Patent Application
20200181497
The present disclosure relates to methods of upgrading challenged feeds and the pitch products thereof.
As used herein, the term “challenged feed” refers to hydrocarbon compositions with a high density and carbon to hydrogen ratio, which indicates a high concentration of to polynucleararomatic hydrocarbons (PNAs). Challenged feedstocks typically have densities of >1.0 g/cc (API gravity of <10), 1050+contents of >15 wt %, Ni+V contents of >20 ppm, and total ash contents of 100-5000 ppm. Examples of challenged feeds include, but are not limited to, a bottoms fraction from fluid catalytic cracking (FCC) processes (also referred to as main column bottoms (MCB)), steam cracker tar, vacuum resid, and deaspihalter residue or rock.
Fluid catalytic cracking (FCC) processes are commonly used in refineries as a method for converting feedstocks, without requiring additional hydrogen, to produce lower boiling fractions suitable for use as fuels. While FCC processes can be effective for converting a majority of a typical input feed, under conventional operating conditions at least a portion of the resulting products can correspond to a fraction that exits the process as a “bottoms” fraction.
This bottoms fraction can typically be a high boiling range fraction, such as a 650° F. (343.3° C.) fraction. Because this bottoms fraction may also contain FCC catalyst fines, this fraction can sometimes be referred to as a catalytic slurry oil.
Steam cracking, also referred to as pyrolysis, has long been used to crack various hydrocarbon feedstocks into olefins, preferably light olefins such as ethylene, propylene, and butenes. Conventional steam cracking utilizes a pyrolysis furnace wherein the feedstock, typically comprising crude or a fraction thereof optionally desalted, is heated sufficiently to cause thermal decomposition of the larger molecules. Among the valuable and desirable products include light olefins such as ethylene, propylene, and butylenes. The pyrolysis process, however, also produces molecules that tend to combine to form high molecular weight materials known as steam cracked tar or steam cracker tar, hereinafter referred to as “SCT”. These are among the least valuable products obtained from the effluent of a pyrolysis furnace. In general, feedstocks containing higher boiling materials (“heavy feeds”) tend to produce greater quantities of SCT. It should be noted that the terms “thermal pyrolysis unit,” “pyrolysis unit,” and “steam cracker” are synonymous terms and all refer to what is conventionally known as a cracker. In practice, cracking is often performed using steam, but other cracking methods are within the scope of this invention other than stream cracking.
SCT is among the least desirable of the products of pyrolysis since it finds few uses. SCT tends to be incompatible with other “virgin” (meaning it has not undergone any hydrocarbon conversion process such as FCC or steam cracking) products of the refinery pipestill. At least one reason for such incompatibility is the presence of asphaltenes. Asphaltenes boil above 1050° F. (567° C.), have MW's above 260, and can precipitate out when blended in concentrations above 100 ppm into other materials, such as fuel oil fractions.
Steam cracking processes are commonly used in refineries as a method for producing olefins from heavy oils or other low value fractions. A side product generated during steam cracking can be steam cracker tar. Steam cracker tar can typically be a highly aromatic product with a boiling range similar to a vacuum gas oil and/or a vacuum resid fraction. Conventionally, steam cracker tar can be difficult to process using a fixed bed reactor because various molecules within a steam cracker tar feed are highly reactive, leading to fouling and operability issues.
Such processing difficulties can be further complicated, for example, by the high viscosity of the feed, the presence of coke fines within a steam cracker tar feed, and/or other properties related to the composition of steam cracker tar.
Still another type of challenging fraction to process in a refinery setting is deasphalter residue or “rock” that is generated from a solvent deasphalting process. For some types of feeds, the deasphalter residue can be used as an asphalt product and/or as a blendstock for forming an asphalt product. However, many types of deasphalter residue are not suitable for asphalt production, and the commercial demand for asphalt is often substantially lower than the available amount of deasphalter residue.
Being able to use these as a challenged feed for upgrading to valuable products would be of value in the industry.
The present disclosure relates to methods of upgrading challenged feeds and the pitch products thereof.
The present invention includes a method comprising: hydroprocessing a challenged feed from a refinery operation to produce a hydroprocessed product; distilling the hydroprocessed product to yield one or more upgraded fractions and a resid fraction; and solvent deasphalting the resid fraction to yield a deasphalted oil stream and a hydroprocessed pitch stream.
The present invention also includes a method comprising: solvent deasphalting fluid catalytic cracking (FCC) slurry oil into 2 wt % to 12 wt % rock and 88 wt % to 98 wt % deasphalted oil, wherein the rock has a softening point between 50° C. and 200° C. and a coking value between 50 wt % and 80 wt %.
The present invention also includes is a method comprising: fluxing a challenged feed from a refinery operation with a weight ratio of the fluxing solvent to the challenged feed of 10:90 to 90:10 to produce a fluxed pitch having one or more properties selected from the group consisting of: a coking value of about 45 wt % to 80 wt %; a micro carbon residue (MCR) of 50 wt % to 90 wt %; a solubility in toluene of 80 wt % to 100 wt %; and a softening point of 50° C. to 150° C.
The present invention includes a composition comprising (or consisting of): a pitch having a micro carbon residue (MCR) of 50 wt % or greater, a solubility in toluene of 95 wt % or greater, and a softening point of 200° C. or less. The present invention can further include a fluxed pitch comprising (or consisting of): the foregoing pitch; and a fluxing solvent, wherein a pitch to fluxing solvent weight ratio of 10:90 to 90:10.
The FIGURE is included to illustrate certain aspects of the embodiments, and should not be viewed as exclusive embodiments. The subject matter disclosed is capable of considerable modifications, alterations, combinations, and equivalents in form and function, as will occur to those skilled in the art and having the benefit of this disclosure.
The FIGURE is diagram of process of the present invention that upgrades a challenged feed from a refinery operation.
The present disclosure relates to methods of upgrading challenged feeds and the pitch products thereof. More specifically, one aspect of the present application relates to upgrading challenged feeds by hydroprocessing the challenged feeds, distilling the resultant product, and solvent deasphalting the resid of the distillation process to produce pitch. Another aspect of the present invention relates to upgrading challenged feeds by fluxing the challenged feed with fluxing solvent to produce pitch.
The FIGURE is diagram of process 100 of the present invention. A challenged feed 102 from a refinery operation 104, optionally blended with a co-feed and/or hydroprocessing solvent 106, is hydroprocessed in a hydroprocessing unit 108. The resultant hydroprocessed product 110 is distilled in distillation unit 112. Distillation unit 112 produces several fractions depending on the design of the distillation unit 112. In the illustrated example, the fractions include a gas fraction 114, a primarily C4− fraction 116, a primarily C5-C9 naphtha fraction 118, a primarily C9-C20 distillate fraction 120, and a resid fraction 122 (primarily C20 and above). The term “primarily” is used above to refer to the fact that, as is readily understood by those skilled in the art, perfect fractionating is not expected from the distillation unit 112. The C4− fraction 116, the C5-C9 naphtha fraction 118, and the distillate fraction 120 are upgraded products of the hydroprocessing process and can be used or further processed as known in the art. The gas fraction 114 typically does not contain significant amounts of hydrocarbon but, rather, contains contaminants or hydroprocessed contaminants like H2S, NH3, H2O, CO and CO2. The resid fraction 122 is further processed by solvent deasphalting in the deasphalting unit 124 to produce a deasphalted oil stream 126 and a hydroprocessed pitch stream 128.
Examples of challenged feeds 102 include, but are not limited to, a bottoms fraction from fluid catalytic cracking (FCC) processes, cracker tar, crude oil resid, and deasphalter residue or rock. Combinations of the foregoing may be used as a challenged feed 102.
The co-feed and/or hydroprocessing solvent 106 can be used to adjust the flow properties of the challenged feed 102 to enhance the ability to transport and process the challenged feed 102. The ratio of challenged feed 102 to the co-feed and/or hydroprocessing solvent 106 can be 100:0 to 10:90, alternatively 90:10 to 30:70, alternatively 85:15 to 40:60, alternatively 80:20 to 50:50, or alternatively 75:25 to 25:75.
Examples of co-feed and/or hydroprocessing solvent 106 include, but are not limited to, aromatic petroleum fraction, methylnaphthalene, dimethylnaphthalene, catalytic slurry oil, heavy coker gas oils, lube extracts, vacuum gas oils derived from heavy oils, and the like, and any combination thereof.
The hydroprocessing unit 108 can be of any suitable design for the challenged feed 102. The type of hydroprocessing that is suitable for upgrading of a challenged feed 102 can be dependent on the nature of the challenged feed 102. For a challenged feed 102 corresponding to a cracker tar, the challenged feed can be processed under fixed bed hydroprocessing conditions in the presence of a catalytic slurry oil co-feed. For a challenged feed corresponding to deasphalter rock, which has a substantial content of micro carbon residue and/or n-heptane insoluble compounds, the challenged feed 102 can be processed under slurry hydroprocessing conditions in the presence of a co-feed corresponding to a cracked feed. The cracked feed can correspond to a substantially vacuum gas oil boiling range feed with a high solubility blending number. A description of hydrocarbon processing methods and units are disclosed in U.S. Patent Application Nos. 2002/0005374, 2017/0022433, and 2018/0134972 and U.S. Pat. No. 8,197,668, which are each incorporated herein by reference.
Briefly, hydroprocessing (such as hydrotreating) can be carried out in the presence of hydrogen. A hydrogen stream can be fed or injected into a vessel or reaction zone or hydroprocessing zone in which the hydroprocessing catalyst is located. Hydrogen, which is contained in a hydrogen “treat gas,” is provided to the reaction zone (not illustrated in the FIGURE). Treat gas, as referred to herein, can be either pure hydrogen or a hydrogen-containing gas, which is a gas stream containing hydrogen in an amount that is sufficient for the intended reaction(s), optionally including one or more other gasses (e.g., nitrogen and light hydrocarbons such as methane), and which will not adversely interfere with or affect either the reactions or the products. Impurities, such as H2S and NH3 are undesirable and would typically be removed from the treat gas before it is conducted to the reactor. In aspects where the treat gas stream is different from a stream that substantially consists of hydrogen (i.e., at least about 99 vol % hydrogen), the treat gas stream introduced into a reaction stage can contain at least about 50 vol %, or at least about 75 vol % hydrogen, or at least about 90 vol % hydrogen.
Hydrogen can be supplied at a rate of from 300 SCF/B (standard cubic feet of hydrogen per barrel of feed) (53 S m3/m3) to 10000 SCF/B (1780 S m3/m3). Preferably, the hydrogen is provided in a range of from 1000 SCF/B (178 S m3/m3) to 5000 SCF/B (891 S m3/m3).
Hydrogen can be supplied co-currently with the challenged feed 102 and/or the co-feed and/or hydroprocessing solvent 106 or separately via a separate gas conduit to the hydroprocessing zone. The contact of the challenged feed 102 and co-feed and/or hydroprocessing solvent 106 with the hydroprocessing catalyst and the hydrogen produces a total product that includes a hydroprocessed oil product, pitch, and, in some embodiments, gas.
In some aspects, a combination of catalysts can be used for hydroprocessing of the challenged feed 102. For example, a challenged feed 102 can be contacted first by a demetallation catalyst, such as a catalyst including NiMo or CoMo on a support with a median pore diameter of 200 Å or greater. A demetallation catalyst represents a lower activity catalyst that is effective for removing at least a portion of the metals content of a feed. This allows a less expensive catalyst to be used to remove a portion of the metals, thus extending the lifetime of any subsequent higher activity catalysts. The demetallized effluent from the demetallation process can then be contacted with a conventional hydrotreating catalyst.
Hydrotreating catalysts suitable for use herein can include those containing at least one Group VIA metal and at least one Group VIII metal, including mixtures thereof. Examples of suitable metals include Ni, W, Mo, Co and mixtures thereof, for example CoMo, NiMoW, NiMo, or NiW. These metals or mixtures of metals are typically present as oxides or sulfides on refractory metal oxide supports. The amount of metals for supported hydrotreating catalysts, either individually or in mixtures, can range from 0.5 wt % to 35 wt %, based on the weight of the catalyst. Additionally or alternately, for mixtures of Group VIA and Group VIII metals, the Group VIII metals are present in amounts of from 0.5 wt % to 5 wt % based on catalyst, and the Group VIA metals are present in amounts of from 5 wt % to 30 wt % based on the catalyst. A mixture of metals may also be present as a bulk metal catalyst wherein the amount of metal is 30 wt % or greater, based on catalyst weight.
Suitable metal oxide supports for the hydrotreating catalysts include oxides such as silica, alumina, silica-alumina, titania, or zirconia. Examples of aluminas suitable for use as a support can include porous aluminas such as gamma or eta. In some aspects, when a porous metal oxide support is utilized, the catalyst can have an average pore size (as measured by nitrogen adsorption) of about 30 Å to about 1000 Å, or about 50 Å to about 500 Å, or about 60 Å to about 300 Å. Pore diameter can be determined, for example, according to ASTM Method D4284-07 Mercury Porosimetry. Additionally or alternately, the catalyst can have a surface area (as measured by the BET method) of about 100 m2/g to 350 m2/g, or about 150 m2/g to 250 m2/g. In some aspects, a supported hydrotreating catalyst can have the form of shaped extrudates. The extrudate diameters can range from 1/32nd to ⅛th inch, from 1/20th to 1/10th inch, or from 1/20th to 1/16th inch. The extrudates can be cylindrical or shaped. Non-limiting examples of extrudate shapes include trilobes and quadralobes.
Without being limited by theory, it is believed that the methods described herein have reduced coke deposition on the catalyst during hydroprocessing because the feedstock and product to the reactor are enriched in aromatics and naphthenes and depleted in paraffins. As a result, the reactor feed and product have solvent properties equivalent to or better than toluene. The high solvency keeps coke precursors in solution. Large pore catalysts and small extrudate sizes minimize coke precursor mass transport limitations. Catalyst with good aromatics saturation activity minimize the concentration of coke precursors. Therefore, less catalyst can be used and/or reactors can be used for longer periods of time.
Contacting conditions in the contacting or hydroprocessing zone can include, but are not limited to, temperature, pressure, hydrogen flow, hydrocarbon feed flow, or combinations thereof. Contacting conditions in some embodiments are controlled to yield a product with specific properties.
The temperature in the contacting zone can be 250° C. to 430° C., alternatively 300° C. to 420° C., or alternatively 350° C. to 420° C. Above about 435° C. thermal reactions of the feedstock can form sufficient coke in the reactor and in upstream and downstream heat exchangers to make conventional fixed bed processing less desirable.
The total pressure in the contacting zone can be 500 psig to 6000 psig, alternatively 1000 psig to 5000 psig, or alternatively 1500 psig to 4000 psig. Preferably, a feed including deasphalter rock can be hydroprocessed under relatively high hydrogen partial pressure conditions. In such aspects, the hydrogen partial pressure during hydroprocessing can be from 1000 psig to 6000 psig, alternatively 1500 psig to 5000 psig, or alternatively 2000 psig to 4000 psig.
The liquid hourly space velocity (LHSV) of the challenged feed 102 and the co-feed and/or hydroprocessing solvent 106, when used, can generally range from 0.01 hr−1 to 5 hr−1, or 0.05 hr−1 to 2 hr−1, or 0.1 hr−1 to 1.5 hr−1.
Based on the reaction conditions described above, in various aspects of the invention, a portion of the reactions taking place in the hydroprocessing reaction environment can correspond to thermal cracking reactions. In addition to the reactions expected during hydroprocessing of a feed in the presence of hydrogen and a hydroprocessing catalyst, thermal cracking reactions can also occur at temperatures of 360° C. and greater. In the hydroprocessing reaction environment, the presence of hydrogen and catalyst can reduce the likelihood of coke formation based on radicals formed during thermal cracking.
In some instances, contacting the input feed in the hydroprocessing unit 108 with the hydroprocessing catalyst in the presence of hydrogen to produce the hydroprocessed product 110 is carried out in a single contacting zone. In another aspect, contacting is carried out in two or more contacting zones.
The distillation unit 112 can have any suitable design to produce the desired hydrocarbon fractions. Such designs are well known in the art. While, the description of the FIGURE includes a gas fraction 114, a C4− fraction 116, a C5-C9 fraction 118, a naphtha fraction 120, and a resid fraction 122, other fractions could be produced. Such fractions include, but are not limited to, kerosene fractions, diesel fractions, and vacuum gas oil fractions. Each of these types of fractions can be defined based on a boiling range, such as a boiling range that includes at least 90 wt % of the fraction, or at least 95 wt % of the fraction. For example, for many types of naphtha fractions, at least 90 wt % of the fraction, or at least 95 wt %, can have a boiling point in the range of 85° F. (29° C.) to 350° F. (177° C.). For some heavier naphtha fractions, at least 90 wt % of the fraction, or at least 95 wt %, can have a boiling point in the range of 85° F. (29° C.) to 400° F. (204° C.). For a kerosene fraction, at least 90 wt % of the fraction, or at least 95 wt %, can have a boiling point in the range of 300° F. (149° C.) to 600° F. (288° C.). For a kerosene fraction targeted for some uses, such as jet fuel production, at least 90 wt % of the fraction, or at least 95 wt %, can have a boiling point in the range of 300° F. (149° C.) to 550° F. (288° C.). For a diesel fraction, at least 90 wt % of the fraction, or at least 95 wt %, can have a boiling point in the range of 400° F. (204° C.) to 750° F. (399° C.). For a (vacuum) gas oil fraction, at least 90 wt % of the fraction, and preferably at least 95 wt %, can have a boiling point in the range of 650° F. (343° C.) to 1100° F. (593° C.). Optionally, for some gas oil fractions, a narrower boiling range may be desirable. For such gas oil fractions, at least 90 wt % of the fraction, or at least 95 wt %, can have a boiling point in the range of 650° F. (343° C.) to 1000° F. (538° C.), or 650° F. (343° C.) to 900° F. (482° C.).
The deasphalting unit 124 can have any suitable design to separate the resid fraction 122 of the distillation unit 112 into the deasphalted oil stream 126 and the hydroprocessed pitch stream 128. Solvent deasphalting is typically performed using a small alkane as a solvent (C3-C7), and can result in production of a deasphalted oil fraction and a residue or rock fraction that is incompatible with the deasphalting solvent, which is referred to herein as pitch. The deasphalted oil fraction can be beneficial. For example, the deasphalted oil fraction can be processed using conventional refinery methods. The pitch fraction can be beneficial as asphalt, sealant (e.g., driveway sealer), or as a binder pitch or an impregnation pitch for the production of aluminum anodes and graphite electrodes to recycle steel.
In the overall process 100, the products are the distillation fractions, the deasphalted oil, and the pitch. The pitch can account for 1 wt % to 35 wt % of the total product, alternatively 5 wt % to 30 wt %, alternatively 10 wt % to 20 wt %, alternatively 15 wt % to 25 wt %, alternatively 20 wt % to 30 wt %.
The pitch can have a micro carbon residue (MCR) of 50 wt % or greater, a solubility in toluene of 50 wt % or greater, and a softening point of 200° C. or less.
MCR is determined by ASTM D4530-15. The pitch can have a MCR of 50 wt % to 90 wt %, alternatively 55 wt % to 85 wt %, alternatively 60 wt % to 80 wt %, alternatively 65 wt % to 80 wt %, or alternatively 65 wt % to 75 wt %.
The solubility of pitch in toluene is measured at 100° C. using the ASTM method for toluene insolubles (ASTM D4312-15). The pitch can have a solubility in toluene of 80 wt % to 100 wt %, alternatively 80 wt % to 99 wt %, or alternatively 90 wt % to 99 wt %.
Softening point is determined by a ring and ball methods described in ASTM D36/D36M-14e1. The softening point of the pitch can be 50° C. to 200° C., alternatively 60° C. to 150° C., or alternatively 50° C. to 120° C.
The distillation of the pitch can be performed according to ExxonMobil method M1567, where Tn is the temperature at which n wt % of the pitch has distilled where n is 1-100. For example, with n=10, T10 is the temperature at which 10 wt % of the pitch has distilled. The pitch can have a T10 distillation point at 800° F. (427° C.) to 1300° F. (704° C.), alternatively 850° F. (454° C.) to 1200° F. (649° C.), or alternatively 800° F. (427° C.) to 1050° F. (566° C.). The pitch can have a T50 distillation point at 1000° F. (538° C.) to 1500° F. (816° C.), alternatively 1100° F. (593° C.) to 1400° F. (760° C.), or alternatively 1200° F. (649° C.) to 1350° F. (732° C.).
The fractions of aromatic ring classes, sulfides, saturated hydrocarbons, polar hydrocarbons, and asphaltenes can be analyzed by liquid chromatography (ExxonMobil Method START and STARS). As used herein, the aromatic ring class (ARC) fractions in the pitch are classified by the number of aromatic rings: ARC1 is 1-ring aromatics; ARC2 is 2-ring aromatics; ARC3 is 3-ring aromatics; and ARC4+ is 4 or more-ring aromatics. The pitch can have fractions according to Table 2.
1-30
1-65
Coking value of the pitch can be measured according to ASTM D4715-98(2017). The coking value of the pitch is important in some applications like anodes for aluminum smelting and electric arc furnaces. In other applications like driveway sealers, the coking value of the pitch is less important. The coking value of the pitch can be about 45 wt % to 80 wt %, alternatively about 45 wt % to 70 wt %, alternatively about 50 wt % to about 60 wt %, alternatively about 55 wt % to about 65 wt %, or alternatively about 60 wt % to about 70 wt %.
Optionally, the pitch from the deasphalting unit 124 can be blended (or fluxed) with a fluxing solvent. Examples of fluxing solvents include, but are not limited to, paraffin solvent (e.g., ISOPAR™ V paraffinic fluid, available from ExxonMobil), xylenes, A200™ aromatic fluid available from ExxonMobil, and the like, and any combination thereof.
A fluxed pitch can comprise pitch and fluxing solvent at a weight ratio of 10:90 to 90:10, alternatively 20:80 to 50:50, alternatively 50:50 to 80:20, or alternatively 25:75 to 75:25.
The fluxed pitch can have a MCR of 50 wt % to 90 wt %, alternatively 55 wt % to 85 wt %, alternatively 60 wt % to 80 wt %, alternatively 65 wt % to 80 wt %, or alternatively 65 wt % to 75 wt %.
The fluxed pitch can have a solubility in toluene of 80 wt % to 100 wt %, alternatively 80 wt % to 99 wt %, or alternatively 90 wt % to 99 wt %.
The softening point of the fluxed pitch can be 50° C. to 150° C., alternatively 60° C. to 140° C., or alternatively 50° C. to 120° C.
In another aspect of the present invention, a challenged feed can be fluxed directly with a fluxing solvent (e.g., one or more of the fluxing solvents described above) to produce a fluxed pitch. The fluxed pitch can comprise challenged feed and fluxing solvent at a weight ratio of 10:90 to 90:10, alternatively 20:80 to 50:50, alternatively 50:50 to 80:20, or alternatively 25:75 to 75:25. The fluxed pitch can have one or more of the properties described herein: a coking value of about to 45 wt % to 80 wt %, alternatively about 45 wt % to 70 wt %, alternatively about 50 wt % to about 60 wt %, alternatively about 55 wt % to about 65 wt %, or alternatively about 60 wt % to about 70 wt %; a MCR of 50 wt % to 90 wt %, alternatively 55 wt % to 85 wt %, alternatively 60 wt % to 80 wt %, alternatively 65 wt % to 80 wt %, or alternatively 65 wt % to 75 wt %; a solubility in toluene of 80 wt % to 100 wt %, alternatively 80 wt % to 99 wt %, or alternatively 90 wt % to 99 wt %; and a softening point of 50° C. to 150° C., alternatively 60° C. to 140° C., or alternatively 50° C. to 120° C.
A first nonlimiting embodiment of the present invention is a method comprising: hydroprocessing a challenged feed from a refinery operation to produce a hydroprocessed product; distilling the hydroprocessed product to yield one or more upgraded fractions and a resid fraction; and solvent deasphalting the resid fraction to yield a deasphalted oil stream and a hydroprocessed pitch stream. The method may optionally further include one or more of the following: Element 1: the method further comprising: blending the challenged feed with a co-feed and/or hydroprocessing solvent before hydroprocessing; Element 2: the method further comprising: performing the hydroprocessing in the presence of hydrogen; Element 3: wherein products consist of the one or more upgraded fractions, the deasphalted oil stream, and the hydroprocessed pitch stream, and wherein the pitch is 1 wt % to 35 wt % of the total product; Element 4: wherein the pitch has a softening point of 50° C. to 200° C.; Element 5: wherein the pitch has a T10 distillation point of 800° F. (427° C.) to 1300° F. (704° C.); Element 6: wherein the pitch has a T50 distillation point of 1000° F. (538° C.) to 1500° F. (815° C.); Element 7: wherein the pitch has a micro carbon residue (MCR) of 50 wt % to 95 wt %; Element 8: wherein the pitch has a solubility in toluene of 95 wt % to 100 wt %; Element 9: wherein the pitch has comprises 0.1 wt % to 15 wt % saturated hydrocarbons, 0.1 wt % to 15 wt % ARC1, 0.1 wt % to 15 wt % ARC2, 1 wt % to 30 wt % ARC3, 10 wt % to 35 wt % ARC4+, 10 wt % to 30 wt % sulfides, 0.1 wt % to 20 wt % polar hydrocarbons, and 1 wt % to 65 wt % asphaltenes; Element 10: wherein the pitch has a coking value of 45 wt % to 80 wt %; Element 11: the method further comprising: blending the hydroprocessed pitch with a fluxing solvent to produce a fluxed pitch; Element 12: Element 11 and wherein the fluxing solvent comprises one selected from the group consisting of a paraffin solvent, xylenes, and any combination thereof. Element 13: Element 11 and wherein the fluxed pitch has a pitch to fluxing solvent weight ratio of 10:90 to 90:10; and Element 14: Element 11 and wherein the fluxed pitch has a softening point of 50° C. to 150° C. Examples of combinations include, but are not limited to, one or more of Elements 1-3 in combination with one or more of Elements 4-10; one or more of Elements 1-3 in combination with one or more of Elements 11-14; one or more of Elements 4-10 in combination with one or more of Elements 11-14; two or more of Elements 1-3 in combination; two or more of Elements 4-10 in combination; and two or more of Elements 11-14 in combination.
Another nonlimiting example embodiment is a method comprising: solvent deasphalting fluid catalytic cracking (FCC) slurry oil into 2 wt % to 12 wt % rock and 88 wt % to 98 wt % deasphalted oil, wherein the rock has a softening point between 50° C. and 200° C. and a coking value between 50 wt % and 80 wt %. The method may optionally further include one or more of the following: Element 5; Element 6; Element 7; Element 8; Element 9; Element 11; Element 12; Element 13; and Element 14. Examples of combinations include, but are not limited to, one or more of Elements 5-9 in combination with one or more of Elements 11-14; two or more of Elements 5-9 in combination; and two or more of Elements 11-14 in combination.
Yet another nonlimiting example embodiment is a method comprising: fluxing a challenged feed from a refinery operation with a weight ratio of the fluxing solvent to the challenged feed of 10:90 to 90:10 to produce a fluxed pitch having one or more properties selected from the group consisting of: a coking value of about 45 wt % to 80 wt %; a micro carbon residue (MCR) of 50 wt % to 90 wt %; a solubility in toluene of 80 wt % to 100 wt %; and a softening point of 50° C. to 150° C. The fluxing solvent can comprise one selected from the group consisting of a paraffin solvent, xylenes, and any combination thereof.
Another nonlimiting example embodiment is a composition comprising (or consisting of): a pitch having a micro carbon residue (MCR) of 50 wt % or greater, a solubility in toluene of 95 wt % or greater, and a softening point of 200° C. or less. The composition may optionally further include one or more of the following: Element 4; Element 5; Element 6; and Element 15: wherein the pitch has comprises 0.1 wt % to 15 wt % saturated hydrocarbons, 0.1 wt % to 15 wt % ARC1, 0.1 wt % to 15 wt % ARC2, 1 wt % to 30 wt % ARC3, 10 wt % to 35 wt % ARC4+, 10 wt % to 30 wt % sulfides, 0.1 wt % to 20 wt % polar hydrocarbons, and 1 wt % to 65 wt % asphaltenes. Yet another nonlimiting example embodiment is a fluxed pitch comprising (or consisting of): the foregoing pitch (optionally with one or more of the foregoing Elements); and a fluxing solvent, wherein a pitch to fluxing solvent weight ratio of 10:90 to 90:10.
Unless otherwise indicated, all numbers expressing quantities of ingredients, properties such as molecular weight, reaction conditions, and so forth used in the present specification and associated claims are to be understood as being modified in all instances by the term “about.” Accordingly, unless indicated to the contrary, the numerical parameters set forth in the following specification and attached claims are approximations that may vary depending upon the desired properties sought to be obtained by the embodiments of the present invention. At the very least, and not as an attempt to limit the application of the doctrine of equivalents to the scope of the claim, each numerical parameter should at least be construed in light of the number of reported significant digits and by applying ordinary rounding techniques.
One or more illustrative embodiments incorporating the invention embodiments disclosed herein are presented herein. Not all features of a physical implementation are described or shown in this application for the sake of clarity. It is understood that in the development of a physical embodiment incorporating the embodiments of the present invention, numerous implementation-specific decisions must be made to achieve the developer's goals, such as compliance with system-related, business-related, government-related and other constraints, which vary by implementation and from time to time. While a developer's efforts might be time-consuming, such efforts would be, nevertheless, a routine undertaking for those of ordinary skill in the art and having benefit of this disclosure.
While compositions and methods are described herein in terms of “comprising” various components or steps, the compositions and methods can also “consist essentially of” or “consist of” the various components and steps.
To facilitate a better understanding of the embodiments of the present invention, the following examples of preferred or representative embodiments are given. In no way should the following examples be read to limit, or to define, the scope of the invention.
A MCB feedstock was pentane deasphalted to produce a Sample Pitch 1 composed of a MCB rock comprising 90.3 wt % carbon, 5.32 wt % H, 2.7 wt % S, and 0.21 wt % N and having a T10 of 883° F. (473° C.), a T30 of 1137° F. (614° C.), a T50 of 1292° F. (700° C.), and an MCR of 71 wt %.
83 wt % of the Sample Pitch 1 was blended with 8.5 wt % ISOPAR™ V paraffinic fluid and 8.5 wt % 1-methylnaphthalene to produce a fluxed pitch composition. The fluxed pitch composition has an MCR of 58, is 90% soluble in toluene, and has a softening point of 120° C. The fluxed pitch composition is expected to be useful as a binder pitch and an impregnation pitch for the production of aluminum anodes and graphite electrodes used to recycle steel.
70 wt % of the Sample Pitch 1 was blended with 15 wt % ISOPAR™ V paraffinic fluid and 15 wt % 1-methylnaphthalene to produce a fluxed pitch composition. The fluxed pitch composition has an MCR of 50, is 90% soluble in toluene, and has a softening point of 65° C. It is expected to be useful as a driveway sealer, and to have excellent durability and weathering resistance.
A blend of 83 wt % of the Sample Pitch 1 with 17 wt % ISOPAR™ V paraffinic fluid was attempted to be produced, but the paraffinic fluid and Sample Pitch 1 were incompatible.
A sour vacuum residue rock was hydrotreated, vacuum distilled, and the bottoms deasphalted to produce a Sample Pitch 2 composed of 88.1 wt % carbon, 8.67 wt % H, 2.5 wt % S, and 0.33 wt % N and having a T10 of 1050° F. (566° C.), a T30 of 1209° F. (654° C.), a T50 of 1337° F. (725° C.), and an MCR of 56 wt %.
88 wt % of the Sample Pitch 2 was blended with 12 wt % ISOPAR™ V paraffinic fluid. The resulting fluxed pitch composition has an MCR of 50, is >98% soluble in toluene, and has a softening point of 120° C. It is expected to be useful as an impregnation pitch and a binder pitch.
80 wt % of the Sample Pitch 2 was blended with 20 wt % ISOPAR™ V paraffinic fluid. The resulting fluxed pitch composition has an MCRT of 45, is >98% soluble in toluene, and has a softening point of 65° C. It is expected to be useful as a driveway sealer.
A steam cracker tar was hydrotreated, vacuum distilled, and the bottoms deasphalted to produce a Sample Pitch 3 composed of 92.3 wt % carbon, 7.55 wt % H, 0.5 wt % S, and 0.1 wt % N and having a T10 of 995° F. (535° C.), a T30 of 1157° F. (625° C.), a T50 of 1350° F. (732° C.), and an MCR of 40 wt %.
80 wt % of the Sample Pitch 3 was fluxed with 20 wt % ISOPAR™ V paraffinic fluid. The resulting fluxed pitch composition has an MCRT of 32, is >98% soluble in toluene, and has a softening point of 100° C. It is expected to be useful as a trackless tack coating.
The six fluxed pitch composition above produced from Sample Pitches 1-3 each are dumbbell blends of high boiling point (mostly 950° F. and greater) pitches with low boiling point (600° F. (316° C.) and lower) fluxes. Each of the six fluxed pitch composition contain only small amounts of 605° F. (318° C.) to 950° F. (510° C.) boiling point range PNAs.
The three fluxed pitch compositions produced from Sample Pitches 2-3 (hydrotreated pitches) were easier to handle than the fluxed pitch composition produced from Sample Pitch 1.
The pitch/asphalt/rock produced by propane deasphalting crude oil vacuum resid was used as the challenged feedstock. 40 wt % of the challenged feedstock was blended with 60 wt % of FCC main columns bottoms (co-feed and/or hydroprocessing solvent). The blend was hydroprocessed in a conventional laboratory scale fixed bed hydrotreating at 3000 psig and 0.4 LHSV over a CoMo hydrotreating catalyst. The temperature was adjusted to achieve 80-90% hydrodesulfurization of the feedstock. The total liquid product was deasphalted in the lab to produce 11 wt % pitch (Sample Pitch 4, properties in Table 1) and 89 wt % deasphalted oil.
The pitch/asphalt/rock produced by propane deasphalting crude oil vacuum resid was used as the challenged feedstock. 25 wt % of the challenged feedstock was blended with 75 wt % of FCC main columns bottoms (co-feed and/or hydroprocessing solvent). The blend was hydroprocessed in a conventional laboratory scale fixed bed hydrotreating at 2000 psig and 0.4 LHSV over a CoMo hydrotreating catalyst. The temperature was adjusted to achieve 80-90% hydrodesulfurization of the feedstock. The total liquid product was deasphalted in the lab to produce 6 wt % pitch (Sample Pitch 5, properties in Table 1) and 94 wt % deasphalted oil.
The pitch/asphalt/rock produced by butane deasphalting crude oil vacuum resid was used as the challenged feedstock. 60 wt % of the challenged feedstock was blended with 40 wt % of xylenes (co-feed and/or hydroprocessing solvent). The blend was hydroprocessed in a conventional laboratory scale fixed bed hydrotreater at 1000 psig and 0.06 LHSV over a CoMo hydrotreating catalyst. The temperature was 400° C. to achieve 80-90% hydrodesulfurization of the feedstock. The total liquid product was vacuum distilled to remove the 600− products. The 600+ distillation bottom was deasphalted in the lab to produce 26 wt % pitch (Sample Pitch 6, properties in Table 1) and 74 wt % deasphalted oil.
The vacuum residue produced after refining Cold Lake feedstock was used as the challenged feedstock. 60 wt % of the challenged feedstock was blended with 40 wt % of xylenes (co-feed and/or hydroprocessing solvent). The blend was hydroprocessed in a conventional laboratory scale fixed bed hydrotreater at 1000 psig and 0.06 LHSV over a CoMo hydrotreating catalyst. The temperature was 400° C. to achieve 80-90% hydrodesulfurization of the feedstock. The total liquid product was vacuum distilled. The vacuum residue was deasphalted in the lab to produce 11 wt % pitch (Sample Pitch 7, properties in Table 1) and 89 wt % deasphalted oil.
The vacuum residue produced after refining Maya feedstock was used as the challenged feedstock. 60 wt % of the challenged feedstock was blended with 40 wt % of xylenes (co-feed and/or hydroprocessing solvent). The blend was hydroprocessed in a conventional laboratory scale fixed bed hydrotreating at 1000 psig and 0.06 LHSV over a CoMo hydrotreating catalyst. The temperature was 400° C. to achieve 80-90% hydrodesulfurization of the feedstock. The total liquid product was vacuum distilled. The vacuum residue was deasphalted in the lab to produce 15 wt % pitch (Sample Pitch 8, properties in Table 2) and 85 wt % deasphalted oil.
Therefore, the present invention is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the present invention may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular illustrative embodiments disclosed above may be altered, combined, or modified and all such variations are considered within the scope and spirit of the present invention. The invention illustratively disclosed herein suitably may be practiced in the absence of any element that is not specifically disclosed herein and/or any optional element disclosed herein. While compositions and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions and methods can also “consist essentially of” or “consist of” the various components and steps. All numbers and ranges disclosed above may vary by some amount. Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. Moreover, the indefinite articles “a” or “an,” as used in the claims, are defined herein to mean one or more than one of the element that it introduces.
This application claims priority to U.S. Provisional Application Ser. No. 62/777,401 filed Dec. 10, 2018, which is herein incorporated by reference in its entirety.
| Number | Date | Country | |
|---|---|---|---|
| 62777401 | Dec 2018 | US |
