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The present invention generally relates to a method for producing hydrocarbons from biomass. Specifically, the present invention relates to converting naturally occurring triglycerides and fatty acids to a composition including naphtha boiling range hydrocarbons. The present invention also relates to the resultant biorenewable naphtha product, whereby the naphtha is used as chemical feed stock, fuel, fuel blend stock, or solvent.
The term “green chemistry” has been used to describe synthesis of chemicals from biorenewable feed stocks. It is considered a sustainable alternative to petroleum-based chemistry, and may mitigate the effect of high oil prices. One of the challenges facing transition to a green chemical industry is that the existing production facilities and infrastructure are designed around hydrocarbon feed stocks. For example, the building blocks of the chemical industry, olefins and BTX aromatics (benzene, toluene, and xylene), are produced in steam crackers (also referred to as ethylene crackers) and catalytic reformers that run on light hydrocarbons. Synthesis gas, or syngas for short, is another chemical building block. Syngas is a mixture of carbon monoxide and hydrogen and can be produced by steam reforming of light hydrocarbons. Naphtha is a C5-C9 hydrocarbon cut that is commonly used as the feedstock for both catalytic reformers and steam crackers. It may also be used as feed for steam reforming units for production of syngas.
In particular, paraffinic naphtha is considered a highly desired feed for steam crackers due to its high ethylene and propylene yields. Production of naphtha from biorenewable sources would enable transition to a green chemical industry without the need to develop new chemistries and build new production facilities.
Similarly, the term “sustainable energy” has been used to refer to renewable sources of energy. Biorenewable fuels are a key component of sustainable energy initiatives. Naphtha may be used directly as fuel in industrial furnaces or turbines. It may also be used in small industrial engines such as lawn mowers and chain saws.
Furthermore, since naphtha hydrocarbons are in the motor gasoline boiling range, they may be used as a gasoline blend stock. Gasoline blends need to meet vapor pressure and octane rating requirements.
One method of producing naphtha hydrocarbons from biomass is by the Fischer-Tropsch (F-T) process. U.S. Pat. No. 7,214,720 to Bayle and co-inventors describes a process involving the steps of (a) gasification, (b) syngas purification, (c) F-T conversion, (d) separation, and (e) recycle of at least a portion of the naphtha to gasifier. Although the process produces the desired hydrocarbon naphtha from a bio-renewable source, gasifiers suffer from a low reliability record. Additionally, the capital costs associated with gasification and F-T conversion are known to be very high. This is in part due to solids handling requirements for the gasifier and heat removal provisions for the highly exothermic F-T reaction. Furthermore, the need to recycle part of the naphtha to the gasifier further reduces the efficiency of this process as a source of bio-renewable naphtha.
U.S. Pat. No. 5,186,722 to Cantrell and Chong describes a catalytic process to convert biomass feeds such as limonene to a composition of cyclic and aromatic compounds in the naphtha boiling range. Although these products are reported to have high octane rating and hence good gasoline blend stocks, they lack the desired properties as a chemical feed stock. As feeds for steam crackers, aromatic compounds give low ethylene and propylene yields. More importantly, the terpene feeds used in the process are among the only biomass sources that to begin with are hydrocarbons. Virtually all other sources of biomass have high oxygen content, typically greater than 10 wt %.
Deoxygenation of biomass feeds such as triglycerides and fatty acids are disclosed in U.S. Pat. No. 7,232,935 to Jakkula and co-inventors. A two step process is disclosed which includes hydrodeoxygenation of triglycerides/fatty acids followed by hydroisomerization. The process produces diesel boiling-range isoparaffins.
To this end, there is a need for biorenewable naphtha that can be used as feed stock for existing petrochemical and refining facilities. In particular, the present invention is a method process for converting high oxygen content biomass, such as sources of triglycerides and/or fatty acids, into naphtha boiling-range hydrocarbons using standard refining processes.
The present invention relates to a method for producing from a biorenewable feed stock a hydrocarbon naphtha composition useful for producing olefins, BTX aromatics, hydrogen, and also for direct use as gasoline blend stock and solvent. The biorenewable feed stock includes sources of glycerides (i.e. monoglycerides, diglycerides, triglycerides, etc.) and/or fatty acids and combinations thereof, such as animal fats, animal oils, poultry fat, poultry oils, vegetable oils, vegetable fats, plant fats and oils, rendered fats, rendered oils, restaurant grease, brown grease, waste industrial frying oils, fish oils, tall oil, and the like and any combinations thereof.
The method for producing hydrocarbon naphtha includes hydrotreating a renewable feedstock to produce a heavy hydrocarbon fraction. This is followed by hydrocracking of the hydrotreated heavy fraction to produce a distribution of hydrocarbon components, typically C3-C18, which is fractionated to recover the naphtha product. The heavy fraction is optionally recycled to the hydrocracker.
The hydrotreating of triglycerides and fatty acids involves olefin hydrogenation and deoxygenation. Hydrotreating thus converts fatty acids into long chain paraffins as illustrated in Equations 1 and 2 for conversion of oleic acid to n-octadecane and n-heptadecane.
When the fatty acids are supported on a glycerol backbone, for example as triglycerides or diglycerides, the hydrotreating reactions of Equations 1 and 2 produce propane as well as the long chain, heavy hydrocarbon fraction. Depending on the source of the fatty acid/triglyceride, the heavy hydrocarbon fraction is predominantly in the C12 to C22 range.
The heavy hydrocarbons may be hydrocracked into shorter chain hydrocarbons to produce biorenewable naphtha. In the illustrative hydrocracking reactions of Equations 3-5, n-octadecane is hydrocracked into naphtha-range hydrocarbons, nonanes, hexanes, pentanes, and propane/butanes byproducts.
FIG. 1 is a schematic diagram of an operation for producing biorenewable naphtha according to the present invention.
FIG. 2 is a schematic diagram of another embodiment of a method for producing biorenewable naphtha in accordance with the present invention.
FIG. 3 is a gas chromatogram showing product from an example.
The present invention relates to a method for producing from a biorenewable feedstock a hydrocarbon product of naphtha boiling point range that can be used as feedstock for olefins, BTX aromatics, and hydrogen plants. The biorenewable naphtha of the present invention may also be used directly as a fuel, a fuel blend stock, or a solvent.
Referring to the process embodiment of FIG. 1, a biorenewable feed 101 is transferred to a hydrotreater 102 where it reacts with hydrogen under pressure of from about 300 psig to about 3,000 psig, preferably from about 1,000 psig to about 2,000 psig. Feed 101 may optionally be pretreated to remove contaminants. The hydrotreater 102 is preferably a packed bed of sulfided bimetallic catalyst, preferably nickel-molybdenum (NiMo), nickel-tungsten (NiW), or cobalt-molybdenum (CoMo) on alumina support. It should be understood by one of ordinary skill in the art that any catalyst may be used in the present invention so long as the catalyst functions in accordance with the present invention as described herein.
To maintain the active metal sulfide functionality of the catalyst despite absence of organic sulfur in most bio-renewable feeds, feed 101 may be supplemented with a sulfur composed that decomposes to hydrogen sulfide when heated and/or contacted with a catalyst. Two preferred sulfur compounds are dimethyl disulfide and carbon disulfide. Preferred concentration of these in the feed 101 is from about 100 to about 2,000 ppm by weight sulfur. Alternatively, feed 101 may include a biorenewable component and a petroleum fraction wherein the petroleum-fraction provides the sulfur.
Feed 101 may be preheated before entering the hydrotreater 102. The hydrotreater 102 operates from about 300° F. to about 900° F., preferably from about 550° F. to about 650° F., and from about 250 psig to about 3,000 psig. In order to reduce the adiabatic temperature rise from the exothermic hydrotreating reactions and to maintain the hydrotreater 102 in the preferred operating range, a number of methods known in the art may be used. These methods include, but are not limited to, feed dilution with a solvent or other diluent, liquid product or solvent recycle, and use of quench zones within the fixed-bed reactor wherein hydrogen is introduced.
The biorenewable feed 101 liquid hourly space velocity through the hydrotreater 102 is from about 0.2 h−1 to about 10 h−1, preferably from about 0.5 h−1 to about 5.0 h−1. The ratio of hydrogen-rich treat gas 110 to biorenewable feed 101 is preferably in the about 2,000 to about 15,000 SCF/bbl range. The hydrogen-rich treat gas 110 may contain from about 70 mol % to about 100 mol % hydrogen.
A hydrotreater effluent 103 includes a deoxygenated heavy hydrotreater fraction and unreacted hydrogen. The hydrotreater effluent 103 may also include water, carbon oxides, ammonia, and hydrogen sulfide. The long chain, heavy hydrocarbon fraction in the liquid phase is separated from the gas phase components in a separation unit 104.
The separation unit 104 includes a high pressure drum (not shown) operated at hydrotreater discharge pressure (about 1,000 psig to about 2,000 psig in the preferred embodiment), wherein long chain, heavy hydrocarbon liquids are separated from hydrogen and gas phase hydrotreater byproducts. It should be understood that the hydrotreater discharge pressure may be operated from about 200 psig to about 3,000 psig. Depending on the temperature of the separation unit 104, water may be in vapor or liquid phase. In a preferred embodiment, the separation unit 104 has a temperature in the about 350° F. to about 500° F. range whereby water, carbon oxides, ammonia, hydrogen sulfide, and propane are removed with hydrogen in a separator drum vapor phase. To enhance removal of the components from the heavy hydrocarbon fraction, the separation unit 104 optionally includes a stripping section (not shown). Water 111 may be condensed, separated, and the hydrogen-rich gas phase 105 recycled to the hydrotreater 102.
A long chain hydrocarbon product stream 112 from the separation unit 104 is then cracked in a hydrocracker 114. Product stream 112 is optionally combined with unconverted heavies from the hydrocracker 114, and recycled stream 125, to form a hydrocracker feed 113.
The heavy hydrocarbon feed 113 cracks in the hydrocracker 114 to form naphtha-range hydrocarbons. Preferably, the hydrocracker 114 operates from about 250 psig to about 3,000 psig, more preferably from about 1,000 psig to about 2,000 psig. Hydrocracker 114 temperatures are from about 400° F. to about 900° F., preferably from about 580° F. to about 750° F. Suitable catalysts for hydrocracking according to the present invention as described herein are bi-functional catalysts with hydrogenation and acidic functionalities. Such catalysts include Group VIII metals on amorphous (e.g. silica-alumina) or crystalline (e.g. zeolite) supports. Preferred hydrocracking catalysts are platinum, palladium or combinations of same on an amorphous silica-alumina support. However, it should be understood that any catalyst may be used in accordance with the present invention as long as it functions as described herein. Preferred ratios of the hydrogen-rich gas to liquid feed for hydrocracking are in the about 1,000 to about 10,000 SCF/bbl range, and liquid hourly space velocity in the about 0.1 h−1 to about 8 h−1 range, preferably from about 0.2 h−1 to about 4 h−. Stream 1115 is an effluent of the hydrocracker 114 wherein un-reacted hydrogen includes a gas phase. Hydrogen-rich gas is separated from the hydrocarbon product in a separation unit 116.
The separation unit 116 includes a high pressure separation drum (not shown), operating at hydrocracker discharge pressure, about 1,000 psig to about 2,000 psig in the preferred embodiment, where hydrocarbon liquids are separated from hydrogen, hydrocarbon vapors, and any other gas phase cracked products. It should be understood that the hydrocracker discharge pressure may be operated from about 200 psig to about 3,000 psig.
A hydrogen-rich gas 117 from the separation unit 116 is combined with a hydrogen-rich gas 105 from the separation unit 104 and optionally processed through an absorption column or scrubber 108 to remove ammonia, carbon oxides, and/or hydrogen sulfide, before recompression for recycle to the hydrotreater 102 and/or hydrocracker 114. Depending on the contaminant to be removed, the scrubber 108 may use various solvents such as amine and caustic solutions. It is clear to those skilled in the art that other gas cleanup technologies may be used instead of or in addition to the scrubber 108 to remove contaminants that affect the hydrotreater 102 and hydrocracker 114 catalyst activity and selectivity. Examples of alternative gas cleanup technologies include membrane systems and adsorbent beds.
A purge stream 107 may be removed from a recycle gas 106 to prevent buildup of contaminants that are not effectively removed in the scrubber 108. The cleaned hydrogen-rich gas 108a from the scrubber 108 may be combined with makeup hydrogen 109 to form a hydrogen-rich gas stream 110 for the hydrotreater 102 and hydrocracker 114.
Stream 123 is the liquid hydrocarbon phase from the separation unit 116. Stream 123 is processed through fractionator unit 124 to fraction the hydrocracker products into a hydrocarbon vapors product 127, the desired naphtha product 126, and a heavies fraction 125 which is optionally recycled to extinction through the hydrocracker 114.
The fractionator unit 124 is operated to recover biorenewable naphtha, typically with a C4-C9 hydrocarbon distribution.
Referring now to FIG. 2, another embodiment of the present invention is illustrated. A biorenewable feed enters a hydrotreater reactor (not shown). Stream 212 is the heavy hydrocarbon product of the hydrotreating reaction in the hydrotreater. Stream 212 is optionally combined with an unconverted heavy fraction 225 to form a hydrocracker feed 213. Hydrocracker feed 213, a C15-C22 hydrocarbon distribution for most common triglycerides and fatty acids, is converted to a C3-C18 distribution in a hydrocracker 214. An effluent 215 from the hydrocracker 214, is separated into a hydrogen-rich gas stream 217 and a cracked liquids stream 223 in a separation unit 216. Operating conditions are the same as for FIG. 1.
A fraction of the hydrogen-rich gas 217 is purged as stream 207 and the remaining fraction of the hydrogen-rich gas 217 is cleaned up in scrubber 208. The cleaned hydrogen-rich gas 208a is then combined with makeup hydrogen 209 to form a recycle hydrogen-rich gas as hydrocracker stream 210.
Stream 223, cracked liquids from the separation unit 216, is transferred to a product fractionators unit 224. The illustrative C3-C18 hydrocracked product is fractioned into a C3/C4 gas stream 227, a naphtha product stream 226, a middle distillate stream 228 suitable for use as jet kerosene or diesel, and a heavies recycle stream 225.
The resultant biorenewable naphtha has a boiling point range from about 70° F. to about 400° F. and a specific gravity at 20° C. of from about 0.680 to about 0.740. The naphtha product includes C4-C10 paraffins that are considered superior feed components for steam crackers, and is also an appropriate feed for conversion to BTX aromatics, and hydrogen production. The naphtha composition is also useful as a solvent in applications where low flash point is not a limitation.
As a fuel or fuel additive, the renewable naphtha provides some benefit as a bio-renewable addition to ethanol in that ethanol typically suffers from low vapor pressures and low energy density. The biorenewable naphtha typically has a Reid Vapor Pressure (RVP)>10 psi and may be blended with ethanol in concentrations of 1-30% to make an entirely renewable gasoline replacement for automobiles that has an improved energy density. The bio-renewable naphtha has low octane ratings (typically less than 40 RON) which is offset by the higher octane of the ethanol fuel which is reported to be in the 129 RON range. Thus, the resulting blend easily meets U.S. performance requirements for vapor pressure and octane rating by utilizing the benefits of both fuels.
An alternate approach for using the biorenewable naphtha of the present invention as described herein as a renewable blend stock for motor gasoline is by isomerization of the C5/C6 fraction, which is a standard refinery unit process. The C5/C6 fraction of the biorenewable naphtha composition may be isomerized to raise RON and make it suitable for blending with gasoline stocks. Typical isomerized products include 2-methylbutane and 2,3-dimethylbutane, with RON values of 93.5 and 105 respectively.
The biorenewable naphtha is used as fuel for industrial burners, boilers, and turbines as an industrial solvent.
Due to its paraffinic nature and its high hydrogen-to-carbon ratio, the bio-renewable naphtha may also be used as a hydrogen source or as a fuel cell fuel.
In order to further illustrate the present invention, the following examples are given. However, it is to be understood that the examples are for illustrative purposes only and are not to be construed as limiting the scope of the subject invention.
The present example demonstrates how naphtha was made from a renewable feedstock. A 100 cc isothermal tubular reactor was filled with 80 cc of a commercial NiMo catalyst and +70-100 mesh glass beads. The catalyst was sulfided with dimethyl disulfide. The sulfiding procedure included step-wise temperature increase to 650° F. After sulfiding, the reactor was cooled to 400° F.
Next a triglyceride/fatty acid feed was introduced to the isothermal reactor. The reactor was slowly heated to 650° F. to achieve full conversion of the triglyceride/fatty acid feed to n-paraffins. The reactor temperature was further increased to 700° F. to maintain good catalyst activity at 80 cc/hr feed rate (1 LHSV).
The hydrotreater performance with beef tallow as the triglyceride/fatty acid feed is summarized in Table 1. The yield of total products on feed basis exceeds 100% in part due to addition of hydrogen and also due to measurement errors associated with gas phase analysis.
|Hydrotreater Conditions and Conversion Performance.|
|Active Metals||Sulfided NiMo|
|Gas/Oil Ratio (scf/bbl)||14,000|
|Products (wt % feed basis)|
|C1 + C2||1.5|
|Total Liquid Hydrocarbons||88.2|
The gas chromatogram of the liquid hydrocarbon product confirmed that under the hydrotreater conditions of Table 1 the tallow feed was converted C15-C18 n-paraffins with no detectable oxygenates remaining. No cracked products (C12—) were detected. FIG. 3 is the chromatogram of the product, showing areas where cracked products and unconverted feed would appear.
The mainly C15-C18 n-paraffin composition obtained from hydrotreating bio-renewable feed stocks was used as feed for a hydrocracking pilot plant. These long chain hydrocarbons were derived via hydrotreating a biorenewable feed in a procedure similar to Example 1. The bio-renewable feed was a blend of chicken fat (45%), brown grease (19%), yellow grease (18%), floatation grease (9%), and miscellaneous waste animal fats from industrial food processing operations (9%). The hydrocracking pilot plant was a prototype of the embodiment of the present invention represented by FIG. 2.
The hydrocracker reactor system was loaded with 4.8 liters of a commercial hydrocracking catalyst. The catalyst was platinum-palladium on amorphous alumina/silica
The reactor was pressurized to 1,000 psig. After catalyst preconditioning, the temperature was increased again to achieve the desired level of hydrocracking to produce the biorenewable naphtha product. The ratio of hydrogen-rich gas (recycle and makeup) to feed was 3,800 SCF/bbl.
The pilot plant fractionation system included three distillation columns in series. The first stripped off the light hydrocarbons (“debutanizer”) from the hydrocracker effluent, the second (“naphtha tower”) separated the naphtha overhead, and the third (“recycle tower”) separated a middle distillate cut overhead from the heavy bottoms that were combined with the fresh feed and recycled to the hydrocracker.
Table 2 provides the composition and properties of the hydrotreated hydrocarbon fraction and Table 3 summarizes the operating conditions of the hydrocracker, conversion performance thereof, and product properties therefrom.
|Composition and properties of hydrocracker feed of Example 2a|
|Component||Pt. (° F.)||Feed||D2887SimDist (° F.)|
|aND = not detectable|
|Hydrocracker Run Conditions, Conversion Performance,|
|and Product Propertiesa|
|Reactor 1 Temp (° F.)||726|
|Reactor 2 Temp (° F.)||721|
|Fresh Feed Wt (g/hr)||2241.0|
|Fresh Feed Vol (cc/hr)||2817.5|
|Recycle Feed Wt (g/hr)||807.6|
|Recycle Feed Vol (cc/hr)||1026|
|Total Feed Vol (cc/hr)||3843|
|H2 Makeup (scf/hr)||24.5|
|Inlet Gas (scf/hr)||102.2|
|Bleed Gas (scf/hr)||15.5|
|Non-condensed C5-C6 + (g/hr)|
|Middle Distillate Ovhd (g/hr)||1538.5|
|Non-condensed C5-C6 (wt %)||3.3%|
|Condensed naphtha (wt %)||25.0%|
|Total naphtha (wt %)||28.3%|
|Material Balance Closure||100.1%|
|Naphtha Tower Temps|
|Recycle Tower Temps|
|Recycle heavies spec. grav.||0.787|
|D2887 SimDist (° F.)|
|Middle Distillate Properties|
|Freeze Point (° C.)||−39.5|
|Cloud Point (° C.)||−43.0|
|Flash Point (° F.)||126|
|D2887 SimDist (° F.)|
|aNM = not measured|
Thus there has been shown and described a method for producing a biorenewable naphtha product that fulfills all objectives and advantages sought therefore. While presently preferred embodiments of the invention have been described for purposes of this disclosure, it will be understood that numerous changes may be made which will readily suggest themselves to those skilled in the art and which are accomplished within the spirit of the invention disclosed and claimed herein. From the above description, it is clear that the present invention is well adapted to carry out the objects and to obtain the advantages mentioned herein as well as those inherent in the invention. While presently preferred embodiments of the invention have been described for purposes of this disclosure, it will be understood that numerous changes may be made which will readily suggest themselves to those skilled in the art and which are accomplished within the spirit of the invention disclosed and claimed.