WO1997038066A1

WO1997038066A1 - Process for reverse staging in hydroprocessing reactor systems

Info

Publication number: WO1997038066A1
Application number: PCT/US1997/004270
Authority: WO
Inventors: Dennis R. Cash
Original assignee: Chevron U.S.A. Inc.
Priority date: 1996-04-09
Filing date: 1997-03-19
Publication date: 1997-10-16
Also published as: CZ374697A3; KR19990022632A; CA2223285A1; BR9706578A; JP2001523277A; SK166197A3; EP0851907A1; PL323925A1; AU2215997A; ID19791A

Abstract

A hydrocarbon feed (1) is passed to a denitrification and desulfurization zone (10); passing said denitrification and desulfurization zone effluent to a purification/cooling zone (20) for removal of NH3 and H2S and cooling, and recovering from said purification/cooling zone a hydrogen/light hydrocarbon stream (30) and a liquid stream containing dissolved gases (35); passing said liquid stream containing dissolved gases to a separation zone (40) and recovering a light product (45), a liquid bottoms (50), and at least one side-cut product therefrom (52); passing said liquid bottoms (50) and said side-cut (52) product and said hydrogen/light hydrocarbon stream from step (30) (b) to a hydrocracking or a hydrotreating zone; passing said hydrocracking or hydrotreating zone effluent (65) to said denitrification and desulfurization zone (10).

Description

PROCESS FORREVERSESTAGING IN HYDROPROCESSING REACTOR SYSTEMS

I. FIELD OF THE INVENTION

The present invention relates to the field of hydroprocessing. In particular, the present invention relates to hydroprocessing to obtain high conversions, product selectivity and selective hydrotreating of specific boiling range products.

II. BACKGROUND OF THE INVENTION

There are two conventional approaches in the petroleum hydroprocessing/hydrotreating art to obtain high conversions. "High conversions" includes sulfur removal, nitrogen removal, hydrocracking, ramsbottom carbon reduction, and the like. The two conventional processes include (a) a long residence time or low space velocity reactors, or (b) a separate reactor loop for the high conversion step after feed impurities are reduced in an initial reactor loop.

The second approach using separate reactor loop is effective. This is because the eliminated feed impurity byproducts such as H₂S, NH₃, are not present in the typically high concentrations that exist in the first reaction loop. There presence in high concentrations would tend to inhibit reaction rates in the second reaction loop.

There exists some conventional approaches in the art for obtaining good product selectivity. "Selectivity" includes obtaining a preferential yield of certain boiling range materials. These conventional processes include (a) recycling the undesirable products for reprocessing with the fresh feed, or (b) reprocessing the undesirable products in a separate reaction loop. Typical approaches in the art to selective hydrotreating of specific boiling range products include (a) overtreating of the entire feed to the point where the most difficult product specification is met, or (b) treating of the whole feed to a lesser extent followed by a separate hydrotreating of particular product cuts to meet the most difficult specifications.

It would be desirable to have a hydroprocessing process which achieved higher conversion or deeper treating processing while avoiding the drawbacks of known processes.

III. SUMMARY OF THE INVENTION

The present invention serves to accomplish these objectives in a single reaction loop including lower costs than multiple loops, while maintaining the advantages of a multiple loop system including higher reaction rates or catalysts tailored for pretreated feeds.

The present invention includes a process for reverse staging to obtain high conversion, selective hydrotreating and product selectivity in a hydroprocessing reactor system including performing in a single reactor loop a higher conversion or deeper treating processing in a top bed(s) of a reactor or in the lead reactor in a series reactor loop and performing the general feed processing in the reactor zones that follow.

IV. BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 depicts one embodiment of a flow diagram of the process of the invention utilizing a common vessel for housing the different treatment zones. FIG. 2 depicts an alternate embodiment of a flow diagram of the process of the invention utilizing separate vessels for housing the different treatment zones.

V. DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS

A. Overview of the Process: Upper and Lower Reaction Zones

The invention is a method of reverse stage hydrotreating a hydrocarbon feed to obtain high conversion, selective hydrotreating and product selectivity in a hydroprocessing reactor system. The method includes passing a hydrocarbon feed to a first hydrotreating zone, e.g., a denitrification and desulfurization zone. In that zone, the hydrocarbon feed is contacted at hydrotreating conditions, e.g., denitrification and desulfurization conditions, with a hydrotreating catalyst, e.g., a denitrification and desulfurization catalyst. After the contacting, a denitrification and desulfurization zone effluent is recovered.

The denitrification and desulfurization zone effluent is then passed to a purification/cooling zone (or termed a "NH₃ and H₂S and cooling zone"). Ammonia and H₂S are removed, typically by water scrubbing. The effluent is cooled by any conventional means, e.g., by heat exchanger. Recovered from the purification/cooling zone is a hydrogen/light hydrocarbon stream from the top and a liquid stream containing dissolved gases from the bottom. The hydrogen/light hydrocarbon stream is optionally passed to a second H₂S removal zone, typically using an amine adsorbent for H S removal. The recovered effluent from the optional H₂S removal zone is optionally passed to a second hydrotreating zone, e.g., the hydrocracking zone discussed below. The liquid stream containing dissolved gases is passed to a separation zone. Any conventional separation may be used, typically distillation. A light product and other fractions selected from a liquid bottoms, one or more side- or mid-cuts, and mixtures thereof, are recovered. The other fractions, i.e., liquid bottoms and/or one or more side- or mid-cuts, are passed to a second hydrotreating zone, e.g., a hydrocracking zone. There, at hydrocracking conditions, the liquid bottoms and/or one or more side- or mid-cuts are contacted with a hydrocracking catalyst. A hydrocracking zone effluent is then recovered. The hydrocracking zone effluent is then passed to the first hydrotreating zone, in one embodiment, a denitrification and desulfurization zone.

The use of the two reaction zones can be varied in this invention. That is, the first and second hydrotreating or reaction zone may each be a hydrocracking zone or a denitrification and desulfurization zone. In one embodiment of the invention, the lower zone which the fresh feed first contacts is a denitrification and desulfurization zone. The upper feed is a hydrocracking zone. In another embodiment, the reverse is true. Alternatively, each zone may both be either a hydrocracking zone or each a denitrification and desulfurization zone. Each may also be a combination or mixture of a hydrocracking zone and a denitrification and desulfurization zone.

B. Advantages of Process of the Invention

The present invention provides a single reaction loop. This single reaction loop method lowers costs as compared to the use of multiple reaction loops. Yet, the single reaction loop of the invention maintains the advantages of higher reaction rates or catalyst tailored for pretreated feeds of a multiple reaction loop system. The present invention accomplishes the final processing in the upper reaction zone or top bed or beds of a reactor or reactors in series while performing the general feed processing in the lower reaction zones that follow.

Another advantage of a series configuration rather than a parallel reactor configuration for the initial conversion and one for the high conversion step is that gas circulation is minimized thereby reducing both investment and operating costs. The capital cost is lower due to smaller equipment and piping. Operating costs are lower due to less compressor power to recirculate gas. The gas circulation is reduced relative to initial processing in a separate loop or parallel reactor of the same loop because (a) the high conversion effluent from the top reaction zone serves as a partial heat sink and thereby reduces the quench requirements for the initial processing in the zones which follow, (b) the unused hydrogen in the high conversion effluent from the top zone serves as a partial source of hydrogen for the initial processing in the zones which follow, and (c) the high conversion effluent from the top reaction zone helps to provide good distribution of the fresh feed and hydrogen for reaction on the catalyst in the zones which follow. Thus, the advantages of using a single loop are reduced investment cost and operating costs by not duplicating similar pieces of equipment in two separate loops, i.e., one for the initial processing and one for the high conversion step.

Advantages of processing the pretreated hydrocarbon in upper reaction zone or top bed separate from the fresh feed include (a) the top bed catalysts are not contaminated with feed impurities, (b) the reaction rate in the top beds is not inhibited by substantial quantities of hydrotreating byproducts, e.g., NH₃ and H₂S, and (c) hydrogen partial pressures are maximized for the finishing processes. In an optional embodiment in the case of residuum processing, the present process can also provide benefits in the lower reaction zones which includes reduced pulsation tendency.

C. Feedstocks and Products

Feedstocks suitable for use in the invention and desired products obtained include any conventional or known hydrocracking/hydroprocessing feedstocks and products. The feedstocks and desired products for the instant process include those disclosed in U.S. Patent Nos. 5,277,793; 5,232,577; 5,073,530; 4,430,203; and 4,404,088 which are incorporated herein by reference. In one preferable embodiment, the hydrocarbon feed is selected from a residuum, a vacuum gas oil, middle-distillates, and mixtures thereof.

D. Reaction Conditions and Catalysts

Suitable hydrocracking and hydroprocessing catalysts and reaction conditions include any conventional or known catalysts and reaction conditions. The catalysts and reaction conditions suitable for the instant process include those disclosed in U.S. Patent Nos. 5,277,793; 5,232,577; 5,073,530; 4,430,203; and 4,404,088 which are incorporated herein by reference. Where the reaction zone is a denitrification and/or desulfurization zone, the contacting occurs at denitrification and/or desulfurization conditions. Where the reaction zone is a hydrocracking zone, the contacting occurs at hydrocracking conditions.

When the above-described process is used to hydrotreat feedstocks to remove sulfur and nitrogen impurities, the following process conditions will typically be used: reaction temperature, 400°F-900°F; pressure, 500 to 5000 psig; LHSV, 0.5 to 20; and overall hydrogen consumption 300 to 2000 scf per barrel of liquid hydrocarbon feed. The hydrotreating catalyst for the beds will typically be a composite of a Group VI metal or compound thereof, and a Group VIII metal or compound thereof supported on a porous refractory base such as alumina. Examples of hydrotreating catalysts are alumina supported cobalt-molybdenum, nickel sulfide, tungsten-nickel sulfide, cobalt molybdate and nickel molybdate.

Correspondingly, when the process is used to hydrocrack feedstocks, the following operating conditions will normally prevail: reaction temperature, 400°F-950°F; reaction pressure 500 to 5000 psig; LHSV, 0.1 to 15; and hydrogen consumption 500 to 2500 scf per barrel of liquid hydrocarbon feed. The hydrocracking catalysts used for the beds will typically be a Group VI, Group VII, or Group VIII metal or oxides or sulfides thereof supported on a porous refractory base such as silica or alumina. Examples of hydrocracking catalysts are oxides or sulfides of Mo, W, V, and Cr supported on such bases.

Generally, where the reaction zone is a denitrification and/or desulfurization zone, the catalyst is any catalyst which will catalyze denitrification and/or desulfurization at denitrification and/or desulfurization conditions. Where the reaction zone is a hydrocracking zone, the catalyst is any catalyst which will catalyze hydrocracking at hydrocracking conditions.

VI. DETAILED DESCRIPTION OF THE DRAWINGS

Modifications of the process that is shown in the drawings and described in this specification that are obvious to those of ordinary skill in the oil refinery process art are intended to be within the scope of the invention. A. Figure 1

As illustrated in the flow diagram of FIG. 1 , the catalytic reactions used in this process are accomplished in two reaction zones 3 and 10. Vessel 2 houses both reaction zones 3 and 10. The initial processing is carried out in the second zone 10 and the high conversion processing carried out in the first zone 3. The flow scheme optionally includes other features which are common in hydroprocessing units such as preheating of liquid and gas feeds to the reactors (preheaters not shown), NH₃ and H₂S removal and effluent cooling and separation zone 20, optional recycle gas purification zone 31 , and recirculation streams 30 and 32, and product separation and distillation zone 40. Liquid bottoms stream 50, and/or side- or mid-cut 52, from distillation zone 40 are joined as stream 54. Stream 54 is passed to reaction zone 3. Make-up hydrogen stream 60 is added to gas recirculation stream 32 (also termed "hydrogen/light hydrocarbon stream 30" or "H₂S removal zone effluent 32"). Alternatively, make-up hydrogen stream 70 is added to feed stream 1 instead of, or in addition to, adding make-up hydrogen to stream 32.

Hydrocracking or deeper hydrotreating takes place in reaction zone 3 depending on the type of catalyst used in that zone. The effluent 65 from reaction zones passes to reaction zone 10. Fresh feed 1 is introduced at an intermediate point between reactor beds 3 and 10. It is processed in the presence of the effluent 65 from the upper reaction zone 3. Effluent 65 assists in distribution of feed stream 1 through reaction zone 10. Effluent 65 also acts as a heat-sink for the exothermic reaction in reaction zone 10.

The effluent 15 from the lower zone 10 is treated for NH₃ and H₂S removal in zone 20. Conventional methods, typically water washing, is utilized for the NH₃ and H₂S removal. Zone 20 is also a cooling and separation zone producing a gas stream 30 and a liquid stream containing dissolved gases 35. Conventional processing is used for the interrelationships of the NH₃ and H₂S removal and cooling and separation processes in zone 20. Zone 20 may include multiple units or sub-zones according to conventional means for accomplishing the NH₃ and H S removal and cooling and separation. A hydrogen rich gas stream 32 is recycled back to the reactors and then mixed with make-up hydrogen stream 60. Alternatively, or in addition to mixing make-up hydrogen stream 60 with hydrogen rich gas stream 32, make-up hydrogen stream 70 is mixed with oil feed stream 1. The recycle gas in stream 30 is optionally purified, e.g., by amine adsorbent for H₂S removal, in zone 31 before recirculation to the reactors. The recycle gas of stream 30 (or stream 32 if further purified in zone 31 ) is optionally fed to stream 54 for feeding to first reaction zone 3 or is passed, as stream 34, to feed stream 1 for feeding to second reaction zone 10.

B. Figure 2

The description of FIG. 2 is the same as for Figure 1 above, except for the following differences. In Figure 1 , a common vessel houses the reaction zones. In Figure 2, separate vessels 2 and 9 house reaction zones 3 and 10, respectively. In Figure 1 , there is a recycle gas purification zone 31. In Figure 2, this unit is omitted.

Claims

VII. CLAIMSWHAT IS CLAIMED IS:

1. A method of reverse stage hydrotreating a hydrocarbon feed to obtain high conversion, selective hydrotreating and product selectivity in a hydroprocessing reactor system, said method comprising:

a. Passing a hydrocarbon feed selected from a residuum, a vacuum gas oil, middle distillate, and mixtures thereof to a denitrification and desulfurization zone; contacting said hydrocarbon feed at a temperature of about 400°F to about 900°F; a pressure of about 500 psig to about 5000 psig; a flow rate of about 0.5 LHSV to about 20 LHSV; and an overall hydrogen consumption of about 300 to about 2000 scf per barrel of liquid hydrocarbon feed, with a denitrification and desulfurization catalyst; and recovering a denitrification and desulfurization zone effluent therefrom;

b. Passing said denitrification and desulfurization zone effluent to a purification/cooling zone for removal of NH₃ and H₂S and cooling, and recovering from said purification/cooling zone a hydrogen/light hydrocarbon stream and a liquid stream containing dissolved gases;

c. Passing said liquid stream containing dissolved gases to a separation zone and recovering a light product, a liquid bottoms, and at least one side-cut product therefrom;

d. Passing said liquid bottoms and said side-cut product and said hydrogen/light hydrocarbon stream from step (b) to a hydrocracking zone; contacting said liquid bottoms and said side-cut product at a temperature of about 400°F to about 950°F; a pressure of about 500 psig to about 5000 psig; a flow rate of about 0.1 LHSV to about 15 LHSV; and an overall hydrogen consumption of about 500 to about 2500 scf per barrel of liquid hydrocarbon feed, with a hydrocracking catalyst; and recovering a hydrocracking zone effluent therefrom; and

e. Passing said hydrocracking zone effluent to said denitrification and desulfurization zone.

2. A process for reverse staging to obtain high conversion, selective hydrotreating and product selectivity in a hydroprocessing reactor system comprising performing in a single reactor loop a higher conversion or deeper treating processing in an upper reaction zone of a reactor or in the lead reactor in a series reactor loop and performing the general feed processing in the reaction zones that follow.

3. The process of claim 2 further comprising feeding make-up hydrogen to said upper reaction zone or the reaction zones that follow.

4. The process of claim 2 further comprising:

a. Recovering an effluent from said reaction zones that follow and passing said effluent to a cooling zone;

b. Recovering from said cooling zone a hydrogen/light hydrocarbon stream and a liquid hydrocarbon stream containing dissolved gases;

c. Passing said hydrogen/light hydrocarbon stream to said upper reaction zone; and d. Passing said liquid stream containing dissolved gases to a separation zone.

5. The process of claim 3 wherein said general feed is selected from a residuum, a vacuum gas oil, a middle distillate, and mixtures thereof; and further comprising passing said hydrogen/light hydrocarbon stream in step (b) to a H₂S removal zone prior to passing to said upper reaction zone or lead reactor in step (c).

6. The process of claim 4 wherein said reactor zones that follow are hydrocracking zones and comprise a hydrocracking catalyst and wherein said hydrocracking zones have a temperature of about 400°F to about 950°F; a pressure of about 500 psig to about 5000 psig; a flow rate of about 0.1 LHSV to about 15 LHSV; and an overall hydrogen consumption of about 500 to about 2500 scf per barrel of liquid hydrocarbon feed.

7. The process of claim 5 wherein said reactor zones that follow are denitrification and desulfurization zones and said process further comprises contacting in said denitrification and desulfurization zones a denitrification and desulfurization catalyst with a general feed selected from residuum, a vacuum gas oil, middle distillates, and mixtures thereof, at a temperature of about 400°F to about 900°F; a pressure of about 500 psig to about 5000 psig; a flow rate of about 0.5 LHSV to about 20 LHSV; and an overall hydrogen consumption of about 300 to about 2000 scf per barrel of liquid hydrocarbon feed, and further comprises recovering a denitrification and desulfurization zone effluent.

8. The process of claim 4 wherein said reaction zones that follow are hydrocracking zones and said process further comprises contacting in said hydrocracking zones a hydrocracking catalyst with a general feed selected from residuum, a vacuum gas oil, middle distillates, and mixtures thereof, at a temperature of about 400°F to about 950°F; a pressure of about 500 psig to about 5000 psig; a flow rate of about 0.1 LHSV to about 15 LHSV; and an overall hydrogen consumption of about 500 to about 2500 scf per barrel of liquid hydrocarbon feed.

9. The process of claim 7 wherein said upper reaction zone or lead reactor is a hydrocracking zone and said process further comprises contacting in said hydrocracking zones a hydrocracking catalyst with at least a portion of said denitrification and desulfurization zone effluent, at a temperature of about 400°F to about 950°F; a pressure of about 500 psig to about 5000 psig; a flow rate of about 0.1 LHSV to about 15 LHSV; and an overall hydrogen consumption of about 500 to about 2500 scf per barrel of liquid hydrocarbon feed.

10. The process of claim 4 wherein said upper reaction zone or lead reactor is a denitrification and desulfurization zone.

11. The process of claim 9 further comprising:

a. Passing said denitrification and desulfurization zone effluent to a purification/cooling zone for removal of NH₃ and H₂S and cooling, and recovering from said purification/cooling zone a hydrogen/light hydrocarbon stream and a liquid stream containing dissolved gases; b. Passing said liquid stream containing dissolved gases to a separation zone and recovering a light product, a liquid bottoms, and at least one side-cut product therefrom; and

c. Passing said liquid bottoms and said side-cut product and said hydrogen/light hydrocarbon stream from step (b) to said upper reaction zone.

12. A method of processing a hydrocarbon feed comprising:

a. Passing a hydrocarbon feed to a second hydrotreating zone, contacting at hydrotreating conditions said hydrocarbon feed with a second hydrotreating catalyst, and recovering a second hydrotreating zone effluent therefrom;

b. Passing said hydrotreated product to a vapor-liquid separation zone, and recovering therefrom a light product and other fractions selected from a liquid bottoms, one or more middle cuts, and mixtures thereof;

c. Passing said other fractions to a first hydrotreating zone, contacting at hydrotreating conditions said hydrocarbon feed with a first hydrotreating catalyst, and recovering a first hydrotreating zone effluent therefrom; and

d. Passing said first hydrotreating zone effluent to said second hydrotreating zone.

13. The process of claim 12 further comprising feeding make-up hydrogen to said second hydrotreating zone.

14. The process of claim 12 further comprising: a. Passing said second hydrotreating zone effluent to a NH₃ and H₂S removal and cooling zone;

b. Recovering from said NH₃ and H₂S removal and cooling zone a hydrogen/light hydrocarbon stream and a liquid hydrocarbon stream containing dissolved gases;

c. Passing said hydrogen/light hydrocarbon stream to said first hydrotreating zone; and

d. Passing said liquid hydrocarbon stream containing dissolved gases to said vapor-liquid separation zone.

15. The process of claim 14 wherein said hydrocarbon feed is selected from a residuum, a vacuum gas oil, middle-distillates, and mixtures thereof.

16. The process of claim 12 wherein said second hydrotreating zone is a denitrification and desulfurization zone having a temperature of about 400°F to about 900°F; a pressure of about 500 psig to about 5000 psig; a flow rate of about 0.5 LHSV to about 20 LHSV; and an overall hydrogen consumption of about 300 to about 2000 scf per barrel of liquid hydrocarbon feed, and wherein said second hydrotreating catalyst comprises a denitrification and desulfurization catalyst.

17. The process of claim 16 wherein said second hydrotreating zone is a hydrocracking zone.

18. The process of claim 12 wherein said first hydrotreating zone is a hydrocracking zone having a temperature of about 400°F to about 950°F; a pressure of about 500 psig to about 5000 psig; a flow rate of about 0.1 LHSV to about 15 LHSV; and an overall hydrogen consumption of about 500 to about 2500 scf per barrel of liquid hydrocarbon feed, and wherein said first hydrotreating catalyst comprises a hydrocracking catalyst.

19. The process of claim 12 wherein said first hydrotreating zone is a denitrification and desulfurization zone.