U.S. patent application number 12/193132 was filed with the patent office on 2009-03-26 for integrated process of algae cultivation and production of diesel fuel from biorenewable feedstocks.
Invention is credited to Ezio N. D'Addario, Graham D. Ellis, Christopher D. Gosling, Terry L. Marker, Giacomo F. Rispoli.
Application Number | 20090077864 12/193132 |
Document ID | / |
Family ID | 40468357 |
Filed Date | 2009-03-26 |
United States Patent
Application |
20090077864 |
Kind Code |
A1 |
Marker; Terry L. ; et
al. |
March 26, 2009 |
Integrated Process of Algae Cultivation and Production of Diesel
Fuel from Biorenewable Feedstocks
Abstract
An integrated process has been developed for producing diesel
boiling range fuel from renewable feedstocks such as plant and
animal fats and oils and for cultivating algae or greenhouse
plants. The process involves catalytically treating a renewable
feedstock by hydrogenating and deoxygenating to provide a
hydrocarbon fraction useful as a diesel boiling range fuel. A
selective separation may be used to remove at least the carbon
dioxide from the first zone effluent.
Inventors: |
Marker; Terry L.; (Palos
Heights, IL) ; Ellis; Graham D.; (Guildford, GB)
; Gosling; Christopher D.; (Roselle, IL) ;
Rispoli; Giacomo F.; (Rome, IT) ; D'Addario; Ezio
N.; (Monterotondo, IT) |
Correspondence
Address: |
HONEYWELL INTERNATIONAL INC;PATENT SERVICES
101 COLUMBIA DRIVE, P O BOX 2245 MAIL STOP AB/2B
MORRISTOWN
NJ
07962
US
|
Family ID: |
40468357 |
Appl. No.: |
12/193132 |
Filed: |
August 18, 2008 |
Related U.S. Patent Documents
|
|
|
|
|
|
Application
Number |
Filing Date |
Patent Number |
|
|
60973806 |
Sep 20, 2007 |
|
|
|
Current U.S.
Class: |
44/307 |
Current CPC
Class: |
Y02E 50/13 20130101;
Y02P 20/125 20151101; Y02P 20/10 20151101; C01B 2203/0485 20130101;
Y02P 30/20 20151101; C10L 1/08 20130101; C01B 2203/0475 20130101;
C01B 2203/0415 20130101; Y02E 50/10 20130101 |
Class at
Publication: |
44/307 |
International
Class: |
C10L 1/04 20060101
C10L001/04 |
Claims
1. An integrated process for producing a paraffin-rich diesel
boiling range product from a renewable feedstock and for
cultivating algae, said integrated process comprising: a) treating
the renewable feedstock in a reaction zone by hydrogenating and
deoxygenating the feedstock using at least one catalyst at reaction
conditions in the presence of hydrogen to provide a reaction zone
product stream comprising hydrogen, carbon dioxide, water and a
paraffins having from about 8 to about 24 carbon atoms; b) cooling
the reaction zone product stream and separating to provide: i) a
gaseous component comprising at least hydrogen and carbon dioxide;
ii) a hydrocarbon product comprising the paraffins; and iii) a
water component; c) recovering the hydrocarbon product; d)
separating the gaseous component comprising at least hydrogen and
carbon dioxide into a stream comprising hydrogen and a stream
comprising carbon dioxide; and e) passing the stream comprising
carbon dioxide to an algae cultivation operation and using the
carbon dioxide stream to cultivate algae.
2. The process of claim 1 wherein the separating step 1(d) is at
essentially the same pressure as the reaction pressure and at a
temperature that is at least about 1.degree. C. above the
separation temperature of step (b), and comprises passing the
gaseous component though at least one amine absorber zone to
produce the hydrogen stream and the carbon dioxide stream.
3. The process of claim 2 wherein the amine absorber zone comprises
an aqueous solution of methyldiethaolamine and piperazine.
4. The process of claim 1 wherein the algae cultivation operation
is selected from the group consisting of an open pond, a covered
pond, a raceway pond, a bioreactor, a photobioreactor, and
combinations thereof.
5. The process of claim 2 wherein the amine is an aqueous solution
of a polyoxypropylene triamine having the formula: ##STR00002##
where R' represents a methylene group and R'' represents hydrogen
or methyl or ethyl and wherein the sum of X+Y=Z is a positive
integer having a value of from about 4 to about 6.
6. The process of claim 2 wherein the gaseous component further
comprises hydrogen sulfide and the amine absorber zone contains an
amine that removes both carbon dioxide and hydrogen sulfide, said
process further comprising regenerating the amine that removes both
carbon dioxide and hydrogen sulfide to generate an acid gas stream
containing carbon dioxide and hydrogen sulfide; passing the acid
gas stream through a second amine absorber zone containing an amine
selective to hydrogen sulfide to generate a carbon dioxide stream;
regenerating the amine selective to hydrogen sulfide to generate a
hydrogen sulfide stream; and recycling at least a portion of the
hydrogen sulfide stream to reaction zone.
7. The process of claim 6 wherein the amine absorber zone and the
second amine absorber zone comprises aqueous solutions of
methyldiethanolamine and piperazine.
8. The process of claim 2 wherein the amine absorber is a flexible
amine absorber.
9. The process of claim 1 wherein a portion of the hydrocarbon
product is recycled to the reaction zone is at a volume ratio of
recycle to feedstock in the range of about 2:1 to about 8:1.
10. The process of claim 1 wherein the reaction conditions in the
reaction zone include a temperature of about 40.degree. C. to about
400.degree. C. and a pressure of about 689 kPa absolute (100 psia)
to about 13,790 kPa absolute (2000 psia) and the separating of step
1 b) is at a pressure that is no more than 1034 kPa absolute (150
psia) less than the pressure of the reaction zone.
11. The process of claim 1 wherein at least a portion of the
hydrogen of step (a) is generated by algae.
12. The process of claim 1 further comprising treating a petroleum
derived hydrocarbon in the reaction zone with the renewable
feedstock.
13. An integrated process for producing a paraffin-rich diesel
boiling point range product from a renewable feedstock and for
cultivating algae, said integrated process comprising: a) treating
the renewable feedstock in a reaction zone by hydrogenating and
deoxygenating the feedstock using at least one catalyst at reaction
conditions in the presence of hydrogen to provide a reaction zone
product stream comprising hydrogen, carbon dioxide, water, and
paraffins having from about 8 to about 24 carbon atoms; b)
selectively separating the reaction zone product stream into a
gaseous stream comprising hydrogen and at least a portion of the
water and carbon dioxide from the reaction zone product stream and
a remainder stream comprising at least the paraffins; c) recycling
a first portion of the remainder stream comprising at least the
paraffins to the reaction zone; d) combining the gaseous stream and
a second portion of the remainder stream to form a combined stream
and separating the combined stream to provide: a. a gaseous
component comprising at least hydrogen, water, and carbon dioxide;
b. a hydrocarbon product; and c. a water component; and recovering
a portion of the hydrocarbon product and recycling a portion of the
hydrocarbon product to the reaction zone; e) selectively separating
the gaseous component using at least one amine absorber zone to
produce at least a stream comprising carbon dioxide and a stream
comprising at least hydrogen and depleted in carbon dioxide; and f)
passing the stream comprising carbon dioxide to an algae
cultivation operation and using the carbon dioxide to cultivate
algae.
14. The process of claim 13 wherein the amine absorber zone
contains an amine selective to carbon dioxide, and the stream
containing at least hydrogen and depleted in carbon dioxide further
comprises hydrogen sulfide.
15. The process of claim 14 wherein the amine is an aqueous
solution of a polyoxypropylene triamine having the formula:
##STR00003## Where R' represents a methylene group and R''
represents hydrogen or methyl or ethyl and wherein the sum of X+Y=Z
is a positive integer having a value of from about 4 to about
6.
16. The process of claim 13 wherein gaseous component further
comprises hydrogen sulfide and the amine absorber zone comprises an
amine selective to carbon dioxide and hydrogen sulfide, said
process further comprising regenerating the amine selective to
carbon dioxide and hydrogen sulfide to generate an acid gas stream
containing carbon dioxide and hydrogen sulfide; passing the acid
gas stream through a second amine absorber zone containing an amine
selective to hydrogen sulfide to generate the stream comprising
carbon dioxide; regenerating the amine selective to hydrogen
sulfide to generate a stream comprising hydrogen sulfide stream;
and recycling at least a portion of the stream comprising hydrogen
sulfide stream to reaction zone.
17. The process of claim 16 wherein the amine absorber zone and the
second amine absorber zone comprise aqueous solutions of
methyldiethanolamine and piperazine.
18. The process of claim 13 wherein the selectively separating in
step 13(b) is performed using a hot high pressure hydrogen stripper
operated at a temperature of about 40.degree. C. to about
300.degree. C. and a pressure of about 689 kPa absolute (100 psia)
to about 13,790 kPa absolute (2000 psia).
19. The process of claim 13 wherein the separating in step 13(d) is
performed using cooling followed by phase separation.
20. The process of claim 13 wherein the amine absorber is a
flexible amine absorber.
21. The process of claim 13 wherein the first portion of the
remainder stream is recycled to the reaction zone at a volume ratio
of recycle to feedstock in the range of about 2:1 to about 8:1, and
wherein the reaction conditions in the reaction zone include a
temperature of about 40.degree. C. to about 400.degree. C. and a
pressure of about 689 kPa absolute (100 psia) to about 13,790 kPa
absolute (2000 psia).
22. The process of claim 13 further comprising introducing a third
portion of the remainder stream to a second reaction zone to
contact an isomerization catalyst at isomerization conditions to
isomerize at least a portion of the n-paraffins into branched
paraffins and generate the said second portion of the remainder
stream.
23. The process of claim 22 further comprising treating a petroleum
derived hydrocarbon in the reaction zone with the renewable
feedstock.
24. A process for producing a branched paraffin-rich diesel product
from a renewable feedstock comprising; a. treating the feedstock in
a first reaction zone by hydrogenating and deoxygenating the
feedstock using a catalyst at reaction conditions in the presence
of hydrogen and at least one sulfur containing compound to provide
a first reaction zone product stream comprising hydrogen, hydrogen
sulfide, carbon dioxide, and a hydrocarbon fraction comprising
n-paraffins useful as a diesel boiling range fuel; b. selectively
separating, in a hot high pressure hydrogen stripper, a gaseous
stream comprising hydrogen, hydrogen sulfide, and at least a
portion of the water and carbon dioxide from the first reaction
zone product stream and introducing a remainder stream comprising
at least the n-paraffins to a second reaction zone to contact an
isomerization catalyst at isomerization conditions to isomerize at
least a portion of the n-paraffins and generate a branched
paraffin-rich stream; c. combining the branched-paraffin-rich
stream and the gaseous stream to form a combined stream and
separating: i. a gaseous component comprising at least hydrogen and
carbon dioxide; ii. a hydrocarbon component; and iii. a water
component and recovering at least a portion of the hydrocarbon
component; d. selectively separating the gaseous component using in
a first amine solution absorber zone to produce a stream comprising
at least hydrogen and depleted in carbon dioxide and a stream
comprising carbon dioxide and hydrogen sulfide; e. selectively
separating the stream comprising carbon dioxide and hydrogen
sulfide in a second amine solution absorber zone to produce a
stream comprising at least hydrogen sulfide and depleted in carbon
dioxide and a stream comprising carbon dioxide; f. recycling at
least a portion of the stream comprising at least hydrogen and
depleted in carbon dioxide and at least a portion of the stream
comprising at least hydrogen sulfide and depleted in carbon dioxide
to the first reaction zone.
25. The process of claim 24 wherein the isomerization conditions in
the second reaction zone include a temperature of about 40.degree.
C. to about 400.degree. C. and a pressure of about 689 kPa absolute
(100 psia) to about 13,790 kPa absolute (2000 psia) and wherein the
hot high pressure hydrogen stripper is operated at a temperature of
about 40.degree. C. to about 300.degree. C. and a pressure of about
689 kPa absolute (100 psia) to about 13,790 kPa absolute (2000
psia).
26. The process of claim 24 further comprising treating a petroleum
derived hydrocarbon in the reaction zone with the renewable
feedstock.
27. An integrated process for producing a paraffin-rich diesel
product from a renewable feedstock and for cultivating algae, said
integrated process comprising: a) generating hydrogen using an
algae cultivation operation; b) treating the feedstock in a
reaction zone by hydrogenating and deoxygenating the feedstock
using at least one catalyst at reaction conditions in the presence
of the hydrogen generated in step (a) to provide a reaction zone
product stream comprising hydrogen, carbon dioxide, water and a
paraffins having from about 8 to about 24 carbon atoms; c) cooling
the reaction zone product stream and separating to provide: i. a
gaseous component comprising at least hydrogen and carbon dioxide;
ii. a hydrocarbon product comprising the paraffins; and iii. a
water component; and d) recovering the hydrocarbon product.
28. The process of claim 27 further comprising separating the
gaseous component comprising at least hydrogen and carbon dioxide
into a stream comprising hydrogen and a stream comprising carbon
dioxide and passing the stream comprising carbon dioxide to an
algae cultivation operation and using the carbon dioxide stream to
cultivate algae.
29. The process of claim 27 further comprising treating a petroleum
derived hydrocarbon in the reaction zone with the renewable
feedstock.
30. An integrated process for producing a paraffin-rich diesel
boiling range product from a renewable feedstock and for
cultivating plants in an enclosed greenhouse, said integrated
process comprising: f) treating the renewable feedstock in a
reaction zone by hydrogenating and deoxygenating the feedstock
using at least one catalyst at reaction conditions in the presence
of hydrogen to provide a reaction zone product stream comprising
hydrogen, carbon dioxide, water and a paraffins having from about 8
to about 24 carbon atoms; g) cooling the reaction zone product
stream and separating to provide: i) a gaseous component comprising
at least hydrogen and carbon dioxide; ii) a hydrocarbon product
comprising the paraffins; and iii) a water component; h) recovering
the hydrocarbon product; i) separating the gaseous component
comprising at least hydrogen and carbon dioxide into a stream
comprising hydrogen and a stream comprising carbon dioxide; and j)
passing the stream comprising carbon dioxide to an enclosed green
house and using the carbon dioxide stream to cultivate plants
growing the enclosed greenhouse.
31. An integrated process for producing a paraffin-rich diesel
boiling range product from a renewable feedstock and for separating
at least two components by supercritical extraction, said
integrated process comprising: a. treating the renewable feedstock
in a reaction zone by hydrogenating and deoxygenating the feedstock
using at least one catalyst at reaction conditions in the presence
of hydrogen to provide a reaction zone product stream comprising
hydrogen, carbon dioxide, water and a paraffins having from about 8
to about 24 carbon atoms; b. cooling the reaction zone product
stream and separating to provide: i. a gaseous component comprising
at least hydrogen and carbon dioxide; ii. a hydrocarbon product
comprising the paraffins; and iii. a water component; c. recovering
the hydrocarbon product; d. separating the gaseous component
comprising at least hydrogen and carbon dioxide into a stream
comprising hydrogen and a stream comprising carbon dioxide; and e.
passing the stream comprising carbon dioxide to a supercritical
extraction operation and using the carbon dioxide stream as the
extractant in the supercritical extraction operation to separate at
least a first component from a second component in a mixture.
Description
CROSS-REFERENCE TO RELATED APPLICATION
[0001] This application claims priority from Provisional
Application Ser. No. 60/973,806 filed Sep. 20, 2007, the contents
of which are hereby incorporated by reference in its entirety.
FIELD OF THE INVENTION
[0002] This invention relates to an integrated process for
cultivating algae and for producing diesel boiling range fuel from
renewable feedstocks such as the glycerides and free fatty acids
found in materials such as plant and animal fats and oils.
Hydrogenation and deoxygenation are performed in one or more
reactors. A vapor stream is separated from the reaction zone
effluent, and carbon dioxide is separated from the vapor stream.
The separated carbon dioxide is passed to an algae cultivation
operation. The hydrocarbons may be optionally isomerized.
Additionally, some algae produce hydrogen which may be employed in
the reaction zone in the diesel boiling range fuel process.
BACKGROUND OF THE INVENTION
[0003] As the demand for diesel boiling range fuel increases
worldwide there is increasing interest in sources other than crude
oil for producing diesel boiling range fuel. One such renewable
source is what has been termed renewable sources. These renewable
sources include, but are not limited to, plant oils such as corn,
rapeseed, canola, soybean and algal oils, animal fats such as
inedible tallow, fish oils and various waste streams such as yellow
and brown greases and sewage sludge. The common feature of these
sources is that they are composed of glycerides and Free Fatty
Acids (FFA). Both of these classes of compounds contain aliphatic
carbon chains having from about 8 to about 24 carbon atoms. The
aliphatic chains in the glycerides or FFAs can be fully saturated,
or mono, di or poly-unsaturated.
[0004] There are reports in the art disclosing the production of
hydrocarbons from oils. For example, U.S. Pat. No. 4,300,009
discloses the use of crystalline aluminosilicate zeolites to
convert plant oils such as corn oil to hydrocarbons such as
gasoline and chemicals such as para-xylene. U.S. Pat. No. 4,992,605
discloses the production of hydrocarbon products in the diesel
boiling range by hydroprocessing vegetable oils such as canola or
sunflower oil. Finally, US 2004/0230085 A1 discloses a process for
treating a hydrocarbon component of biological origin by
hydrodeoxygenation followed by isomerization. It is also known that
a key component in the cultivation of algae is carbon dioxide.
[0005] Applicants have developed an integrated process that
generates and separates a carbon dioxide stream suitable for use in
an algae cultivation operation. The carbon dioxide is generated
through a diesel boiling range fuel production process and is
separated from other vaporous components. The diesel boiling range
fuel production process comprises one or more steps to hydrogenate
and deoxygenate (via catalytic decarboxylation, decarbonylation
and/or hydrodeoxygenation) the renewable feedstock. Sulfur
containing components may be naturally present in the feedstock or
may be added to the feedstock or the reaction mixture for various
different purposes. Carbon dioxide and water are generated in the
reaction zone and need to be at least partially removed from the
reactor effluent prior to recycling any excess hydrogen back to the
reaction zone. The effluent from the reaction zone is separated
into at least a vapor portion and a liquid portion though, for
example, cooling and separating. At least some of the liquid
portion may be recycled to the reaction zone. The vapor portion is
treated using an amine absorber solution to remove at least the
carbon dioxide and optionally the sulfur component such as hydrogen
sulfide so that the remaining hydrogen can be recycled back to the
first reaction zone. The separated carbon dioxide is passed to an
algae cultivation operation. The separated hydrogen sulfide may be
used for other purposes. Optionally, selective separation unit such
as a hot high pressure hydrogen stripper may be employed to
selectively separate the majority of the hydrocarbon liquid portion
from the vapor portion of the effluent and some of this hydrocarbon
liquid portion may be recycled to the reactor. The vapor portion is
then cooled to separate any water. Optionally, the hydrocarbons
produced by the deoxygenation reactions may be isomerized to
produce branched-paraffins.
SUMMARY OF THE INVENTION
[0006] A hydroconversion process for producing at least a diesel
boiling range fuel from a renewable feedstock wherein the process
comprises treating the renewable feedstock in a catalytic reaction
zone by hydrogenating and deoxygenating the feedstock at reaction
conditions to provide a reaction product comprising paraffins and a
gaseous fraction comprising at least carbon dioxide and hydrogen.
The paraffins are optionally isomerized to produce branched
paraffins. At least one sulfur containing component may be is
present in the reaction mixture.
[0007] The carbon dioxide generated in the catalytic reaction zone
and any excess hydrogen are selectively removed from the desired
reaction product as a vapor stream using, for example, (1) a
cooling and separating process or (2) an integrated hot high
pressure stripper using a high purity hydrogen stream as the
stripping gas followed by the cooling and separating process. The
carbon dioxide is then separated from the hydrogen using, for
example, at least one selective amine absorber solution. The
separated carbon dioxide is passed to an algae cultivation
operation. The hydrogen sulfide may be removed from the vapor
stream using the amine absorber solution, or the amine absorber
solution may be specially chosen to allow the hydrogen sulfide to
recycle with the hydrogen to the reactor.
[0008] In another embodiment, hydrogen produced by algae is
introduced to the catalytic reaction zone of the diesel boiling
range fuel production process.
BRIEF DESCRIPTION OF THE DRAWINGS
[0009] FIG. 1 is a general flow scheme diagram of the
invention.
[0010] FIG. 2 is a more detailed flow scheme diagram of one
embodiment of the invention.
[0011] FIG. 3 is a detailed flow scheme diagram of the embodiment
of the invention employing the optional hot high pressure hydrogen
stripper.
[0012] FIG. 4 is a detailed flow scheme diagram of the embodiment
of the invention employing the optional hot high pressure hydrogen
stripper and the optional isomerization reaction zone.
[0013] FIG. 5 is a portion of a flow scheme showing the operation
of the flexible absorber embodiment.
DETAILED DESCRIPTION OF THE INVENTION
[0014] As stated, the present invention relates to an integrated
process for producing a hydrocarbon stream useful at least as
diesel boiling range fuel or a diesel boiling range fuel blending
component from renewable feedstocks such as renewable feedstocks
originating from plants or animals as well as producing a carbon
dioxide stream useful in the cultivation of algae. The term
renewable feedstock is meant to include feedstocks other than those
obtained from crude oil. Another term that has been used to
describe this class of feedstock is biorenewable fats and oils. The
renewable feedstocks that can be used in the present invention
include any of those which comprise glycerides and free fatty acids
(FFA). Most of the glycerides will be triglycerides, but
monoglycerides and diglycerides may be present and processed as
well. Examples of these renewable feedstocks include, but are not
limited to, canola oil, corn oil, soy oils, rapeseed oil, soybean
oil, colza oil, tall oil, sunflower oil, hempseed oil, olive oil,
linseed oil, coconut oil, castor oil, peanut oil, palm oil, mustard
oil, jatropha oil, tallow, yellow and brown greases, lard, train
oil, fats in milk, fish oil, algal oil, sewage sludge, and the
like. Additional examples of renewable feedstocks include
non-edible vegetable oils from the group comprising Jatropha curcas
(Ratanjoy, Wild Castor, Jangli Erandi), Madhuca indica (Mohuwa),
Pongamia pinnata (Karanji Honge), and Azadiracta indicia (Neem).
The triglycerides and FFAs of the typical vegetable or animal fat
contain aliphatic hydrocarbon chains in their structure which have
about 8 to about 24 carbon atoms with a majority of the fats and
oils containing high concentrations of fatty acids with 16 and 18
carbon atoms. Mixtures or co-feeds of renewable feedstocks and
petroleum-derived hydrocarbons may also be used as the feedstock.
Other feedstock components which may be used, especially as a
co-feed component in combination with the above listed feedstocks,
include spent motor oils and industrial lubricants, used paraffin
waxes, liquids derived from the gasification of coal, biomass, or
natural gas followed by a downstream liquefaction step such as
Fischer-Tropsch technology, liquids derived from depolymerization,
thermal or chemical, of waste plastics such as polypropylene, high
density polyethylene, and low density polyethylene; and other
synthetic oils generated as byproducts from petrochemical and
chemical processes. Mixtures of the above feedstocks may also be
used as co-feed components. One advantage of using a co-feed
component is the transformation of what has been considered to be a
waste product from a petroleum based or other process into a
valuable co-feed component to the current process.
[0015] Renewable feedstocks that can be used in the present
invention may contain a variety of impurities. For example, tall
oil is a byproduct of the wood processing industry and tall oil
contains esters and rosin acids in addition to FFAs. Rosin acids
are cyclic carboxylic acids. The renewable feedstocks may also
contain contaminants such as alkali metals, e.g. sodium and
potassium, phosphorous as well as solids, water and detergents. An
optional first step is to remove some or all of these contaminants.
One possible pretreatment step involves contacting the renewable
feedstock with an ion-exchange resin in a pretreatment zone at
pretreatment conditions. The ion-exchange resin is an acidic ion
exchange resin such as Amberlyst.TM.-15 and can be used as a bed in
a reactor through which the feedstock is flowed through, either
upflow or downflow. The conditions at which the reactor is operated
are well known in the art.
[0016] Another possible means for removing contaminants is a mild
acid wash. This is carried out by contacting the feedstock with an
acid such as sulfuric, nitric or hydrochloric acid in a reactor.
The acid and feedstock can be contacted either in a batch or
continuous process. Contacting is done with a dilute acid solution
usually at ambient temperature and atmospheric pressure. If the
contacting is done in a continuous manner, it is usually done in a
counter current manner. Yet another possible means of removing
metal contaminants from the feedstock is through the use of guard
beds some of which are well known in the art. These can include
alumina guard beds either with or without demetallation catalysts
such as nickel or cobalt. Filtration and solvent extraction
techniques are other choices which may be employed. Hydroprocessing
such as that described in U.S. application Ser. No. 11/770,826,
hereby incorporated by reference, is another pretreatment technique
which may be employed.
[0017] The renewable feedstock is flowed to a first reaction zone
comprising one or more catalyst beds in one or more reactors. The
term "feedstock" is meant to include feedstocks that have not been
treated to remove contaminants as well as those feedstocks purified
in a pretreatment zone. In the reaction first zone, the feedstock
is contacted with a hydrogenation or hydrotreating catalyst in the
presence of hydrogen at hydrogenation conditions to hydrogenate
reactive component such as the olefinic or unsaturated portions of
the aliphatic side chains of a glyceride molecule. Hydrogenation or
hydrotreating catalysts are any of those well known in the art such
as sulfided nickel or nickel/molybdenum dispersed on a high surface
area support. Other hydrogenation catalysts include one or more
noble metal catalytic elements dispersed on a high surface area
support. Non-limiting examples of noble metals include Pt and/or Pd
dispersed on gamma-alumina. Hydrogenation conditions include a
temperature of about 40.degree. C. to about 400.degree. C. and a
pressure of about 689 kPa absolute (100 psia) to about 13,790 kPa
absolute (2000 psia). In another embodiment the hydrogenation
conditions include a temperature of about 200.degree. C. to about
350.degree. C. and a pressure of about 1379 kPa absolute (200 psia)
to about 4826 kPa absolute (700 psia). Other operating conditions
for the hydrogenation zone are well known in the art.
[0018] The hydrogenation and hydrotreating catalysts enumerated
above are also capable of catalyzing decarbonylation,
decarboxylation and/or hydrodeoxygenation of the feedstock to
remove oxygen. Decarbonylation, decarboxylation, and
hydrodeoxygenation are herein collectively referred to as
deoxygenation reactions. Decarbonylation, decarboxylation, and
hydrodeoxygenation conditions include a relatively low pressure of
about 1379 kPa (200 psia) to about 6895 kPa (1000 psia), a
temperature of about 200.degree. C. to about 400.degree. C. and a
liquid hourly space velocity of about 0.5 to about 10 hr.sup.-1. In
another embodiment the decarbonylation, decarboxylation, and
hydrodeoxygenation conditions include the same relatively low
pressure of about 3447 kPa (500 psia) to about 6895 kPa (1000
psia), a temperature of about 288.degree. C. to about 345.degree.
C. and a liquid hourly space velocity of about 1 to about 4
hr.sup.-1. Since hydrogenation is an exothermic reaction, as the
feedstock flows through the catalyst bed the temperature increases
and decarboxylation, decarbonylation and hydrodeoxygenation will
begin to occur. Thus, it is envisioned and is within the scope of
this invention that all reactions occur simultaneously in one
reactor or in one bed. Alternatively, the conditions can be
controlled such that hydrogenation primarily occurs in one bed and
decarboxylation, decarbonylation and/or hydrodeoxygenation occurs
in a second bed. Of course if only one bed is used, then
hydrogenation may occur primarily at the front of the bed, while
decarboxylation, decarbonylation and hydrodeoxygenation occurs
mainly in the middle and bottom of the bed. Finally, desired
hydrogenation can be carried out in one reactor, while
decarboxylation and/or hydrodeoxygenation can be carried out in a
separate reactor.
[0019] Sulfur containing components are often present in the
reaction mixture. Such components may be present in the feedstock
naturally, or may be added to the feedstock or the reaction zone.
Sulfur-containing components may be organic, inorganic, natural, or
synthetic. A single sulfur-containing component may be present or
more than one may be present. The sulfur containing component may
be present in an amount ranging from about 1 ppm to about 5 mass %.
Many sulfur containing components are converted to hydrogen sulfide
in the reaction zone. For ease of understanding, the description
below will use the term hydrogen sulfide as the primary example of
a sulfur containing component, but that is not meant to limit the
scope of the claims in any way.
[0020] The reaction product from the deoxygenation reactions
comprises both a liquid portion and a gaseous portion. The liquid
portion comprises a hydrocarbon fraction which is primarily
paraffins and having a large concentration of paraffins in the
range of about 9 to about 18 carbon atoms. Different feedstocks
will result in different distributions of paraffins. The gaseous
portion comprises hydrogen, carbon dioxide, carbon monoxide, water
vapor, propane and perhaps sulfur components such as hydrogen
sulfide. For the case where there is no isomerization catalyst in
the reaction zone, most of the hydrocarbons will be normal
paraffins. The hydrogenation/deoxygenation catalyst may catalyze a
slight amount of isomerization but it is expected that no more than
about 5 or about 10 mass % of the normal paraffins would be
isomerized to branched paraffins. The diesel boiling range fuel old
flow properties depend on the relative amounts of normal and
branched paraffin in the product. In warmer climate regions, poor
cold flow properties are not a great concern. In colder climate
regions, improvements to cold flow properties are needed and at
least some of the normal paraffins are isomerized to branched
paraffins. By optimizing the isomerization requirement where
appropriate due to the climate, a substantial cost savings in both
capital costs and operating costs can be achieved.
[0021] The effluent from the reaction zone is conducted to a
selective separation zone comprising, for example, a heat exchanger
and a product separator and optionally an air or water cooler.
After cooling, a vapor stream containing the hydrogen, hydrogen
sulfide, carbon monoxide, and carbon dioxide is readily separated
from the liquid phase containing the normal paraffins having from
about 8 to about 24 carbon atoms in the product separator. Suitable
operating conditions of the separator include, for example, a
temperature of about 20 to 80.degree. C. or 45 to 50.degree. C. and
a pressure of about 2758 kPa absolute (400 psia) to about 68985 kPa
absolute (1000 psia) with a specific embodiment at 3850 kPa
absolute (560 psia). This selective separation zone is operated at
essentially the same pressure as the reaction zone. By
"essentially" it is meant that the operating pressure of the
selective separation zone is within about 1034 kPa absolute (150
psia) of the operating pressure of the reaction zone. For example,
the selective separation zone is no more than 1034 kPa absolute
(150 psia) less than that of the reaction zone. The vapor stream
and the liquid stream are both removed from the product separator.
A portion of the liquid stream may be recycled to the reaction
zone, at the feed location or at one or more intermediate
locations. A water byproduct stream is also removed. The liquid
stream may be recovered or may be routed to a product recovery
column to separate the light ends from the diesel and naphtha
products.
[0022] Optionally, the effluent from the deoxygenation reaction
zone is conducted to a hot high pressure hydrogen stripper before
at least a portion of the effluent is cooled and conducted to the
cold product separator. One benefit of this embodiment is that a
liquid stream of paraffins is generated at or near to the
temperature and pressure of the reaction zone, and a portion of
that stream may be recycled to the reaction zone with minimal
pumping energy and minimal additional heating. Saving the utilities
of pumping and reheating can significantly reduce the cost of the
overall process and if the recycle stream is large enough would
more than offset the additional capital cost of the hot high
pressure hydrogen stripper. Likewise the net liquid going to the
product recovery column needs less heating to separate light
byproducts. Another benefit is the liquid stream is essentially dry
and therefore does not pass carry water back to the reactor. In
addition, the separation in the cold product separator becomes more
efficient since the phase separation does not include the heavy
hydrocarbons having from about 8 to about 24 or more carbon atoms.
Furthermore, any unreacted tri-, di- and or mono-glycerides or free
fatty acids present in the reactor effluent during a unit start-up
or unit upset are selectively removed in the hot separator liquid
and do not come into contact with a condensed water phase where
they could contaminate the byproduct water.
[0023] The reaction zone effluent enters the hot high pressure
stripper and the water and normally gaseous components, are carried
with the hydrogen stripping gas and separated into an overhead
stream. By using a dry hydrogen stream as the stripping gas, water,
carbon monoxide, carbon dioxide, and any ammonia or hydrogen
sulfide are selectively separated from the hydrocarbon liquid
product in the hot high pressure hydrogen stripper. The hydrogen
stripping gas can be hydrogen make-up gas that is effectively free
of carbon oxides and water. By effectively free, it is meant that
the hydrogen make-up gas is free of carbon oxides and water, or if
carbon oxides or water are present they are in such a small amount
so as not to effect the stripping. The remainder of the
deoxygenation effluent stream is removed as hot high pressure
hydrogen stripper bottoms and contains the liquid hydrocarbon
fraction having components such as normal hydrocarbons having from
about 8 to about 24 carbon atoms. A portion of this liquid
hydrocarbon fraction in hot high pressure hydrogen stripper bottoms
may be used as the hydrocarbon recycle described below, and the
stripper bottoms are already at or near the operating conditions of
the reaction zone thereby saving the costs involved with pumping or
heating of the recycle portion. The stripper bottoms are conducted
to a product recovery column.
[0024] The temperature of the hot high pressure hydrogen stripper
may be controlled in a limited range to achieve the desired
separation and the pressure may be maintain at approximately the
same pressure as the reaction zone to minimize both investment and
operating costs. The hot high pressure hydrogen stripper may be
operated at conditions ranging from a pressure of about 689 kPa
absolute (100 psia) to about 13,790 kPa absolute (2000 psia), and a
temperature of about 40.degree. C. to about 350.degree. C. In
another embodiment the hot high pressure hydrogen stripper may be
operated at conditions ranging from a pressure of about 1379 kPa
absolute (200 psia) to about 4826 kPa absolute (700 psia), or about
2413 kPa absolute (350 psia) to about 4882 kPa absolute (650 psia),
and a temperature of about 50.degree. C. to about 350.degree. C.
The hot high pressure hydrogen stripper may be operated at
essentially the same pressure as the reaction zone. By
"essentially" it is meant that the operating pressure of the high
pressure hydrogen stripper is within about 1034 kPa absolute (150
psia) of the operating pressure of the reaction zone. For example,
the pressure of the hot high pressure hydrogen stripper separation
zone is no more than 1034 kPa absolute (150 psia) less than that of
the reaction zone.
[0025] One purpose of the hot high pressure hydrogen stripper is to
separate the gaseous portion of the effluent from the liquid
portion of the effluent. As hydrogen is an expensive resource, to
conserve costs, the separated hydrogen is ultimately recycled to
the deoxygenation reactor. Hydrogen is a reactant in at least one
of the deoxygenation reactions, and to be effective, a sufficient
quantity of hydrogen must be in solution to most effectively take
part in the catalytic reaction. Past processes have operated at
high pressures in order to achieve a desired amount of hydrogen in
solution that is readily available for reaction. However, higher
pressure operations are more costly to build and to operate as
compared to their lower pressure counterparts. One advantage of the
present invention is the ability to operate in a pressure range of
about 1379 kPa absolute (200 psia) to about 4826 kPa absolute (700
psia) which is lower than that found in other previous operations.
In another embodiment the operating pressure is in the range of
about 2413 kPa absolute (350 psia) to about 4481 kPa absolute (650
psia), and in yet another embodiment operating pressure is in the
range of about 2758 kPa absolute (400 psia) to about 4137 kPa
absolute (600 psia). Furthermore, the rate of reaction is increased
resulting in a greater amount of throughput of material through the
reactor in a given period of time.
[0026] In one embodiment, the desired amount of hydrogen is kept in
solution at lower pressures by employing a large recycle of
hydrocarbon. Other processes have employed hydrocarbon recycle in
order to control the temperature in the reaction zones since the
reactions are exothermic reactions. However, the range of recycle
to feedstock ratios used herein is determined not on temperature
control requirements, but instead, based upon feedstock composition
and hydrogen solubility requirements. Hydrogen has a greater
solubility in the hydrocarbon product than it does in the
feedstock. By utilizing a large hydrocarbon recycle the solubility
of hydrogen in the liquid phase in the reaction zone is greatly
increased and higher pressures are not needed to increase the
amount of hydrogen in solution. In one embodiment of the invention,
the volume ratio of hydrocarbon recycle to feedstock is from about
2:1 to about 8:1, or about 2:1 to about 6:1. In another embodiment
the ratio is in the range of about 3:1 to about 6:1 and in yet
another embodiment the ratio is in the range of about 4:1 to about
5:1.
[0027] The gaseous portion of the reaction zone effluent in the
overhead from the hot high pressure hydrogen stripper is cooled, by
techniques such as heat exchange, air cooling, or water cooling and
passed to a cold separator where liquid components are separated
from the gaseous components by phase separation. Suitable operating
conditions of the cold separator include, for example, a
temperature of about 20 to 80.degree. C. or 45 to 50.degree. C. and
a pressure of relatively low pressure of about 3447 kPa (500 psia)
to about 6895 kPa (1000 psia), with one embodiment at 3850 kPa
absolute (560 psia). A water byproduct stream is also separated.
The gaseous component stream from the cold separator comprises
hydrogen, carbon monoxide, carbon dioxide, and hydrogen sulfide
while the liquid component stream from the cold separator comprises
naphtha and LPG. Again, this separation may be operated at
essentially the same pressure as the reaction zone. By
"essentially" it is meant that the operating pressure of the cold
separator is within about 1034 kPa absolute (150 psia) of the
operating pressure of the reaction zone. For example, the pressure
of the separator is no more than 1034 kPa absolute (150 psia) less
than that of the reaction zone.
[0028] Either the hot high pressure hydrogen stripper bottoms or
the liquid component from the cold product separator in the
embodiment with no hot high pressure hydrogen stripper may be
recovered as diesel boiling point range product. However, the
liquid component from the product separator and the hot high
pressure hydrogen stripper bottoms, if present, collectively
contain the hydrocarbons useful as diesel boiling range fuel or
diesel boiling range fuel blending component as well as smaller
amounts of naphtha and LPG and may be further purified in a product
recovery column. The product recovery column fractionates lower
boiling components and dissolved gases from the diesel product
containing C.sub.8 to C.sub.24 paraffins. Suitable operating
conditions of the product recovery column include a temperate of
from about 20 to about 200.degree. C. at the overhead and a
pressure from about 0 to about 1379 kPa absolute (0 to 200
psia).
[0029] Although this hydrocarbon fraction is useful as a diesel
boiling range fuel or a diesel boiling range fuel blending
component, because it comprises essentially n-paraffins, it will
have poor cold flow properties. To improve the cold flow properties
of the liquid hydrocarbon fraction, the paraffins produced in the
first reaction zone are optionally contacted with an isomerization
catalyst under isomerization conditions to at least partially
isomerize the n-paraffins to branched paraffins. The effluent of
the second reaction zone, the isomerization zone, is a
branched-paraffin-rich stream. By the term "rich" it is meant that
the effluent stream has a greater concentration of branched
paraffins than the stream entering the isomerization zone, and
preferably comprises greater than 50 mass-% branched paraffins. It
is envisioned that the isomerization zone effluent may contains 70,
80, or 90 mass-% branched paraffins. Isomerization can be carried
out in a separate bed of the same reaction zone, i.e. same reactor,
described above for the deoxygenation reactions or the
isomerization can be carried out in a separate reactor. For ease of
description the following will address the embodiment where a
second reactor is employed for the isomerization reaction. The
hydrogen stripped product of the deoxygenation reaction zone is
contacted with an isomerization catalyst in the presence of
hydrogen at isomerization conditions to isomerize the normal
paraffins to branched paraffins. Only minimal branching is
required, enough to overcome the cold-flow problems of the normal
paraffins. Since attempting for significant branching runs the risk
of high degree of undesired cracking, the predominant isomerized
product is a mono-branched paraffin.
[0030] The isomerization of the paraffinic product can be
accomplished in any manner known in the art or by using any
suitable catalyst known in the art. One or more beds of catalyst
may be used. It is preferred that the isomerization be operated in
a co-current mode of operation. Fixed bed, trickle bed down flow or
fixed bed liquid filled up-flow modes are both suitable. See also,
for example, US 2004/0230085 A1 which is incorporated by reference
in its entirety. Suitable catalysts comprise a metal of Group VIII
(IUPAC 8-10) of the Periodic Table and a support material. Suitable
Group VIII metals include platinum and palladium, each of which may
be used alone or in combination. The support material may be
amorphous or crystalline. Suitable support materials include
amorphous alumina, amorphous silica-alumina, ferrierite, mesoporous
silica alumina, ALPO-31, SAPO-11, SAPO-31, SAPO-37, SAPO-41, SM-3,
MgAPSO-31, FU-9, NU-10, NU-23, ZSM-12, ZSM-22, ZSM-23, ZSM-35,
ZSM-48, ZSM-50, ZSM-57, MeAPO-11, MeAPO-31, MeAPO-41, MeAPSO-11,
MeAPSO-31, MeAPSO-41, MeAPSO-46, ELAPO-11, ELAPO-31, ELAPO-41,
ELAPSO-11, ELAPSO-31, ELAPSO-41, laumontite, cancrinite, offretite,
hydrogen form of stillbite, magnesium or calcium form of mordenite,
and magnesium or calcium form of partheite, each of which may be
used alone or in combination. ALPO-31 is described in U.S. Pat. No.
4,310,440. SAPO-11, SAPO-31, SAPO-37, and SAPO-41 are described in
U.S. Pat. No. 4,440,871. SM-3 is described in U.S. Pat. No.
4,943,424; U.S. Pat. No. 5,087,347; U.S. Pat. No. 5,158,665; and
U.S. Pat. No. 5,208,005. MgAPSO is a MeAPSO, which is an acronym
for a metal aluminumsilicophosphate molecular sieve, where the
metal Me is magnesium (Mg). Suitable MeAPSO-31 catalysts include
MgAPSO-31. MeAPSOs are described in U.S. Pat. No. 4,793,984, and
MgAPSOs are described in U.S. Pat. No. 4,758,419. MgAPSO-31 is a
preferred MgAPSO, where 31 means a MgAPSO having structure type 31.
Many natural zeolites, such as ferrierite, that have an initially
reduced pore size can be converted to forms suitable for olefin
skeletal isomerization by removing associated alkali metal or
alkaline earth metal by ammonium ion exchange and calcination to
produce the substantially hydrogen form, as taught in U.S. Pat. No.
4,795,623 and U.S. Pat. No. 4,924,027. Further catalysts and
conditions for skeletal isomerization are disclosed in U.S. Pat.
No. 5,510,306, U.S. Pat. No. 5,082,956, and U.S. Pat. No.
5,741,759.
[0031] The isomerization catalyst may also comprise a modifier
selected from the group consisting of lanthanum, cerium,
praseodymium, neodymium, samarium, gadolinium, terbium, and
mixtures thereof, as described in U.S. Pat. No. 5,716,897 and U.S.
Pat. No. 5,851,949. Other suitable support materials include
ZSM-22, ZSM-23, and ZSM-35, which are described for use in dewaxing
in U.S. Pat. No. 5,246,566 and in the article entitled "New
molecular sieve process for lube dewaxing by wax isomerization,"
written by S. J. Miller, in Microporous Materials 2 (1994) 439-449.
The teachings of U.S. Pat. No. 4,310,440; U.S. Pat. No. 4,440,871;
U.S. Pat. No. 4,793,984; U.S. Pat. No. 4,758,419; U.S. Pat. No.
4,943,424; U.S. Pat. No. 5,087,347; U.S. Pat. No. 5,158,665; U.S.
Pat. No. 5,208,005; U.S. Pat. No. 5,246,566; U.S. Pat. No.
5,716,897; and U.S. Pat. No. 5,851,949 are hereby incorporated by
reference.
[0032] U.S. Pat. No. 5,444,032 and U.S. Pat. No. 5,608,968 teach a
suitable bifunctional catalyst which is constituted by an amorphous
silica-alumina gel and one or more metals belonging to Group VIIIA,
and is effective in the hydroisomerization of long-chain normal
paraffins containing more than 15 carbon atoms. U.S. Pat. No.
5,981,419 and U.S. Pat. No. 5,908,134 teach a suitable bifunctional
catalyst which comprises: (a) a porous crystalline material
isostructural with beta-zeolite selected from boro-silicate
(BOR--B) and boro-alumino-silicate (Al--BOR--B) in which the molar
SiO.sub.2:Al.sub.2O.sub.3 ratio is higher than 300:1; (b) one or
more metal(s) belonging to Group VIIIA, selected from platinum and
palladium, in an amount comprised within the range of from 0.05 to
5% by weight. Article V. Calemma et al., App. Catal. A: Gen., 190
(2000), 207 teaches yet another suitable catalyst.
[0033] The isomerization catalyst may be any of those well known in
the art such as those described and cited above. Isomerization
conditions include a temperature of about 150.degree. C. to about
360.degree. C. and a pressure of about 1724 kPa absolute (250 psia)
to about 4726 kPa absolute (700 psia). In another embodiment the
isomerization conditions include a temperature of about 300.degree.
C. to about 360.degree. C. and a pressure of about 3102 kPa
absolute (450 psia) to about 3792 kPa absolute (550 psia). Other
operating conditions for the isomerization zone are well known in
the art.
[0034] At least a portion of the hydrogen in the isomerization zone
effluent may be separated in an optional isomerization effluent
separator with the separated hydrogen being removed in an overhead
stream. Suitable operating conditions of the isomerization effluent
separator include, for example, a temperature of 230.degree. C. and
a pressure of 4100 kPa absolute (600 psia). If there is a low
concentration of carbon oxides, or the carbon oxides are removed,
the hydrogen may be recycled back to the hot high pressure hydrogen
stripper for use both as a stripping gas and to combine with the
remainder as a bottoms stream. The remainder may be passed to the
isomerization reaction zone and thus the hydrogen becomes a
component of the isomerization reaction zone feed streams in order
to provide the necessary hydrogen partial pressures for the
reactor.
[0035] The hydrogen is also a reactant in the deoxygenation
reactors, and different feedstocks will consume different amounts
of hydrogen. The isomerization effluent separator allows
flexibility for the process to operate even when larger amounts of
hydrogen are consumed in the first reaction zone. Furthermore, at
least a portion of the remainder or bottoms stream of the
isomerization effluent separator may be recycled to the
isomerization reaction zone to increase the degree of
isomerization. Suitable operating conditions of the isomerization
effluent separator include, for example, a temperature of
230.degree. C. and a pressure of 4100 kPa absolute (600 psia).
[0036] The remainder of the final effluent, after the removal of at
least a portion of the hydrogen, still has liquid and gaseous
components and is cooled, by techniques such as air cooling or
water cooling and passed to a cold separator where the liquid
component is separated from the gaseous component as discussed
above. A water byproduct stream is also separated.
[0037] The LPG/Naphtha stream may be further separated in a
debutanizer or depropanizer in order to separate the LPG into an
overhead stream, leaving the naphtha in a bottoms stream. Suitable
operating conditions of this unit include a temperate of from about
20 to about 200.degree. C. at the overhead and a pressure from
about 0 to about 2758 kPa absolute (0 to 400 psia). The LPG may be
sold as valuable product or may be used as feed to a hydrogen
production facility. Similarly, the naphtha may be used as feed to
a hydrogen or gasoline production facility, or may be blended into
the gasoline pool.
[0038] The gaseous component separated in the product separator of
any of the embodiments above comprises mostly hydrogen and the
carbon dioxide from the decarboxylation reaction. Other components
such as carbon monoxide, propane, and hydrogen sulfide or other
sulfur containing component may be present as well. It is desirable
to recycle the hydrogen to the reaction zone, but if the carbon
dioxide was not removed, its concentration would quickly build up
and effect the operation of the reaction zone. Usually, carbon
dioxide would be removed from the hydrogen by means well known in
the art such as absorption, along with hydrogen sulfide, using an
amine, reaction with a hot carbonate solution, pressure swing
absorption, etc. and if desired, essentially pure carbon dioxide
could be recovered by regenerating the spent absorption media.
However, the separation of carbon dioxide from hydrogen may be
complicated by the sulfur containing component such as hydrogen
sulfide which is sometimes present to maintain the sulfided state
of the deoxygenation catalyst or to control the relative amounts of
the decarboxylation reaction and the hydrogenation reaction that
are both occurring in the deoxygenation zone. Because the hydrogen
sulfide serves a useful purpose in the deoxygenation reaction zone,
it is desirable to recycle the hydrogen sulfide to the reaction
zone as opposed to purchasing additional hydrogen sulfide or sulfur
components. In some applications, there may be a need to control
the level of hydrogen sulfide being recycled which may require
removing the substantially all the hydrogen sulfide in order to
control the amount of separated hydrogen sulfide that is recycled
to the reaction zone. Therefore, the techniques for removing the
carbon dioxide also need to provide the sulfur management in the
process.
[0039] In one embodiment of the invention an amine absorber is used
to selectively remove carbon dioxide while allowing hydrogen and
hydrogen sulfide to pass to recycle. In this embodiment the gaseous
stream from the cold product separated is routed through an amine
absorber containing an aqueous solution of a polyoxypropylene
triamine having the formula:
##STR00001##
Where R' represents a methylene group and R'' represents hydrogen
or methyl or ethyl and wherein the sum of X+Y=Z is a positive
integer having a value of from about 4 to about 6. These amines are
fully described in U.S. Pat. No. 4,710,362 which is hereby
incorporated by reference in its entirety. The amine is in a
aqueous solution containing about 35 to about 55 wt. % of the
polyoxypropylene triamine, and the absorption in the absorber may
be conducted at about 20.degree. C. to about 50.degree. C.
[0040] In another embodiment, two amine absorbers are employed. The
first amine scrubber removes both carbon dioxide and hydrogen
sulfide allowing hydrogen to pass to recycle. The amine chosen to
be employed in first amine absorber is capable of removing at least
both the components of interest, carbon dioxide and the sulfur
components such as hydrogen sulfide. Suitable amines are available
from DOW and from BASF, and in one embodiment the amines are a
promoted or activated methyldiethanolamine (MDEA). The promoter may
be piperazine, and the promoted amine may be used as an aqueous
solution. See U.S. Pat. No. 6,337,059, hereby incorporated by
reference in its entirety. Suitable amines for the first amine
absorber from DOW include the UCARSOL.TM. AP series solvents such
as AP802, AP804, AP806, AP810 and AP814. The carbon dioxide and
hydrogen sulfide are absorbed by the amine while the hydrogen
passes through first amine absorber to be recycled to the first
reaction zone. The amine is regenerated and the carbon dioxide and
hydrogen sulfide are released and removed. The regenerated amine
may be recycled and reused. The released carbon dioxide and
hydrogen sulfide are passed through a second amine absorber which
contains an amine selective to hydrogen sulfide, but not selective
to carbon dioxide. Again, suitable amines are available from DOW
and from BASF, and in one embodiment the amines are a promoted or
activated MDEA. Suitable amines for the second amine absorber zone
from DOW include the UCARSOL.TM. HS series solvents such as HS101,
HS102, HS103, HS104, HS115. Therefore the carbon dioxide passes
through second amine absorber and is available for use elsewhere.
The amine may be regenerated which releases the hydrogen sulfide to
be recycled. A portion of the hydrogen sulfide may be sent to a
Clauss plant. Regenerated amine is then recycled and reused. The
hydrogen sulfide recycle to the reaction zone may be controlled so
that the appropriate amount of sulfur is maintained in the reaction
zone. Conditions for the first scrubber zone includes a temperature
in the range of 30 to 60.degree. C. At least the first absorber is
operated at essentially the same pressure as the reaction zone. By
"essentially" it is meant that the operating pressure of the
absorber is within about 1034 kPa absolute (150 psia) of the
operating pressure of the reaction zone. For example, the pressure
of the absorber is no more than 1034 kPa absolute (150 psia) less
than that of the reaction zone. Also, at least the first absorber
is operated at a temperature that is at least 1.degree. C. higher
than that of the separator. Keeping at least the first absorber
warmer than the separator operates to maintain any light
hydrocarbons in the vapor phase and prevents the light hydrocarbons
from condensing into the absorber solvent. Conditions for the
second amine solution absorber zone may include from about 20 to
about 60.degree. C. and a pressure in the range of about 138 kPa
(20 psia) to about 241 kPa (35 psia).
[0041] The gaseous component stream from the cold product separator
has a total volume that is much greater than the combined volume of
carbon dioxide and hydrogen sulfide. Typically, the amount of
hydrogen sulfide in vapor stream 36 ranges from about 0.01 to about
2 volume-%. In the configurations shown in the figures, the first
amine absorber zone is sized to accommodate the flow of the entire
vapor stream from the cold product separator. However, the second
amine absorber zone is greatly reduced in size as compared to the
first since the flow of material to the second amine absorber zone
is only a fraction of vapor stream from the cold product separator.
The reduction in the size of the second amine absorber zone allows
for reduced capital and operating costs.
[0042] In yet another embodiment, the process may be equipped with
a flexible solvent absorber. Processes discussed herein require
sulfur management steps to control the sulfur component used in the
process. However, not all diesel boiling range processes using
renewable feedstock require sulfur management. Therefore, to
provide the greatest degree of flexibility from the process units,
a flexible absorber may be employed as the amine absorber. A
flexible absorber allows for at least two different amine solvents
to be supplied to the flexible absorber. For example, when sulfur
management is required, amines as discussed above may be supplied
to the flexible absorber. In applications where sulfur management
is not required, other amines may be supplied to the flexible
absorber. Or, the flexible absorber may be used to supply the
carbon dioxide selective amine in one application, and the carbon
dioxide and hydrogen sulfide selective amine in another
application. For example The purpose of the flexible absorption
system is to (a) selectively remove carbon dioxide from the recycle
gas when feed sulfur content is low, for example refined soybean
oil, and it is advantageous to allow hydrogen sulfide to build up
in the recycle gas to maintain the required hydrogen sulfide
partial pressure in the hydrodeoxygenation reaction zone and (b)
remove both carbon dioxide and hydrogen sulfide from the recycle
gas when the sulfur content in the reaction zone of the feed is
high, for example brown grease, it is undesirable for hydrogen
sulfide to build up in the recycle gas to the deoxygentation
reaction zone. A polyoxypropylenetriamine-rich solvent may be used
for case (a) and a formulated MDEA-based solvent such as
UCARSOL.RTM., may be used for case (b). The choice of solvent will
be dictated by the sulfur content in the reaction zone, the
hydrodeoxygenation catalyst active metals loading and the target
hydrogen sulfide concentration in the reaction zone.
[0043] Two separate solvent make-up systems and recycle reservoirs
are required. The gas to the absorber enters the absorber zone and
is sent to the bottom of the absorber vessel. The gas flows upward
through the acid gas absorption section and then passes through a
demisting pad. The absorber is equipped with multiple trays, or
packing where the feed gas counter-currently contacts either the
carbon dioxide selective polyoxypropylenetriamine-type solvent or
the MDEA-based non-selective solvent. In both cases, the cooled
lean solvent enters near the tower top through a liquid distributor
and flows down through the packing, absorbing either the carbon
dioxide while letting the hydrogen sulfide pass through or
absorbing both the carbon dioxide and the hydrogen sulfide to the
required product specification. This lean solvent line is equipped
with an antifoam injection point to allow for the injection of
anti-foam when needed. A solvent reservoir is maintained in the
bottom of the absorber via liquid level control. High and low level
alarms are provided since loss of liquid level can cause
high-pressure gas to exit the absorber bottom. The product gas
passes through a demisting pad at the top of the absorber to
minimize entrainment of liquid. The product gas exiting the
absorber leaves the zone water saturated.
[0044] As the effluent gas stream from the flexible absorber is
recycled to the reaction zone it is typically required that the gas
be first cooled and any condensable liquids removed in an
appropriate separator. If separated, the condensable aqueous phase
liquid recovered could contain solvent and to reduce solvent
make-up requirements for the flexible unit, the aqueous phase from
this downstream separator should be routed back to the absorber
zone. The rich solvent may be regenerated as is known in the art.
Two separate regeneration systems may be required, one for each of
the different amine solvents that may be used.
[0045] The flexible absorber is operated at essentially the same
pressure as the reaction zone pressure and near ambient
temperature. By "essentially" it is meant that the pressure of the
flexible absorber is within 1034 kPa absolute (150 psia) of the
pressure of the product separator. The pressure of the flexible
absorber is no more than 1034 kPa absolute (150 psia) less than the
pressure of the product separator. Lean solvent should enter the
absorber slightly warmer than the acid gas stream so as to prevent
condensation of any light product hydrocarbons in the amine
solvent.
[0046] For the amine solvent which selectively removes only carbon
dioxide, the absorber effluent gas will contain from about 100 to
about 1000 ppm carbon dioxide and >50% of the hydrogen sulfide
present in the gas entering the absorber. For the amine solvent
which selectively removes both carbon dioxide and hydrogen sulfide,
the absorber effluent gas will contain <1 ppm hydrogen sulfide
and from about 100 to about 1000 ppm carbon dioxide.
[0047] At least one flexible absorber would be used in the place of
a traditional absorber, but it is within the scope of the invention
to replace all traditional absorbers with flexible absorbers. FIG.
5. shows a drawing of a sample flexible absorber. Vapor stream 522
from the cold product separator enters flexible absorber 556.
Liquid amine absorber is introduced through either line 550 or 552.
Line 550 is connected to first solvent source 554 and line 552 is
connected to second solvent source 556. Each of the two solvent
sources provide a solvent of differing selectivity. For example,
first solvent source 554 may provide a solvent of the type
disclosed in U.S. Pat. No. 4,710,362 and second solvent source 556
may provide a solvent such as the UCARSOL.TM. AP series solvents
from DOW such as AP802, AP804, AP806, AP810 and AP814. As an
example, when an application calls for only carbon dioxide to be
removed from the stream 522, the solvent from the first solvent
source 554 would be directed to flexible absorber 530. However,
when an application requires both carbon dioxide and hydrogen
sulfide to be removed from the stream 522, solvent from the second
source would be directed to flexible absorber 530. In either case,
solvent is removed from flexible absorber 530 via line 531 and
conducted to a regeneration zone.
[0048] The techniques exemplified here for the separation of the
carbon dioxide are not limiting, and other known techniques for the
separation of the carbon dioxide may be used. The hydrogen stream
remaining after the removal of the carbon oxides may be recycled to
the reaction zone. The hydrogen stream may contain the hydrogen
sulfide being recycled to the reaction zone, or the separated
hydrogen sulfide may be recycled independently such as in
controlled amounts. The hydrogen recycle stream may be introduced
to the inlet of the reaction zone and/or to any subsequent
beds/reactors.
[0049] The carbon dioxide stream is conducted to an algae
cultivation operation. Algae require three primary components to
grow: sunlight, carbon dioxide and water. Algae grow through
photosynthesis where sunlight energy is converted to chemical
energy to drive, for example, the formation of sugars or the
fixation of nitrogen into amino acids. Often algae cultivation is
performed in open ponds such as raceway ponds, open air
bioreactors, photobioreactors and combinations thereof. Raceway
ponds are shallow ponds which have the algae and the nutrients
circulating around a track with paddlewheels stirring the pond
solution and providing the fluid flow. The algae is suspended in
the water of the pond and are circulated to the surface with
regular frequency. If contamination, pH control, temperature
control, and other parameters are an issue, the algae cultivation
operation may be closed off or covered, such as a greenhouse.
Carbon dioxide and nutrients are continuously fed to the ponds and
an excess of carbon dioxide is thought to increase algae
production. Often, the carbon dioxide is bubbled though the pond.
Algae-containing water is removed and processed to obtain algae
oil. The carbon dioxide stream from the diesel boiling range fuel
generation process may be utilized in any algae cultivation
operation, since carbon dioxide is a key component in the
cultivation operations. The term algae is meant to include
microalgae. Some strains of microalgae may be cultivated under
saline conditions
[0050] Algae strains typically sited in the literature for algae
oil production are Chlorphycae, Bacilliarophy (diatom algae),
Botryococcus braunii and Dunaliella tertiolecta. Algal strains such
as Botryococcus braunii can produce long chain hydrocarbons
representing 86% of its dry weight. The green alga Botryococcus is
unique in the quality and quantity of the liquid hydrocarbons it
produces. Some scientists consider the ancestors of Botryococcus to
be responsible for many of the world's fossil fuel deposits. The
Dunaliella tertiolecta strain is reported to have oil yield of
about 37% (organic basis). D. tertiolecta is a fast growing strain
and that means it has a high CO.sub.2 sequestration rate as well. A
favored strain of algae includes Chlorophyceae (green algae). Green
algae tend to produce starch, rather than lipids, and green algae
have very high growth rates at 30.degree. C. and high light in a
water solution of type I at 55 mmho/cm. Another favored algae
strain is Bacilliarophy (diatom algae). However, the diatom algae
needs silicon in the water to grow, whereas green algae requires
nitrogen to grow. Under nutrient deficiency the algae produced more
oils per weight of algae, however the algae growths also were
significantly less.
[0051] Some green algae, such as Chlamydomonas reinhardtii and
Chlamydomonas moewusii, are known to sometimes switch from the
production of oxygen to the production of hydrogen. If the algae
culture medium is deprived of sulfur the algae will switch from the
production of oxygen via normal photosynthesis to the production of
hydrogen though the enzyme hydrogenase. If the algae is able to
produce hydrogen, then another integration with the diesel boiling
range fuel production process becomes available. The hydrogen
produced by the algae may be introduced to the reaction zone of the
diesel boiling range fuel production process. The hydrogen may be
combined with other sources of hydrogen, and may be combined with
the feedstock to the reaction zone.
[0052] The carbon dioxide from the diesel boiling range fuel
process described above may be integrated with the algae
cultivation operation, the hydrogen produced from an algae
cultivation process may be integrated with the diesel boiling range
fuel process, or both integrations may be simultaneously employed
providing multiple points of integration between the diesel boiling
range fuel process and the algae cultivation process. In each case,
a byproduct of one process is being used as a valuable component of
another process.
[0053] The algae can be used to also utilize waste carbon dioxide
from other processes such as power plants burning coal or other
fossil fuels. The algae eliminate the need for sequestering the
carbon dioxide made from power plants and actually use all the
carbon dioxide byproduct to make oil which can be turned into
valuable fuel as described herein.
[0054] The following embodiments are presented in illustration of
this invention and are not intended as an undue limitation on the
generally broad scope of the invention as set forth in the claims.
First the process without the optional isomerization zone is
described in general as with reference to FIG. 1. Then the process
without the optional isomerization reaction zone is described in
more detail with reference to FIG. 2. The process is described in
detail employing the optional hot high pressure hydrogen stripper,
but not the optional isomerization reaction zone with reference to
FIG. 3. The process is described in detail employing the optional
isomerization reaction zone with reference to FIG. 4.
[0055] Turning to FIG. 1 renewable feedstock 102 enters
deoxygenation reaction zone 104 along with recycle hydrogen and
hydrogen sulfide stream 126 and optional product recycle 112.
Contacting the renewable feedstock with the deoxygenation catalyst
generates deoxygenated product 106 which is directed to optional
first selective separation zone 108 which comprises a hot high
pressure hydrogen stripper. Hydrogen-rich make-up gas 110 and
optionally recycle hydrogen is added to optional first selective
separation zone. The hydrogen in the reaction zone or the
hydrogen-rich make-up gas may be produced by particular strains of
algae.
[0056] Carbon oxides and water vapor are removed with hydrogen in
optional first selective separation zone overhead 114 and separated
deoxygenated liquid product are removed in optional first selective
separation zone bottoms 116. Both streams are passed to product
recovery zone 120. Product recovery zone 120 comprises at least a
cooler, a cold product separator, and a product recovery column.
Carbon dioxide and hydrogen stream 122, light ends stream 124,
water byproduct stream 128, and paraffin-rich product 118 are all
removed from product recovery zone 120. Paraffin-rich product 118
may be collected for use as diesel boiling range fuel. Carbon
dioxide and hydrogen stream 122 is directed to second selective
separation zone 130 which contains one or more selective amine
absorbers. At least carbon dioxide is removed from stream 122 via
line 132. Carbon dioxide stream 132 is conducted to algae
cultivation operation 170 and algae is collected from stream 172.
Hydrogen recycle stream 126 is removed from second selective
separation zone and recycled to the deoxygenation reaction zone
104.
[0057] Turning to FIG. 2, the process begins with a renewable
feedstock stream 202 which may pass through an optional feed surge
drum. The feedstock stream is combined with recycle stream 216 to
form combined feed stream 220, which is heat exchanged with reactor
effluent and then introduced into catalytic deoxygenation reactor
204. The heat exchange may occur before or after the recycle is
combined with the feed. Deoxygenation reactor 204 may contain
multiple beds shown in FIG. 2 as 204a, 204b, 204c and 204d.
Deoxygenation reactor 204 contains at least one catalyst capable of
catalyzing decarboxylic and/or hydrodeoxygenation of the feedstock
to remove oxygen. Deoxygenation reactor effluent stream 206
containing the products of the decarboxylic and/or
hydrodeoxygenation reactions is removed from deoxygenation reactor
204 and heat exchanged with stream 220 containing feed to the
deoxygenation reactor. Stream 206 comprises a liquid component
containing largely normal paraffin hydrocarbons in the diesel
boiling range and a gaseous component containing largely hydrogen,
vaporous water, carbon monoxide, carbon dioxide and propane.
[0058] Deoxygenation reactor effluent stream 206 is directed to air
cooler 232 and then introduced into product separator 234. In
product separator 234 the gaseous portion of the stream comprising
hydrogen, carbon monoxide, hydrogen sulfide, carbon dioxide and
propane are phase separated and removed in stream 236 while the
liquid hydrocarbon portion of the stream is removed in stream 238.
A portion of the liquid hydrocarbon stream 238a is recycled to the
reaction zone 204. A water byproduct stream 240 may also be removed
from product separator 234. Stream 238 is introduced to product
recovery column 242 where components having higher relative
volatilities are separated into stream 244 with the remainder, the
diesel range components, being withdrawn from product recovery
column 242 in line 246. Stream 244 is optionally introduced into a
fractionator which operates to separate LPG into an overhead
leaving a naphtha bottoms stream (not shown).
[0059] The vapor stream 236 from product separator 234 contains the
gaseous portion of the reaction zone effluent which comprises at
least hydrogen, carbon monoxide, carbon dioxide and propane and is
directed to a system of at least one amine absorber and regenerator
256 to separate carbon dioxide and optionally hydrogen sulfide (if
present) from the vapor stream. Because of the cost of hydrogen, it
is desirable to recycle the hydrogen to deoxygenation reactor 204,
but it is not desirable to circulate the carbon dioxide or an
excess of sulfur containing components. In one embodiment, vapor
stream 236 is passed through a system of one amine absorber 256,
also called a scrubber. The amine chosen to be employed in the
single amine absorber 256 is capable of selectively removing carbon
dioxide while allowing hydrogen and hydrogen sulfide to pass
through the absorber. Suitable amines for use in are described in
U.S. Pat. No. 4,710,362. The amine absorber may be operated at from
about 20 to about 60 C and a pressure in the range of about 3447
kPa (500 psia) to about 6895 kPa (1000 psia).
[0060] In another embodiment, to separate both the sulfur
containing components and the carbon dioxide from the hydrogen,
vapor stream 236 is passed through a system of at least two amine
absorbers 256 and 258. The amine employed in amine scrubber 256 is
capable of selectively removing at least both the components of
interest, carbon dioxide and the sulfur components such as hydrogen
sulfide. Suitable amines are available from DOW and from BASF, and
in one embodiment the amines are a promoted or activated
methyldiethanolamine (MDEA). The promoter may be piperazine, and
the promoted amine may be used as an aqueous solution. See U.S.
Pat. No. 6,337,059, hereby incorporated by reference in its
entirety. Suitable amines for the first amine absorber zone from
DOW include the UCARSOL.TM. AP series solvents such as AP802,
AP804, AP806, AP810 and AP814. The carbon dioxide and hydrogen
sulfide are absorbed by the amine while the hydrogen passes through
first amine scrubber zone and into line 216 to be recycled to
reaction zone 204. The amine is regenerated and the carbon dioxide
and hydrogen sulfide are released and removed in line 262. Within
the first amine absorber zone, regenerated amine may be recycled
for use again. The released carbon dioxide and hydrogen sulfide in
line 262 are passed through optional second amine scrubber zone 258
which contains an amine selective to hydrogen sulfide, but not
selective to carbon dioxide. Again, suitable amines are available
from DOW and from BASF, and in one embodiment the amines are a
promoted or activated MDEA. Suitable amines for the second amine
absorber zone from DOW include the UCARSOL.TM. HS series solvents
such as HS101, HS102, HS103, HS104, HS115. Therefore the carbon
dioxide passes through second amine scrubber zone 258 and into line
266. The carbon dioxide in line 266 is passed to an algae
cultivation operation 270 and used, along with nutrients and
sunlight, to cultivate the algae. Algae is removed in line 272. The
amine may be regenerated which releases the hydrogen sulfide into
line 260. At least a portion of the hydrogen sulfide in line 260
may be recycled to the reaction zone 204, possibly in measured
controlled amount. Excess hydrogen sulfide may be directed to a
Claus plant. Regenerated amine is then reused. Conditions for each
scrubber zone include from about 20 to about 60 C. and a pressure
in the range of about 3447 kPa (500 psia) to about 6895 kPa (1000
psia).
[0061] In another embodiment, the amine solution absorber zone 256
may contain the amine solution of U.S. Pat. No. 4,710,362 which
selectively separates only the carbon dioxide and allows the
hydrogen sulfide to pass with the hydrogen into recycle line 216.
In this embodiment, the second amine absorber zone 258 is not
necessary.
[0062] In yet another embodiment, amine scrubber zone 256 may
contain the flexible amine scrubber such as shown in FIG. 5 and
described in detail above. In this embodiment, the amine solvent
best suited for the separation required is provided to the
absorber.
[0063] Another embodiment of the invention employs a hot high
pressure hydrogen stripper. Turning to FIG. 3, the process begins
with a renewable feedstock stream 302 which may pass through an
optional feed surge drum. The feedstock stream is combined with
recycle stream 316 to form combined feed stream 320, which is heat
exchanged with reactor effluent and then introduced into
deoxygenation reactor 304. The heat exchange may occur before or
after the recycle is combined with the feed. Deoxygenation reactor
304 may contain multiple beds shown in FIG. 3 as 304a, 304b, 304c
and 304d. Deoxygenation reactor 304 contains at least one catalyst
capable of catalyzing decarboxylic and/or hydrodeoxygenation of the
feedstock to remove oxygen. Deoxygenation reactor effluent stream
306 containing the products of the decarboxylic and/or
hydrodeoxygenation reactions is removed from deoxygenation reactor
304 and heat exchanged with stream 320 containing feed to the
deoxygenation reactor. Stream 306 comprises a liquid component
containing largely normal paraffin hydrocarbons in the diesel
boiling range and a gaseous component containing largely hydrogen,
vaporous water, carbon monoxide, carbon dioxide and propane.
[0064] Deoxygenation reactor effluent stream 306 is directed to hot
high pressure hydrogen stripper 308. Make up hydrogen in stream 310
is also introduced to hot high pressure hydrogen stripper 308. In
hot high pressure hydrogen stripper 308, the gaseous component of
deoxygenation reactor effluent 306 is stripped from the liquid
component of deoxygenation reactor effluent 306 using make-up
hydrogen 310 and optional recycle hydrogen (not shown). The gaseous
component comprising hydrogen, vaporous water, carbon monoxide,
carbon dioxide and possibly some propane, is separated into hot
high pressure hydrogen stripper overhead stream 314. The remaining
liquid component of deoxygenation reactor effluent 306 comprising
primarily normal paraffins having a carbon number from about 8 to
about 24 with a cetane number of about 60 to about 100 is removed
as hot high pressure hydrogen stripper bottoms 312.
[0065] A portion of hot high pressure hydrogen stripper bottoms
forms recycle stream 313 and is combined with renewable feedstock
combined stream 320. Another portion of recycle stream 313,
optional stream 313a, may be routed directly to deoxygenation
reactor 304 and introduced at interstage locations such as between
beds 304a and 304b and/or between beds 304c and 304d in order, for
example, to aid in temperature control. The remainder of hot high
pressure hydrogen stripper bottoms in stream 312 is routed to
product recovery column 342.
[0066] Hydrogen stripper overhead stream 314 is air cooled using
air cooler 332 and introduced into product separator 334. In
product separator 334 the gaseous portion of the stream comprising
hydrogen, carbon monoxide, hydrogen sulfide, carbon dioxide and
propane are removed in stream 336 while the liquid hydrocarbon
portion of the stream is removed in stream 338. A liquid water
byproduct stream 340 may also be removed from product separator
334. Stream 338 is introduced to product recovery column 342 where
components having higher relative volatilities are separated into
stream 344 with the remainder, the diesel range components, being
withdrawn from product recovery column 342 in line 346. Stream 344
may be introduced into a fractionator which operates to separate
LPG into an overhead and leaving a naphtha bottoms (not shown).
[0067] The vapor stream 336 from product separator 334 contains the
gaseous portion of the isomerization effluent which comprises at
least hydrogen, carbon monoxide, carbon dioxide and propane and is
directed to a system of amine absorbers to separate carbon dioxide
and optionally hydrogen sulfide (if present) from the vapor stream.
The separation of the carbon dioxide and the optional separation of
any hydrogen sulfide is described with reference to FIG. 2 and is
not repeated here. Note that the carbon dioxide in line 366 is
passed to an algae cultivation operation 370 and used, along with
nutrients and sunlight, to cultivate the algae. Algae is removed in
line 372. Other separation systems are possible, such as adsorbents
and treating processes.
[0068] Turning to FIG. 4, the process begins with a renewable
feedstock stream 402 which may pass through an optional feed surge
drum. The feedstock stream is combined with recycle stream 416 to
form combined feed stream 420, which is heat exchanged with reactor
effluent and then introduced into deoxygenation reactor 404. The
heat exchange may occur before or after the recycle is combined
with the feed. Deoxygenation reactor 404 may contain multiple beds
shown in FIG. 4 as 404a, 404b, and 404c. Deoxygenation reactor 404
contains at least one catalyst capable of catalyzing decarboxylic
and/or hydrodeoxygenation of the feedstock to remove oxygen.
Deoxygenation reactor effluent stream 406 containing the products
of the decarboxylic and/or hydrodeoxygenation reactions is removed
from deoxygenation reactor 404 and heat exchanged with stream 420
containing feed to the deoxygenation reactor. Stream 406 comprises
a liquid component containing largely normal paraffin hydrocarbons
in the diesel boiling range and a gaseous component containing
largely hydrogen, vaporous water, carbon monoxide, carbon dioxide
and propane.
[0069] Deoxygenation reactor effluent stream 406 is directed to hot
high pressure hydrogen stripper 408. Make up hydrogen in stream 410
is also introduced to hot high pressure hydrogen stripper 408. In
hot high pressure hydrogen stripper 408, the gaseous component of
deoxygenation reactor effluent 406 is stripped from the liquid
component of deoxygenation reactor effluent 406 using make-up
hydrogen 410 and optional recycle hydrogen 411. The gaseous
component comprising hydrogen, vaporous water, carbon monoxide,
carbon dioxide and possibly some propane, is separated into hot
high pressure hydrogen stripper overhead stream 414. The remaining
liquid component of deoxygenation reactor effluent 406 comprising
primarily normal paraffins having a carbon number from about 8 to
about 24 with a cetane number of about 60 to about 100 is removed
as hot high pressure hydrogen stripper bottoms 412.
[0070] A portion of hot high pressure hydrogen stripper bottoms
forms recycle stream 413 and is combined with renewable feedstock
combined stream 420. Another portion of recycle stream 413,
optional stream 413a, may be routed directly to deoxygenation
reactor 404 and introduced at interstage locations such as between
beds 404a and 404b and/or between beds 404b and 404c in order, for
example, to aid in temperature control. The remainder of hot high
pressure hydrogen stripper bottoms in stream 412 is routed to
isomerization zone 468 where it contacts an isomerization catalyst
to convert normal paraffins to branched paraffins. Stream 412 may
be heat exchanged with isomerization reactor effluent 422.
[0071] The product of the isomerization reactor containing a
gaseous portion of hydrogen and propane and a
branched-paraffin-rich liquid portion is removed in line 422, and
after optional heat exchange with stream 412, is introduced into
hydrogen separator 426. The overhead stream 428 from hydrogen
separator 426 contains primarily hydrogen which may be recycled
back to hot high pressure hydrogen stripper 408. Bottom stream 429
from hydrogen separator 426 is air cooled using air cooler 432 and
introduced into product separator 434. In product separator 434 the
gaseous portion of the stream comprising hydrogen, carbon monoxide,
hydrogen sulfide, carbon dioxide and propane phase separate and are
removed in stream 436 while the liquid hydrocarbon portion of the
stream is removed in stream 438. A liquid water byproduct stream
440 may also be removed from product separator 434. Stream 438 is
introduced to product recovery column 442 where components having
higher relative volatilities are separated into stream 444 with the
remainder, the diesel range components, being withdrawn from
product recovery column 442 in line 446. Stream 444 is introduced
into fractionator 448 which operates to separate LPG into overhead
450 leaving a naphtha bottoms 452.
[0072] The vapor stream 436 from product separator 434 contains the
gaseous portion of the isomerization effluent which comprises at
least hydrogen, carbon monoxide, carbon dioxide and propane and is
directed to a system of at least one amine solution absorber to
separate carbon dioxide and optionally hydrogen sulfide from the
vapor stream. The separation of the carbon dioxide and the optional
separation of any hydrogen sulfide is described with reference to
FIG. 2 and is not repeated here. Note that the carbon dioxide in
line 466 is passed to an algae cultivation operation 470 and used,
along with nutrients and sunlight, to cultivate the algae. Algae is
removed in line 472. Other separation systems are possible, such as
adsorbents and treating processes.
[0073] Other techniques of separating the carbon dioxide generated
in the deoxygenation reaction zone may be employed, with the
separated carbon dioxide being provided for use in an algae
cultivation operation.
[0074] In an alternate embodiment, the carbon dioxide generated in
the deoxygenation reaction zone may be employed in enclosed green
houses to grow plants. The plants may then become a source of
renewable feedstock to the diesel boiling range fuel production
process. In this embodiment, upon separation of the carbon dioxide
as discussed above, the carbon dioxide may be conducted to one or
more enclosed green houses in order to cultivate plants being grown
in the enclosed green houses.
[0075] In yet another alternate embodiment of the invention, the
carbon dioxide generated in the deoxygenation reaction zone may be
employed in supercritical extraction processes. In this embodiment,
upon separation of the carbon dioxide as discussed above, the
carbon dioxide may be conducted to one or more supercritical
extraction operations to be used as an extractant in the
supercritical extraction operations in order to separate at least
two components from a mixture.
* * * * *