Hydrocarbon conversion process

One exemplary embodiment can be a process for hydrocarbon conversion. The process can include providing a feed to a slurry hydrocracking zone, obtaining a hydrocarbon stream including one or more C16-C45 hydrocarbons from the at least one separator, providing another feed to a hydrocracking zone, and providing hydrogen from a three-stage compressor to the slurry hydrocracking zone and the hydrocracking zone. Moreover, the slurry hydrocracking zone may include a slurry hydrocracking reactor and at least one separator.

FIELD OF THE INVENTION

This invention generally relates to a process for hydrocarbon conversion and a process for hydrogen distribution in an apparatus.

DESCRIPTION OF THE RELATED ART

Many configurations have been proposed to reduce capital costs by integrating processing units. Often, hydroprocessing units may utilize similar feeds, catalysts, process conditions, and various utilities. As such, hydroprocessing units can share make-up and recycle gas systems, such as those systems that provide hydrogen. The hydrogen can be compressed to the pressure required by the individual units. Such compression is usually undertaken with a compressor. Thus, it can be desirable to minimize the cost and number of compressors, as compressors can be an expensive component for a hydroprocessing unit. As a result, any integration and sharing of equipment can reduce the costs of manufacturing and maintaining the hydroprocessing facility. Therefore, it can be desirable to manufacture hydroprocessing facilities in an economic and efficient manor to minimize capital costs and increase opportunities for sharing equipment infrastructure.

SUMMARY OF THE INVENTION

One exemplary embodiment can be a process for hydrocarbon conversion. The process can include providing a feed to a slurry hydrocracking zone, obtaining a hydrocarbon stream including one or more C16-C45 hydrocarbons from the at least one separator, providing another feed to a hydrocracking zone, and providing hydrogen from a three-stage compressor to the slurry hydrocracking zone and the hydrocracking zone. Moreover, the slurry hydrocracking zone may include a slurry hydrocracking reactor and at least one separator.

Another exemplary embodiment can be a process for hydrogen distribution for an apparatus. The process may include providing a three-stage compressor having a first stage, a second stage, and a third stage; providing hydrogen from the first stage to at least one of a naphtha hydrotreating zone and an isomerization zone; providing hydrogen from the second stage to a hydrotreating zone; and providing hydrogen from the third stage to at least one of a slurry hydrocracking zone and a hydrocracking zone.

A further exemplary embodiment may be a process for hydrogen distribution for an apparatus. The process can include providing a three-stage compressor including a first stage, a second stage, and a third stage; providing hydrogen from the first stage to at least one of a naphtha hydrotreating zone and an isomerization zone; providing hydrogen from the second stage to a hydrotreating zone; providing hydrogen from the third stage to a slurry hydrocracking zone; and providing hydrogen from the third stage to a hydrocracking zone. The hydrocracking zone may include a hydrocracking reactor, a hot separator, a cold separator, a hot flash drum, and a cold flash drum. Also, the hydrotreating zone can include a hydrotreating reactor, a hot separator, a cold separator, and a recycle gas compressor. Often, hydrogen is recycled from the cold separator to the hydrotreating reactor. Additionally, the slurry hydrocracking zone may include a slurry hydrocracking reactor, a hot separator, a warm separator, a cold separator, and a recycle gas compressor. Generally, hydrogen is recycled from the slurry hydrocracking zone cold separator to the slurry hydrocracking reactor.

The embodiments provided herein can allow the integration of make-up and recycle gas systems for hydrogen provided to a slurry hydrocracking zone, a hydrocracking zone, and a hydrotreating zone. As an example, integrating compression systems from two zones can allow a single spare to be utilized for the compressors operating with each respective zone, thereby eliminating capital costs. The embodiments disclosed herein can provide a three-stage compressor providing hydrogen to several zones and thus further reduce costs.

DEFINITIONS

As used herein, the term “stream” can include various hydrocarbon molecules, such as straight-chain, branched, or cyclic alkanes, alkenes, alkadienes, and alkynes, and optionally other substances, such as gases, e.g., hydrogen, or impurities, such as heavy metals, and sulfur and nitrogen compounds. A stream can also include aromatic and non-aromatic hydrocarbons, or other gases absent hydrocarbons, such as hydrogen. Moreover, the hydrocarbon molecules may be abbreviated C1, C2, C3 . . . Cn where “n” represents the number of carbon atoms in the one or more hydrocarbon molecules. Furthermore, a superscript “+” or “−” may be used with an abbreviated one or more hydrocarbons notation, e.g., C3+or C3−, which is inclusive of the abbreviated one or more hydrocarbons. As an example, the abbreviation “C3+” means one or more hydrocarbon molecules of three carbon atoms and/or more.

As used herein, the term “zone” can refer to an area including one or more equipment items and/or one or more sub-zones. Equipment items can include one or more reactors or reactor vessels, heaters, exchangers, pipes, pumps, compressors, and controllers. Additionally, an equipment item, such as a reactor, dryer, or vessel, can further include one or more zones or sub-zones.

As used herein, the term “megapascal” may be abbreviated “MPa”.

As used herein, the term “liquid hourly space velocity” may be abbreviated “LHSV”.

As used herein, the term “overhead stream” can mean a stream withdrawn at or near a top of a vessel, typically a distillation column or flash drum.

As used herein, the term “bottom stream” can mean a stream withdrawn at or near a bottom of a vessel, typically a distillation column or flash drum.

As depicted, process flow lines in the FIGURE can be referred to interchangeably as, e.g., lines, pipes, feeds, products, parts, portions, or streams.

DETAILED DESCRIPTION

Referring to the FIGURE, an exemplary apparatus10can include a three-stage compressor100, a slurry hydrocracking zone200, a hydrocracking zone300, and a hydrotreating zone400, and a separation zone500. Optionally, the apparatus10may also include a naphtha hydrotreatment zone170and an isomerization zone180. An exemplary naphtha hydrotreatment zone is disclosed in, e.g., U.S. Pat. No. 7,727,490 and an exemplary isomerization zone is disclosed in, e.g., U.S. Pat. No. 7,223,898. Often, the apparatus10can be any suitable refinery or chemical manufacturing facility. Generally, the apparatus10can include a make-up hydrogen system that includes the three-stage compressor100and a recycle hydrogen system that may permit recycling of hydrogen in and among the zones200,300, and400. Generally, the recycle hydrogen system contains hydrogen that has higher amounts of impurities, such as one or more C1-C3 hydrocarbons, as compared to the make-up hydrogen system. These hydrogen systems will be discussed in further detail hereinafter and are indicated in the FIGURE by dashed lines.

The three-stage compressor100can include a first stage compressor110, a second stage compressor120, and a third stage compressor130and provide make-up hydrogen to the zones170,180,200,300, and400. Hence, the three-stage compressor100can include several stages integrated together and can provide hydrogen to the various hydroprocessing zones at the requisite pressure. Particularly, the first stage compressor110can receive a hydrogen stream104and provide an outlet or discharge stream114; the second stage compressor120can receive a portion118of the outlet or discharge stream114and provide an outlet or discharge stream122at a higher pressure; and the third stage compressor130can receive a portion126of the second stage outlet or discharge stream122and provide an outlet or discharge stream132at an even higher pressure.

The suction pressure for the first stage compressor110can be about 2.0-about 3.0 MPa, the suction pressure for the second stage compressor120can be about 4.0-about 6.0 MPa, and the suction pressure for the third stage compressor130can be about 8.0-about 12.0 MPa. The discharge pressure for the first stage compressor110may be about 4.0-about 6.0 MPa; for the second stage compressor120may be about 8.0-about 12.0 MPa, preferably about 8.0-about 10.0 MPa; and for the third stage compressor130may be about 16.0-about 24.0 MPa, preferably about 16.0-about 19.0 MPa. Generally, the first stage compressor110and the second stage compressor120may have respective coolers and knock-out pots prior to, respectively, the suction of the second stage compressor120and the third stage compressor130.

Often, parallel compressors are installed. In a typical installation, a total of ten stages of compression can be eliminated from the slurry hydrocracking zone200and the hydrotreating zone400by increasing the size of the hydrocracking zone300compressors. Using the three-stage compressor100may reduce cost by at least 25% by integrating the compression systems for the various zones200,300, and400. Additional savings may be obtained by utilizing larger compressors.

The slurry hydrocracking zone200can include a slurry hydrocracking reactor210, at least one separator220, a recycle gas scrubber280, and a recycle gas compressor286. Generally, the slurry hydrocracking reactor210can operate at any suitable conditions, such as a temperature of about 400-about 500° C. and a pressure of about 3-about 24 MPa. Exemplary slurry hydrocracking zones are disclosed in, e.g., U.S. Pat. No. 5,755,955; U.S. Pat. No. 5,474,977; US 2009/0127161; US 2010/0248946; US 2011/0306490; and US 2011/0303580. Often, slurry hydroprocessing is carried out using reactor conditions sufficient to crack at least a portion of a feed204to lower boiling products, such as one or more distillate hydrocarbons, naphtha, and/or C1-C4 products. The feed204can include hydrocarbons boiling from about 340-about 570° C., and may include one or more of a crude oil atmospheric distillation column residuum boiling above about 340° C., a crude oil vacuum distillation column residuum boiling above about 560° C., tars, a bitumen, coal oils, and shale oils. A catalyst may be combined with the feed204to obtain a solids content of about 0.01-about 10%, by weight, before being combined with hydrogen, as hereinafter described.

Typically, the slurry catalyst composition can include a catalytically effective amount of one or more compounds having iron. Particularly, the one or more compounds can include at least one of an iron oxide, an iron sulfate, and an iron carbonate. Other forms of iron can include at least one of an iron sulfide, a pyrrhotite, and a pyrite. What is more, the catalyst can contain materials other than an iron, such as at least one of molybdenum, nickel, and manganese, and/or a salt, an oxide, and/or a mineral thereof. Preferably, the one or more compounds includes an iron sulfate, and more preferably, at least one of an iron sulfate monohydrate and an iron sulfate heptahydrate.

Alternatively, one or more catalyst particles can include about 2-about 45%, by weight, iron oxide and about 20-about 90%, by weight, alumina. In one exemplary embodiment, iron-containing bauxite is a preferred material having these proportions. Bauxite can have about 10-about 40%, by weight, iron oxide, and about 54-about 84%, by weight, alumina and may have about 10-about 35%, by weight, iron oxide and about 55-about 80%, by weight, alumina Bauxite also may include silica and titania in amounts of usually no more than about 10%, by weight, and typically in amounts of no more than about 6%, by weight. Volatiles such as water and carbon dioxide may also be present, but the foregoing weight proportions exclude such volatiles. Typically, iron oxide is also present in bauxite in a hydrated form, but again the foregoing proportions exclude water in the hydrated composition.

In another exemplary embodiment, it may be desirable for the catalyst to be supported. Such a supported catalyst can be relatively resilient and maintain its particle size after being processed. As a consequence, such a catalyst can include a support of alumina, silica, titania, one or more aluminosilicates, magnesia, bauxite, coal and/or petroleum coke. Such a supported catalyst can include a catalytically active metal, such as at least one of iron, molybdenum, nickel, and vanadium, as well as sulfides of one or more of these metals. Generally, the catalyst can have about 0.01-about 30%, by weight, of the catalytic active metal based on the total weight of the catalyst.

The at least one separator220can include a hot separator230, a warm separator240, and a cold separator250. Generally, an effluent214from the slurry hydrocracking reactor210can be provided to the at least one separator220with various hydrocarbon streams being obtained, such as a bottom stream234from the hot separator230, a bottom stream244from the warm separator240, and a bottom stream254from the cold separator250. Often, the hot separator230can be about 200-about 480° C., and the warm separator240can be about 170-about 380° C. Generally, the cold separator250is no more than about 100° C., preferably no more than about 70° C. The streams234,244, and254, can be provided to the separation zone500. Moreover, a top stream238from the hot separator230can be provided to the warm separator240, which in turn can provide a top stream248to the cold separator250.

The hydrocracking zone300can include a hydrocracking reactor320, a hot separator340, a cold separator350, a hot flash drum360, and a cold flash drum370. Generally, the hydrocracking zone300can receive another feed304to be received within the hydrocracking reactor320. The another feed304can include a vacuum gas oil or other hydrocarbon fraction having at least about 50%, by weight, of its components boiling at a temperature above about 390° C.

Generally, the hydrocracking reactor320can operate at any suitable conditions, such as a temperature of about 290-about 470° C. and a pressure of about 3.5-about 21 MPa. Generally, the hydrocracking reactor320can include a first bed324and a second bed328containing any suitable catalyst. Afterwards, the hydrocracking reactor320can provide an effluent332. Although only one hydrocracking reactor320is depicted in the hydrocracking zone300, it should be understood that additional hydrocracking reactors may be utilized as well as other suitable reactors, such as a hydrotreating reactor.

Suitable hydrocracking catalysts may include amorphous silica-alumina bases or low-level zeolite bases combined with one or more Group VIII or Group VIB metal hydrogenating components. Alternatively, the catalyst may include any crystalline zeolite cracking base with a deposited Group VIII metal hydrogenating component, such as iron, cobalt, nickel, ruthenium, rhodium, palladium, osmium, iridium and platinum. Additional hydrogenating components may be selected from Group VIB such as molybdenum and tungsten for incorporation with the zeolite base.

Sometimes, the zeolite cracking bases are referred to as molecular sieves and are usually composed of silica, alumina and one or more exchangeable cations such as sodium, magnesium, calcium, and rare earth metals. The hydrocracking conditions may include a temperature of about 290-about 470° C., a pressure of about 3.5-about 20.7 MPa, a LHSV from about 1.0—less than about 2.5 hr−1, and a hydrogen rate of about 420-about 2,530 Nm3/m3oil.

Often, the effluent332is provided to the hot separator340, which can provide a top stream342and a bottom stream344. Typically, the top stream342is provided to the cold separator350, which in turn provides a bottom stream354to the cold flash drum370. Often, the hot separator340can be about 200-about 470° C. Generally, the cold separator350is no more than about 100° C., preferably no more than about 70° C. The bottom stream344from the hot separator340may be provided to the hot flash drum360, which in turn can provide a top stream362and a bottom stream364. The top stream362may be combined with the bottom stream354to form a combined stream366provided to the cold flash drum370. Generally, the cold flash drum370provides a top stream372and a bottom stream374. The streams364,372, and374exiting the hydrocracking zone300can be provided to the separation zone500.

The hydrotreating zone400can include a hydrotreating reactor420, a hot separator430, a cold separator440, a recycle gas scrubber450, and a recycle gas compressor460. Generally, the hydrotreating zone400can desulfurize, denitrify, or saturate a further feed404. The further feed404can include one or more C8-C21 hydrocarbons and have hydrocarbons boiling from about 180-about 370° C. Typically, the further feed404can be a diesel cut.

The further feed404can be provided to the hydrotreating reactor420, which can operate at any suitable conditions, such as a temperature of about 290-about 460° C. and a pressure of about 3.0-about 9.0 MPa. The hydrotreating reactor420can contain any suitable number of beds, such as a first bed424and a second bed426.

Suitable hydrotreating catalysts include those which are comprised of at least one Group VIII metal, preferably iron, cobalt and/or nickel, and at least one Group VI metal, preferably molybdenum and/or tungsten, on a high surface area support material, preferably alumina. Other suitable hydrotreating catalysts may include zeolitic catalysts, as well as noble metal catalysts where the noble metal may be selected from palladium and/or platinum. More than one type of hydrotreating catalyst may be used in the same vessel. Often, the Group VIII metal is present in an amount ranging from about 2-about 20%, by weight, and the Group VI metal is present in an amount ranging of about 1-about 25%, by weight.

Preferred hydrotreating reaction conditions include a temperature from about 290-about 455° C., a pressure of about 3.0-about 9.0 MPa, an LHSV of about 0.5-about 4 hr−1, and a hydrogen rate of about 160-about 1,020 Nm3/m3oil, with a hydrotreating catalyst or a combination of hydrotreating catalysts. Exemplary hydrocracking and hydrotreating zones are disclosed in, e.g., U.S. application Ser. No. 13/076,670 filed 31 Mar. 2011.

A hydrotreating effluent428can be obtained from the hydrotreating reactor420and provided to the hot separator430. The hot separator430can provide a top stream434and a bottom stream436. The bottom stream436can be provided to the separation zone500while the top stream434can be provided to the cold separator440. Often, the hot separator430can be about 200-about 470° C. Generally, the cold separator440is no more than about 100° C., preferably no more than about 70° C. The cold separator440can provide a bottom stream446to the separation zone500and a top stream444, containing mostly hydrogen, to the recycle gas scrubber450. The recycle gas scrubber450can receive a lean amine stream452to wash the hydrogen by removing sulfur compounds. A rich amine stream454can exit a bottom of the recycle gas scrubber450that may also provide a top stream456that contains mostly hydrogen. The top stream456can be provided to the recycle gas compressor460, which may provide a recycle or discharge stream464that can be recycled within the hydrotreating zone400.

The separation zone500can include any suitable number of separation vessels and/or distillation columns to provide various hydrocarbon products. Although a single separation zone500is depicted, it should be understood that the separation zone500can include at least one of a separator and a fractionation column, and often includes multiple vessels to produce the desired hydrocarbon products and may include sub-zones.

Referring to the make-up hydrogen system, the three-stage compressor100can provide several hydrogen streams. As an example, a portion of the discharge stream114may be separated at point “C” and be provided as a stream162that may in turn be split into streams164and166and be provided to the respective naphtha hydrotreatment zone170and isomerization zone180. As such, the pressure of the discharge stream114is often suitable for zones requiring a lower pressure.

The discharge stream122from the second stage compressor120can be split into a stream124that can be routed at point “D” to the hydrotreating zone400and combined with recycled hydrogen from point “E”. The make-up and recycled hydrogen can be provided to the further feed404as well as the hydrotreating reactor420between the beds424and426.

The hydrogen from the discharge stream132can be provided to at least one of the slurry hydrocracking zone200and the hydrocracking zone300, and split into a stream140and collected at a point “H” and then provided, directly or indirectly, to the slurry hydrocracking zone200. Particularly, the hydrogen may be provided as a stream274and as a stream298. A recycled hydrogen stream276may be split into a recycled hydrogen portion262and a recycled hydrogen portion268. The recycled hydrogen portion262can combined with the stream274to form a combined hydrogen stream288provided to the feed204. Also, the recycled hydrogen portion268can be combined with the stream298to form a combined stream296provided to the effluent214, as hereinafter described. Another portion of the discharge stream132can be obtained as a stream148and be split into streams134and136to be provided to, respectively, the another feed304for the hydrocracking zone300and the hydrocracking reactor320along with recycled hydrogen from point “G”, as hereinafter described.

In addition, hydrogen gas can be recycled within and optionally among the zones200,300, and400. Particularly, a top stream258can be obtained from the cold separator250in the slurry hydrocracking zone200. Furthermore, a top stream264containing hydrogen can be obtained from the cold separator350in the hydrocracking zone300and be combined with the stream258to form a stream266provided to the recycle gas scrubber280. The gases can be cleaned by being contacted with the lean amine stream282and obtained as a top stream272from the recycle gas scrubber280. The stream272can be sent to the recycle gas compressor286to provide a discharge stream274that can be split into the stream276and a stream278at point “G” sent to the hydrocracking zone300. This recycled hydrogen can be combined with the make-up hydrogen discussed above, namely a recycled hydrogen stream138can be combined with the make-up hydrogen stream134to form a combined hydrogen stream142added to the another feed304, and a recycled hydrogen stream140may be combined with the make-up hydrogen stream136to form a combined hydrogen stream144provided to the hydrocracking reactor320between the first and second beds324and328.

In addition, the recycled hydrogen portion268split from the recycled hydrogen stream276can be combined with the stream298to form the combined hydrogen stream296before being added to the effluent214from the slurry hydrocracking reactor210.

Moreover, the top stream444from the hydrotreating zone400can be provided to the recycle gas scrubber450. After washing, the hydrogen stream456provided to the recycle gas compressor460may be discharged as the recycle or discharge stream464at point “E”. The recycle gas can be combined with the make-up hydrogen, particularly, recycle streams468and472may be combined with, respectively, make-up streams480and476to form combined hydrogen streams484and488. These combined hydrogen streams484and488may be provided, respectively, to the further feed404and the hydrotreating reactor420between the first and second beds424and426.

The embodiments disclosed herein can provide a recycle gas scrubber280servicing both a slurry hydrocracking zone200and a hydrocracking zone300further reducing capital costs. Generally, the hydrocracking zone300operates more effectively with a higher purity hydrogen. Therefore, make-up hydrogen can be provided to the inlet of the hydrocracking zone300to allow more severe processing. In addition to sharing of the recycle gas scrubber, the zones200and300may also share the recycle gas compressor286, further reducing capital costs. Integration can also reduce utilities, such as wash water and amine systems.