Integrated Process for Complete Conversion of Residue Feedstock

Abstract

The focus of this invention is the economic integration of two well-known technologies to provide an economical, integrated process unit for the complete conversion of residue feedstock. The technologies employed are heavy oil hydrocracking, which can be via an ebullated-bed, fixed-bed or slurry bed process, and coking, which can be via a delayed coking or fluid coking (with or without integrated gasification). The invention is most applicable to residue hydrocracking of high CCR and metals atmospheric and vacuum residues where coking of the unconverted hydrocracker residue is the most practical and economical method of hydrocracking bottoms disposal.

Claims

1. An integrated process for converting residue feedstock comprising: a) feeding a residue feedstock and a hydrogen stream into a residue hydrocracker unit containing catalyst to partially convert said residue feedstock and to create a hydrocracker vapor product stream and a hydrocracker liquid product stream; b) feeding said hydrocracker liquid product stream along with a steam stream to a steam stripper to create a stripper naphtha stream, a stripper vapor stream containing nominally C4 and lighter hydrocarbon gases and sour gases, and a stripper bottoms stream, said stripper bottoms stream comprising a heavy boiling fraction and a light boiling fraction; c) feeding said stripper bottoms stream to a heater to produce a heated stripper bottoms stream, said heated stripper bottoms stream comprising a heated heavy boiling fraction and a heated light boiling fraction; d) feeding said heated stripper bottoms stream comprising said heated heavy boiling fraction and said heated light boiling fraction into a coking unit wherein said heated heavy boiling fraction from said heated stripper bottoms stream produces a solid coke product and a light converted residue product stream; and e) feeding said light converted residue stream along with said heated light boiling fraction of said heated stripper bottoms stream to a coker fractionation unit to produce a fractionator vapor stream, a coker naphtha stream, a light gas oil stream, and a heavy gas oil stream.

2. The process of claim 1 further comprising: f) feeding said fractionator vapor stream, said stripper vapor stream from step b) and said hydrocracker vapor stream from step a) to gas a recovery unit; and g) feeding said coker naphtha stream from step e), said stripper naphtha stream from step b), said light gas oil stream, and said heavy gas oil stream to downstream processing units for production of final petroleum products.

3. The process of claim 1 wherein said residue hydrocracker unit operates at a reactor temperature of between 350-450 C., an inlet pressure of between 70-210 barg, and a space velocity of between 0.05 to 1.5 hr.sup.1.

4. The process of claim 1 wherein said residue hydrocracker unit operates at a reactor temperature of between 415-430 C., an inlet pressure of between 100-175 barg, and a space velocity of between 0.1-0.3 hr.sup.1.

5. The process of claim 1 wherein said residue hydrocracker unit comprises one or more ebullated-bed units operating in series or in parallel.

6. The process of claim 1 wherein said residue hydrocracker unit comprises one or more slurry bed reactors operating in series or in parallel.

7. The process of claim 1 wherein said residue hydrocracker unit comprises one or more fixed bed reactors operating in series or in parallel.

8. The process of claim 1 wherein said residue hydrocracker unit comprises one or more ebullated-bed reactors and one or more slurry-bed reactors operating in series or in parallel.

9. The process of claim 1 wherein said residue hydrocracker unit comprises one or more ebullated-bed reactors and one or more fixed-bed reactors operating in series or in parallel.

10. The process of claim 1 wherein said residue hydrocracker unit comprises one or more slurry-bed reactors and one or more fixed-bed reactors operating in series or in parallel.

11. The process of claim 1 wherein said heater from step c) is selected from the group comprising a gas-fired heater, an oil-fired heater, or an electric heater.

12. The process of claim 1 wherein said coking unit from step d) is selected from the group comprising a delayed coker, a fluid coker, and a fluid coker with gasification.

13. The process of claim 1 wherein said coke product from said coking unit from step d) is completely gasified.

14. The process of claim 1 wherein said steam stripper from step b) creates a stripper naphtha stream, a stripper vapor stream containing nominally C4 and lighter hydrocarbon gases and sour gases, a stripper bottoms stream, said stripper bottoms stream comprising a heavy fraction and a light fraction, and a residue hydrocracker diesel stream.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

[0029] FIG. 1 is a schematic showing Applicant's process for integration of hydrocracking and coking for the complete conversion of residue feedstock.

[0030] FIG. 2 is a schematic showing an optional configuration of Applicant's process wherein a side draw is taken from the residue hydrocracker stripper column and this stream routed directly to downstream processing.

DETAILED DESCRIPTION OF THE INVENTION

[0031] FIG. 1 is a schematic showing Applicant's process for efficiently and effectively integrating hydrocracking and coking for the complete conversion of residue feedstock.

[0032] A residue feedstock 10 is first processed along with hydrogen and catalyst (both not shown) in a residue hydrocracker unit 20 to partially convert the residue feedstock 10 and produce a hydrocracker gas stream 9 and a liquid conversion product stream 11 that comprises light hydrocarbon liquids from the cracking of the residue feedstock and unconverted residue.

[0033] Generally, for instance the residue hydrocracker unit 20 operates at a reactor temperature of between 350-450 C., an inlet pressure of between 70-210 barg, and a space velocity of between 0.05 to 1.5 hr.sup.1 but preferably between 415-430 C., an inlet pressure of between 100-175 barg, and a space velocity of between 0.1-0.3 hr.sup.1.

[0034] Additionally, the residue hydrocracker unit 20 may consist of one or more ebullated-bed reactors, one or more slurry bed reactors, one or more fixed bed reactors or some combination of the above.

[0035] The residue hydrocracking reactor(s) may employ a catalyst or catalysts, especially a granular catalyst comprising, on an amorphous substrate, at least one metal or metal compound with a hydrogenating function. This catalyst can be a catalyst comprising metals of group VIII, for example nickel and/or cobalt, most often in combination with at least one metal of group VIB, for example molybdenum and/or tungsten. For example, a catalyst comprising from 0.5 to 10% by weight of nickel and preferably from 1 to 5% by weight of nickel (expressed as nickel oxide NiO), and from 1 to 30% by weight of molybdenum and preferably from 5 to 20% by weight of molybdenum (expressed as molybdenum oxide MoO.sub.3) on an amorphous metal substrate can be used. This substrate will be chosen from, for example, the group formed by alumina, silica, silica-aluminas, magnesia, clays and mixtures of at least two of these minerals. This substrate can likewise contain other compounds, and, for example, oxides chosen from the group formed by boron oxide, zirconia, titanium oxide, and phosphoric anhydride.

[0036] The liquid conversion product stream 11 from the residue hydrocracker unit 20 is routed along with a separate steam stream 12 to a steam stripper 22. The steam stripper 22 removes dissolved light gases (nominally C4 and lighter hydrocarbons and sour gases) 8 and also separates the liquid conversion product stream 11 into a residue hydrocracker naphtha stream 13 (for instance with a typical nominal boiling range of isopentane (82 C.) to 180 C.) and a stripper bottoms stream 14 (with a typical nominal boiling range of greater than 180 C.).

[0037] Using the steam stripper 22 to remove the dissolved light gases stream 8 and hydrocracker naphtha stream 13 serves at least two important features of Applicant's unique processing configuration. First, the stripper bottoms stream 14, which serves as the feedstream for the coke drums in the coking unit, (24 and 24a), do not contain the lighter residue hydrocracker naphtha products 13, thus reducing the size of the coke drums required for processing the feed. Moreover, the removal of the residue hydrocracker naphtha stream 13 avoids co-mingling the coker naphtha stream 30 and residue hydrocracker naphtha 13. This is important since these streams require different downstream processing conditions and catalysts mainly due to the silicon compounds and diolefins found in a typical coker naphtha but not in a typical residue hydrocracker naphtha.

[0038] The stripper bottoms stream 14 contains all of the unconverted residue (also called in the present invention as heavy boiling fraction which has typically nominal 540 C.+ boiling range) as well as conversion products from the residue hydrocracker (also called in the present invention as light boiling fraction having nominal 180-540 C. boiling range) and, as mentioned above, comprises the feed to the coking unit. The stripper bottoms stream 14 is first routed to a heater unit 23 for heating. The heater may be a fuel gas-fired or oil-fired heater or an electric heater. According to the invention, the stripper (heated) bottoms stream 14 which comprises a heavy boiling fraction (nominal 540 C.+) and a light boiling fraction (nominal 180-540 C.) is treated in a coking unit wherein said heated heavy boiling fraction from said heated stripper bottoms stream produces a solid coke product and a light converted residue product stream (via cracking). Further, the nature of the coking unit is such that the heated light boiling fraction of the heated bottoms stream passes through said coking unit substantially unconverted (less than 20% of this fraction converts).

[0039] As shown in FIG. 1, the heated stripper bottoms 7 are injected into the coke drums 24 and 24a of the coking unit. According to the invention, the coking unit can be a delayed coking unit which is a batch process typically utilizing pairs of coke drums. As one is being filled with heated feed, the coke is being removed from the second via a hydraulic process using high-pressure water. According to another embodiment, the coking unit can be a fluid coking unit, with or without gasification, which is a different process, more akin to fluid catalytic cracking. Fluid coking is a continuous process in which coke is continuously removed and at least partially used to provide heat for the process in place of the heater 23. Fluid cokers operate at higher temperatures than delayed cokers (typically 510-570 C.). The drawings are representative of a delayed coking unit. Two coke drums 24 and 24a are indicated in this drawing but it is possible to have configurations utilizing different numbers of coke drums. The feed to the coke drums is heated to typically 450-490 C. and the drums typically operate at a pressure of 2.0-8.0 barg.

[0040] In the coke drums 24 and 24a, the final conversion of the residue feedstock 10 is completed with gas products and light liquid products produced and, depending on the coking technology selected, a solid coke product may also be produced. In the embodiment of FIG. 1, the coke drums 24 and 24a produce a combined hydrocracked product stream 16 comprising a liquid product (of a typical nominal boiling range of isopentane (82 C.) to 540 C.) and a coker gas stream comprised of nominal C4 and lighter hydrocarbons and sour gases and a coke product 15. The combined cracked product stream 16 is thereafter sent to a coker fractionator 26.

[0041] The coker fractionator 26 produces a gas stream comprised of nominal C4 and lighter hydrocarbons and sour gas 17, a liquid coker naphtha stream 30 (typically nominal isopentane (82 C.) to 180 C.), a combined coker and hydrocracker light gas oil stream 31 (typically nominal 180-350 C.), and from the column bottom, a combined coker and hydrocracker heavy gas oil stream 32 (typically nominal 350-540 C.). These streams (30, 31, and 32) are routed to downstream processing for production of final products (not shown). Although not shown, the fractionator vapor 17 is combined with overhead vapor from the residue hydrocracker stripper 8 and from the residue hydrocracker 9 and sent to a gas recovery section.

[0042] Importantly, the invention alleviates the need for and cost of atmospheric and vacuum fractionators specific to the residue hydrocracker and associated heat exchange equipment. As stated, this equipment is a major source of fouling for residue hydrocracking units and its elimination will result in a large increase in the plant on-stream time.

[0043] As noted above, the stripper bottoms are sent directly to the coker heater. The operation of the coker will be identical to the current state of the art with the exception that the feedstock will contain a higher content of vacuum gas oil necessitating larger coke drums due to higher vapor velocity in the drums. The inclusion of residue hydrocracker light products in the common atmospheric fractionator will result in a larger tower than in a stand-alone arrangement.

[0044] An advantage of the current invention is that there is no unconverted residue (UCO) stream to dispose of. All of the feed residue is converted to gases, light liquids, and (depending on the coking technology employed), a solid coke product.

[0045] FIG. 2 shows an optional configuration wherein an additional side draw 6 comprising diesel fraction with a typical nominal boiling range of 180-350 C. is taken from the residue hydrocracker steam stripper column 22 and this stream routed directly to downstream processing. The effect of adding the side draw 6 would increase the cost of the stripper tower, but reduce the cost of the coker heater, coke drums and coker fractionator.

[0046] The current invention results in a more economical and more reliable process for hydrocracking/coking of heavy residue. Relative to the current state-of-the-art, the invention configuration will save an estimated 25-30% of the cost of separate ebullated-bed/delayed coking fractionation sections and for certain feedstocks will increase the on-stream time by 5-10%.

[0047] The invention described herein has been disclosed in terms of a specific embodiment and application. However, these details are not meant to be limiting and other embodiments, in light of this teaching, would be obvious to persons skilled in the art. Accordingly, it is to be understood that the drawings and descriptions are illustrative of the principles of the invention, and should not be construed to limit the scope thereof.