Patent Application
20050205462
Not applicable.
Not applicable.
The present invention is generally related towards the field of converting hydrocarbon gas to liquid hydrocarbons. In particular, the present invention provides a hydroprocessing method and apparatus for improving products prepared as liquid hydrocarbons from synthesis gas. More particularly, the present invention provides a method and apparatus for enhancing the yield and cold-flow properties of certain hydrocarbon products.
Natural gas, found in deposits in the earth, is an abundant energy resource. For example, natural gas commonly serves as a fuel for heating, cooking, and power generation, among other things. The process of obtaining natural gas from an earth formation typically includes drilling a well into the formation. Wells that provide natural gas are often remote from locations with a demand for the consumption of the natural gas.
Thus, natural gas is conventionally transported large distances from the wellhead to commercial destinations in pipelines. This transportation presents technological challenges due in part to the large volume occupied by a gas. Because the volume of a gas is so much greater than the volume of a liquid containing the same number of molecules, the process of transporting natural gas typically includes chilling and/or pressurizing the natural gas in order to liquefy it. However, this contributes to the final cost of the natural gas.
Further, naturally occurring sources of crude oil used for liquid fuels such as gasoline and middle distillates have been decreasing and supplies are not expected to meet demand in the coming years. Middle distillates typically include heating oil, jet fuel, diesel fuel, and kerosene. Fuels that are liquid under standard atmospheric conditions have the advantage that in addition to their value, they can be transported more easily in a pipeline than natural gas, since they do not require energy, equipment, and expense required for liquefaction.
Thus, for all of the above-described reasons, there has been interest in developing technologies for converting natural gas to more readily transportable liquid fuels, i.e. to fuels that are liquid at ambient temperatures and pressures. One method for converting natural gas to liquid fuels involves two sequential chemical transformations. In the first transformation, natural gas or methane, the major chemical component of natural gas, is reacted with water and/or molecular oxygen to form syngas, which is a combination of carbon monoxide gas and hydrogen gas. In the second transformation, known as the Fischer-Tropsch synthesis, carbon monoxide is reacted with hydrogen to form organic molecules containing carbon and hydrogen, known as hydrocarbons. In addition, other organic molecules containing oxygen in addition to carbon and hydrogen known as oxygenates may be formed during the Fischer-Tropsch process. Hydrocarbons comprising hydrogen and carbon atoms with no unsaturated carbon-carbon bonds are know as paraffins. Paraffins with a straight carbon chain are known as linear paraffins, which include normal alkanes. Paraffins with a branched carbon chain are known as isoparaffins. Isoparaffins comprise isomers of linear paraffins. Isomers are molecules having the same molecular formula as another molecule, but having a different structure and, therefore, different properties. As the carbon atoms in a paraffin molecule increase, the number of possible combinations, or isomers, increases sharply. For example, octane, an 8-carbon-atom molecule, has 18 isomers; decane, a 10-carbon-atom molecule, has 75 isomers. Paraffins are particularly desirable as the basis of synthetic diesel fuel.
Typically the Fischer-Tropsch product stream contains hydrocarbons having a range of numbers of carbon atoms, and thus having a range of molecular weights. Thus, the Fischer-Tropsch products produced by conversion of natural gas commonly contain a range of hydrocarbons including gases, liquids and waxes. Depending on the molecular weight product distribution, different Fischer-Tropsch product mixtures are ideally suited to different uses. In the Fischer-Tropsch process, synthesis gas is catalytically transformed into a hydrocarbon product. The hydrocarbon product primarily comprises normal paraffins. It is generally free of heteroatomic impurities such as sulfur, nitrogen or metals. The hydrocarbon product contains practically no aromatics, naphthenes or, more generally, cyclic compounds, in particular when cobalt catalysts are used. In contrast, the Fischer-Tropsch hydrocarbon product can include a non-negligible quantity of oxygen-containing compounds which, expressed as the weight of oxygen, is generally less than about 10% by weight, and also a quantity of unsaturated compounds (generally olefins) that is generally less than 15% by weight. However, the Fischer-Tropsch product fractions, primarily comprising normal paraffins, cannot be used as they are, in particular because their cold properties are not compatible with the normal use of petroleum cuts. As an example, the pour point of a linear hydrocarbon containing 20 carbon atoms per molecule (boiling point of about 340° C., i.e., usually included in the middle distillate cut) is about +37° C. rendering it impossible to use, as the specification for diesel fuel pour point is −150° C. Fischer-Tropsch hydrocarbon product, mainly comprising linear paraffins, must be transformed into products with a higher added value such as diesel, or kerosene, which are obtained after further hydroprocessing. For example, hydrocarbon waxes from Fischer-Tropsch may be subjected to an additional processing step for conversion to liquid and/or gaseous hydrocarbons and/or for conversion to more branched hydrocarbons. Thus, in the production of a Fischer-Tropsch product stream for processing to a fuel it is desirable to maximize the production of high value liquid hydrocarbons, such as hydrocarbons with at least 5 carbon atoms per hydrocarbon molecule (C5+ hydrocarbons) as well as to enhance some of the cold flow properties of some liquid fuel obtained therefrom.
These processes are well known, but are continually under development in an attempt to enhance the quality of the liquid hydrocarbon products and increase product yields. The embodiments disclosed herein are directed towards these and other related goals.
The present invention is generally directed towards an improvement in preparing liquid hydrocarbons. In particular, the present invention provides methods and apparatus for enhancing the yield and/or cold-flow properties of certain hydrocarbon products, increasing the degree of isomerization in the diesel product and/or increasing the production rate of the diesel product.
In general, the disclosed embodiments of the present invention comprise apparatus and methods in which hydrocarbons are: (a) fractionated into at least two fractions, wherein the at least two fractions have different boiling point ranges; (b) reacting at least a portion of one of the fractions in a first hydrocracking reaction zone to produce a first product stream; (c) and reacting at least a portion of a second fraction in a second hydrocracking zone to produce a second product stream. The two hydrocracking zones can be operated in parallel or in series. In a preferred embodiment, one hydrocracking zone is placed downstream of the other hydrocracking zone, thereby receiving an effluent stream from the upstream hydrocracking zone. In an alternate embodiment, the hydrocarbons are passed through a hydrotreating zone prior to fractionation.
Most of the other embodiments of the present invention include at least one or more of the following variations to the general embodiment: feeding at least a portion of the first product stream to the second hydrocracking zone; reacting a heavier fraction in the first hydrocracking zone and a lighter fraction in the second hydrocracking zone; and fractionating one or more of the hydrocracked product streams to produce at least a middle distillate.
A preferred embodiment of the present invention comprises feeding a heavy hydrocarbon stream at an entry point in the hydrocracking unit, while feeding a light hydrocarbon stream to the hydrocracking unit at an entry point located downstream of the entry point for the heavy hydrocarbon stream, such as to minimize cracking of hydrocarbons in the diesel and/or gasoline range, and increase the yield of desirable products (diesel and/or gasoline).
Another preferred embodiment of the present invention further comprises employing two hydroconversion zones, wherein at least one zone comprises a bifunctional catalyst suitable for promoting hydroisomerization, dewaxing, or combinations thereof. The use of a bifunctional catalyst in a downstream hydroconversion zone in a series of hydroconversion zones is particularly preferred, so as to form branched hydrocarbons in the diesel range, and to increase the degree of branching of a diesel product obtained therefrom, and hence, one or more of the cold flow properties of a desirable diesel product.
A preferred embodiment of a method for increasing the degree of isomerization of a diesel product from a Fischer-Tropsch synthesis comprises: (A) reacting a mixture of hydrogen and carbon monoxide at conversion promoting conditions so as to form a synthetic hydrocarbon stream, wherein the synthetic hydrocarbon stream comprises primarily C5+ paraffins; (B) forming a fractionator feedstream comprising the synthetic hydrocarbon stream; (C) separating the fractionator feedstream into at least three fractions: a light fraction; an intermediate fraction; and a heavy fraction; wherein the light fraction has a boiling range with a 5% boiling point of about 300° F., wherein the intermediate fraction has a boiling range with a 5% boiling point lower than that of the heavy fraction, and higher than that of the light fraction; (D) passing substantially all of the heavy fraction to a first hydroconversion zone containing a hydrocracking catalyst; (E) reacting portion of said heavy fraction with hydrogen under hydrocracking promoting conditions in the first hydroconversion zone to form a first hydroconverted effluent; (F) passing at least a portion of said first hydroconverted effluent to a second hydroconversion zone; (G) passing at least a portion of the intermediate fraction to the second hydroconversion zone; (H) reacting portion of said first hydroconverted effluent and portion of the intermediate fraction with hydrogen in the second hydroconversion zone with a catalyst under conditions suitable to promote hydroisomerization, hydrocracking, dewaxing, or combinations thereof, to form a second hydroconverted effluent, wherein the portion of the intermediate fraction passed to the second and the portion of the first hydroconverted effluent passed through the second hydroconversion zone have lost their separate identities; (I) separating the second hydroconverted effluent produced in step (H) to create at least a middle distillate fraction therefrom; and (J) forming a synthetic paraffinic fuel by blending at least a portion of the light fraction from step (b); at least a portion of the middle distillate fraction from step (I); and optionally, a portion of the intermediate fraction from step (B) not passed to second hydroconversion zone.
A method for increasing the production yield of a diesel product primarily derived from a Fischer-Tropsch synthesis comprises: A) providing a hydrocarbon stream comprising C5+ hydrocarbons, wherein a majority of said C5+ hydrocarbons are products of a Fischer-Tropsch synthesis; B) optionally, reacting said hydrocarbon stream with hydrogen in a hydrotreater under hydrotreating promoting conditions to form a hydrotreated hydrocarbon stream comprising primarily of C5+ paraffins; C) separating by fractionation the hydrocarbon stream into at least
Alternative embodiments of the present invention comprise having a plurality of hydrocracking zones separately fed by multiple hydrocarbon streams with various boiling point ranges. The different hydrocarbon streams are fed into the multiple hydrocracking zones successively. For example, a C60+ stream may be fed into a first zone with C50-C60, C50-C40, C30-C40 and C20-C30 streams being fed into subsequent downstream successive zones. Another embodiment comprising an upstream zone and a downstream zone includes passing a C20+ stream to the upstream zone under hydrocracking promoting conditions to form an upstream zone effluent, and passing the upstream zone effluent and a C20− stream to the downstream zone to form a hydrocracked product. In addition, the embodiments of the present invention include methods for producing liquid hydrocarbons derived from hydrocarbon gas using at least the general embodiments disclosed herein with respect to the hydroprocessing the hydrocarbon products.
Other embodiments are within the spirit of the present invention and are disclosed herein or will be readily understood by those of ordinary skill in the art. All of these and other embodiments, features and advantages of the present invention will become apparent with reference to the following detailed description and drawings.
For a more detailed understanding of the present invention, reference is made to the accompanying Figures, wherein:
Certain terms are used throughout the following description and claims to refer to particular system components. As one skilled in the art will appreciate, individuals and companies may refer to a component by different names. This document does not intend to distinguish between components that differ in name but not function. The terms used herein are intended to have their customary and ordinary meaning. The disclosure should not be interpreted as disclaiming any portion of a term's ordinary meaning. Rather, unless specifically stated otherwise, definitions or descriptions disclosed herein are intended to supplement, i.e., be in addition to, the scope of the ordinary and customary meaning of the term or phrase.
As used herein, a “Cn hydrocarbon” represents a hydrocarbon with ‘n’ carbon atoms, and “Cn+ hydrocarbons” represents hydrocarbons with ‘n’ or more carbon atoms; and “Cm− hydrocarbons” represents hydrocarbons with ‘m’ or less carbon atoms.
“Heteroatomic compounds” represent organic compounds, which comprise not only carbon and hydrogen, but also other atoms, such as nitrogen, sulfur, and/or oxygen. The non-carbon and non-hydrogen atoms (e.g., oxygen, sulfur and nitrogen, respectively) are “heteroatoms”. Examples of heteroatomic compounds comprising oxygen are alcohols, aldehydes, esters, ketones, and the like. Examples of heteroatomic compounds comprising sulfur are mercaptans, thiophenes, and the like. Examples of heteroatomic compounds comprising nitrogen are amines. For example, methyl propyl ketone (CH3COC3H7), 1-pentanol (C5H11OH), decyl mercaptan (C10H22S), and dipropyl amine ((C3H7)2NH) are heteroatomic compounds.
As used herein, to “hydroprocess” means to treat a hydrocarbon stream with hydrogen.
As used herein, to “hydrotreat” generally refers to the saturation of unsaturated carbon-carbon bonds and removal of heteroatoms (oxygen, sulfur, nitrogen) from heteroatomic compounds. To “hydrotreat” means to treat a hydrocarbon stream with hydrogen without making any substantial change to the carbon backbone of the molecules in the hydrocarbon stream. For example, hydrotreating a hydrocarbon stream comprising predominantly an alkene with an unsaturated C═C bond in the alpha position (first carbon-carbon bond in the carbon chain) would yield a hydrocarbon stream comprising predominantly the corresponding alkane (e.g., for hydrotreating of alpha-pentene, the ensuing reaction follows: H2C═CH—CH2—CH2—CH3+H2→CH3—CH2—CH2—CH2—CH3).
As used herein, “ultra-low severity” hydrotreatment means hydrotreatment at conditions such that a substantial portion of the olefins in a stream becomes saturated, but a substantial amount of the heteroatoms in the stream remain attached to their parent molecule. Two of the most important factors in determining whether a hydrotreating process does not convert a substantial amount of, for example, oxygenates to paraffins are catalyst composition and temperature.
As used herein, to “hydroisomerize” means to convert at least a portion of hydrocarbons to more branched hydrocarbons. An example of hydroisomerization comprises the conversion of linear paraffins into isoparaffins. Another example of hydroisomerization comprises the conversion of monobranched paraffins into dibranched paraffins.
As used herein, to “hydrocrack” generally refers to the breaking down of high molecular weight material into lower molecular weight material. To “hydrocrack” means to split an organic molecule with hydrogen to the resulting molecular fragments to form two smaller organic molecules (e.g., for hydrocracking of n-decane, the exemplary reaction follows: C10H22+H2 →C4H10 and skeletal isomers +C6H14 and skeletal isomers). Because a hydrocracking catalyst can be active in hydroisomerization, there can be some skeletal isomerization during the hydrocracking step, therefore isomers of the smaller hydrocarbons can be formed.
As used herein, the boiling range distribution and specific boiling points for a hydrocarbon stream or fraction within the diesel boiling range or heavier than the diesel boiling range are generally determined by the SimDis method of the American Society for Testing and Materials (ASTM) D2887 “Boiling Range Distribution of Petroleum Fractions by GC”, unless otherwise stated. The test method ASTM D2887 is applicable to fractions having a final boiling point of 538° C. (1000° F.) or lower at atmospheric pressure as measured by this test method. This test method is limited to samples having a boiling range greater than 55° C. (100° F.), and having a vapor pressure sufficiently low to permit sampling at ambient temperature. The ASTM D2887 method typically covers the boiling range of the n-paraffins having a number of carbon atoms between about 5 and 44. Further, it should be understood by those of ordinary skill in the art that a fraction or stream of a particular set of hydrocarbons will exhibit a certain identity. The identity will generally be defined as is done herein by boiling point ranges. Other characteristics may set apart a particular fraction's identity as may be discussed herein, e.g., carbon number, degree of isomerization, etc.
As used herein, the boiling range distribution and specific boiling points for a hydrocarbon stream or fraction within the naphtha boiling range or lighter than the naphtha boiling range are generally determined by the ASTM D 86 standard distillation method “Standard Test Method for Distillation of Petroleum Products at Atmospheric Pressure”, unless otherwise stated.
As used herein, a “diesel” is any hydrocarbon cut having at least a portion, which falls within the diesel boiling range. The diesel boiling range in this application includes hydrocarbons, which boil in the range of about 300° F. to about 750° F. (about 150-400° C.), preferably in the range of about 350° F. to about 650° F. (about 170-350° C.).
As used herein, a “middle distillate” means a hydrocarbon stream which includes kerosene, home heating oil, range oil, stove oil, and diesel that has a 50 percent boiling point in the ASTM D86 standard distillation test falling between 371° F. and 700° F. (about 188-370° C.).
In addition, where words are used interchangeably, e.g., hydroconversion “beds,” “zones,” and “chambers,” or “fractionated,” “distilled,” and “separated,” it is intended that all sets of terms used interchangeably herein individually will have a broader meaning than their ordinary meaning, one that incorporates the full scope of each interchangeable term. Thus, nothing herein should be interpreted as disclaiming or disavowal of a term's scope unless specifically stated as otherwise.
There are shown in the Figures, and herein will be described in detail, specific embodiments of the present invention with the understanding that the present disclosure is to be considered an exemplification of the principles of the invention, and is not intended to limit the invention to that illustrated and described herein. The present invention is susceptible to embodiments of different forms or order and should not be interpreted to be limited to the particular methods or compositions contained herein. In particular, various embodiments of the present invention provide a number of different configurations of the overall gas to liquid conversion process.
The present invention is generally related towards enhancing the yield and/or cold-flow properties of certain hydrocarbon products, increasing the degree of isomerization in a diesel product and/or increasing the production rate of a diesel product. Diesel is generally consider to start at about C9 and can extend to about C22. The peak of the boiling range is typically around C16-C18. Depending on the climatic conditions in which the diesel is used, local specifications can allow these limits to be higher or lower. Specifications of diesel fuels will define limits on viscosity, boiling range, density, lubricity, cloud point, pour point, and others. The number of carbon atoms that make up the molecules of a given fuel are a consequence of the tailoring of the fuel to meet those specification requirements. In reality, fuels comprise an array of molecule types.
In a cracking environment, a C30 paraffin for example can be hydrocracked into two diesel range paraffinic molecules with smaller numbers of carbon atoms. In an environment where diesel yield is desirable, the C30+ paraffin molecule would be cracked once and the cracked diesel range paraffinic molecules would pass immediately to a downstream processing. However, in practicality, at least one of the cracked diesel range paraffinic molecules can be hydrocracked to produce even smaller paraffinic molecules, some of which may no longer be in the diesel boiling range. Hence, secondary cracking tends to reduce the yield of diesel.
Because a hydrocracking process can yield a range of hydrocarbons of differing boiling points, some of which are undesirable, the present invention generally relates to various methods that favor the formation of more desired hydrocarbons and less of the undesirable ones. The methods generally include reducing the residence time of desirable hydrocarbons during hydrocracking, thereby decreasing secondary cracking and increasing isomerization. This is achieved by various hydrocracking configurations, which introduce at least two hydrocarbon feedstreams of different boiling ranges at different entry points in a hydrocracking unit.
In general, the embodiments of the present invention are directed toward using multiple hydrocarbon fractions (having different boiling ranges) that can be introduced at different entry points into a hydrocracking environment. The hydrocracking environment may be comprised of a single hydrocracking bed/chamber, multiple hydrocracking beds/chambers placed in series or in parallel, or a combination thereof. In addition, each hydrocracking bed/chamber may include one or more hydrocracking zones. The differing hydrocarbon fractions are introduced into the different hydrocracking zones. The selection of the hydrocracking arrangement, as well as the selection of the hydrocarbon fractions may be used to achieve certain benefits or end results.
Fractionator feedstream 10 comprises hydrocarbon stream 8 and a hydroconverted recycling stream 70. In general terms, hydrocarbon stream 8 preferably comprises C5+ hydrocarbons from a hydrocarbon synthesis reactor (not shown). Suitable hydrocarbon synthesis reactors will be discussed in more detail below. A preferred hydrocarbon synthesis reactor comprises a Fischer-Tropsch synthesis reactor.
Hydrocarbon stream 8 preferably comprises primarily C5+ hydrocarbons, some of which are saturated hydrocarbons (i.e., have no unsaturated carbon-carbon bonds) such as paraffins, and some of which are unsaturated hydrocarbons (i.e., have unsaturated carbon-carbon bonds) such as alkenes (also called olefins). Hydrocarbon stream 8 should contain at least 70% by weight of C5+ linear paraffins, preferably at least 75% by weight of C5+ linear paraffins; more preferably at least 85% by weight of C5+ linear paraffins. Hydrocarbon stream 8 could contain up to 15% by weight of olefins. Hydrocarbon stream 8 may also comprise. heteroatomic compounds such as sulfur-containing compounds (e.g., sulfides, thiophenes, benzothiophenes, and the like); nitrogen-containing compounds (e.g., amines, ammonia); and oxygenated hydrocarbons also called oxygenates (e.g., alcohols, aldehydes, esters, aldols, ketones, and the like). Hydrocarbon stream 8 could contain up to 10% by weight of oxygenates, but more typically between about 0.5% and about 5% by weight of oxygenates. Hydrocarbon stream 8 also typically contains less than 0. 1% by weight of sulfur-containing and nitrogen-containing compounds. Hydrocarbon stream 8 comprising C5+ hydrocarbon products from a hydrocarbon synthesis reactor may be hydrotreated prior to being fed to fractionator 15. If hydrocarbon stream 8 is hydrotreated prior to being fed to fractionator 15, hydrocarbon stream 8 should contain at least 90% by weight of C5+ linear paraffins, preferably at least 95% by weight of C5+ linear paraffins. Fractionator feedstream 10 may further comprise some other hydrocarbon source such as derived from crude oils, shale oils, and/or tar sands.
Fractionator feedstream 10 is introduced into fractionator 15 to be separated into at least a heavier fraction 30 and a lighter fraction 25. It should be understood that for purposes of this disclosure and unless described otherwise, “heavier” and “lighter” are intended to denote the boiling point range of the fraction. The terms are also intended to mean heavier or lighter relative to each other. For example, the heavier fraction is intended to mean that the boiling range of the heavier fraction is higher than that of the lighter fraction. Like the embodiments described later in association with
The heavier fraction 30 preferably comprises hydrocarbons with a boiling range comprising a 5% boiling point equal to or greater than 640° F. The lighter fraction 25 should comprise hydrocarbons with a boiling range comprising a 5% boiling point equal to or greater than about 350° F. and a 95% boiling point less than, equal to, or up to about 150° F. greater than the initial boiling point of the heavier fraction 30. Although not specified above, it will be understood by one of ordinary skill in this art that the heavier and lighter fractions 30 and 25 may be comprised of a vast number of actual constituents. For example, in one embodiment, the heavier fraction 30 may have a boiling range comprising a 5% boiling point of about 800° F. (representing hydrocarbons with about 30 or more carbon atoms or “C30+ hydrocarbons”). The lighter fraction 25 may have a boiling range comprising a 5% boiling point of about 570° F. and a 95% boiling point of about 800° F. (representing hydrocarbons with about 15 to 30 carbon atoms or “C15-C30 hydrocarbons”); or a boiling range comprising a 5% boiling point of about 640° F. and a 95% boiling point of about 800° F. (representing hydrocarbons with about 20 to 30 carbon atoms or “C20-C30 hydrocarbons”); or a boiling range comprising a 5% boiling point of about 570° F. and a 95% boiling point of about 730° F. (representing hydrocarbons with about 15 to 25 carbon atoms or “C15-C25 hydrocarbons”). In another embodiment, the heavier fraction 30 may have a boiling range comprising a 5% boiling point of about 640° F. (representing hydrocarbons with more than about 20 carbon atoms or “C20+ hydrocarbons”). The lighter fraction 25 may have a boiling range comprising a 5% boiling point of about 570° F. and a 95% boiling point of about 640° F. (representing hydrocarbons with about 15 to 20carbon atoms or “C15-C20 hydrocarbons”); or a boiling range comprising a 5% boiling point of about 380° F. and a 95% boiling point of about 640° F. (representing hydrocarbons with about 10 to 20 carbon atoms or “C10-C20 hydrocarbons”); or a boiling range comprising a 5% boiling point of about 580° F. and a 95% boiling point of about 800° F. (representing hydrocarbons with about 15 to 30 carbon atoms or “C15-C30 hydrocarbons”). All of these more specific embodiments, as well as others, are within the scope of the present invention.
It should be understood by those of ordinary skill in the art that producing a fraction with a definite cutoff, e.g., 30 carbon atoms, is generally very difficult and expensive, although not impossible. The reality, especially in industrial settings, is that a distillation process targeting a cutoff of a specified carbon number or temperature will still contain a small amount of material above or below the target that becomes entrained into the fraction for various reasons. For example, no two fractions of “diesel” are exactly the same, however, it still is designated and sold as “diesel.” It is therefore intended that these explicitly specified fractions may contain a small amount of other material. The amount outside the targeted range will generally be determined by how much time and expense the user is willing to expend and/or by the limitations of the type of fractionation technique or equipment available.
The heavier fraction 30 is fed into hydrocracking unit 40 where some of the components of heavier fraction 30 are hydroconverted under hydrocracking promoting conditions, i.e., the carbon chain length of these hydroconverted components is decreased, to produce a first hydroconverted effluent stream 60. A portion 62 of the first hydroconverted effluent stream 60 may be fed into the second hydroconversion zone 50 (configuration shown). Another portion 64 is fed into fractionator feedstream 10 via recycle line 70 (configuration shown by a dotted line) or fed directly into fractionator 15 (configuration not shown).
A portion 26 of lighter fraction 25 and a portion 62 of first hydroconverted effluent 60 are fed to the second hydroconversion unit 50. While hydrocarbons from lighter fraction 25 and portion 62 of effluent 60 pass through hydroconversion zone 55, some of them are hydroconverted in the presence of hydrogen to form a second hydroconverted effluent stream 65. Second hydroconverted effluent stream 65 and portion 64 of first effluent stream 60 may be fed, either separately (not shown) or combined (as shown in recycle line 70), into fractionator feedstream 10. Alternatively, second effluent stream 65 and portion 64 of first effluent stream 60 may be fed directly into fractionator 15 (configuration not shown). Another portion 28 of lighter fraction 25, not sent to second hydroconversion unit 50, can be blended with fraction 20 to form a diesel product 29 (illustrated in dotted line). Alternatively, substantially all of lighter fraction 25 can be sent to second hydroconversion unit 50, and fraction 20 comprises a full-boiling range diesel product.
Each of the zones 45 and 55 may be contained within a single vessel within their respective hydrocracking units 40 and 50. In addition, it is within the scope of the invention that each hydrocracking unit may comprise separate vessels or physical structures, each housing one or more hydroconversion zones (this configuration is not shown).
The method also includes introducing hydrogen gas into the hydrocracking units 40 and 50, so that the hydrogen gas flows through each of the hydrocracking zones 45 and 55 and over the catalyst present in each of the two hydrocracking zones 45 and 55. The flowing hydrogen should contact the catalyst in hydrocracking zones 45 and 55, so as to favor reaction between hydrocarbons and hydrogen. A portion of the hydrogen feed may be distributed via a distribution zone upstream of each hydroconversion zone 45 and 55 as a separate hydrogen feed to each of the hydroconversion zones 45 and 55 is preferred. There may be some unconsumed hydrogen from portion 62 of hydroconverted effluent 60 fed to second hydrocracking unit 50, which is carried-over to hydroconversion zone 55.
Each hydroconversion zone 45 and 55 may experience an increase in temperature from upstream to downstream as the hydrocarbons pass through each zone and react with hydrogen over the catalyst present in each zone. However, since the catalytic hydrocracking reaction of highly paraffinic stream is not as exothermic as that of aromatic-containing stream, the temperature rise is not so significant in the hydroconversion zones 45 and 55, thus a quench is not required to cool along each of the hydroconversion zone. The temperature at the feedstream entry point of each hydroconversion zone 45 and 55 could be adjusted by careful control of the temperature of their respective feedstreams. The temperature at the feedstream entry point of the second hydroconversion zone 55 may be equal to or greater than about that of the temperature of portion 62 of hydroconverted effluent 60 from first hydroconverted zone 45 and the temperature of portion 26 of the light fraction 25. In other words, neither of portion 26 of the light fraction 25 and portion 62 of the first hydroconverted effluent 60 are used as quenching fluids for the second hydroconversion zone 55. Hence, passing portion 26 of the light fraction 25 and portion 62 of the first hydroconverted effluent 60 to second zone 55 does not quench the hydroconversion reaction taking place in second zone 55.
Preferably, each of hydroconversion zones 45 and 50 comprises at least one hydrocracking catalyst. The hydrocracking catalyst in each zone should comprise a hydrogenation component and a cracking component (typically an acid component). The hydrogenation component may include a metal selected from the group consisting of platinum (Pt), palladium (Pd), nickel (Ni), cobalt (Co), tungsten (W), molybdenum (Mo), and combinations thereof. The hydrogenation component in the hydrocracking catalysts preferably includes Pt, Pd, or combination thereof The cracking component for the hydrocracking catalyst in hydroconversion zone 45 may be an amorphous cracking material and/or a molecular sieve material. A preferred cracking component comprises an amorphous silica-alumina; however Y-type zeolite, SAPO-type molecular sieves (-11; -31; -37; -41), ZSM-type zeolites (-5; -11; -48), and dealuminated zeolites may also be used. The cracking component may support the hydrogenation component; however the catalyst may further comprise a binder, which supports both hydrogenation component and cracking component. If, for example, more hydroisomerization is desirable in hydroconversion zone 55, the hydrocracking catalyst in the hydroconversion zone 55 could comprise a less acidic cracking component.
The first hydroconversion zone 45 may comprise a hydrocracking catalyst bed, and the second hydroconversion zone 55 may comprise a bifunctional catalyst bed and suitable conversion promoting conditions for hydrocracking, hydroisomerization, dewaxing, or combinations thereof. This hydrocracking arrangement should increase the degree of isomerization in the effluent 65 of hydrocracking unit 50.
In addition, the size of hydrocracking unit 50 is expected to be smaller than the size of hydrocracking unit 40. Indeed, the hydrocarbon feed rate to hydrocracking unit 40 should be at least two times greater than the hydrocarbon feed rate to hydrocracking unit 50. Typically, the mass flow rate of light fraction 25 represents less than about 30% of the mass flow rate of heavy fraction 30, preferably less than about 20% of the mass flow rate of heavy fraction 30. Typically, the mass flow rate f portion 64 of first hydroconverted effluent 60, being fed to the second hydrocracking unit 50, represents less than about 60% of the mass flow rate of first hydroconverted effluent 60, preferably less than about 40% of the mass flow rate of first hydroconverted effluent 60.
In some embodiments, when light fraction 25 comprises a heavy diesel product (C15-C20 or C16-C22), portion 26 of light fraction 25 would represent less than 50%, preferably less than 30% of light fraction 25. Alternatively, when light fraction 25 comprises a light wax (C20-C25 or C20-C30), portion 26 of light fraction 25 could represent substantially all of light fraction 25 (i.e., more than 90%).
The conversion promoting conditions in both hydroconversion zones 45 and 55 are preferably at a temperature of about 500° F. to about 750° F. (260-400° C.) and at a pressure of about 500 psig to about 1500 psig (3,550-10,440 kPa), an overall hydrogen consumption of 200-10,000 standard cubic feet per barrel of hydrocarbon feed or scf H2/bbl HC [about 35-1,800 STP m3 H2/m3 HC feed], preferably 200-2,000 scf H2/bbl HC, more preferably 250-500 scf H2/bbl HC using a liquid hourly space velocities based on the hydrocarbon feedstock of about 0.1 to about 10 hr−1, preferably between 0.25 to 5 hr−1. In some embodiments, the average temperature in hydroconversion zone 55 may be lower than that of hydroconversion zone 45, in order to decrease the. severity of the hydrocracking and to favor hydroisomerization instead. In alternate embodiments, the average temperature in hydroconversion zone 55 is about the same as in hydroconversion zone 45 or slightly higher than that of hydroconversion zone 45.
In a preferred embodiment, hydrocracking in zones 45 and 55 takes place over a platinum or palladium catalyst preferably supported on a structured silica-alumina material such as a zeolite (i.e., ZSM-5) or an amorphous silica-alumina at a temperature of about 500° F. to about 750° F. (260-400° C.) and at a pressure of about 500 psig to about 1500 psig (3,550-10,440 kPa), with a hydrogen flow between about 200 standard cubic feet of hydrogen per barrel of hydrocarbon feed and about 1,000 scf H2/bbl HC.
In one preferred embodiment illustrated in
Using the process scheme depicted in
The source of the liquid hydrocarbon stream 106 is not critical for the present invention; however, in a preferred embodiment, the liquid hydrocarbon stream 106 includes hydrocarbon products with at least 5 or more carbon atoms (C5+ hydrocarbons) generated in a hydrocarbon synthesis reactor (not shown). Suitable hydrocarbon synthesis reactors will be discussed in more detail below. A preferred hydrocarbon synthesis reactor comprises a Fischer-Tropsch synthesis reactor.
Liquid hydrocarbon stream 106 may further contain hydrocarbons from other sources, for examples hydrocarbons from crude oil refining, or from processing of shale oils and/or tar sands. For example, Fischer-Tropsch C5+ hydrocarbon products can be combined with one or more light boiling range fractions obtained from a distillation of crude oil and/or with one or more heavy boiling range fractions obtained from vacuum distillation, deoiling and dewaxing processes or from processing of shale oils or tar sands, in order to form liquid hydrocarbon stream 106.
Liquid hydrocarbon stream 106 should comprise primarily C5+ hydrocarbons, some of which are saturated hydrocarbons (i.e., have no unsaturated carbon-carbon bonds) such as alkanes and paraffins, and some of which are unsaturated hydrocarbons (i.e., have unsaturated carbon-carbon bonds) such as alkenes (also called olefins). Liquid hydrocarbon stream 106 should contain at least 70% by weight of C5+ linear paraffins, preferably at least 75% by weight of C5+ linear paraffins; more preferably at least 85% by weight of C5+ linear paraffins. Liquid hydrocarbon stream 106 could contain up to 25% by weight of olefins, preferably up to 15% by weight of olefins; more preferably up to 10% by weight of olefins. Liquid hydrocarbon stream 106 may also comprise some cyclic compounds such as aromatics, but its aromatic content is typically less than 1%. Liquid hydrocarbon stream 106 may also comprise. heteroatomic compounds such as sulfur-containing compounds (e.g., sulfides, thiophenes, benzothiophenes, and the like); nitrogen-containing compounds (e.g., amines, ammonia); and oxygenated hydrocarbons also called oxygenates (e.g., alcohols, aldehydes, esters, ketones, and the like). Liquid hydrocarbon stream 106 could contain up to 10% by weight of oxygenates, preferably up to 5% by weight of oxygenates, but contains typically less than 0.1 percent by weight of sulfur-containing and nitrogen-containing compounds. Liquid hydrocarbon stream 106 may further comprise some solid material. The solid material in liquid hydrocarbon stream 106 could comprise catalyst particles, particularly when at least a portion of the liquid hydrocarbon stream 106 is derived from a hydrocarbon synthesis reactor employing free-flowing or suspended catalyst particles for promoting the synthesis.
Liquid hydrocarbon stream 106 is passed through an optional hydrotreater 105 under hydrotreating promoting conditions so as to convert unsaturated hydrocarbons to saturated hydrocarbons and remove at least a portion of, or substantially all of, heteroatoms (such as sulfur, oxygen, and nitrogen) from heteoatomic compounds which may be present in liquid hydrocarbon stream 106.
It is preferred that the hydrotreating in optional hydrotreater 105 removes substantially all olefins. Olefins are known to cause chemical instability in diesel fuel. This instability frequently manifests itself in the formation of gums, which may form solid deposits in the fuel system and engine. This instability is typically measured by the oxidation stability ASTM D2274 test. Moreover, the hydrotreating conditions should be selected to remove substantially all of the oxygen atoms from oxygenates present in the liquid hydrocarbon stream 106, or to remove only a portion of oxygen atoms from the oxygenates. Oxygenates (particularly alcohols) derived from Fischer-Tropsch synthesis have shown to advantageously increase the lubricity of a diesel product provided by Fischer-Tropsch synthesis.
Hydrotreating in optional hydrotreater 105 may comprise mild hydrotreating conditions. A mild hydrotreatment would have the benefits of converting substantially all unsaturated hydrocarbons to saturated hydrocarbons, removing a substantial portion or all of the heteroatoms from the heteroatomic compounds present in the hydrocarbon stream, and optionally also capturing most of the solid material. The mild hydrotreatment may be performed over a hydrotreating catalyst comprising at least one metal from the group consisting of Ni, Co, Pd, Pt, Mo, W, Cu—Cr combinations, Cu—Zn combinations, and Ru, preferably comprising Ni, Co, Mo, W or combinations thereof, more preferably comprising Ni, over at temperatures above 300° F. (about 150° C.), preferably from 350° F. to about 600° F. (about 170-315° C.), more preferably from 360° F. to about 600° F. (about 180-315° C.), with a hydrogen partial pressure in the outlet of hydrotreater 105 between about 100 psia and about 2,000 psia (about 690-13,800 kPa).
Hydrotreating in optional hydrotreater 105 may comprise “ultra-low severity” hydrotreating conditions. A “ultra-low severity” hydrotreatment is used to remove only a portion of the oxygen atoms from the oxygenates present in the liquid hydrocarbon stream 106, while removing substantially all of the olefins in said hydrocarbon stream 106, such that the hydrotreated stream 108 may comprise some oxygenates, but is substantially free of olefins. The Applicants believe that an “ultra-low severity” hydrotreatment step of the liquid hydrocarbon stream 106, which comprises primarily Fischer-Tropsch C5+ hydrocarbon products may be desirable to increase the lubricity of diesel product obtained therein. Two of the most important factors in determining whether a hydrotreating unit employs “ultra-low severity” conditions are catalyst composition and temperature. “Ultra-low severity” hydrotreating can take place with a hydrotreating catalyst comprising at least one of the following metals: a metal from Group 6 (new IUPAC notation), such as molybdenum (Mo) and tungsten (W), or a metal from Groups 8, 9, and 10 of the Periodic Table (new Notation as found in, for example, the CRC Handbook of Chemistry and Physics, 82nd Edition, 2001-2002, and used throughout this specification), such as nickel (Ni), palladium (Pd), platinum (Pt), ruthenium (Ru), iron (Fe), and/or cobalt (Co), or combinations thereof. Highly active catalysts, such as those comprising Ni, Pd, Pt, W, Mo, Ru or combinations thereof, must be operated at relatively low temperatures (to maintain ultra-low severity hydrotreating conditions) between about 180° F. and about 350° F. (about 80-180° C.), more preferably between about 180° F. and about 320° F. (about 80-160° C.), still more preferably between about 180° F. to about 300° F. (about 80-150° C.). By way of example only, a highly active hydrotreating catalyst, such as a nickel-based hydrotreating catalyst, begins to convert a substantial amount of oxygenates to paraffins at about 250° F. In contrast, less active hydrotreating catalysts, such as those comprising Fe or Co, do not begin to convert oxygenates until a temperature of about 350° F. is reached. For these less-active catalysts with lower hydrotreating activity (e.g., with Co or Fe), a preferred temperature range for “ultra-low severity” hydrotreating is between about 350° F. and about 570° F. (about 180-300° C.). Additionally, there are other parameters such as for example, pressure and liquid hourly space velocity, which may be varied by one person of ordinary skill in the art to effect the desired “ultra-low severity” hydrotreating. Preferably the hydrogen partial pressure is between about 100 psia and about 1,000 psia (690-6900 kPa), more preferably between about 300 psia and about 500 psia (2060-3450 kPa). The liquid hourly space velocity is preferably between 1 and 10 hr−1, more preferably between 0.5 and 6 hr−1, still more preferably between about 1 and about 5 hr−1. It should be understood that the hydrotreating catalyst for “ultra-low severity” hydrotreatment can be with or without support, although is preferably supported, and can comprise promoters to improve catalyst performance and/or support structural integrity.
Advantageously, regardless of hydrotreatment conditions used for the hydrotreating of liquid hydrocarbon stream 106, hydrotreating in hydrotreater 105 can also remove or reduce solid material that may be present in the liquid hydrocarbon stream 106. It is expected that, if the hydrocracking feedstreams are not hydrotreated prior to entering a hydroconversion zone in hydrocracking unit 140, the presence of heteroatomic compounds and of solid material in these hydrocracking feedstreams could reduce the performance of the hydrocracking unit. Indeed, sulfur is a known poison of hydrocracking catalysts. Solid material depositing on top of and/or embedding in a hydroconversion zone comprising a fixed catalytic bed increases the pressure drop across that catalytic bed. Even though a hydrotreating zone comprising a catalytic bed would suffer similar disadvantages from heteroatomic compounds and solid material, a hydrotreating catalyst (such as comprising Ni and/or Co) is typically less sensitive to poisoning from heteoatomic compounds than a hydrocracking catalyst (comprising Pt and/or Pd). Moreover, typical hydrotreating catalysts use cheaper hydrogenation metals (Co and/or Ni) and hence are less costly than hydrocracking catalysts comprising at least one expensive precious metal (such as Pt or Pd). Therefore, using larger catalytic bed volume and/or replacing more frequently the hydrogenation catalyst are more cost-effective options for a hydrotreating unit than for a hydrocracking unit. Therefore the removal of heteroatoms from heteroatomic compounds as well as solid material in a hydrotreating zone prior to hydrocracking may result in a more-cost effective hydroprocessing scheme 100. Yet, the hydrotreating step of the feedstream for the hydrocracking/hydroisomerization zones may not be performed prior to the hydrocracking step. A hydrotreating step could be omitted. Or a hydrotreating step could be performed after the hydrocracking step, and optionally, at least a portion of the hydrocracked product stream could be hydrotreated prior to being fed to the fractionator.. However, not hydrotreating prior to hydrocracking would result in at least one of following shortfalls: a) in shortening the operating lifetime of the expensive hydrocracking catalyst(s) present in the various hydrocracking zones; b) in decreasing the hydrocracking performance; or c) in increasing the hydrogen need of at least the first hydrocracking zone. Thus, the benefits would have to be measured against the possible shortfalls on a case-by-case basis. Removing most of the solid material and some of heteroatoms which may be present in the hydrocarbon stream 106 should benefit the downstream hydrocracking step performed in unit 140, especially by minimizing the possible negative impact from said heteroatoms and/or solid material on the hydrocracking performance and hydrocracking catalyst longevity.
Hydrotreating of liquid hydrocarbon stream 106 in hydrotreater 105 results in obtaining a hydrotreated hydrocarbon stream 108. Hydrotreated hydrocarbon stream 108 should comprise a substantial portion of saturated hydrocarbons. If hydrocarbon stream 108 is hydrotreated prior to being fed to fractionator 115, hydrocarbon stream 108 should contain at least 90% by weight of C5+ linear paraffins, preferably at least 95% by weight of C5+ linear paraffins. Hydrotreated hydrocarbon stream 108 should be substantially free of solid material (i.e., less than 50 ppm solid). In addition, hydrotreated hydrocarbon stream 108 may comprise some oxygenates (preferably not more than about 2%)if the hydrotreatment step employs “ultra-low severity” conditions. Alternatively, hydrotreated hydrocarbon stream 108 could be substantially free of oxygenates, substantially free of sulfur-containing compounds, substantially free of nitrogen-containing compounds, i.e., wherein “substantially free” means less than 50 ppm of each heteroatom selected from O, S or N. Finally, hydrotreated hydrocarbon stream 108 can also include water.
Fractionator feedstream 110 comprises hydrotreated hydrocarbon stream 108 and optionally hydroconverted effluent stream 155 (as shown in
Fractionator feedstream 110 is fed to fractionator 115 in order for its components to be separated based on their boiling point, so as to generate various hydrocarbon fractions of different boiling ranges. The type of fractionator is not critical to the present invention and can comprise any fractionator technology and/or methods known in the art. One of ordinary skill in the art will readily understand the types of fractionators useful for separating liquid hydrocarbons of this nature into the various fractions described herein. For ease of discussion, and without any intention to be so limited, fractionator 115 can comprise a standard atmospheric fractional distillation apparatus. Accordingly, fractionator feedstream 110 is separated into at least two fractions. For example, fractionator feedstream 110 may be separated into a heavier fraction 130 and a lighter fraction 125, such that the heavier fraction 130 and portions (or all) of the lighter fraction 125 serve as feedstreams to hydrocracking unit 140.
The heavier fraction 130 preferably comprises hydrocarbons with a boiling range comprising a 5% boiling point equal to or greater than about 640° F. The lighter fraction 125 should comprise hydrocarbons with a boiling range comprising a 5% boiling point equal to or greater than about 350° F. and a 95% boiling point less than, equal to, or up to 150° F. greater than the 5% boiling point of the heavier fraction 130. Although not specified above, it will be understood by one of ordinary skill in this art that the heavier and lighter fractions 130 and 125 may be comprised of a vast number of actual constituents. For example, in one embodiment, the heavier fraction 130 may have a boiling range comprising a 5% boiling point of about 800° F. (representing hydrocarbons with about 30 or more carbon atoms or “C30+ hydrocarbons”). The lighter fraction 125 may have a boiling range comprising a 5% boiling point of about 570° F. and a 95% boiling point of about 800° F. (representing hydrocarbons with about 15 to 30 carbon atoms or “C15-C30 hydrocarbons”); or a boiling range comprising a 5% boiling point of about 640° F. and a 95% boiling point of about 800° F. (representing hydrocarbons with about 20 to 30 carbon atoms or “C20-C30 hydrocarbons”); or a boiling range comprising a 5% boiling point of about 570° F. and a 95% boiling point of about 730° F. (representing hydrocarbons with about 15 to 25 carbon atoms or “C15-C25 hydrocarbons”). In another embodiment, the heavier fraction 130 may have a boiling range comprising a 5% boiling point of about 640° F. (representing hydrocarbons with more than about 20 carbon atoms or “C20+ hydrocarbons”). The lighter fraction 125 may have a boiling range comprising a 5% boiling point of about 570° F. and a 95% boiling point of about 640° F. (representing hydrocarbons with about 15 to 20 carbon atoms or “C15-C20 hydrocarbons”); or a boiling range comprising a 5% boiling point of about 380° F. and a 95% boiling point of about 640° F. (representing hydrocarbons with about 10 to 20 carbon atoms or “C10-C20 hydrocarbons”); or a boiling range comprising a 5% boiling point of about 580° F. and a 95% boiling point of about 800° F. (representing hydrocarbons with about 15 to 30 carbon atoms or “C15-C30 hydrocarbons”). All of these more specific embodiments, as well as others, are within the scope of the present invention.
The fractionation of optionally-hydrotreated fractionator feedstream 110 preferably results in generating more than two fractions, e.g., a middle distillate fraction 120, an intermediate distillate fraction 125, a waxy fraction 130, a naphtha fraction 135, and a gas exhaust 138, wherein the intermediate fraction 125 has a 5% boiling point greater than that of middle distillate fraction 120, and a 5% boiling point lower than that of waxy fraction 130. Each of fractions 120 and 135 may be one or more separate streams and is merely representative in
In one preferred embodiment, fractionator 115 comprises an atmospheric distillation column. In this embodiment, as a non-limiting example, middle distillate fraction 120 preferably comprises a light diesel (representing hydrocarbons with about 9 up to 15 carbon atoms, such as comprising C9-C12 or C9-C15 or C10-C15 hydrocarbons); intermediate fraction 125 preferably comprises a heavy diesel (representing hydrocarbons with about 12 up to 22 carbon atoms, such as comprising C12- C20 or C12-C22 or C15-C22 hydrocarbons), wherein fraction 125 has a higher boiling range than fraction 120; waxy fraction 130 comprises hydrocarbon wax (i.e., C20+ hydrocarbons); naphtha fraction 135 comprises a naphtha (such as comprising C5-C10or C5-C9 hydrocarbons) and some water; and gas exhaust 138 comprises hydrocarbons with 4 or less carbon atoms (C5− hydrocarbons), and may include small amounts of water.
In one other embodiment, separating by fractionation hydrocarbon stream 108 comprises generating at least
One alternate embodiment of the method with employs two fractionation units is illustrated in
Referring again to
Feedstock to the first hydroconversion zone 145 comprises waxy fraction 130 from fractionator 115. In one preferred embodiment of
In a standard hydrocracking configuration, hydrocracking takes place throughout a hydrocracking zone. Some of the C5+ hydrocarbons are cracked to smaller hydrocarbons, wherein a portion of said smaller hydrocarbons are within the boiling point range of desirable products (such as naphtha, middle distillates and/or diesel). However, some of the smaller hydrocarbons formed during hydrocracking can undergo secondary cracking, as they pass through the remainder of the hydroconversion zone under conversion promoting conditions. Their long residence time in the hydroconversion zone can result in “over-cracking”, and hence to the production of very light hydrocarbons with less than 5 carbon atoms, such as those comprised in exhaust 138 and/or sometimes found in naphtha fraction 135, thereby decreasing the yield of desirable middle distillate fraction 120. The idea of the present invention is to reduce secondary cracking of hydrocarbons within the boiling point range of desirable products, and to increase isomerization of hydrocarbons within the boiling point range of desirable products, and thus to increase the overall degree of branching of hydrocarbons in the desirable products, and possibly to further increase yield of the middle distillates, especially of diesel. It is believed that reducing the residence time of the lighter components (such as with a boiling point less than about 650° F.) by partial withdrawal and/or intentionally increasing the pool of lighter components by adding a light hydrocarbon stream in the hydrocracking zones will achieve the desired results. The boiling points of branched paraffins tend to be lower than that of their corresponding normal paraffin; for example, an isoparaffin with 21 carbon atoms (i-C21) has a lower boiling point than the normal C21 paraffin. Hence, some isomerized heavy hydrocarbons, for example the branched hydrocarbons comprising 21 to 25 carbon atoms will boil in the diesel boiling range. As a non-limiting example, if heavy wax fraction 130 comprises C30+ hydrocarbons and is fed to the first hydroconversion zone 145, and if intermediate fraction 125 comprises a light wax with primarily C20-C30 hydrocarbons, and a portion 126 of intermediate fraction is fed to the second hydroconversion zone 150 placed downstream of the first zone 145, a 10-15% increase in production of hydrocarbons boiling in the diesel range can be accomplished may be expected compared to a case where both waxy fraction 130 and portion 126 of intermediate fraction are fed to the first hydroconversion zone 145.
In addition, the introduction of additional lighter hydrocarbons along the hydrocracking zone(s) favors hydroisomerization, which can increase the iso/normal paraffin ratio of the fraction 120 and/or product 129.
Substantially all of fraction 130 is fed to first hydroconversion zone 145. A purge 136 (shown in dotted line) taken from fraction 130 may be performed in order to remove some material resilient to the hydroprocessing. Purge 136 typically represents not more than about 2 percent by volume of fraction 130, preferably less than about 1 percent by volume of fraction 130.
The hydrocarbons from waxy fraction 130 pass through the first hydroconversion zone 145 under hydrocracking promoting conditions, such that some of the hydrocarbons in waxy fraction 130 are hydrocracked, i.e., the hydrocarbons are split into two smaller hydrocarbon molecules in the presence of hydrogen and a catalyst, so the carbon chain length of at least a portion of the hydrocarbons passing through zone 145 is decreased. A first hydroconverted effluent comprising hydrocracked products and unconverted hydrocarbons exit first hydroconversion zone 145 (not shown). For example, if waxy fraction 130 contains hydrocarbons with 20 or more carbon atoms, first hydroconverted effluent may comprise hydrocarbons with one carbon atom to 20 or more carbon atoms.
The method further comprises feeding to the second hydroconversion zone 150 at least a portion of the first hydroconverted effluent exiting the first hydroconversion zone 145. Preferably the hydrocarbons in the first hydroconverted effluent passing from the first (upstream) hydroconversion zone 145 to the second (downstream) hydroconversion zone 150 cascades down (without inter-zone separation) to an inter-zone distribution (not shown). Optionally, a portion 160 of first hydroconverted effluent (shown in dotted line) is not passed down to the downstream zone 150. Instead, portion 160 of first hydroconverted effluent may exit hydrocracking unit 140 and can be sent to fractionator 115 either directly (not shown) or by combining with hydrocracker effluent 155 (as illustrated). At least a portion 126 of lighter fraction 125 is also fed to second hydroconversion zone 150. A preferred embodiment comprises feeding to the second hydroconversion zone 150 substantially all of the first hydroconverted effluent exiting first hydroconversion zone 145 and at least a portion 126 of the intermediate fraction 125. Portion 126 may comprise up to 50% of fraction 125, especially when fraction 125 comprises a diesel cut, such as a heavy diesel. In other embodiments, portion 126 may comprise up to 100% of fraction 125, especially when fraction 125 comprises a wax cut, such as a light wax cut.
The method also includes introducing hydrogen gas into the hydrocracking unit 140, so that the hydrogen gas flows through the hydrocracking zones 145 and 150 and over the catalyst present in each of the two hydrocracking zones 145 and 150. The flowing hydrogen should contact the catalyst in hydrocracking zones 145 and 150, so as to favor reaction between hydrocarbons and hydrogen. The hydrogen feed may be sent only to the first hydroconversion zone 145; alternatively, some portions of the hydrogen feed may be distributed via a distribution zone upstream of each hydroconversion zone 145 and 150. For example, hydrogen could be fed in the inter-zone distribution (not shown) wherein the hydrocarbon feedstock to the second hydroconversion zone 150 is distributed.
Because the hydrocracking reaction of hydrocarbons with hydrogen is typically exothermic, the temperature of the first hydrocracked effluent first hydroconversion zone 145 may be slightly higher than the temperature desired for optimum performance of the second hydroconversion zone 150. Therefore, the portion of hydrogen feed or/and the portion 126 of intermediate fraction 125 may have a temperature sufficiently low enough while entering the second hydroconversion zone 150, so that the combined feedstream comprising hydrogen and the hydrocarbon feedstock (portion 126 and first hydrocracked effluent from first zone 145) to the second hydroconversion zone 150 has an appropriate temperature effective for the conversion of said combined feedstream in the second hydroconversion zone 150. The temperature rise in the hydrocracking zones 145 and 150 is not significant so as to require a quench to cool along each of the hydrocracking zone. The temperature of the respective feedstream (hydrogen and hydrocarbon feeds) at the entrance of each hydroconversion zone 140 and 145 is not necessarily selected so as to quench the temperature for controlling the exotherm, but more importantly, is selected in order to adjust the temperature of the hydroconversion zone within a reasonable temperature range. Therefore the method may further include admixing the first hydrocracked effluent exiting first hydroconversion zone 145 with a feedstream, as long as the feedstream has a temperature low enough so as to achieve a temperature of the admixture (comprising first hydrocracked effluent and the feedstream) within acceptable temperature conditions for downstream hydroconversion zone 150. The feedstream preferably comprises the portion 126 of the intermediate stream 125, at least a portion of the hydrogen feed, or mixture thereof.
The first hydrocracked effluent from first hydroconversion zone 145 and portion 126 of intermediate fraction 125 pass through second hydroconversion zone 150 under conditions suitable for hydrocarbon components to react with hydrogen to favor hydrocracking, hydroisomerization, dewaxing or combinations thereof, so as to form smaller and/or branched hydrocarbons. A hydrocracked effluent stream 155 exits hydrocracking unit 140. A portion 128 of intermediate fraction 125, not sent to hydrocracking unit 140, can be blended with middle distillate stream 120 to form a diesel product 129. Alternatively, the totality of intermediate fraction 125 can be sent to second hydroconversion zone 150 and middle distillate stream 120 comprises a diesel product.
Hydrocracking unit 140 may include using a bifunctional catalyst in at least one hydrocracking zone, preferably in one downstream hydroconversion zone (the second if there are only two zones). The first hydroconversion zone 145 may comprises a hydrocracking catalyst bed, and the second downstream hydroconversion zone 150 may comprise a bifunctional hydrocracking catalyst bed suitable for hydrocracking, hydroisomerization, dewaxing, or combinations thereof. This catalyst bed arrangement may further improve the degree of isomerization in the effluent 155 of hydrocracking unit 140.
Preferably, the hydrocracking in hydrocracking zones 145 and 150 takes place over at least one hydrocracking catalyst comprising a hydrogenation component and a cracking component (typically an acid component). The hydrogenation component may include a metal selected from the group consisting of platinum (Pt), palladium (Pd), nickel (Ni), cobalt (Co), tungsten (W), molybdenum (Mo), and combinations thereof. The hydrogenation component in the hydrocracking catalysts preferably includes Pt, Pd, or combination thereof. The cracking component for the hydrocracking catalyst in the first hydroconversion zone may be an amorphous cracking material and/or a molecular sieve material. A preferred cracking component comprises an amorphous silica-alumina; however Y-type zeolite, SAPO-type molecular sieves (-11; -31; -37; -41), ZSM-type zeolites (-5; -11; -48), and dealuminated zeolites may also be used. The cracking component may support the hydrogenation component; however the catalyst may further comprise a binder, which supports both hydrogenation component and cracking component. If, for example, more hydroisomerization is desirable in the second hydroconversion zone 150, the hydrocracking catalyst in the downstream hydroconversion zone 150 could comprise a less acidic cracking component. Thus, it is envisioned that the hydrocracking catalysts in both hydroconversion zones could comprise the same hydrogenation component (such as Pt, Pd or both), but could comprise different cracking components with various acid strengths. Yet it is also noted that a catalyst gradient may comprise the two hydroconversion zones, by varying gradually the acid strength of the catalyst from high acidity at the entry point of waxy stream 130 to low acidity at the exit point of hydroconverted effluent stream 155, so as to gradually increase the hydroisomerization along hydrocracking unit 140.
Isomerization can serve to enhance certain properties of hydrocarbon mixtures. Increasing the degree of branching of hydrocarbons in a diesel fuel, which is primarily comprised on Fischer-Tropsch hydrocarbon products, can be favorable to improving its cold-flow properties, such as pour point, cloud point, cold filter plugging point and the like. The cloud point (measured by ATSM D2500) is the highest temperature used to characterize cold flow properties and the pour point (measured by ASTM D97) is the lowest. The cold filter plugging point (CFPP defined by ASTM D6371-99) temperatures will usually be in between the pour and cloud points. Thus, the pour point represents the lowest temperature (in ° F. or ° C.) at which a liquid remains pourable (meaning it still behaves as a fluid). The pour point is the lowest temperature at which a fuel can be handled without excessive amounts of wax crystals forming, and so preventing flow. If a diesel fuel is held at a temperature below its pour point, wax can begin to separate out which most likely results in blocking fuel-injection filters. In oils, the pour point is generally increased by increasing the linear paraffin content. However, isoparaffins (or branched paraffins) are known to reduce the pour point of highly paraffinic hydrocarbons mixture. Hence, adding branched hydrocarbons or converted linear hydrocarbons to branched hydrocarbons by hydroisomerization to a fuel or oil would typically improve at least one cold-flow property of this fuel or oil.
Dewaxing, which also comprises isomerization, has also been shown to be effective in decreasing the pour point of middle distillates. The catalytic dewaxing typically employs a dual-function catalytic metal/molecular sieve catalyst to hydroisomerize and selectively crack waxy hydrocarbons and generate low pour point. distillates comprising isomerized paraffins. The isomerized paraffins and selectively cracked paraffins remain in the distillate range and therefore the distillate yield in catalytic dewaxing is usually quite high (i.e., greater than 70%). Therefore, in one embodiment of the present invention, a dewaxing catalyst comprising both cracking and hydroisomerization functions may be used in one of the hydrocracking zones. Since isomerization of middle distillate range hydrocarbon distillate is particularly desirable to increase the pour point of said distillate without affecting the distillate yield, the use of catalytic dewaxing is particularly desirable in a downstream hydroconversion zone such as second hydroconversion zone 150.
Accordingly, hydrocracking unit 140 can comprise a bifunctional hydrocracking/hydroisomerizing catalyst. Any suitable bifunctional catalyst will suffice. Typically bifunctional catalysts comprise at least one metal from Groups 8, 9, 10 of the Periodic Table (new IUPAC Notation) and at least one support selected from the group consisting of alumina, titania, zirconia, magnesia, silica, thoria, silica-alumina, shape-selective material such as molecular sieves, zeolites and the like, and combinations thereof. Preferably, the bifunctional catalyst comprises nickel, cobalt, platinum, or palladium. When the bifunctional catalyst comprises cobalt or nickel, preferably it also comprises a metal from Group 6 of the Periodic Table (new IUPAC Notation), such as molybdenum or tungsten. The support should be acidic and preferably comprises a zeolitic material, an amorphous silica-alumina, or combinations thereof. When the feedstreams to hydrocracking unit 140 are primarily derived from a hydrocarbon synthesis such as a Fischer-Tropsch synthesis, a more preferred bifunctional catalyst comprises at least one metal selected from the group consisting of palladium and platinum.
The composition of the hydrocracking catalyst may be the same throughout the entire hydrocracking unit 140, including both hydroconversion zones 145 and 150. The compositions may also be the same if the hydroconversion zones 145 and 150 are housed within separate hydrocracking units. It should be understood that the active metal contents of the catalysts may differ, but the compositional makeup may remain the same from zone to zone. It should also be understood that a hydrocracking/hydroisomerization activity gradient may exist within the hydrocracking unit 140 or within either or both specific hydroconversion zones 145 and 150. The activity gradient may be achieved by varying the acidity of the catalyst along the hydrocracking unit 140 or at least one of the hydroconversion zones.
The conversion promoting conditions in both hydroconversion zones 145 and 150 are preferably at a temperature of about 500° F. to about 750° F. (260-400° C.) and at a pressure of about 500 psig to about 1500 psig (3,550-10,440 kPa), an overall hydrogen consumption of 200-10,000 standard cubic feet per barrel of hydrocarbon feed (scf H2/bbl HC) or about 35-1,800 STP m3 H2/m3 HC feed, preferably 200-2,000 scf H2/bbl HC, preferably 200-1,000 scf H2/bbl HC, using a liquid hourly space velocities based on the hydrocarbon feedstock of about 0.1 to about 10 hr−1, preferably between 0.25 to 5 hr−1. In some embodiments, the average temperature in hydroconversion zone 150 is lower than that of hydroconversion zone 145, in order to decrease the severity of the hydrocracking and to favor instead hydroisomerization.
In a preferred embodiment, hydrocracking in zones 145 and 150 takes place over a platinum or palladium catalyst preferably supported on a structured silica-alumina material such as a zeolite (i.e., ZSM-5) or an amorphous silica-alumina at a temperature of about 500° F. to about 750° F. (260-400° C.) and at a pressure of about 500 psig to about 1500 psig (3,550-10,440 kPa), with a hydrogen flow between 2,000 and 10,000 standard cubic feet per barrel of hydrocarbon feed.
At least a portion of hydroconverted effluent stream 155 may be fed into either fractionator feedstream 110 (as shown) or directly into fractionator 115 (configuration not shown). When substantially all of hydroconverted effluent stream 155 is sent to fractionator 115, the heavy components (those with a boiling point greater than 700° F.) are recycled close to extinction. The complete recycling of heavy components from hydroconverted effluent stream 155 to hydrocracking unit 140 thereby increases the amount of desirable hydrocarbons in the middle distillate range, thus increases the yield of desirable products represented in
An alternate embodiment of the method for producing liquid hydrocarbon products comprising more branched paraffins as illustrated in
Hydrocarbon stream 208 may be obtained by passing a liquid hydrocarbon feedstream 206 through an optional hydrotreater 205 in the same manner as described for
Fractionator feedstream 210 should comprise substantially all of hydrocarbon stream 108. Fractionator feedstream 210 may further comprise hydroconverted effluent stream 255 (as shown), and/or any other hydrocarbon stream (not shown) such as derived from crude oils, shale oils, and/or tar sands, which preferably has been previously hydrotreated.
In general terms, the hydrocarbons in fractionator feed 210 may be separated by fractionator 215 into a heavier fraction 230 and a lighter fraction 225. Fraction 220 may be one or more streams and is merely representative in
Fractionator feedstream 210 is fed to atmospheric distillation column 260 to generate middle distillate fraction 220, naphtha fraction 235, gas exhaust 238, and wax fraction 270, wherein wax fraction 270 has a 5% boiling point greater than that of middle distillate fraction 220 and further wherein middle distillate fraction 220 has a 5% boiling point greater than that of naphtha fraction 235.
Wax fraction 270 from atmospheric distillation column 260 is fed to distillation unit 265 so as to form a light wax fraction 225 and a heavy wax fraction 230, wherein light wax fraction 225 has a lower boiling range than heavy wax fraction 230. As a not-limiting example of such embodiment illustrated in
Heavy wax fraction 230 from distillation unit 265 is fed to first hydroconversion zone 245, whereas light wax fraction 225 is fed to second hydroconversion zone 250. In one preferred embodiment of
Operating conditions and catalyst selection for hydrocracking unit 240 are preferably the same as those described for hydrocracking unit 40 of
In general terms, fractionator feedstream 310 preferably comprise a C5+ hydrocarbon product from a hydrocarbon synthesis reactor (not shown), which optionally has been hydrotreated, as is described in
The type of fractionator for units 315 and 375 is not critical to the present invention and can comprise any of the fractionator technology and/or methods known in the art. One of ordinary skill in the art will readily understand the types of fractionators useful for separating liquid hydrocarbons of this nature into the various fractions described herein. For ease of discussion, and without any intention to be so limited, fractionators 315 and 375 can comprise a standard atmospheric fractional distillation apparatus.
Accordingly, fractionator feedstream 310 is fed to fractionator 315 in order for its components to be separated based on their boiling point, so as to generate various hydrocarbon fractions 320, 325, 330, 335, and exhaust 338 of different boiling ranges. As an example, feedstream 310 may be separated into a gas exhaust 338 (comprising C1-C5 hydrocarbons), a naphtha fraction 335 (comprising about C5-C9 hydrocarbons), a light diesel fraction 320 (comprising at least about C9-C15 hydrocarbons), an intermediate stream 325 (comprising about C15-C22 or about C15-C30 hydrocarbons), and a wax fraction 330 (comprising about C20+ hydrocarbons).
Fraction 320 could comprise at least a portion of ‘straight-run’ diesel obtained from a Fischer-Tropsch synthesis, so called ‘straight-run’ because the carbon backbone of its components is quite similar to the original components from the hydrocarbon synthesis in the diesel boiling range. Fraction 325 may also comprise a fraction of ‘straight-run’ diesel. In one embodiment of
Wax fraction 330 is fed to first hydroconversion zone 345, where some of the hydrocarbons are cracked to smaller hydrocarbons to generate a first hydroconverted effluent exiting first hydroconversion zone 345 (not shown). First hydroconverted effluent and at least a portion 326 of intermediate stream 325 are then passed through second hydroconversion zone 350 to generate a second hydroconverted effluent stream 355 exiting hydrocracking unit 340.
Hydroconverted effluent stream 355 is sent to second fractionator 375 in order for its components to be separated based on their boiling point, so as to generate various hydrocarbon fractions 380, 385, 390, and exhaust 395 of different boiling ranges. As an example, hydroconverted effluent stream 355 is separated into a second gas exhaust 395 (comprising about C1-C5 hydrocarbons), a second naphtha fraction 390 (comprising about C5-C9 hydrocarbons), a second diesel fraction 385 (comprising about C9-C22 hydrocarbons), and a second wax fraction 380 (comprising C20+ hydrocarbons). Second wax fraction 380 is preferably sent to hydrocracking unit 340, particularly to first hydroconversion zone 345, for further hydroconversion in hydrocracking unit 340.
Streams 390 and 335 may be combined to form a naphtha range product 398. Streams 385, 320 and optionally a portion 328 of fraction 325 may be combined to form a diesel product 397 with acceptable cold-flow property (such as pour point and/or cold filter plugging point).
The hydrocracking conditions in both hydroconversion zones 345 and 350 are similar to those generally described in
A particularly preferred embodiment of this hydroprocessing scheme 300 is the use of a bifunctional catalyst in the second hydroconversion zone 350, so as to favor hydroisomerization of hydrocarbons in hydroconversion zone 350. The enhanced isomerization, which takes place in downstream hydroconversion zone 350, should result in obtaining an effluent 355 of hydrocracking unit 340 with a large proportion of branched hydrocarbons, particularly in the diesel and naphtha boiling ranges. Preferably the second (downstream) hydroconversion zone 350 in hydrocracking unit 340 comprises some hydroisomerization promoting conditions, such that the ratio of branched/linear paraffins is greatly enhanced in hydroconverted effluent stream 355. To favor hydroisomerization in downstream hydroconversion zone 350, hydroconversion zone 350 may comprise a dewaxing catalyst with some hydrocracking function and a dominant hydroisomerization function. The dewaxing catalyst in downstream hydroconversion zone 350 preferably includes a shape-selective zeolite, such as any of ZSM-5, ZSM-11, ZSM-12, ZSM-22, ZSM-23, ZSM-35, and ZSM-38 zeolites. The dewaxing catalyst may comprise a hydrogenation component such as a metal from Groups 8-12 of the Periodic Table (new IUPAC Notation), such as palladium, platinum, rhenium, rhodium, nickel, cobalt, molybdenum, tungsten, copper, or combinations thereof. Combinations of one or more noble metals together with non-noble metals are of interest. Base metal hydrogenation components may also be used in a dewaxing catalyst, especially nickel, cobalt, molybdenum, tungsten, copper or sometimes zinc. Suitable combinations of metals in a dewaxing catalyst would include platinum-tungsten, platinum-nickel, platinum-nickel-tungsten, cobalt-nickel, cobalt-molybdenum, nickel-tungsten, cobalt-nickel-tungsten, or cobalt-nickel-titanium.
The use of a bifunctional catalyst in the second hydroconversion zone 350 results in obtaining hydroconverted effluent stream 355 with a significant content in branched hydrocarbons. Highly-branched hydroconverted effluent stream 355 can be separated in fractionator 375 to generate wax fraction 380, diesel fraction 385, and naphtha fraction 390, all with a high degree of branching.
In one embodiment of
Another embodiment of the present invention employs a hydrocracking unit having a plurality of hydroconversion zones operated in series and multiple hydrocarbon streams with different boiling ranges, which are fed into the multiple hydroconversion zones successively.
Optionally-hydrotreated hydrocarbon stream 508 may be obtained by passing hydrocarbon product stream 506 through hydrotreater 505 in the same manner as described for
Fractionator feedstream 510 should comprise optionally-hydrotreated hydrocarbon stream 508. Fractionator feedstream 510 may further comprise hydroconverted effluent stream 590 (as shown), and/or other hydrocarbon stream(s) (not shown) such as derived from crude oils, shale oils, and/or tar sands, which preferably has been previously hydrotreated.
Like in
Accordingly, fractionator 515 separates fractionator feedstream 510 into various fraction 518, 520, 525, and gas exhaust 528. Fractions 520 and 525 may be representative in
Heavy stream 518 from the first fractionator 515 is fed to fractionator 535 to be separated into various fractions 530, 540, 545, 550, and 555 of different boiling ranges with decreasing 95% boiling points. It should be noted that fractionator 535 may comprise one distillation unit or a multitude of distillation units, preferably fractionator 535 comprises a vacuum distillation in order to achieve the desired number of fractions.
In general, fractions 530, 540, 545, 550, and 555 are fed into hydrocracking unit 560 successively in terms of highest boiling point ranges to lowest. For example, fraction 530 may introduce a C60+ stream, fraction 540 a C50-C60 stream, fraction 545 a C40-C50 stream, fraction 550 a C30-C40 stream and fraction 555 a C20-C30 stream. Fractions 530, 540, 545, 550, and 555 may be fed to separate hydroconversion zones 565, 570, 575, 580 and 585, respectively. At least a portion of the hydrocarbons passing through each hydroconversion zone may be successively passed to the next subsequent zone, i.e., a portion of the hydrocarbons preferably pass from hydroconversion zone 565 into hydroconversion zone 570 along with fraction 540. The hydroconversion zones 565, 570, 575, 580 and 585 may or may not be contained within a single hydrocracking vessel, provided that the flow is consistent with the scope of the present invention. In other words, hydrocracking unit 560 may comprise multiple units (not shown) each containing one or more of the hydroconversion zones. Hydrogen feed is supplied to hydrocracking unit 560 in a similar fashion as described in
At least a portion of the hydrocracking unit effluent stream 590 flowing out of the hydroconversion zone 560 may be fed directly (configuration not shown) to fractionator 515 or via fractionator feedstream 510 (as shown).
In addition, any portion of hydrocarbons removed from hydrocracking unit 560, ie., any portion of hydroconverted effluent from a hydroconversion zone which is not passed to a subsequent hydroconversion zone, may also be fed directly to fractionator 515 or via fractionator feedstream 510, or directed to other uses as desired (configuration not shown).
These general ideas are also incorporated into embodiments comprising larger processes and systems for converting hydrocarbon gases to liquids. For example, one embodiment generally comprises a method for converting synthesis gas (typically produced from a syngas type reactor) into liquid hydrocarbons via a Fischer-Tropsch type synthesis. The liquid hydrocarbons may then be hydroprocessed using the various embodiments disclosed herein into final products, e.g., diesel and naphtha.
Gas stream 620 comprising a H2/CO mixture is fed into a hydrocarbon synthesis reactor 625 (typically comprising a Fischer-Tropsch synthesis) to produce a wide range of hydrocarbons 630 (from gas to wax; i.e., from C1 to C100 or more hydrocarbons). The hydrocarbons 630 may then be hydroprocessed in hydroprocessing 635 to produce the desired liquid hydrocarbon products 640. The hydroprocessing 635 configuration may be any of the general ideas and embodiments disclosed herein.
It will be readily understood by one of ordinary skill in the art that various other processes or steps are necessary for carrying out a gas to liquids process. For example, the temperature or the water content of the gas stream 620 leaving the synthesis gas generation unit 615 will be too high to directly enter the hydrocarbon synthesis reactor 625, thereby requiring cooling of gas stream 620 and/or removing the water from gas stream 620. Another example is that the pressure of gas stream 620 leaving the synthesis gas generation 615 may be too low to directly be fed to hydrocarbon synthesis reactor 625, thereby requiring compression of gas stream 620. These additional intermediate processes or units, such as compressors, heat exchangers and water separation vessels are assumed.
Syngas and Fischer-Tropsch reactors and reactions, including catalysts and process designs, are expressly mentioned herein only as a preferred embodiments and for the sake of clarity and illustration. One skilled in the art will readily understand the applicability of the present invention towards other synthesis catalysts and reaction systems. Thus, this specificity should not be interpreted as limiting but instead the present invention should be limited only by the claims as provided.
Nonetheless, a syngas reactor in synthesis gas generation 615 can comprise any of the synthesis gas technology and/or methods known in the art. In preferred embodiments, the conversion step in synthesis gas generation 615 comprises a reaction between a light hydrocarbon gas and an oxidant. The hydrocarbon-containing feedstock 610 is almost exclusively obtained as one or more light hydrocarbons, such as natural gas or methane. However, the most important component of gas stream 610 is generally methane. Other suitable hydrocarbon feedstocks (hydrocarbons with four carbons or less) are also readily available. Similarly, the oxidant may come from a variety of sources and will be somewhat dependent upon the nature of the reaction being used. For example, a partial oxidation reaction requires diatomic oxygen as the oxidant feedstock while steam reforming requires only steam as the oxidant, and dry reforming employs CO2 as the oxidant. An autothermal reforming reaction combining partial oxidation reaction and steam reforming uses both diatomic oxygen and water as oxidant feedstocks. According to the preferred embodiment of the present invention, partial oxidation, and particularly catalytic partial oxidation, is assumed for at least part of the syngas production reaction which takes place in synthesis gas generation 615.
Regardless of the feedstocks sources, the hydrocarbon-containing feed and the oxidant-containing feed are reacted under catalytic conditions in synthesis gas generation 615. The catalyst compositions useful for synthesis gas reactions are well known in the art. They generally are comprised of a catalytic metal. The most common catalytic metals are metals from Groups 8, 9, and 10 of the Periodic Table (new IUPAC notation) such as noble metals. The support structures may be monoliths, wire mesh and/or particulates. Often, the support selected will dictate the type of catalyst bed that must be used. For example, fixed beds are comprised of monoliths and large particle sized supports (such as larger than 0.5 mm). Supports comprised of small particles tend to be more useful in fluidized beds (gas and solid phases) and/or slurry beds (with gas, liquid and solid phases). The support matrix usually comprises an inorganic oxide, such as alumina, titania, silica, zirconia, or combinations thereof such as silica-alumina. The support matrix may be modified or stabilized by at least one modifier, stabilizer, or structural promoter, in order to confer resistance to support sintering and/or metal sintering in high temperature environments.
The synthesis gas feedstock 610 is generally preheated and passed over or through the catalyst bed in synthesis gas generation 615. As the feedstock 610 contacts the catalyst, synthesis reactions take place. Gas stream 620 comprising synthesis gas product contains primarily hydrogen and carbon monoxide, however, many other minor components may be present in gas stream 620, including steam, nitrogen, carbon dioxide, ammonia, hydrogen cyanide, etc., as well as unreacted feedstock, such as methane, other light hydrocarbons, water, and/or oxygen. Gas stream 620 comprising synthesis gas, i.e., syngas, is then ready to be used, treated, or directed to its intended purpose. For example, in the instant case some or all of the gas stream 620 comprising syngas will be used as a feedstock for the hydrocarbon synthesis process 625.
The hydrocarbon synthesis reactor in hydrocarbon synthesis process 625 preferably comprises a Fischer-Tropsch reactor. Any Fischer-Tropsch technology and/or methods known in the art will suffice, however, a slurry bubble reactor is preferred. The feed gas charged to the process of the invention comprises synthesis gas. In addition, feed gas may further comprise off-gas recycle from the present or another Fischer-Tropsch process. Preferably the hydrogen is provided by free hydrogen, although some Fischer-Tropsch catalysts have sufficient water gas shift activity to convert some water (and CO) to hydrogen (and CO2) for use in the Fischer-Tropsch process. It is preferred that the molar ratio of hydrogen to carbon monoxide in the feed gas 620 be greater than 0.5:1 (e.g., from about 0.67 to about 2.5). Preferably, when cobalt, nickel, and/or ruthenium catalysts are used, the feed gas 620 contains hydrogen and carbon monoxide in a molar ratio of about 1.4:1 to about 2.3:1. Preferably, when iron catalysts are used, the feed gas stream contains hydrogen and carbon monoxide in a molar ratio between about 1.4:1 and about 2.2:1. The feed gas 620 may also contain carbon dioxide. The feed gas 620 should contain only a low concentration of compounds or elements that have a deleterious effect on the catalyst, such as poisons. For example, the feed gas 620 may need to be pretreated to ensure that it contains low concentrations of sulfur or nitrogen compounds such as hydrogen sulfide, hydrogen cyanide, ammonia and carbonyl sulfides.
The feed gas 620 to the hydrocarbon synthesis reactor is contacted with the catalyst in a reaction zone inside unit 625. Mechanical arrangements of conventional design may be employed as the reaction zone including, for example, fixed bed, fluidized bed, slurry bubble column or ebullating bed reactors, among others. Accordingly, the preferred size and physical form of the catalyst particles may vary depending on the reactor in which they are to be used. A reaction zone employing a slurry bubble column is preferred, and accordingly the catalyst particles have a preferred weight average size between about 30 microns and about 150 microns.
The Fischer-Tropsch process 625 is typically run in a continuous mode. In this mode, the gas hourly space velocity through the reaction zone typically may range from about 50 hr−to about 10,000 hr−1, preferably from about 300 hr−1 to about 2,000 hr−1. The gas hourly space velocity is defined as the volume of gas feed per time per reaction zone volume. The volume of gas feed is at standard conditions of pressure (101 kPa) and temperature (0° C.). The reaction zone volume is defined by the portion of the reaction vessel volume where the reaction takes place and which is occupied by a gaseous phase comprising reactants, products and/or inerts; a liquid phase comprising liquid/wax products and/or other liquids; and a solid phase comprising catalyst. The reaction zone temperature is typically in the range from about 160° C. to about 300° C. Preferably, the reaction zone is operated at conversion promoting conditions at temperatures from about 190° C. to about 260° C.; more preferably from about 205° C. to about 230° C. The reaction zone pressure is typically in the range of about 80 psia (552 kPa) to about 1000 psia (6895 kPa), more preferably from 80 psia (552 kPa) to about 800 psia (5515 kPa), and still more preferably, from about 140 psia (965 kPa) to about 750 psia (5170 kPa). Most preferably, the reaction zone pressure is from about 250 psia (1720 kPa) to about 650 psia (4480 kPa).
When the Fischer-Tropsch reactor comprises a slurry bubble column reactor, the syngas feedstock bubbles up through the slurry. The gas fed to the column generally serves to maintain some level of mixing as the gas moves up the column. As the gas moves upward, it comes in contact with the catalyst material and the hydrocarbon synthesis reaction takes place. Products are formed including hydrocarbons and water. Water is a by-product of the Fischer-Tropsch reaction as shown in Equation (1).
CO+2H2⇄CH2
+H2O (1)
Fischer-Tropsch catalysts are well known in the art and generally comprise a catalytically active metal, a promoter and optionally a support structure. The most common catalytic metals are Group 8, 9 and 10 metals of the Periodic Table (new IUPAC Notation), such as cobalt, nickel, ruthenium, and iron or mixtures thereof. The preferred metals used in Fischer-Tropsch catalysts with respect to the present invention are cobalt, iron and/or ruthenium, however, this invention is not limited to these metals or the Fischer-Tropsch reaction. Other suitable catalytic metals include Groups 8, 9 and 10 metals. The promoters and support material are not critical to the present invention and may be comprised, if at all, by any composition known and used in the art. Promoters suitable for Fischer-Tropsch synthesis may comprise at least one metal from Group 1, 7, 8, 9, 10, 11, and 13. When the catalytic metal is cobalt, the promoter is preferably selected from the group consisting of ruthenium (Ru), platinum (Pt), palladium (Pd), rhenium (Re), boron (B), silver (Ag), and combinations thereof. When the catalytic metal is iron, the promoter is preferably selected from the group consisting of lithium (Li), copper (Cu), potassium (K), silver (Ag), manganese (Mn), sodium (Na), and combinations thereof. The preferred support composition when used preferably comprises an inorganic oxide selected from the group consisting of alumina, silica, titania, zirconia and mixtures thereof. The inorganic oxide is preferably stabilized by the use of a structural promoter or stabilizer, so as to confer hydrothermal resistance to the support and the catalyst made therefrom. In preferred embodiments, Fischer-Tropsch process 625 comprises one or more hydrocarbon synthesis reactors and each reactor comprises a slurry bubble column operated with particles of a cobalt catalyst. The cobalt catalyst particles preferably comprise a weight average particle size between about 30 microns and 150 microns.
While preferred embodiments of this invention have been shown and described, modifications thereof can be made by one skilled in the art without departing from the spirit or teaching of this invention. The embodiments described herein are exemplary only and are not limiting. Many variations and modifications of the processes are possible and are within the scope of this invention. Accordingly, the scope of protection is not limited to the embodiments described herein, but is only limited by the claims that follow, the scope of which shall include all equivalents of the subject matter of the claims. In addition, unless order is explicitly recited, the recitation of steps in a claim is not intended to require that the steps be performed in any particular order, or that any step must be completed before the beginning of another step.
