydrocarbons (e.g., C4+ hydrocarbons) from the first gas stream  131  into the isomerization reactor effluent  142 . In the illustrated embodiment, the isomerization reactor effluent  142  from the common volume  136  with the absorbed C4+ hydrocarbons are passed to the second separate volume  132  of the column  123 , for example, where it is stripped in the second separate volume  132  by heat from the second stripping reboiler  402  to strip lighter components and form the second gas stream  133  and the product stream  148  including renewable diesel. Similar levels of lighter components can be stripped from the isomerization reactor effluent  142  as described previously. In some embodiments, the second gas stream  133  passes through tray  200  to the common volume  136 . In the illustrated embodiment, a second bottoms stream  410  is withdrawn from the second separate volume  132 . In the illustrated embodiment, a portion of the second bottoms stream  410  is recovered as the product stream  148  including renewable diesel. Example embodiments include passing another portion of the second bottoms stream  410  to the second stripping reboiler  402  as second reboiler feed stream  412 . In some embodiments, the pressure of the second reboiler feed stream  412  is increased using a pump (not shown). From the second stripping reboiler  402 , in some embodiments, a second reboiler return stream  414  is passed back to the second separate volume  132  where it contacts the isomerization reactor effluent  142 , for example, in a countercurrent manner. 
     In the illustrated embodiment, an overhead gas stream  304  is withdrawn from the column  123  and passed to the external condenser  302  of the reflux system  300 . The external condenser  302  cools and at least partially condenses the overhead gas stream  304 . In some embodiments, the cooled overhead gas stream  304  is passed to the reflux drum  306 . The reflux drum  306  functions, for example, as gas-liquid separator to separate lighter hydrocarbons and other gases from water and heavier hydrocarbons in the cooled overhead gas stream  304 . From the reflux drum  306 , example embodiments include withdrawing a light ends stream  144  and produced water stream  226 . In some embodiments, the remainder liquid in the reflux drum  306  is a hydrocarbon liquid that is pressurized by reflux pump  310  and returned to the column as liquefied hydrocarbon reflux  312 . In accordance with example embodiments, a portion of the liquefied hydrocarbon reflux  312  is recovered as naphtha product stream  146 . 
       FIG.  5    is a schematic illustration of an integrated stripper column in accordance with one or more embodiments. In  FIG.  5   . the integrated stripper  122  includes a common reboiler  500 . The integrated stripper  122  uses heat from the common reboiler  500  for separation instead of separate stripping gases. 
     In operation, example embodiments include introducing the hydrotreated stream  128  into the first separate volume  130  of the column  123 . In some embodiments, the hydrotreated stream  128  is stripped in the first separate volume  130  by heat from the common reboiler  500  to remove isomerization contaminants and form an isomerization feed stream  108  and a first gas stream  131 . Similar levels of the isomerization contaminants can be stripped from the hydrotreated stream  128  as described previously. In some embodiments, the first gas stream  131  passes through tray  200  to the common volume  136 . In the illustrated embodiment, a first bottoms stream  404  is withdrawn from the first separate volume  130 . In some embodiments, a portion of the first bottoms stream  404  is recovered as the isomerization feed stream  108  and passed to the isomerization stage  106  (e.g., shown on  FIG.  1   ). Example embodiments include passing another portion of the first bottoms stream  404  to the common reboiler  500  as first reboiler feed stream  406 . In some embodiments, the pressure of the first reboiler feed stream  406  is increased using a pump (not shown). From the common reboiler  500 , in some embodiments, a first reboiler return stream  408  is passed back to the first separate volume  130  where it contacts the hydrotreated stream  128 , for example, in a countercurrent manner. 
     In the illustrated embodiment, the isomerization reactor effluent  142  is introduced into the common volume  136  of the column  123 . In the common volume, in some embodiments, the isomerization reactor effluent  142  and the first gas stream  131  from the first separate volume  130  are contacted, for example, in a countercurrent manner. This results in absorption of hydrocarbons (e.g., C4+ hydrocarbons) from the first gas stream  131  into the isomerization reactor effluent  142 . Example embodiments include passing the isomerization reactor effluent  142  from the common volume  136  with the absorbed C4+ hydrocarbons to the second separate volume  132  of the column  123  where it is stripped in the second separate volume  132  by heat from the common reboiler  500  to strip lighter components and form the second gas stream  133  and the product stream  148  including renewable diesel Similar levels of lighter components can be stripped from the isomerization reactor effluent  142  as described previously. In some embodiments, the second gas stream  133  passes through tray  200  to the common volume  136 . Example embodiments include withdrawing a second bottoms stream  410  from the second separate volume  132 . In some embodiments, a portion of the second bottoms stream  410  is recovered as the product stream  148  including renewable diesel. Example embodiments include passing another portion of the second bottoms stream  410  to the common reboiler  500  as second reboiler feed stream  412 . In some embodiments, the pressure of the second reboiler feed stream  412  is increased using a pump (not shown). From the common reboiler  500 , in some embodiments, a second reboiler return stream  414  is passed back to the second separate volume  132  where it contacts the isomerization reactor effluent  142 , for example, in a countercurrent manner. The common reboiler may include of two or more cells to provide the heat required for the integrated stripper  122  to achieve the specification required for the isomerization reactor feed stream  108  and final renewable diesel product stream  148 . 
     In the illustrated embodiment, an overhead gas stream  304  is withdrawn from the column  123  and passed to the external condenser  302  of the reflux system  300 . The external condenser  302  cools and at least partially condenses the overhead gas stream  304 . In some embodiments, the cooled overhead gas stream  304  is passed to the reflux drum  306 . The reflux drum  306  functions, for example, as gas-liquid separator to separate lighter hydrocarbons and other gases from water and heavier hydrocarbons in the cooled overhead gas stream  304 . From the reflux drum  306 , in some embodiments, a light ends stream  144  and produced water stream  226  are withdrawn. In some embodiments, the remainder liquid in the reflux drum  306  is a hydrocarbon liquid, for example, that is pressurized by reflux pump  310  and returned to the column as liquefied hydrocarbon reflux  312 . Example embodiments include recovering a portion of the liquefied hydrocarbon reflux  312  as naphtha product stream  146 . 
       FIGS.  2 - 5    illustrate various stripping schemes for the column  123 .  FIGS.  2  and  3    use first stripping medium  212  and second stripping medium  230 .  FIG.  4    uses first stripping reboiler  400  and second stripping reboiler  402 .  FIG.  5    uses common reboiler  500 . In some embodiments, a reboiler is combined with a stripping medium. While not shown, in some embodiments, the first stripping reboiler  400  is used for stripping in the first separate volume  130  while the second stripping medium  230  is used for stripping in the second separate volume  132 . While not shown, in further embodiments, the second stripping reboiler  402  is used for stripping in the second separate volume  132  while the first stripping medium  212  is used for stripping in the first separate volume  130 . In other embodiments, any combination of the stripping and condensing configurations illustrated in  FIG.  2 - 5    may be used. 
       FIG.  6    is a schematic illustration of an alternative configuration of the system  100  in accordance with one or more embodiments. In the illustrated embodiment, the system  100  includes the following stages: (i) an HDO stage  102  in which a feed stream  104  containing a biofeedstock is reacted with hydrogen to reduce oxygen in the biofeedstock; and (ii) an isomerization stage  106  that receives an isomerization feed stream  108  containing hydrocarbons from the HDO stage  102  and isomerizes the hydrocarbons to improve the cold flow properties of a distillate boiling range portion of the hydrocarbons. In the illustrated embodiment, the HDO stage  102  includes an HDO reactor  110 , an HDO separator  112 , amine unit  114 , and a hydrogen recycle compressor  116 . In accordance with example embodiments, the HDO stage  102  also includes a number of heat exchangers, including, but not limited, first HDO effluent heat exchanger  600 , second HDO effluent heat exchanger  602 , and hydrogen heat exchanger  604 . In accordance with example embodiments, the isomerization stage  106  includes an isomerization reactor  118  and an isomerization reactor effluent separator  120 . In some embodiments, the isomerization stage  106  also includes an isomerization effluent heat exchanger  606 . In the illustrated embodiment, the system  100  includes an integrated stripper  122  for an integrated scheme for the HDO stage  102  and the isomerization stage  106 . While not shown, in some embodiments, the system  100  includes further heat integration. Those of ordinary skill in the art, with the benefit of this disclosure, should be able to develop optimized heat exchanger network schemes that optimize the external heating and cooling for the system  100 . 
     In  FIG.  6   , the HDO reactor  110  includes a first catalyst bed  608 , second catalyst bed  610 , third catalyst bed  612 , fourth catalyst bed  614 , and fifth catalyst bed  616 . While  FIG.  6   , illustrates the HDO reactor  110  as including five catalyst beds, it should be understood that the HDO reactor  110  may have more or less than five catalyst beds in accordance with present embodiments. In the illustrated embodiment, portions of feed stream  104  can be delivered to various regions of the HDO reactor. For example, the feed stream  104  may be divided into 2, 3, 4, 5, or more portions with each portion introduced into the HDO reactor  110  between different sets of catalyst beds. For example, a first portion  618  can be delivered into the HDO reactor above the first catalyst bed  608 . In the illustrated embodiment, the first portion  618  is combined with the hydrogen treat gas stream  124  with the combined feed stream  620  passed through hydrogen heat exchanger  604  for heating followed by introduction into the HDO reactor  110  above the first catalyst bed  608 . In another embodiment (not shown), the hydrogen treat gas stream  124  passes through hydrogen heat exchanger  604  for heating followed mixing it with the first portion  618  and then introducing the mixed stream into the HDO reactor  110  above the first catalyst bed  608 . In some embodiments, a second portion  622  of the feed stream  104  is delivered into the HDO reactor between the first and second catalyst beds  608 ,  610 . In some embodiments, a third portion  624  of the feed stream  104  is delivered into the HDO reactor between the second and third catalyst beds  610 ,  612 . In some embodiments, a fourth portion  626  of the feed stream  104  is delivered into the HDO reactor between the third and fourth catalyst beds  612 ,  614 . In some embodiments, a fifth portion  628  of the feed stream  104  is delivered into the HDO reactor between the fourth and fifth catalyst beds  614 ,  616 . Any suitable amount of the feed stream  104  can be delivered into the various locations of the HDO reactor with the optional constraint that from 1.0 vol % to 30 vol % of the total fresh feed from the feed stream  104  is introduced above the first catalyst bed  608  with a remainder of the fresh feed being introduced downstream. In alternative embodiments, 5.0 wt % to 20 wt %, or 10 wt % to 30 wt %, or 10 wt % to 25 wt % of the total fresh feed is introduced above the first catalyst bed  608  with a remainder of the fresh feed being introduced downstream. In some embodiments, the volume percentage of fresh feed (relative to the total fresh feed) increases for each downstream region. By exposing only a minor portion of the total fresh feed to the first catalyst bed  608 , the temperature rise across the first catalyst bed  608  can be managed to a target level. The resulting deoxygenated effluent from the first catalyst bed  608  can then be at least partially passed into the second catalyst bed  610  (or other subsequent catalyst bed), along with additional fresh feed. The deoxygenated effluent from the first catalyst bed  608  serves, for example, as an additional diluent and/or heat transfer fluid in subsequent catalyst beds for performing deoxygenation. Additionally, one or more techniques can be used to further assist with managing the temperature in subsequent catalyst beds, such as using additional hydrogen treat gas as a quench gas between catalyst beds, using heat exchangers to further cool the deoxygenated effluent, and/or using recycle streams. In some embodiments, while not shown, the HDO reactor  110  includes additional beds that do not include fresh feed but could have quench stream or no quench stream. The quench stream could be, for example, from a liquid recycle stream or hydrogen quench. 
     In some embodiments, the biofeedstock from the feed stream  104  is exposed to hydrodeoxygenation conditions in the HDO reactor  110  in the presence of the catalyst beds that contain hydrodeoxygenation catalyst such that the biofeedstock reacts with the hydrogen to reduce oxygen in the biofeedstock. The reaction in the HDO reactor  110  produces hydrotreated biofeedstock, including paraffins, reaction intermediates (if any), and unreacted biofeedstock (if any) and hydrogen. The paraffins include, for example, long chain paraffinic molecules, such as molecules ranging from 10 carbons long to 24 carbons long or from 10 carbons long to 19 carbons long or from 15 carbons long to 19 carbons long along with light ends having 9 or fewer carbons. In some embodiments, the hydrodeoxygenation substantially deoxygenates the biofeedstock. This corresponds to removing 90% or more, for example, 95% or more, 98% or more, 99% or more, 99.5% or more, 99.9% or more, or completely (measurably) all the oxygen present in the biofeedstock. Alternately, substantially deoxygenating the biofeedstock corresponds to reducing the oxygenate level of the hydrotreated biofeedstock to 0.1 wt. % or less, for example, 0.05 wt. % or less, 0.03 wt. % or less, 0.02 wt. % or less, 0.01 wt. % or less, 0.005 wt. % or less, 0.003 wt. % or less, 0.002 wt. % or less, or 0.001 wt. % or less. 
     During operation of a reactor performing hydrodeoxygenation, the temperature across a catalyst bed can increase. While the distribution of the feed stream  104  shown in  FIG.  6    can mitigate this temperature increase, it can also be beneficial to reduce the temperature of the effluent from one catalyst bed prior to introducing that effluent into the next catalyst bed. To assist with temperature management, the configuration shown in  FIG.  6    provides recycle streams of hydroxygenated effluent as quench streams for various reactor regions. Using product recycle from HDO stage (from the low temperature high pressure separator or the isomerization reactor feed) or the final product to provide cooling of effluent between catalyst beds can provide various advantages. For example, using product recycle can reduce or minimize hydrogen circulation relative to aspects where a hydrogen quench gas is used for cooling between catalyst beds. In some embodiments, heat exchangers are used to remove the heat of reaction between catalyst beds, for example, between first and second catalyst beds  608 ,  610 , between second and third catalysts beds  610 ,  612 , and between third and fourth catalyst beds  612 ,  614 . 
     In the illustrated embodiment, multiple recycle streams are used as quench streams between different sets of catalyst beds. For example, first recycle stream  630  is used as a quench flow between the first catalyst bed  608  and the second catalyst bed  610 . Second recycle stream  632  is used as a quench flow between the second catalyst bed  610  and the third catalyst bed  612 . Third recycle stream  634  is used as a quench flow between the third catalyst bed  612  and the fourth catalyst bed  614 . Fourth recycle stream  636  is used as a quench flow between the fourth catalyst bed  614  and the fifth catalyst bed  616 . Optionally, any convenient number of recycle streams can be used that are introduced into any convenient combination of the regions. 
     In the illustrated embodiment, a hydrotreated effluent stream  126  including hydrotreated biofeedstock is withdrawn from the HDO reactor  110  and flowed to the first HDO effluent heat exchanger  600  for cooling. Example embodiments include combining a cooled hydrotreated effluent stream  638  with a gas stream  140  from the isomerization stage  106  and then passing this combined stream to the second HDO effluent heat exchanger  602  for additional cooling. In the illustrated embodiment, the mixed HDO effluent stream  640  is then be passed to the HDO separator  112 , where a gas-phase portion is separated from liquid-phase products. In the illustrated embodiment, the HDO separator  112  produces a hydrotreated stream  128  including liquid hydrocarbons (e.g., paraffins). In some embodiments, the gas-phase stream  129  contains hydrogen, for example, that can be recycled to the HDO reactor  110 . A portion of the hydrotreated stream  128  can be recycled as effluent recycle stream  642  and split to form the various quench streams after pressurizing in HDO recycle pump  644 . As illustrated, example embodiments include withdrawing a water stream  646  from the HDO separator  112 . 
     In the illustrated embodiment, the gas-phase stream  129  is passed to an amine unit  114 . In some embodiments, the gas-phase stream  129  contains lighter contaminants from the hydrotreated effluent stream  126 , including, but not limited to, carbon monoxide, carbon dioxide, hydrogen sulfide, water (e.g., equilibrium water), and ammonia, as well as some hydrocarbons having 6 carbons or less. In the amine unit  114 , for example, hydrogen sulfide is incorporated into the gas-phase stream  129  to provide a hydrogen treat gas stream  124  that contains hydrogen and hydrogen sulfide. In some embodiments, the amine unit  114  also removes contaminant gases from the gas-phase stream  129 , such as ammonia, carbon monoxide, and carbon dioxide, that were generated in the HDO reactor  110 . In some embodiments, the hydrogen treat gas stream  124  from the amine unit  114  is compressed by hydrogen recycle compressor  116  and then recycled to the HDO reactor  110 . If needed, example embodiments include adding make-up hydrogen gas  648  to the hydrogen treat gas stream  124  (or directly to the HDO reactor  110 ). By incorporation of hydrogen sulfide into the hydrogen treat gas stream  124 , the hydrogen treat gas stream  124  should contain sufficient hydrogen sulfide to substantially maintain the catalysts in the HDO reactor  110  in a sulfided state. 
     In the illustrated embodiment, the amine unit  114  includes a vessel  650  including an amine adsorber section  652  and an amine stripper section  654 . While  FIG.  6    illustrates one of the vessel  650 , it should be understood that the amine unit  114  can be configured with multiple vessels, for example, with the amine adsorber section  652  and amine stripper section  654  in separate vessels. In the illustrated embodiment, the gas-phase stream  129  is introduced into the amine adsorber section  652  along with a lean amine stream  656  (e.g., 0.1 vol % or less of hydrogen sulfide). In the amine adsorber section  652 , in some embodiments, the gas-phase stream  129  contacts the lean amine stream  656 , for example, in a counter current manner, thus allowing for adsorption of one or more contaminants (e.g., carbon dioxide, hydrogen sulfide, etc.) from the gas-phase stream  129  into the lean amine stream  656 . As the gas-phase stream  129  travels up the vessel  650  into amine stripper section  654 , it should contact a rich amine stream  658  (e.g., molar ratio of hydrogen sulfide to amine of 0.25 or more, 0.30 or more, such as up to 1.0). In the illustrated embodiment, the rich amine stream  658  (the feed temperature can be determined based on optimization) is introduced into the vessel  650  above the lean amine stream  656 . As illustrated, example embodiments include introducing the rich amine stream  658  into the amine stripper section  654 , such that it contacts the gas-phase stream  129  in the amine stripper section  654 , for example, in a counter current manner, where hydrogen sulfide is transferred to the gas-phase stream  129 . This results in a hydrogen treat gas stream  124  withdrawn as an overhead from the vessel  650  that is enriched in hydrogen sulfide. In some embodiments, a rich amine bottoms stream  660  and a purge stream  662  are be withdrawn from the vessel  650 . The purge stream  662  functions, for example, to control hydrogen purity and carbon monoxide concentration in the hydrogen treat gas stream  124  recycled to the HDO reactor  110 . While not illustrated, an optional water wash can be used in the vessel  650 , for example, above the rich amine stream  658  to reduce or minimize the potential for entrained amine in the hydrogen treat gas stream  124 . After addition of the hydrogen sulfide, the resulting hydrogen treat gas stream  124  containing both hydrogen and H 2 S includes, for example, 5 ppmv to 3.0 vol % of H 2 S, or 0.05 vol % to 1.0 vol %, or 0.05 vol % to 0.3 vol %, or 0.1 vol % to 3.0 vol %, or 0.1 vol % to 1.0 vol %. In such embodiments, the hydrogen content of the hydrogen treat gas stream  124  can be 75 vol % or more, or 80 vol % or more, or 85 vol % or more, or 90 vol % or more, such as up to 99.95 vol %. 
     In addition to the gas-phase stream  129  being withdrawn from the HDO separator  112  and passed to the amine unit  114 , example embodiments also include withdrawing a hydrotreated stream  128  including hydrocarbons from the HDO separator  112  as illustrated on  FIG.  6   . In some embodiments, he hydrotreated stream  128  is passed to the integrated stripper  122 . The integrated stripper includes, for example, a vessel  123  including a first separate volume  130 , a second separate volume  132 , and a common volume  136 . Example embodiments include introducing the hydrotreated stream  128  into the first separate volume  130  where it contacts (e.g., countercurrently) a first stripping medium  212  to remove isomerization contaminants (e.g., carbon monoxide, carbon dioxide, and water) from the hydrotreated stream  128  and form an isomerization feed stream  108  and a first gas stream  131 . In some embodiments, the hydrotreated stream  128  and the first stripping medium  212  countercurrently contact across a first tray section  659  (or a first packed section  204  as shown on  FIG.  2   ) in the first separate volume  130 . Similar levels of contaminants can be removed from the hydrotreated stream  128  as previously described. 
     In some embodiments, the isomerization feed stream  108  including the stripped hydrocarbons is pressurized by isomerization feed pump  664  and then passed to the isomerization reactor  118  after heating. Example embodiments include adding make-up hydrogen  666  to the isomerization feed stream  108  prior to introduction into the isomerization reactor  118 . In the isomerization reactor, catalytic isomerization is performed by exposing the stripped hydrocarbons in the isomerization feed stream  108  to an isomerization catalyst under effective isomerization conditions. Example embodiments include withdrawing an isomerization reactor product stream  138  from the isomerization reactor  118  and cooling the isomerization reactor product stream  138  in isomerization effluent heat exchanger  606 . In some embodiments, the cooled isomerization product stream  668  is then be passed to the isomerization reactor effluent separator  120 . In the isomerization reactor effluent separator  120 , in some embodiments, the liquid-phase products in the cooled isomerization product stream  668  is separated from the gas-phase products to form a gas stream  140  and an isomerization reactor effluent  142 . In the illustrated embodiment, the gas stream  140  including, for example, hydrogen and lighter hydrocarbons (e.g., C1-C10 hydrocarbons), dependent on the operating conditions of the isomerization reactor effluent separator  120 , are combined with the cooled hydrotreated effluent stream  638 . 
     In the illustrated embodiment, the isomerization reactor effluent  142  is then be passed to the integrated stripper  122 . In  FIG.  6   , in some embodiments, the isomerization reactor effluent  142  from the isomerization stage  106  enters the common volume  136  of the vessel  123  where it contacts the first gas stream  131  from the first separate volume  130 . The isomerization reactor effluent  142  absorbs hydrocarbons (e.g., C4+ hydrocarbons) from the first gas stream  131 . In the illustrated embodiment, the common volume  136  also receives a second gas stream  133  from the second separate volume  132 . In some embodiments, vapor in the common volume  136  flows upward through tray  210  into the condenser  208 . In some embodiments, a coolant is introduced into the condenser  208 , shown as inlet cooling water stream  218  and outlet cooling water stream  220 . From the condenser  208 , example embodiments include withdrawing a light ends stream  144 , a water-hydrocarbon mixture  222 , and a naphtha product stream  146 . In some embodiments, the water-hydrocarbon mixture  220  is passed to a separator  224  to produce a water stream  226  and a hydrocarbon stream  228 . Example embodiments include returning the hydrocarbon stream  228  to the column  123 . 
     In the illustrated embodiment, the isomerization reactor effluent  142  from the common volume  136  with the absorbed hydrocarbons (e.g., C4+ hydrocarbons) is passed to the second separate volume  132  of the column  123 . In some embodiments, a second stripping medium  230  is also introduced into the second separate volume  132 . In some embodiments, the isomerization reactor effluent  142  is stripped by the second stripping medium  230  to remove lighter components, such as hydrocarbons having less than 10 carbons. For example, in some embodiments, the isomerization reactor effluent  142  and the second stripping medium  230  are contacted in a countercurrent manner across the second tray section  661  (or packing, such as second packing section  206  on  FIG.  2   ). This results in formation of at least a second gas stream  133  and a product stream  148 . Example embodiments include passing the second gas stream  133  to the common volume  136 , while the product stream  148  may be withdrawn from the column  123 . In some embodiments, the product stream  148  includes renewable diesel. In the illustrated embodiment, the product stream  148  is further treated, for example, the product stream  148  may be processed through various equipment. In some embodiments, the product stream  148  is cooled in heat exchanger  678  then passed through filter-coalescer  680  and then a salt dryer  682  to provide a treated product stream  684  if the second stripping medium  230  is steam, for example, to meet the water specification of the final product. 
     Feedstocks 
     In accordance with present embodiments, the renewable diesel is produced from a biofeedstock. As used herein, a biofeedstock refers to a feed derived from a biological source, which is a feed derived from a biological raw material component, such as vegetable fats/oils or animal fats/oils, fish oils, pyrolysis oils, and algae lipids/oils, as well as components of such materials, and in some embodiments can specifically include one or more type of lipid compounds. Lipid compounds are typically biological compounds that are insoluble in water, but soluble in nonpolar (or fat) solvents. Non-limiting examples of such solvents include alcohols, ethers, chloroform, alkyl acetates, benzene, and combinations thereof. 
     Examples of vegetable oils that can be used in accordance with this invention include, but are not limited to, rapeseed (canola) oil, soybean oil, coconut oil, sunflower oil, palm oil, palm kernel oil, peanut oil, linseed oil, tall oil, corn oil, castor oil, jatropha oil, jojoba oil, olive oil, flaxseed oil, camelina oil, safflower oil, babassu oil, tallow oil and rice bran oil. 
     As an example, in some embodiments, renewable diesel production can correspond to conversion of a biofeedstock including a substantial portion of vegetable oil into renewable diesel. Such a biofeedstock can include 40 wt % or more of a bio-oil, or 60 wt % or more, or 80 wt % or more, such as up to being substantially composed of a bio-oil (99 wt % or more). Some types of bio-oil can correspond to soybean oil, canola oil, and/or other types of oils corresponding to a primary bio-oil product. In such aspects, the bio-oil can optionally have a triglyceride content of 40 wt % or more, or 60 wt % or more, or 80 wt % or more, such as up to being substantially composed of triglycerides. Other types of bio-oils can correspond to oils such as the corn oil that is formed as a secondary product during ethanol production from corn biomass. 
     Algae oils or lipids can typically be contained in algae in the form of membrane components, storage products, and/or metabolites. Certain algal strains, particularly microalgae such as diatoms and cyanobacteria, can contain proportionally high levels of lipids. Algal sources for the algae oils can contain varying amounts, e.g., from 2 wt % to 40 wt % of lipids, based on total weight of the biomass itself. 
     Vegetable fats/oils, animal fats/oils, fish oils, pyrolysis oils, and/or algae lipids/oils as referred to herein can also include processed material. Non-limiting examples of processed vegetable, animal (including fish), and algae material include fatty acids and fatty acid alkyl esters. Alkyl esters typically include C 1 -C 5  alkyl esters of fatty acids. One or more of methyl, ethyl, and propyl esters are preferred. 
     Other bio-derived feeds usable in the present invention can include any of those which include primarily triglycerides and free fatty acids (FFAs). The triglycerides and FFAs typically contain aliphatic hydrocarbon chains in their structure having from 8 to 36 carbons, preferably from 10 to 26 carbons, for example from 10 to 22 carbons or 14 to 22 carbons. Types of triglycerides can be determined according to their fatty acid constituents. The fatty acid constituents can be readily determined using Gas Chromatography (GC) analysis. This analysis involves extracting the fat or oil, saponifying (hydrolyzing) the fat or oil, preparing an alkyl (e.g., methyl) ester of the saponified fat or oil, and determining the type of (methyl) ester using GC analysis. In one embodiment, a majority (i.e., greater than 50%) of the triglyceride present in the lipid material can be included of C 10  to C 26  fatty acid constituents, based on total triglyceride present in the lipid material. Further, a triglyceride is a molecule having a structure corresponding to a reaction product of glycerol and three fatty acids. Although a triglyceride is described herein as having side chains corresponding to fatty acids, it should be understood that the fatty acid component does not necessarily contain a carboxylic acid hydrogen. Other types of feed that are derived from biological raw material components can include fatty acid esters, such as fatty acid alkyl esters (e.g., FAME and/or FAEE). 
     A feed derived from a biological source can have a wide range of nitrogen and/or sulfur contents. For example, a feedstock based on a vegetable oil source can contain up to 300 wppm nitrogen. In contrast, a biomass based feed stream containing whole or ruptured algae can sometimes include a higher nitrogen content. Depending on the type of algae, the nitrogen content of an algae based feed stream can be at least 2 wt %, for example at least 3 wt %, at least 5 wt %, such as up to 10 wt % or possibly still higher. The sulfur content of a feed derived from a biological source can also vary. In some embodiments, the sulfur content can be 500 wppm or less, or 200 wppm or less, or 100 wppm or less, or 50 wppm or less, such as down to being substantially free of sulfur (1.0 wppm or less). 
     Aside from nitrogen and sulfur, oxygen can be another heteroatom component in feeds derived from a biological source. For example, a feed derived from a biological source, prior to hydrodeoxygenation, can include 1.0 wt % to 15 wt % of oxygen, or 1.0 wt % to 10 wt %, or 3.0 wt % to 15 wt %, or 3.0 wt % to 10 wt %, or 4.0 wt % to 15 wt %, or 4.0 wt % to 12 wt %. 
     In some embodiments, a portion of a mineral feedstock can be co-processed with a feed derived from a biological source. A mineral feedstock refers to a conventional feedstock, typically derived from crude oil and that has optionally been subjected to one or more separation and/or other refining processes. In one preferred embodiment, the mineral feedstock can be a petroleum feedstock boiling in the diesel range or above. Examples of suitable feedstocks can include, but are not limited to, virgin distillates, hydrotreated virgin distillates, kerosene, diesel boiling range feeds (such as hydrotreated diesel boiling range feeds), light cycle oils, atmospheric gas oils, and the like, and combinations thereof. The amount of mineral feedstock blended with a feed derived from a biological source can correspond to 1.0 wt % to 50 wt % of the weight of the blended feedstock. Alternatively, the amount of feed derived from biological source can correspond to 1.0 wt % to 50 wt % of the weight of the blended feed stock. Additionally or alternately, in some embodiments, the amount of mineral feedstock blended with the bio-derived feed is low enough so that the resulting blended or combined feed has a sulfur content of 10 wppm to 1000 wppm. 
     Mineral feedstocks for blending with a bio-derived can be relatively free of nitrogen (such as a previously hydrotreated feedstock) or can have a nitrogen content from 1 wppm to 2000 wppm nitrogen, for example from 50 wppm to 1500 wppm or from 75 to 1000 wppm. In some embodiments, the mineral feedstock can have a sulfur content from 1 wppm to 10,000 wppm sulfur, for example from 10 wppm to 5,000 wppm or from 100 wppm to 2,500 wppm. However, in various aspects, such mineral feedstocks can be combined with a bio-derived feed (and/or other feeds) so that the resulting combined feed has a sulfur content of 1000 wppm or less, 300 wppm or less, or 200 wppm or less, or 100 wppm or less, such as down to 0.1 wppm or possibly still lower. Additionally or alternately, the combined feed can have an oxygen content of 1.0 wt % or more, such as 1.0 wt % to 15 wt %. 
     The content of sulfur, nitrogen, oxygen, and olefins in a feedstock created by blending two or more feedstocks can typically be determined using a weighted average based on the blended feeds. For example, a mineral feed and a bio-derived feed can be blended in a ratio of 20 wt % mineral feed and 80 wt % bio-derived feed. If the mineral feed has a sulfur content of 1000 wppm, and the bio-derived feed has a sulfur content of 10 wppm, the resulting blended feed could be expected to have a sulfur content of 208 wppm. 
     Hydrodeoxygenation Stage 
     In various embodiments, a biofeedstock can be exposed to hydroprocessing conditions in a hydroprocessing stage. An HDO stage can include one or more HDO reactors, with each HDO reactor including one or more catalyst beds. The catalyst beds within a reactor can include similar catalysts or different catalysts, depending on the configuration. Exposing a biofeedstock to hydroprocessing conditions can result in hydrodeoxygenation of the feed. In some embodiments, the hydrodeoxygenation includes reacting the biofeedstock with hydrogen to remove oxygen. The reaction in the HDO stage should produce a hydrotreated effluent that includes paraffin products, reaction intermediates, and unreacted biofeedstock and hydrogen. Example reaction intermediates include esters, acids, and ketones, alcohols, among others. 
     Some examples of HDO catalysts can correspond to hydrotreating catalysts. Examples of suitable HDO catalysts include at least one Group 6 metal and/or Group 8 metal, optionally on a support such as alumina or silica. Specific examples can include, but are not limited to, NiMo, CoMo, and NiW supported catalysts. In some embodiments, a catalyst can be used that includes a Group 6 metal on a support material, but less than 1.0 wt % of a Group 8 metal. In other aspects, a hydrotreating catalysts that include both a Group 6 metal and a Group 8 metal on a support material can be used. At least one Group 6 metal, in oxide form, can typically be present in an amount ranging from 2.0 wt % to 40 wt %, relative to a total weight of the catalyst, or 6.0 wt % to 40 wt %, or 10 wt % to 30 wt %. When a Group 8-10 metal is also present, the at least one Group 8-10 metal, in oxide form, can typically be present in an amount ranging from 2.0 wt % to 40 wt %, preferably for supported catalysts from 2.0 wt % to 20 wt % or from 4.0 wt % to 15 wt %. 
     The HDO catalyst can be provided in a reactor in one or more catalyst beds. For example, a convenient bed length in some reactors is a bed length of 25 feet to 30 feet. Such a bed length reduces difficulties in a catalyst bed associated with poor flow patterns. Due to the heat release from the initial bed during olefin saturation and deoxygenation, some embodiments use a shorter catalyst bed as the initial bed, such as having a bed length of 10 feet to 25 feet. 
     The HDO reactor can be operated at any suitable conditions that are effective for hydrodeoxygenation. Effective hydrodeoxygenation conditions include, but are not limited to, a temperature of 230° C. or higher, for example, 285° C. or higher, 315° C. or higher, or 340° C. or higher. Additionally, or alternately, the temperature can be 400° C. or less, for example, 370° C. or less, or 340° C. or less. Suitable effective temperatures can be from 230° C. to 375° C., or 250° C. to 350° C. Effective hydrotreatment conditions can additionally or alternately include, but are not limited to, a total pressure of 2.8 MPag or more, for example, 3 MPag or more, 5 MPag or more, or 7 MPag or more. Additionally or alternately, the total pressure can be 10 MPag or less, for example 8 MPag or less, 7 MPag or less, or 6 MPag or less. In some embodiments, the hydrodeoxygenation conditions can include, but are not necessarily limited to, a temperature of 315° C. to 425° C. and a total pressure of 2 MPag to 21 MPag). 
     Additional hydrodeoxygenation conditions for the HDO reactor include a hydrogen treat gas rate and a liquid hourly space velocity (LSHV). The LHSV can be from 0.1 hr −1  to 10 hr 1 , or from 0.2 hr −1  to 5.0 hr −1 . The hydrogen treat gas rate can be any convenient value that provides sufficient hydrogen for deoxygenation of a feedstock. Typical values can range from 500 scf/B (84 Nm 3 /m 3 ) to 10,000 scf/B (1685 Nm 3 /m 3 ). One option for selecting a treat gas rate can be to select a rate based on the expected stoichiometric amount of hydrogen for complete deoxygenation and olefin saturation of the feedstock. For example, many types of feeds derived from biological sources have a stoichiometric hydrogen need for deoxygenation of between 200 scf/B (34 Nm 3 /m 3 ) to 5000 scf/B (˜850 Nm 3 /m 3 ). In some embodiments, the hydrogen treat gas rate can be selected based on a multiple of the stoichiometric hydrogen need, such as at least 1 times the hydrogen need, or at least 1.5 times the hydrogen need, or at least 2 times the hydrogen need, such as up to 10 times the hydrogen need or possibly still higher. In other aspects where at least a portion of the gas phase deoxygenation effluent is recycled, any convenient amount of hydrogen relative to the stoichiometric need can be used. In various aspects, the hydrogen treat gas can be an H 2 S-enriched hydrogen treat gas as described herein with an H 2 S content of 5 ppmv to 3.0 vol %. 
     As previously described, the HDO stage should at least partially deoxygenate the biofeedstock. Deoxygenating the biofeedstock can avoid problems with catalyst poisoning or deactivation due to the creation of water or carbon oxides during the subsequent isomerization stage. The HDO stage can be used to substantially deoxygenate the biofeedstock. This corresponds to removing 90% or more, for example, 95% or more, 98% or more, 99% or more, 99.5% or more, 99.9% or more, or completely (measurably) all the oxygen present in the biofeedstock. Alternately, substantially deoxygenating the biofeedstock can correspond to reducing the oxygenate level of the hydrotreated biofeedstock to 0.1 wt. % or less, for example, 0.05 wt. % or less, 0.03 wt. % or less, 0.02 wt. % or less, 0.01 wt. % or less, 0.005 wt. % or less, 0.003 wt. % or less, 0.002 wt. % or less, or 0.001 wt. % or less. 
     Isomerization Stage 
     In various embodiments, an isomerization feed stream can be exposed to isomerization conditions in an isomerization stage. The isomerization feed stream can include hydrocarbons from the HDO stage. The isomerization stage can include one or more isomerization reactors, with each isomerization reactor including one or more catalyst beds. The catalyst beds within a reactor can include similar catalysts or different catalysts, depending on the configuration. Exposing an isomerization feed stream to isomerization conditions can result in hydroisomerization of long chain hydrocarbons with improved cold flow properties of the distillate boiling range portion of the effluent. In the isomerization stage, long chain hydrocarbons can also be hydrocracked. Fatty acid carbon chains often correspond to unbranched carbon chains. After deoxygenation, such unbranched carbon chains can often have relatively poor cold flow properties, such as relatively high pour points, cloud points, or cold filter plugging points. In production of renewable diesel, it can be desirable to expose a distillate boiling range product to an isomerization catalyst under isomerization conditions in order to improve the cold flow properties 
     Isomerization catalysts can include molecular sieves such as crystalline aluminosilicates (zeolites). More generally, isomerization catalysts can correspond to catalysts having a zeotype framework. The isomerization catalyst can optionally be a supported catalyst, such as a catalyst including a zeotype framework and a binder material. In an embodiment, the zeotype framework can include, consist essentially of, or be ZSM-5, ZSM-22, ZSM-23, ZSM-35, ZSM-48, zeolite Beta, or a combination thereof, for example ZSM-23 and/or ZSM-48, or ZSM-48 and/or zeolite Beta. Optionally but preferably, zeotype frameworks that are selective for isomerization by isomerization as opposed to cracking can be used, such as ZSM-48, zeolite Beta, ZSM-23, or a combination thereof. Additionally or alternately, the zeotype framework can include, consist essentially of, or be a 10-member ring 1-D zeotype framework. Optionally but preferably, the isomerization catalyst can include a binder for the zeotype framework, such as alumina, titania, silica, silica-alumina, zirconia, or a combination thereof, for example alumina and/or titania or silica and/or zirconia and/or titania. 
     Aside from the zeotype framework(s) and optional binder, the isomerization catalyst can also include at least one metal hydrogenation component, such as a Group 8-10 metal. Suitable Group 8-10 metals can include, but are not limited to, Pt, Pd, Ni, or a combination thereof. When a metal hydrogenation component is present, the isomerization catalyst can include 0.1 wt % to 10 wt % of the Group 8-10 metal, or 0.1 wt % to 5.0 wt %, or 0.5 wt % to 10 wt %, or 0.5 wt % to 5.0 wt %, or 1.0 wt % to 10 wt %, or 1.0 wt % to 5.0 wt %. 
     In some embodiments, the isomerization catalyst can include an additional Group 6 metal hydrogenation component, such as W and/or Mo. In such aspects, when a Group 6 metal is present, the isomerization catalyst can include 0.5 wt % to 20 wt % of the Group 6 metal, or 0.5 wt % to 10 wt %, or 2.5 wt % to 20 wt %, or 2.5 wt % to 10 wt %. As one example, the isomerization catalyst can include 0.1 wt % to 5.0 wt % Pt and/or Pd as the hydrogenation metal component. As another example, the isomerization catalyst can include as the hydrogenation metal components Ni and W, Ni and Mo, or Ni and a combination of W and Mo. 
     Catalytic isomerization can be performed by exposing the isomerization feed stream to an isomerization catalyst under effective (catalytic) isomerization conditions. Effective isomerization conditions can include, but are not limited to, a temperature of 260° C. or higher, for example, 285° C. or higher, 315° C. or higher, or 340° C. or higher. Additionally, or alternately, the temperature can be 450° C. or less, for example 370° C. or less, or 345° C. or less. Effective isomerization conditions can additionally or alternately include, but are not limited to, a total pressure of 1.4 MPag or more, for example, 1.7 Mpag or more, 3.4 MPag or more, 5.2 MPag or more, or 6.9 MPag or more. Additionally or alternately, the total pressure can be 35 MPag or less, for example 10 MPag or less. In some embodiments, isomerization conditions include a temperature of 260° C. to 450° C. and a pressure of 1.4 Mpag to 35 Mpag. The liquid hourly space velocity (LHSV) of the feed relative to the isomerization catalyst can be characterized can be from 0.1 hr −1  to 10 hr −1 . 
     Additional Embodiments 
     Accordingly, the preceding description describes production of renewable diesel and, more particularly, to use of an integrated stripper for product separation. The methods, systems, and apparatus disclosed herein may include any of the various features disclosed herein, including one or more of the following embodiments. 
     Embodiment 1. A method of processing a biofeedstock, including: hydrotreating the biofeedstock by reaction with hydrogen in the presence of a hydrodeoxygenation catalyst to form at least a hydrotreated effluent stream; cooling the hydrotreated effluent stream; separating a gas-phase portion from at least the cooled hydrotreated effluent stream to form at least a gas-phase stream and a hydrotreated stream; stripping at least a portion of the hydrotreated stream to remove isomerization contaminants and form at least an isomerization feed stream and a first gas stream; contacting at least a portion of the isomerization feed stream with an isomerization catalyst to form an isomerization effluent stream; separating at least the isomerization effluent stream to form at least a first gas stream and an isomerization reactor effluent; contacting at least a portion of the isomerization reactor effluent with the first gas stream such that the isomerization reactor effluent adsorbs at least hydrocarbons having 4 carbons are more from the first gas stream; and stripping at least a portion of the isomerization effluent stream to form at least a product stream and a second gas stream, wherein the product stream comprises renewable diesel and has a minimum flash point of about 35° C. to about 60° C. as determined in accordance with ATSTM D93. 
     Embodiment 2. The method of embodiment 1 further comprising combining at least the first gas stream separated from the isomerization effluent stream with the hydrotreated effluent stream prior to the separating the gas-phase portion such that the separating the gas-phase portion separates at least a combined stream of the first gas stream and the hydrotreated effluent stream. 
     Embodiment 3. The method of embodiment 1 or embodiment 2 further comprising cooling the isomerization effluent stream prior to the separating the isomerization effluent stream. 
     Embodiment 4. The method of any preceding embodiment further comprising combining the hydrotreated effluent stream with at least a portion of the first gas stream from the separating the isomerization effluent stream prior to the separating the gas-phase portion. 
     Embodiment 5. The method of any preceding embodiment, wherein the isomerization contaminants comprise at least one of carbon monoxide, carbon dioxide, or water. 
     Embodiment 6. The method of any preceding embodiment, wherein the stripping at least a portion of the hydrotreated stream comprises counter current contact with a first stripping medium, and wherein the stripping at least a portion of the isomerization effluent stream comprises counter current with a second stripping medium. 
     Embodiment 7. The method of any one of embodiments 1 to 5, wherein a stripping medium for at least one of the hydrotreated stream and/or the isomerization effluent stream comprises heat from one or more stripping reboilers. 
     Embodiment 8. The method of any preceding embodiment, wherein the stripping of at least a portion of the hydrotreated stream is performed in a first separate volume of a tower, wherein the stripping of at least a portion of the isomerization effluent stream is performed in a second separate volume of the tower, wherein the first and second separate volumes are separated by a dividing wall, wherein the contacting of at least a portion of the isomerization reactor effluent with the first gas stream occurs in a common volume that is above the first and second separate volumes, wherein liquid can flow from the common volume to the second separate volume but cannot flow from the common volume to the first separate volume. 
     Embodiment 9. The method of embodiment 8, wherein vapor from the common volume is condensed in a condenser and separated to form at least a naphtha product stream and a light ends stream comprising carbons having from 1 carbon to 6 carbons. 
     Embodiment 10. The method of embodiment 9, wherein the condenser comprises of a spiral condenser. 
     Embodiment 11. The method of any preceding embodiment, further comprising stripping a rich amine stream with at least portion of the gas-phase stream from the separating the gas-phase portion to enrich the gas-phase stream with hydrogen sulfide, wherein the hydrogen for the hydrotreating is provided in a hydrogen treat gas that comprises at least a portion of the enriched gas-phase stream, wherein the rich amine stream has a molar ratio of hydrogen sulfide to amine of 0.25 or more. 
     Embodiment 12. The method of embodiment 11, further comprising contacting the gas-phase stream with a lean amine stream to strip contaminants from the gas-phase stream prior to the stripping the rich amine stream. 
     Embodiment 13. The method of any preceding embodiment, wherein the biofeedstock comprises a vegetable oil. 
     Embodiment 14. A method for integration of product separation in renewable diesel production, comprising: stripping a hydrotreated effluent stream comprising hydrotreated biofeedstock to remove isomerization contaminants and form at least an isomerization feed stream and a first gas stream; contacting an isomerization effluent with the first gas stream such that the isomerization effluent adsorbs at least C4+ hydrocarbons from the first gas stream; and stripping at least a portion of an isomerization effluent in an integrated stripper while separated from the stripping the hydrocarbon stream by a dividing wall to remove hydrocarbons having 10 carbons or less and form at least a product stream and a second gas stream, wherein the product stream comprises renewable diesel. 
     Embodiment 15. The method of embodiment 14, wherein the isomerization contaminants comprise at least one of carbon monoxide, carbon dioxide, or water. 
     Embodiment 16. The method of embodiment 14 or embodiment 15, wherein the stripping at least a portion of the hydrotreated stream comprising counter currently contacting the hydrotreated stream with a first stripping medium, and wherein the stripping at least a portion of the isomerization effluent stream comprises counter currently contacting the at least a portion of the isomerization effluent stream with a second stripping medium. 
     Embodiment 17. The method of embodiment 16, wherein the first stripping medium and the second stripping medium each individually comprise natural gas, steam, an inert gas, or combinations thereof. 
     Embodiment 18. The method of any one of embodiments 14 to 17, wherein the stripping the at least a portion of the hydrotreated stream is performed in a first separate volume of a tower, where the stripping at least a portion of the isomerization effluent stream is performed in a second separate volume of the tower, wherein the first and second separate volumes are separated by a dividing wall, and wherein the contacting at least a portion of the isomerization reactor effluent with the first gas stream occurs in a common volume that is above the first and second separate volumes. 
     Embodiment 19. The method of embodiment 18, wherein vapor from the common volume is condensed and separated to form at least a naphtha product stream and a light ends stream comprising carbons having from 1 carbon to 6 carbons. 
     Embodiment 20. The method of any one of embodiments 14 to 19, wherein the hydrotreated biofeedstock comprises hydrotreated vegetable oil. 
     To facilitate a better understanding of the embodiments described herein, the following examples of certain aspects of some embodiments are given. In no way should the following examples be read to limit, or define, the scope of the present disclosure. 
     Examples 
     To illustrate integrated stripping, a simulation was performed with an integrated stripper  122  configured as shown in  FIG.  2   . The integrated stripped  122  used in this example had a dividing wall  134  separating the first and second separate volumes  130 ,  132 . A hydrotreated stream  128  was fed to the first separate volume  130  where it was stripped with natural gas at 125 psig (862 kpa) and 38° C. as the first stripping medium  212 . The stripping section with natural gas had 5 theoretical stages. 
     The gas from the first separate volume (e.g., shown on  FIG.  2    as first gas stream  131 ) from the first separate volume passed through a chimney tray (shown on  FIG.  2    as tray  200 ) where it counter currently contacts an isomerization reactor effluent  142  in common volume  136 . This isomerization reactor effluent is then fed to the other size of the dividing wall  134  in the second separate volume  132  where it is stripped with steam at 125 psig (862 kpag) as the second stripping medium  230 . The integrated stripper is operated at a pressure of 70 psig (483 kpag) and overhead temperature of 170° F. (77° C.). The second separate volume  132  is operated with a bottoms temperature of 404° F. (207° C.). The isomerization reactor effluent stripping is done using steam. The stripping of isomerization reactor effluent was simulated using 11 theoretical stages with isomerization reactor effluent fed on stage 4 and the feed from first separate volume  130  was fed on stage 7. 
     The overhead from the common volume  136  is fed to a condenser  208 . The overhead condensed naphtha and water (e.g., hydrocarbon stream  228  and water stream  226  on  FIG.  2   ) are separated in separator  224 . The naphtha is fed back into the integrated stripper  122 . A side stream is removed from the integrated stripper  122  as a green naphtha product (e.g., naphtha product stream  146 ). A product stream  148  including renewable diesel is withdrawn from the second separate volume  132  and an isomerization feed stream  108  is withdrawn from the first separate volume  130 . 
     The simulated feeds to the integrated stripper  122  are provided in the table below. In the following table, NBP refers to “Normal Boiling Point.” 
     
       
         
           
               
               
               
             
               
                   
                 TABLE 1 
               
               
                   
                   
               
               
                   
                   
                 Isomerization 
               
               
                   
                 Hydrotreated 
                 Reactor 
               
               
                   
                 Stream 128 
                 Effluent 142 
               
               
                   
                   
               
             
            
               
                   
               
            
           
           
               
               
               
               
            
               
                   
                 Temperature 
                 350° F. 
                 500° F. 
               
               
                   
                   
                 (177° C.) 
                 (260° C.) 
               
               
                   
                 Pressure 
                 625 psig 
                 790 psig 
               
               
                   
                   
                 (4309 kpag) 
                 (5500 kpag) 
               
               
                   
                 Rate 
                 131430 lb/hr 
                 112468 lb/hr 
               
               
                   
                   
                 (59616 kg/hr) 
                 (51015 kg/hr) 
               
               
                   
                 Molar 
               
               
                   
                 Composition 
               
               
                   
                 H 2   
                 3.87 
                 9.61 
               
               
                   
                 CO 
                 0.17 
                 0.00 
               
               
                   
                 CO 2   
                 0.15 
                 0.00 
               
               
                   
                 H 2 O 
                 0.23 
                 0.00 
               
               
                   
                 H 2 S 
                 0.03 
                 0.00 
               
               
                   
                 C1-C2 
                 2.42 
                 0.27 
               
               
                   
                 C3 
                 22.82 
                 2.14 
               
               
                   
                 C4-C6 
                 6.71 
                 4.95 
               
               
                   
                 NBP 60-350 
                 5.75 
                 10.06 
               
               
                   
                 NBP 350-650 
                 56.18 
                 69.62 
               
               
                   
                 NBP 650+ 
                 1.65 
                 3.24 
               
               
                   
                   
               
            
           
         
       
     
     The simulated products from the integrated stripper  122  are provided in the table below. The product stream  148  is shown with 3.57 mole % of water was sent through simulated product treatment, including a salt dryer to bring the water content down to 0.01 mole %. 
     
       
         
           
               
               
               
               
               
             
               
                   
                 TABLE 2 
               
               
                   
                   
               
               
                   
                   
                   
                 Naphtha Product 
                 Product 
               
               
                   
                 Isomerization 
                   
                 Stream 146 
                 Stream 148 
               
               
                   
                 Feed Stream 
                 Light ends 
                 (Green Naphtha 
                 (Renewable 
               
               
                   
                 108 
                 stream 144 
                 Product) 
                 Diesel) 
               
               
                   
                   
               
             
            
               
                   
               
            
           
           
               
               
               
               
               
            
               
                 Temperature 
                 348° F. 
                 170° F. 
                 170° F. 
                 404° F. 
               
               
                   
                 (177° C.) 
                 (77° C.) 
                 (77° C.) 
                 (207° C.) 
               
               
                 Pressure 
                 800 psig 
                 70 psig 
                 70 psig 
                 70 psig 
               
               
                   
                 (5520 kpag) 
                 480 (kpag) 
                 480 (kpag) 
                 480 (kpag) 
               
               
                 Total Mass Rate 
                 121,879 lb/hr 
                 13,367 lb/hr 
                 890 lb/hr 
                 108,545 lb/hr 
               
               
                   
                 (55,280 kg/hr) 
                 (6,060 kg/hr) 
                 (400 kg/hr) 
                 (49,230 kg/hr) 
               
               
                 Total Molar Comp. 
               
               
                 Percent 
               
               
                 H2 
                 0.00 
                 23.65 
                 0.20 
                 0.00 
               
               
                 CO 
                 0.00 
                 0.36 
                 0.01 
                 0.00 
               
               
                 CO2 
                 0.01 
                 0.32 
                 0.02 
                 0.00 
               
               
                 H2O 
                 0.01 
                 5.22 
                 0.40 
                 3.57 
               
               
                 H2S 
                 0.00 
                 0.05 
                 0.01 
                 0.00 
               
               
                 C1-C2 
                 1.55 
                 6.07 
                 0.42 
                 0.00 
               
               
                 C3 
                 7.03 
                 41.15 
                 13.49 
                 0.01 
               
               
                 C4-C6 
                 3.70 
                 15.97 
                 20.97 
                 0.05 
               
               
                 NBP 60-350 
                 6.18 
                 7.09 
                 64.43 
                 7.58 
               
               
                 NBP 350-650 
                 79.12 
                 0.00 
                 0.05 
                 84.73 
               
               
                 NBP 650+ 
                 2.33 
                 0.00 
                 0.00 
                 3.94 
               
               
                   
               
            
           
         
       
     
     While the invention has been described with respect to a number of embodiments and examples, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments can be devised which do not depart from the scope and spirit of the invention as disclosed herein. Although individual embodiments are discussed, the invention covers all combinations of all those embodiments. 
     While compositions, methods, and processes are described herein in terms of “comprising,” “containing,” “having,” or “including” various components or steps, the compositions and methods can also “consist essentially of” or “consist of” the various components and steps. The phrases, unless otherwise specified, “consists essentially of” and “consisting essentially of” do not exclude the presence of other steps, elements, or materials, whether or not, specifically mentioned in this specification, so long as such steps, elements, or materials, do not affect the basic and novel characteristics of the invention, additionally, they do not exclude impurities and variances normally associated with the elements and materials used. 
     The phrase “major amount” or “major component” as it relates to components included within the renewable diesel of the specification and the claims means greater than or equal to 50 wt. %, or greater than or equal to 60 wt. %, or greater than or equal to 70 wt. %, or greater than or equal to 80 wt. %, or greater than or equal to 90 wt. % based on the total weight of the thermal management fluid. The phrase “minor amount” or “minor component” as it relates to components included within the renewable diesel of the specification and the claims means less than 50 wt. %, or less than or equal to 40 wt. %, or less than or equal to 30 wt. %, or greater than or equal to 20 wt. %, or less than or equal to 10 wt. %, or less than or equal to 5 wt. %, or less than or equal to 2 wt. %, or less than or equal to 1 wt. %, based on the total weight of the thermal management fluid. The phrase “substantially free” or “essentially free” as it relates to components included within the renewable diesel of the specification and the claims means that the particular component is at 0 weight % within the renewable diesel, or alternatively is at impurity type levels within the renewable diesel (less than 100 ppm, or less than 20 ppm, or less than 10 ppm, or less than 1 ppm). 
     All numerical values within the detailed description herein are modified by “about” the indicated value, and take into account experimental error and variations that would be expected by a person having ordinary skill in the art 
     For the sake of brevity, only certain ranges are explicitly disclosed herein. However, ranges from any lower limit may be combined with any upper limit to recite a range not explicitly recited, as well as, ranges from any lower limit may be combined with any other lower limit to recite a range not explicitly recited, in the same way, ranges from any upper limit may be combined with any other upper limit to recite a range not explicitly recited.