HYDROTREATING PROCESS AND MULTIFUNCTION HYDROTREATER

Abstract

A multifunction hydrotreater includes a particulate removal zone having a particulate trap to remove particulate contaminants from a coal tar stream and a demetallizing zone including a demetallizing catalyst to remove organically bound metals from the departiculated stream. The demetallizing zone is positioned after the particulate removal zone. The hydrotreater also includes a hydrodesulfurization, hydrodenitrogenation, and hydrodeoxygenation zone positioned after the demetallization zone, which includes at least one hydrodesulfurization, hydrodenitrogenation, and hydrodeoxygenation catalyst to provide a hydrotreated coal tar stream.

Description

RELATED APPLICATIONS

This application claims priority to U.S. Provisional Application No. 61/906,083 filed on Nov. 19, 2013, the entirety of which is incorporated herein by reference.

BACKGROUND OF THE INVENTION

Many different types of chemicals are produced from the processing of petroleum. However, petroleum is becoming more expensive because of increased demand in recent decades.

Therefore, attempts have been made to provide alternative sources for the starting materials for manufacturing chemicals. Attention is now being focused on producing liquid hydrocarbons from solid carbonaceous materials, such as coal, which is available in large quantities in countries such as the United States and China.

Pyrolysis of coal produces coke and coal tar. The coke-making or “coking” process consists of heating the material in closed vessels in the absence of oxygen to very high temperatures. Coke is a porous but hard residue that is mostly carbon and inorganic ash, which may be used in making steel.

Coal tar is the volatile material that is driven off during heating, and it comprises a mixture of a number of hydrocarbon compounds. It can be separated to yield a variety of organic compounds, such as benzene, toluene, xylene, naphthalene, anthracene, and phenanthrene. These organic compounds can be used to make numerous products, for example, dyes, drugs, explosives, flavorings, perfumes, preservatives, synthetic resins, and paints and stains. The residual pitch left from the separation is used for paving, roofing, waterproofing, and insulation.

While coal tar can provide numerous useful and valuable chemicals, the coal tar also includes impurities such as solid particulate matter, metals, nitrogen, oxygen, and sulfur. Catalysts traditionally used to form useful chemicals from a hydrocarbon source are often deactivated by one or more of these impurities.

Thus, there is a need for a process for hydrotreating process and multifunction hydrotreater to remove these impurities from the coal tar.

SUMMARY OF THE INVENTION

In a first aspect, a multifunction hydrotreater includes a particulate removal zone having a particulate trap to remove particulate contaminants from a coal tar stream and a demetallizing zone including a demetallizing catalyst to remove organically bound metals from the de-particulated stream. The demetallizing zone is positioned after the particulate removal zone. The hydrotreater also includes a hydrodesulfurization, hydrodenitrogenation, and hydrodeoxygenation zone positioned after the demetallization zone, which includes at least one hydrodesulfurization, hydrodenitrogenation, and hydrodeoxygenation catalyst to provide a hydrotreated coal tar stream.

In another aspect, a hydrotreating process includes pyrolyzing a coal feed in a pyrolysis zone to produce a coke stream and a coal tar stream and separating a pitch fraction from the coal tar stream to form a reduced pitch coal tar stream. The reduced pitch coal tar stream is contacted with a particulate trap to remove particulate contaminants from the coal feed to form a de-particulated coal tar stream. The process further includes contacting the de-particulated coal tar stream with a demetallizing catalyst to remove organically-bound metals to form a demetallized coal tar stream, and contacting the demetallized coal tar stream with one or more catalysts for hydrodesulfurization, hydrodenitrogenation, and hydrodeoxygenation to produce a hydrotreated coal tar stream.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 illustrates one embodiment of the hydrotreater process of the present invention.

FIG. 2A illustrates one embodiment of the hydrodesulfurization/hydrodenitrogenation/hydrodeoxygenation zone of the process of FIG. 1.

FIG. 2B illustrates another embodiment of the hydrodesulfurization/hydrodenitrogenation/hydrodeoxygenation zone of the process of FIG. 1.

DETAILED DESCRIPTION OF THE INVENTION

FIG. 1 shows one embodiment of a hydrotreating process 5. A coal feed 10 can be sent to a pyrolysis zone 15, a gasification zone 20, or the coal feed 10 can be split into two parts and sent to both.

In the pyrolysis zone 15, the coal 10 is heated to a high temperature, e.g., up to about 2,000° C. (3,600° F.), in the absence of oxygen to drive off the volatile components. Coking produces coke 25 and coal tar stream 30. The coke 25 can be used in other processes, such as the manufacture of steel.

The coal tar stream 30 which comprises the volatile components from the coking process can be sent to a contamination removal zone 35, if desired.

The optional contaminant removal zone 35 for removing one or more contaminants from the coal tar stream or another process stream may be located at various positions along the process depending on the impact of the particular contaminant on the product or process and the reason for the contaminant's removal, as described further below. For example, the contaminant removal zone can be positioned upstream of the separation zone 45. Some contaminants have been identified to interfere with a downstream processing step or hydrocarbon conversion process, in which case the contaminant removal zone 35 may be positioned upstream of the separation zone 45 or between the separation zone 45 and the particular downstream processing step at issue. Still other contaminants have been identified that should be removed to meet particular product specifications. Where it is desired to remove multiple contaminants from the hydrocarbon or process stream, various contaminant removal zones may be positioned at different locations along the process. In still other approaches, a contaminant removal zone may overlap or be integrated with another process within the system, in which case the contaminant may be removed during another portion of the process, including, but not limited to the separation zone or the downstream hydrocarbon conversion zone. This may be accomplished with or without modification to these particular zones, reactors or processes. While the contaminant removal zone is often positioned downstream of the hydrocarbon conversion reactor, it should be understood that the contaminant removal zone in accordance herewith may be positioned upstream of the separation zone, between the separation zone and the hydrocarbon conversion zone, or downstream of the hydrocarbon conversion zone or along other streams within the process stream, such as, for example, a carrier fluid stream, a fuel stream, an oxygen source stream, or any streams used in the systems and the processes described herein. The contaminant concentration is controlled by removing at least a portion of the contaminant from the coal tar stream 30. As used herein, the term removing may refer to actual removal, for example by adsorption, absorption, or membrane separation, or it may refer to conversion of the contaminant to a more tolerable compound, or both.

The decontaminated coal tar feed 40 is sent to an optional separation zone 45 where it is separated into two or more fractions. Coal tar comprises a complex mixture of heterocyclic aromatic compounds and their derivatives with a wide range of boiling points. The number of fractions and the components in the various fractions can be varied as is well known in the art. A typical separation process involves separating the coal tar into four to six streams. For example, there can be a fraction comprising NH₃, CO, and light hydrocarbons, a light oil fraction with boiling points between 0° C. and 180° C., a middle oil fraction with boiling points between 180° C. to 230° C., a heavy oil fraction with boiling points between 230 to 270° C., an anthracene oil fraction with boiling points between 270° C. to 350° C., and pitch.

The light oil fraction contains compounds such as benzenes, toluenes, xylenes, naphtha, coumarone-indene, dicyclopentadiene, pyridine, and picolines. The middle oil fraction contains compounds such as phenols, cresols and cresylic acids, xylenols, naphthalene, high boiling tar acids, and high boiling tar bases. The heavy oil fraction contains benzene absorbing oil and creosotes. The anthracene oil fraction contains anthracene. Pitch is the residue of the coal tar distillation containing primarily aromatic hydrocarbons and heterocyclic compounds.

As illustrated, the coal tar feed 40 is separated into gas fraction 50 containing gases such as NH₃ and CO as well as light hydrocarbons, such as ethane, hydrocarbon fractions 55, 60, and 65 having different boiling point ranges, and pitch fraction 70.

Suitable separation processes include, but are not limited to, fractionation, such as distillation, solvent extraction, and adsorption.

One or more of the fractions 50, 55, 60, 65, 70 can be further processed, as desired. As illustrated, fraction 60 can be sent to a hydrotreater 75. Hydrotreating is a process in which hydrogen gas is contacted with a hydrocarbon stream in the presence of suitable catalysts which are primarily active for the removal of heteroatoms, such as sulfur, nitrogen, and metals from the hydrocarbon feedstock. In hydrotreating, hydrocarbons with double and triple bonds may be saturated. Aromatics may also be saturated. Typical hydrotreating reaction conditions include a temperature of about 290° C. (550° F.) to about 455° C. (850° F.), a pressure of about 3.4 MPa (500 psig) to about 27.6 MPa (4,000 psig), a liquid hourly space velocity of about 0.1 hr⁻¹ to about 5 hr⁻¹, and a hydrogen rate of about 168 to about 1,011 Nm³/m³ oil (1,000-10,000 scf/bbl). Typical hydrotreating catalysts include at least one Group VIII metal, preferably iron, cobalt and nickel, and at least one Group VI metal, preferably molybdenum and tungsten, on a high surface area support material, preferably alumina Other typical hydrotreating catalysts include zeolitic catalysts, as well as noble metal catalysts where the noble metal is selected from palladium and platinum.

The hydrotreater 75 includes at least a departiculating zone 80, a demetallizing zone 90, and a hydrodesulfurization/hydrodenitrogenation/hydrodeoxygenation (HDS/HDN/HDO) zone 110. The hydrotreater 75 can be formed as a single unit or as discrete zones in fluid communication with one another.

The fraction 60 first enters the departiculating zone 80. The departiculating zone 80 includes a particulate trap or filter to remove solid particles such as ash from the fraction 60. After passing through the departiculating zone, 80, a departiculated feed 85 is routed to the demetallizing zone 90.

In the demetallizing zone 90, the departiculated stream 80 is contacted with a demetallizing catalyst to remove organically bound metals from the departiculated stream 85. The demetallizing catalyst is a low-acidity, large pore catalyst, including at least one of a nickel-molybdenum catalyst and a cobalt-molybdenum catalyst.

Additionally, a quench fluid 95 is optionally introduced to the departiculated stream 85 as shown in FIG. 1, or at an injection port in the demetallizing zone 90. The quench fluid 95 is preferably a relatively cool liquid having a temperature less than the stream 85, and preferably in the range of about 26.67° C. (80° F.) to about 65.5° C. (150° F.), to lower the temperature of the hydrocarbon steam 85. Demetallizing reactions promoted by the demetallizing catalysts are exothermic. Accordingly, a cooling method is desirable to help control the temperature of the stream 85 as it undergoes demetallization. Example quench fluids include hydrogen gas, or liquid product.

After passing through the demetallizing zone 90, the demetallized feed 105 is routed to the HDS/HDN/HDO zone 110. The demetallized feed is contacted with multiple hydrotreating catalysts in the HDS/HDN/HDO zone 110 to remove sulfur, nitrogen, and oxygen heteroatoms. The hydrotreating catalysts include at least one Group VIII metal, such as iron, cobalt, or nickel, and at least one Group VI metal, preferably molybdenum or tungsten, on a high surface area support material, preferably alumina or silica. Other hydrotreating catalysts can include zeolitic material. Preferably the hydrotreating catalysts used in the HDS/HDN/HDO zone 110 include one or more of a nickel-molybdenum catalyst, a cobalt-molybdenum catalyst, a nickel-tungsten catalyst, and a nickel-cobalt-molybdenum catalyst. After being contacted with the hydrotreating catalysts, a hydrotreated feed 120 is produced from the HDS/HDN/HDO zone 110.

The HDS/HDN/HDO zone 110 can be formed in different ways. As an example, FIG. 2A shows the HDS/HDN/HDO zone 110 formed as two separate zones arranged sequentially and in fluid communication. In a first zone 200, the demetallized stream 105 is contacted with a first hydrotreating catalyst as described above. The first hydrotreating catalyst preferably has a relatively large pore structure, including pores sized in the range of about 5 nm to about 30 nm, and preferably in the range of about 10 nm to about 15 nm. After contact with the first catalyst, a partially hydrodesulfurized, hydrodenitrogenated, and hydrodeoxygenated stream 210 is routed to a second zone 215. In the second zone, the stream 210 is contacted with a second hydrotreating catalyst, distinct from the first catalyst. The second catalyst preferably has a relatively small pore structure. For example, the pores may have a diameter of about 10 nm or less, and preferably in a range of about 5 nm to about 10 nm.

Alternatively, as shown in FIG. 2B, the HDS/HDN/HDO zone 110 may include a plurality of beds arranged sequentially. As shown in FIG. 2B, the zone 110 includes three beds 110a, 110b, 110c, but those of skill in the art will recognize that more or fewer beds may be included without departing from the scope of the invention. Each of the beds 110a, 110b, 110c includes one or more hydrotreating catalysts. The demetallized stream 105 enters the HDS/HDN/HDO zone 110 and flows through the beds 110a, 110b, 110c in sequence, contacting the stream with the catalysts contained in each of the beds. The catalyst in each bed 110a, 110b, 110c may be the same or different. Where multiple catalysts are desired, one or more of the beds may include a stacked catalyst. Additionally, quench injection ports 225 are positioned between each of the beds 110a, 110b, and 110c as shown in FIG. 2B. The quench ports 225 allow for injection of the quench liquid 95 to help control the temperature of the hydrocarbon stream as it passes through the HDS/HDN/HDO zone 110.

Returning now to FIG. 1, after exiting the HDS/HDN/HDO zone 110, the hydrotreated stream 120 is routed to a separation zone 125 to separate the hydrotreated product into two or more fractions. The separation zone 125 preferably includes a condenser to remove water from the hydrotreated stream 120 and a separation column to divide the stream 120 into a plurality of products. For example, as shown in FIG. 1, the stream 120 is divided into a naphtha stream 135, a kerosene stream 140, a diesel stream 145, and a vacuum gas oil stream 150. A byproduct stream 130 including one or more of the water removed in the condenser and an ammonia product separated in the separation column is output from the separation zone 125 and recycled to the pyrolysis zone 15 as a hydrogen donor source. Each of the streams 135, 140, 145, 150 is output from the separation zone 125 for further downstream processing as desired. Suitable processes include, but are not limited to, hydrocracking, fluid catalytic cracking, alkylation, transalkylation, oxidation, and hydrogenation.

Hydrocracking is a process in which hydrocarbons crack in the presence of hydrogen to lower molecular weight hydrocarbons. Typical hydrocracking conditions may include a temperature of about 290° C. (550° F.) to about 468° C. (875° F.), a pressure of about 3.5 MPa (500 psig) to about 27.58 MPa (4,000 psig), a liquid hourly space velocity (LHSV) of about 0.5 to less than about 5 hr⁻¹, and a hydrogen rate of about 421 to about 2,527 Nm³/m³ oil (2,500-15,000 scf/bbl). Typical hydrocracking catalysts include amorphous silica-alumina bases or low-level zeolite bases combined with one or more Group VIII or Group VIB metal hydrogenating components, or a crystalline zeolite cracking base upon which is deposited a Group VIII metal hydrogenating component. Additional hydrogenating components may be selected from Group VIB for incorporation with the zeolite base.

Fluid catalytic cracking (FCC) is a catalytic hydrocarbon conversion process accomplished by contacting heavier hydrocarbons in a fluidized reaction zone with a catalytic particulate material. The reaction in catalytic cracking is carried out in the absence of substantial added hydrogen or the consumption of hydrogen. The process typically employs a powdered catalyst having the particles suspended in a rising flow of feed hydrocarbons to form a fluidized bed. In representative processes, cracking takes place in a riser, which is a vertical or upward sloped pipe. Typically, a pre-heated feed is sprayed into the base of the riser via feed nozzles where it contacts hot fluidized catalyst and is vaporized on contact with the catalyst, and the cracking occurs converting the high molecular weight oil into lighter components including liquefied petroleum gas (LPG), gasoline, and a distillate. The catalyst-feed mixture flows upward through the riser for a short period (a few seconds), and then the mixture is separated in cyclones. The hydrocarbons are directed to a fractionator for separation into LPG, gasoline, diesel, kerosene, jet fuel, and other possible fractions. While going through the riser, the cracking catalyst is deactivated because the process is accompanied by formation of coke which deposits on the catalyst particles. Contaminated catalyst is separated from the cracked hydrocarbon vapors and is further treated with steam to remove hydrocarbon remaining in the pores of the catalyst. The catalyst is then directed into a regenerator where the coke is burned off the surface of the catalyst particles, thus restoring the catalyst's activity and providing the necessary heat for the next reaction cycle. The process of cracking is endothermic. The regenerated catalyst is then used in the new cycle. Typical FCC conditions include a temperature of about 400° C. to about 800° C., a pressure of about 0 to about 688 kPa g (about 0 to 100 psig), and contact times of about 0.1 seconds to about 1 hour. The conditions are determined based on the hydrocarbon feedstock being cracked, and the cracked products desired. Zeolite-based catalysts are commonly used in FCC reactors, as are composite catalysts which contain zeolites, silica-aluminas, alumina, and other binders.

Transalkylation is a chemical reaction resulting in transfer of an alkyl group from one organic compound to another. Catalysts, particularly zeolite catalysts, are often used to effect the reaction. If desired, the transalkylation catalyst may be metal stabilized using a noble metal or base metal, and may contain suitable binder or matrix material such as inorganic oxides and other suitable materials. In a transalkylation process, a polyalkylaromatic hydrocarbon feed and an aromatic hydrocarbon feed are provided to a transalkylation reaction zone. The feed is usually heated to reaction temperature and then passed through a reaction zone, which may comprise one or more individual reactors. Passage of the combined feed through the reaction zone produces an effluent stream comprising unconverted feed and product monoalkylated hydrocarbons. This effluent is normally cooled and passed to a stripping column in which substantially all C5 and lighter hydrocarbons present in the effluent are concentrated into an overhead stream and removed from the process. An aromatics-rich stream is recovered as net stripper bottoms, which is referred to as the transalkylation effluent.

The transalkylation reaction can be effected in contact with a catalytic composite in any conventional or otherwise convenient manner and may comprise a batch or continuous type of operation, with a continuous operation being preferred. The transalkylation catalyst is usefully disposed as a fixed bed in a reaction zone of a vertical tubular reactor, with the alkylaromatic feed stock charged through the bed in an upflow or downflow manner. The transalkylation zone normally operates at conditions including a temperature in the range of about 130° C. to about 540° C. The transalkylation zone is typically operated at moderately elevated pressures broadly ranging from about 100 kPa to about 10 MPa absolute. The transalkylation reaction can be effected over a wide range of space velocities. That is, volume of charge per volume of catalyst per hour; weight hourly space velocity (WHSV) generally is in the range of from about 0.1 to about 30 hr¹. The catalyst is typically selected to have relatively high stability at a high activity level.

Alkylation is typically used to combine light olefins, for example mixtures of alkenes such as propylene and butylene, with isobutane to produce a relatively high-octane branched-chain paraffinic hydrocarbon fuel, including isoheptane and isooctane. Similarly, an alkylation reaction can be performed using an aromatic compound such as benzene in place of the isobutane. When using benzene, the product resulting from the alkylation reaction is an alkylbenzene (e.g. toluene, xylenes, ethylbenzene, etc.). For isobutane alkylation, typically, the reactants are mixed in the presence of a strong acid catalyst, such as sulfuric acid or hydrofluoric acid. The alkylation reaction is carried out at mild temperatures, and is typically a two-phase reaction. Because the reaction is exothermic, cooling is needed. Depending on the catalyst used, normal refinery cooling water provides sufficient cooling. Alternatively, a chilled cooling medium can be provided to cool the reaction. The catalyst protonates the alkenes to produce reactive carbocations which alkylate the isobutane reactant, thus forming branched chain paraffins from isobutane. Aromatic alkylation is generally now conducted with solid acid catalysts including zeolites or amorphous silica-aluminas

The alkylation reaction zone is maintained at a pressure sufficient to maintain the reactants in liquid phase. For a hydrofluoric acid catalyst, a general range of operating pressures is from about 200 to about 7,100 kPa absolute. The temperature range covered by this set of conditions is from about −20° C. to about 200° C. For at least alkylation of aromatic compounds, the temperature range is from about 100° C. to about 200° C. at the pressure range of about 200 to about 7,100 kPa.

Oxidation involves the oxidation of hydrocarbons to oxygen-containing compounds, such as aldehydes. The hydrocarbons include alkanes, alkenes, typically with carbon numbers from 2 to 15, and alkyl aromatics, Linear, branched, and cyclic alkanes and alkenes can be used. Oxygenates that are not fully oxidized to ketones or carboxylic acids can also be subjected to oxidation processes, as well as sulfur compounds that contain —S—H moieties, thiophene rings, sulfoxide and sulfone groups. The process is carried out by placing an oxidation catalyst in a reaction zone and contacting the feed stream which contains the desired hydrocarbons with the catalyst in the presence of oxygen. The type of reactor which can be used is any type well known in the art such as fixed-bed, moving-bed, multi-tube, CSTR, fluidized bed, etc. The feed stream can be flowed over the catalyst bed either up-flow or down-flow in the liquid, vapor, or mixed phase. In the case of a fluidized-bed, the feed stream can be flowed co-current or counter-current. In a CSTR the feed stream can be continuously added or added batch-wise. The feed stream contains the desired oxidizable species along with oxygen. Oxygen can be introduced either as pure oxygen or as air, or as liquid phase oxidants including hydrogen peroxide, organic peroxides, or peroxy-acids. The molar ratio of oxygen (O₂) to alkane can range from about 5:1 to about 1:10. In addition to oxygen and alkane or alkene, the feed stream can also contain a diluent gas selected form nitrogen, neon, argon, helium, carbon dioxide, steam or mixtures thereof. As stated, the oxygen can be added as air which could also provide a diluent. The molar ratio of diluent gas to oxygen ranges from greater than zero to about 10:1. The catalyst and feed stream are reacted at oxidation conditions which include a temperature of about 300° C. to about 600° C., a pressure of about 101 kPa to about 5,066 kPa and a space velocity of about 100 to about 100,000 hr⁻¹.

Hydrogenation involves the addition of hydrogen to hydrogenatable hydrocarbon compounds. Alternatively hydrogen can be provided in a hydrogen-containing compound with ready available hydrogen, such as tetralin, alcohols, hydrogenated naphthalenes, and others via a transfer hydrogenation process with or without a catalyst. The hydrogenatable hydrocarbon compounds are introduced into a hydrogenation zone and contacted with a hydrogen-rich gaseous phase and a hydrogenation catalyst in order to hydrogenate at least a portion of the hydrogenatable hydrocarbon compounds. The catalytic hydrogenation zone may contain a fixed, ebullated or fluidized catalyst bed. This reaction zone is typically at a pressure from about 689 kPa gauge (100 psig) to about 13,790 kPa gauge (2,000 psig) with a maximum catalyst bed temperature in the range of about 177° C. (350° F.) to about 454° C. (850° F.). The liquid hourly space velocity is typically in the range from about 0.2 hr⁻¹ to about 10 hr⁻¹ and hydrogen circulation rates from about 200 standard cubic feet per barrel (SCFB) (35.6 m³/m³) to about 10,000 SCFB (1778 m³/m³).

In some processes, all or a portion of the coal feed 10 is mixed with oxygen 155 and steam 160 and reacted under heat and pressure in the gasification zone 20 to form syngas 165, which is a mixture of carbon monoxide and hydrogen. The syngas 165 can be further processed using the Fischer-Tropsch reaction to produce gasoline or using the water-gas shift reaction to produce more hydrogen.

While at least one exemplary embodiment has been presented in the foregoing detailed description of the invention, it should be appreciated that a vast number of variations exist. It should also be appreciated that the exemplary embodiment or exemplary embodiments are only examples, and are not intended to limit the scope, applicability, or configuration of the invention in any way. Rather, the foregoing detailed description will provide those skilled in the art with a convenient road map for implementing an exemplary embodiment of the invention. It being understood that various changes may be made in the function and arrangement of elements described in an exemplary embodiment without departing from the scope of the invention as set forth in the appended claims.

Claims

1. A multifunction hydrotreater comprising:

a particulate removal zone comprising a particulate trap to remove particulate contaminants from a coal tar stream;

a demetallizing zone comprising a demetallizing catalyst to remove organically bound metals from the de-particulated stream, the demetallizing zone positioned after the particulate removal zone; and

a hydrodesulfurization, hydrodenitrogenation, and hydrodeoxygenation zone comprising at least one hydrodesulfurization, hydrodenitrogenation, and hydrodeoxygenation catalyst to provide a hydrotreated coal tar stream, the hydrodesulfurization, hydrodenitrogenation, and hydrodeoxygenation zone positioned after the demetallizing zone.

2. The multifunction hydrotreater of claim 1, wherein said hydrodesulfurization, hydrodenitrogenation, and hydrodeoxygenation zone comprises:

a first zone comprising a first hydrodesulfurization, hydrodenitrogenation, and hydrodeoxygenation catalyst; and

a second zone comprising a second hydrodesulfurization, hydrodenitrogenation, and hydrodeoxygenation catalyst.

3. The multifunction hydrotreater of claim 2, wherein each of said first and second catalysts includes one or more of a nickel-molybdenum catalyst, a cobalt-molybdenum catalyst, a nickel-tungsten catalyst, and a nickel-cobalt-molybdenum catalyst.

4. The multifunction hydrotreater of claim 3, wherein said first catalyst and said second catalyst are distinct.

5. The multifunction hydrotreater of claim 2, wherein said first catalyst is a large pore catalyst and said second catalyst is a small pore catalyst.

6. The multifunction hydrotreater of claim 1, wherein said hydrodesulfurization, hydrodenitrogenation, and hydrodeoxygenation zone includes a plurality of beds arranged sequentially.

7. The multifunction hydrotreater of claim 6, further comprising:

a quench medium injection port between each of said plurality of beds.

8. The multifunction hydrotreater of claim 1, wherein said demetallizing catalyst is a low-acidity large pore catalyst including at least one of a nickel-molybdenum catalyst and a cobalt-molybdenum catalyst.

9. The multifunction hydrotreater of claim 1, further comprising:

a quench medium injection port in said demetallizing zone.

10. The multifunction hydrotreater of claim 1, further comprising: a condenser in fluid communication with an upstream coal pyrolysis zone, said condenser positioned after the hydrodesulfurization, hydrodenitrogenation, and hydrodeoxygenation zone, a condensed water portion of the hydrotreated coal tar stream being provided to said upstream coal pyrolysis zone as a hydrogen donor stream.

11. A hydrotreating process comprising:

pyrolyzing a coal feed in a pyrolysis zone to produce a coke stream and a coal tar stream;

separating a pitch fraction from the coal tar stream to form a reduced pitch coal tar stream;

contacting the reduced pitch coal tar stream with a particulate trap to remove particulate contaminants from the coal feed to form a de-particulated coal tar stream;

contacting the de-particulated coal tar stream with a demetallizing catalyst to remove organically-bound metals to form a demetallized coal tar stream;

contacting the demetallized coal tar stream with one or more catalysts for hydrodesulfurization, hydrodenitrogenation, and hydrodeoxygenation to produce a hydrotreated coal tar stream.

12. The hydrotreating process of claim 11 further comprising:

introducing the hydrotreated coal tar stream into a separation column to separate the coal tar stream into at least a naphtha stream, a kerosene stream, a diesel stream, and a vacuum gas oil stream.

13. The hydrotreating process of claim 12, wherein said separation further produces an ammonia stream.

14. The hydrotreating process of claim 13, further comprising:

introducing the ammonia stream to said pyrolysis zone as a hydrogen donor stream.

15. The hydrotreating process of claim 11, further comprising:

injecting a quench medium into the de-particulated coal tar stream.

16. The hydrotreating process of claim 11, wherein contacting the demetallized coal tar stream with one or more catalysts for hydrodesulfurization, hydrodenitrogenation, and hydrodeoxygenation comprises contacting the de-metallized coal tar stream with said one or more catalysts for hydrodesulfurization, hydrodenitrogenation, and hydrodeoxygenation in a series of sequential beds, and further comprising:

injecting a relatively cool quench medium into the de-metallized coal tar stream between said sequential beds.

17. The hydrotreating process of claim 11, wherein said one or more catalysts for hydrodesulfurization, hydrodenitrogenation, and hydrodeoxygenation comprise one or more of a nickel-molybdenum catalyst, a cobalt-molybdenum catalyst, a nickel-tungsten catalyst, and a nickel-cobalt-molybdenum catalyst.

18. The hydrotreating process of claim 11, wherein said one or more catalysts for hydrodesulfurization, hydrodenitrogenation and hydrodeoxygenation comprise a plurality of catalysts comprising at least one large pore catalyst and at least one small pore catalyst.

19. The hydrotreating process of claim 11, wherein said one or more catalysts for hydrodesulfurization, hydrodenitrogenation, and hydrodeoxygenation comprises a plurality of stacked catalysts.

20. The hydrotreating process of claim 11, wherein said demetallizing catalyst is a low-acidity large pore catalyst including at least one of a nickel-molybdenum catalyst and a cobalt-molybdenum catalyst.