Process for the intense conversion of residues, maximizing the gasoline yield

Abstract

A process for the intense conversion of a heavy hydrocarbon feed, comprising a) ebullated bed hydroconversion of the feed; b) separating at least a portion of hydroconverted liquid effluent obtained from a); c)i) either hydrotreatment of at least a portion of the gas oil fraction and of the vacuum gas oil fraction obtained from b), ii) or hydrocracking at least a portion of gas oil fraction and vacuum gas oil fraction obtained from b); d) fractionation of at least a portion of the effluent obtained from c)i) or c)ii); e) recycling at least a portion of unconverted vacuum gas oil fraction obtained from the fractionation d) to said first hydroconversion a); f) hydrocracking at least a portion of gas oil fraction obtained from fractionation d); g) recycling all or a portion of effluent obtained from f) to the fractionation d).

Claims

1. A process for the intense conversion of a heavy hydrocarbon feed, comprising the following steps: a) a first step for ebullated bed hydroconversion of the feed in the presence of hydrogen, comprising at least one three-phase reactor containing at least one ebullated bed hydroconversion catalyst; b) a step for separating at least a portion of the hydroconverted liquid effluent obtained from step a) into a gasoline fraction, a gas oil fraction, a vacuum gas oil fraction and an unconverted residual fraction; c) i) either a step for hydrotreatment of at least a portion of the gas oil fraction and the vacuum gas oil fraction obtained from step b) in a reactor comprising at least one fixed bed hydrotreatment catalyst; ii) or a first step for hydrocracking at least a portion of the gas oil fraction and the vacuum gas oil fraction obtained from step b) in a reactor comprising at least one fixed bed hydrocracking catalyst; d) a step for fractionating at least a portion of the effluent obtained from step c)i) or step c)ii) into a gasoline fraction, a gas oil fraction and an unconverted vacuum gas oil fraction; e) a step for recycling at least a portion of the unconverted vacuum gas oil fraction obtained from fractionation step d) to said first hydroconversion step a); f) a second step for hydrocracking at least a portion of the gas oil fraction obtained from fractionation step d); g) a step for recycling all or a portion of the effluent obtained from step f) to the fractionation step d).

2. The process according to claim 1, in which at least a portion of the residual unconverted fraction obtained from step b) is sent to a deasphalting section in which it is treated in an extraction step using a solvent under conditions for obtaining a deasphalted hydrocarbon cut and pitch.

3. The process according to claim 2, in which at least a portion of the deasphalted hydrocarbon cut obtained from the deasphalting step is sent to the hydrotreatment step c)i) or the hydrocracking step c)ii) as a mixture with the gas oil fraction and the vacuum gas oil fraction obtained from step b) and optionally with a straight run gas oil fraction and/or a straight run vacuum gas oil fraction.

4. The process according to claim 2, in which at least a portion of the deasphalted hydrocarbon cut obtained from the deasphalting step is sent to a second step for hydroconversion in the presence of hydrogen, said step being carried out in fixed bed or ebullated bed mode.

5. The process according to claim 4, in which the effluent obtained from the second hydroconversion step undergoes a separation step h) in order to produce at least a gasoline fraction, a gas oil fraction, a vacuum gas oil fraction and a residual unconverted fraction.

6. The process according to claim 5, in which at least a portion of the gas oil and vacuum gas oil fractions obtained from the separation step h) is sent to the hydrotreatment step c)i) or the hydrocracking step c)ii) as a mixture with the gas oil fraction and the vacuum gas oil fraction obtained from step b) and optionally with a straight run gas oil fraction and/or a straight run vacuum gas oil fraction.

7. The process according to claim 2, in which at least a portion of the vacuum gas oil fraction obtained from the fractionation step d) is recycled to the inlet of the deasphalting step and/or to the inlet of the first hydroconversion step.

8. The process according to claim 1, in which the hydroconversion step a) is operated under an absolute pressure in the range 5 to 35 MPa, at a temperature of 260° C. to 600° C. and at an hourly space velocity of 0.05 h.sup.−1 to 10 h.sup.−1.

9. The process according to claim 1, in which the operating conditions used in the hydrotreatment step c)i) are a pressure in the range 5 to 35 MPa, a temperature in the range 320° C. to 460° C. and a liquid hourly space velocity in the range 0.1 to 10 h.sup.−1.

10. The process according to claim 1, in which the operating conditions used in the first hydrocracking step c)ii) are a weighted average catalytic bed temperature in the range 300° C. to 550° C., a pressure in the range 5 to 35 MPa and a liquid hourly space velocity in the range 0.1 to 20 h.sup.−1.

11. The process according to claim 1, in which the second hydrocracking step is carried out at a temperature at least 10° C. below that employed during the hydrotreatment step c)i) or the first hydrocracking step c)ii), and at a liquid hourly space velocity (feed flow rate/volume of catalyst) which is at least 30% higher, preferably at least 45% higher, more preferably at least 60% higher than that employed during the hydrotreatment step c)i) or the first hydrocracking step c)ii).

12. The process according to claim 2 in which, in the deasphalting step, the typical temperature at the head of the extractor is in the range 60° C. to 220° C. and the temperature at the bottom of the extractor is in the range 50° C. to 190° C.

13. The process according to claim 1, in which the feed is selected from heavy hydrocarbon feeds of the atmospheric residue or vacuum residue type obtained, for example, by straight run oil cut distillation or by vacuum distillation of crude oil, distillate type feeds such as vacuum gas oils or deasphalted oils, asphalts obtained from oil residue solvent deasphalting, coal in suspension in a hydrocarbon fraction such as, for example, gas oil obtained by vacuum distillation of crude oil or a distillate obtained from the liquefaction of coal, used alone or as a mixture.

Description

BRIEF DESCRIPTION OF FIGURES

(1) FIG. 4 is a schematic representation of a process of the prior art.

(2) FIGS. 1-3 are schematic representations of various embodiments of the invention

EXAMPLES

(3) The feed used in these examples had the composition detailed in Table 1. It was an “Arabian Heavy” type residue, i.e. a vacuum residue obtained by distillation of a crude oil originating from the Arab Peninsula.

(4) TABLE-US-00001 TABLE 1 Composition of the feed used (“Arabian Heavy” vacuum residue) Property Unit Value Density — 1.040 Viscosity at 100° C. cSt 5200 Conradson Carbon % by wt 23.5 C7 asphaltenes % by wt 13.8 Nickel ppm 52 Vanadium ppm 140 Nitrogen ppm 5300 Sulphur % by wt 5.4 565° C..sup.− cut* % by wt 16.45 *cut containing products with a boiling point of less than 565° C.

(5) This feed was used in the various variations of the process illustrated by layouts 0, 1N, 2N, 3N (respectively represented in FIGS. 1, 2, 3 and 4) without the addition of straight run gas oil and/or straight run vacuum gas oil (SR GO-VGO) to the inlet of the hydrocracking step (HCK) or hydrotreatment step (HDT). Furthermore, regarding the layouts 2N and 3N, the recycle of VGO obtained from fractionation was sent only to the deasphalting unit (SDA), while in the case of layout 1N it was sent to the first hydroconversion unit H-Oil.sub.RC.

(6) The operating conditions for the conversion sections H-Oil.sub.RC, H-Oil.sub.DC, first and second hydroconversion unit, first and second HCK unit (hydrocracking units) in a first variation using two hydrocracking units as well as the solvent deasphalting unit (SDA) are summarized in Table 2.

(7) Table 2bis summarizes the operating conditions for the units in a second variation using the conversion sections H-Oil.sub.RC, H-Oil.sub.DC, first and second hydroconversion unit, one hydrotreatment unit HDT (replacing the first hydrocracking unit), one hydrocracking unit as well as one solvent deasphalting unit (SDA).

(8) The H-Oil hydroconversion units were operated with ebullated bed reactors and the hydrocracking units were operated with fixed bed reactors.

(9) The deasphalting unit was operated with an extraction column.

(10) TABLE-US-00002 TABLE 2 Operating conditions for units HCK HCK Parameter H-Oil.sub.RC H-Oil.sub.DC (1.sup.st step) (2.sup.nd step) SDA Liquid HSV h.sup.-1 0.25 0.3 0.5 1.2 — Pressure MPa 18 17 18 18 4.5 WABT SOR* ° C. 420 445 385 370 — Extractor 120 at temperature extractor head 90 at extractor bottom H.sub.2/feed m.sup.3/m.sup.3 400 300 1000 1000 — Solvent/feed m.sup.3/m.sup.3 — — — — 2/1 Extractor inlet m.sup.3/m.sup.3 4/1 Extract bottom Catalysts HOC 458 ™ HTS 458 ™ HRK 1448 ™ HYK 732 ™ — HYK 732 ™ — Catalyst NiMo/Al.sub.2O.sub.3 NiMo/Al.sub.2O.sub.3 NiMo/Al.sub.2O.sub.3 NiMo/zeolite Y compositions NiMo/zeolite Y *Weighted Average Bed Temperature at Start of Run

(11) TABLE-US-00003 TABLE 2bis Operating conditions for units Parameter H-Oil.sub.RC H-Oil.sub.DC HDT HCK SDA Liquid HSV h.sup.-1 0.25 0.3 0.7 0.8 — Pressure MPa 18 17 18 18 4.5 WABT SOR* ° C. 420 445 390 375 — Extractor 120 at temperature extractor head 90 at extractor bottom H.sub.2/feed m.sup.3/m.sup.3 400 300 1000 1000 — Solvent/feed m.sup.3/m.sup.3 — — — — 2/1 Extractor inlet m.sup.3/m.sup.3 4/1 Extract bottom Catalysts HOC 458 ™ HTS 458 ™ HRK 1448 ™ HYK732 ™ — Catalyst NiMo/Al.sub.2O.sub.3 NiMo/Al.sub.2O.sub.3 NiMo/Al.sub.2O.sub.3 NiMo/zeolite Y composition *Weighted Average Bed Temperature at Start of Run

(12) The catalysts used were commercial catalysts from Axens. The solvent used in the SDA unit was a mixture of butanes comprising 60% of nC4 and 40% of iC4.

(13) The yields for the products obtained with the operating conditions of Table 2 are indicated in Table 3 in the form of a percentage by weight for each product obtained with respect to the initial weight of the vacuum residue feed (SR VR) introduced into the process.

(14) TABLE-US-00004 TABLE 3 Yields of products as a function of the process layout used Variation 1N Variation 2N Variation 3N (HCK 1.sup.st (HCK 1.sup.st (HCK 1.sup.st % by weight vs. FIG. 0 step) step) step) SR VR* (prior art) (invention) (invention) (invention) LN 8 21 22 23 HN 9 42 45 49 GO 47 <1 <1 <1 VGO 5 1 7 2 VR + pitch 22 22 10 11 Total liquids 91 87 84 86 *LN: Light Naphta, HN: Heavy Naphta, GO: Gas Oil VGO: Vacuum Gas Oil, VR: Vacuum Residue, SR Straight Run.

(15) It appears that the variations 1N, 2N and 3N with a hydrocracking (HCK 1.sup.st step) in step c) in accordance with the invention favours the formation of light naphtha (LN) and heavy naphtha (HN) and a reduction in the overall liquid yield due to a more intense conversion. This reduction in the liquid yield is, however, very limited and in the range 4% to 7% compared with the prior art layout (layout 0).

(16) At the same time, a considerable increase in the naphtha yield was noticed; it passed from 8% (layout 0) to more than 20% (layouts 1N, 2N, 3N) for the light naphtha and from 9% to values in the range 40% to 50% for the heavy naphtha.

(17) The overall naphtha yield was thus 72% with layout 3N, with a negligible production of GO and VGO (<3%), the other principal products being pitch and vacuum residue (pitch obtained from the SDA unit and VR effluent obtained from the H-Oil.sub.DC unit), which represented approximately 10% of yield points. The layout 1N resulted in higher yields of VR+pitch than layouts 2N and 3N.

(18) Table 3bis describes the results obtained when the first hydrocracking of step c)i) was replaced with a hydrotreatment with the operating conditions indicated in Table 2bis.

(19) TABLE-US-00005 TABLE 3bis Yields of products as a function of the process layout used Variation 3N % by weight vs. FIG. 0 (HDT) SR VR* (prior art) (invention) LN 8 24 HN 9 51 GO 47 <1 VGO 5 1 VR + pitch 22 11 Total liquids 91 87

(20) It appears that variation 3N, carried out with a hydrotreatment (HDT) step instead of the first hydrocracking step, resulted in the substantial formation of light naphtha (LN) and heavy naphtha (HN) and a substantial reduction in the liquid yield compared with the prior art. The results obtained were of the same order of magnitude as for the variations 1N, 2N and 3N carried out with the first hydrocracking step (Table 3), or even slightly higher. Removal of the contaminants in the hydrotreatment section and thus their absence in the second hydrocracking step could explain these results.

(21) Table 4 indicates the properties of the various products obtained using the various layouts of the process.

(22) TABLE-US-00006 TABLE 4 Properties of products obtained from hydrocracking LN HN Cut points ° C. 30-80 80-150 Density — 0.685 0.755 Sulphur ppm <1 <1 P/N/A* % by wt 63/36/1 31/66/3 Cetane — — — *Paraffins/Naphthenes/Aromatics

(23) The naphthas obtained from the hydrocracking step may be upgraded as they are, for example in catalytic reforming units, in order to produce gasoline.

(24) The vacuum residues (VR obtained from the H-Oil.sub.RC unit, VR obtained from the H-Oil.sub.DC unit and asphalt obtained from deasphalting) were principally upgraded as heavy fuel after adjusting their viscosity by mixing with distillates available on site.

(25) The preceding examples can be repeated with similar success by substituting the generically or specifically described reactants and/or operating conditions of this invention for those used in the preceding examples.

(26) From the foregoing description, one skilled in the art can easily ascertain the essential characteristics of this invention and, without departing from the spirit and scope thereof, can make various changes and modifications of the invention to adapt it to various usages and conditions.