JP6151717B2 - Integrated hydroprocessing and steam pyrolysis process including redistribution of hydrogen for direct processing of crude oil - Google Patents

Description

Related Application This application claims the benefit of US Provisional Application No. 61 / 591,814, filed Jan. 27, 2012. This disclosure is incorporated herein by reference in its entirety.

FIELD OF THE INVENTION The present invention relates to an integrated hydroprocessing and steam pyrolysis process for producing petrochemical products such as olefins and aromatics by direct processing of crude oil.

  Lower olefins (ie ethylene, propylene, butylene and butadiene) and aromatics (ie benzene, toluene and xylene) are basic intermediates widely used in the petrochemical and chemical industries. Pyrolysis, or steam pyrolysis, is typically the main type of process for the formation of these materials in the presence of steam and in the absence of oxygen. The feedstock for steam pyrolysis can include petroleum gas and distillates such as naphtha, kerosene and gas oil. Usually, the availability of these feedstocks is limited and expensive in crude oil refineries, requiring energy intensive process steps.

  A survey was conducted using heavy hydrocarbons as the feedstock for the steam pyrolysis reactor. A major drawback of conventional major heavy hydrocarbon pyrolysis operations is coke formation. For example, a steam cracking process for heavy liquid hydrocarbons is disclosed in US Pat. No. 4,217,204. In this patent, molten salt mist is introduced into the steam cracking reaction zone to minimize coke formation. In one example, an Arabian light crude with 3.1 wt% Conradson carbon residue could be used to continue the pyrolysis unit operation for 624 hours in the presence of molten salt. In the comparative example without the addition of molten salt, the steam cracking reactor was clogged due to coke formation in the reactor and became inoperable after only 5 hours.

Furthermore, the yield and distribution of olefins and aromatics using heavy hydrocarbons as a feedstock for steam pyrolysis reactors are different from those using light hydrocarbon feedstocks. Heavy hydrocarbons have a higher aromatic content than light hydrocarbons, as indicated by the higher Mining Bureau Correlation Index (BMCI). BMCI is a measurement of the aromaticity of the feedstock and is calculated as follows:

BMCI = 87552 / VAPB + 473.5 * (sp.gr.) − 456.8 (1)
Where
VAPB = volume average boiling point (Rankine scale),
sp. gr. = Specific gravity of the feedstock.

  As BMCI decreases, the yield of ethylene is expected to increase. Therefore, to obtain the desired olefin in higher yields with steam pyrolysis, while avoiding the formation of more undesirable products and coke in the coil section of the reactor, usually high paraffinic or low fragrance Supply of group-based raw materials is preferred.

  The absolute coke formation rate in the steam cracker is reported by Cai et al. "Coke Formation in Steam Crackers for Ethylene Production", Chem. Eng. & Proc. , Vol. 41, (2002), 199-214. In general, the absolute coke formation rate is ascending order, olefin> aromatic compound> paraffins (olefin represents heavy olefin).

  To be able to meet the increasing demand for these petrochemical products, other types of bulk feedstocks such as raw crude oil have become attractive to producers. The use of crude feedstock could minimize or eliminate the possibility of refineries becoming a bottleneck in the production of these petrochemical products.

  Although the steam pyrolysis process is well developed and suitable for its intended purpose, the choice of feedstock has been very limited.

  The systems and processes described herein are integrated with a hydroprocessing zone that includes hydrogen redistribution to enable direct processing of crude feedstocks and produce petrochemicals that contain olefins and aromatics. Provide a steam pyrolysis zone.

  Integrated hydroprocessing and steam pyrolysis process to produce olefins and aromatic petrochemicals by direct processing of crude oil reduced the step of separating crude oil into light and heavy components, heavy components and hydrogen Loading into a hydroprocessing zone operating under conditions effective to produce a hydroprocessing effluent with contaminant content, increased paraffinity, reduced Mining Authority correlation index, and increased National Petroleum Institute specific gravity Loading the hydrotreating effluent and steam into the convection section of the steam pyrolysis zone, heating the mixture from the convection section of the steam pyrolysis zone and sending it to the gas-liquid separation section, from the steam pyrolysis zone The step of removing the residual part from the gas-liquid separation part, the light component from the first separation step, the light part from the gas-liquid separation part, Loading the zone pyrolysis section, recovering the mixed product stream from the steam pyrolysis zone, separating the mixed product stream, purifying the hydrogen recovered from the mixed product stream and reusing it in the hydroprocessing zone And recovering olefins and aromatics from the separated mixed product stream.

  As used herein, the term “crude oil” should be understood to include whole crude oil from conventional sources, crude oil that has undergone some pretreatment. Also, the term crude oil should be understood to include those that have undergone water-oil separation; and / or gas-oil separation, and / or desalination, and / or stabilization.

Other aspects, embodiments, and advantages of the process of the present invention are discussed in detail below. Furthermore, both the foregoing information and the following detailed description are merely exemplary examples of various aspects and embodiments, and may be summarized or framed for an understanding of the nature and characteristics of the claimed features and embodiments. It will be understood that it is intended to provide work. The accompanying figures are exemplary and are provided to gain a further understanding of the various aspects and embodiments of the process of the invention.
The invention is described in more detail below with reference to the accompanying drawings.

FIG. 3 illustrates a process flow of an embodiment of an integration process described herein. 2A-2C. 2 is a perspective, top, and side schematic view of a gas-liquid separation device used in certain steam pyrolysis unit embodiments in the integrated process described herein. FIG.

  A process flow diagram including an integrated hydroprocessing and steam pyrolysis process and system including hydrogen redistribution is shown in FIG. The integrated system typically includes an initial feed separation zone 20, a selective catalytic hydroprocessing zone, a steam pyrolysis zone 30, and a product separation zone.

Typically, the crude feed is flushed so that light fractions (including further minimum hydrocarbons that require cracking and easily released hydrogen, for example, having a boiling point in the range of up to about 185 ° C.) Only the fraction that needs to be hydrogenated, i.e., the fraction with less than a predetermined hydrogen content, is hydrotreated. This is advantageous because the hydrogen partial pressure in the hydrotreating reactor is increased and the efficiency of hydrogen transfer via saturation is improved. This reduces hydrogen dissolution loss and H ₂ consumption. Easily released hydrogen contained in the crude feedstock is redistributed to maximize the yield of products such as ethylene. Hydrogen redistribution enables a reduction in the overall heavy product and an increase in light olefin production.

  The first separation zone 20 includes an inlet for receiving the feed stream 1, a discharge outlet for the light fraction 22 and a discharge outlet for the heavy fraction 226. Separation zone 20 may be a single stage separation device such as a flash separator having a cut point in the range of about 150 ° C to about 260 ° C. In certain embodiments, the light fraction 22 may be a naphtha fraction. Table 1 shows the hydrogen content with various cut points.

In further embodiments, the separation zone 20 includes or consists essentially of a cyclonic phase separation device, or other separation device based on physical or mechanical separation of vapor and liquid (ie, flash Works when there is no zone). An example of a gas-liquid separator is illustrated by FIGS. 2A to 2C and will be described based on them. A similar arrangement of gas-liquid separators is described in US 2011/0247500. This patent is incorporated herein by reference in its entirety. In embodiments where the separation zone includes or consists essentially of a separation device based on physical or mechanical separation of vapor and liquid, the cut point is based on the vaporization temperature and fluid velocity of the material entering the device. Can be adjusted.

  The hydroprocessing zone includes a hydrogenation reaction zone 4 with an inlet that receives a mixture of light hydrocarbon fraction 21 and hydrogen 2 recycled from the steam pyrolysis product stream, and optionally supplemental hydrogen. The hydrogenation reaction zone 4 further includes an outlet for discharging the hydroprocessing effluent 5.

The reactor effluent 5 from the hydrogenation reactor is cooled in a heat exchanger (not shown) and sent to a high pressure separator 6. The separator overhead stream 7 is purified in an amine unit 12 and the resulting hydrogen rich gas stream 13 is sent to a recycle compressor 14 and used as recycle gas 15 in a hydrogenation reactor. The bottom stream 8, which is substantially in liquid phase from the high pressure separator 6, is cooled and introduced into the low pressure cold separator 9, where it is divided into a gas stream and a liquid stream 10. The gas from the low pressure cold separator includes any light hydrocarbon such as hydrogen, H ₂ S, NH ₃ and C ₁ -C ₄ hydrocarbons. In typical examples, these gases are sent for further processing such as flare processing or fuel gas processing. In certain embodiments herein, the hydrogen gas stream 11 comprising any light hydrocarbons, such as hydrogen, H ₂ S, NH ₃ and C ₁ -C ₄ hydrocarbons, is converted to a steam cracker product 44. It is collected by combining with. All or part of the liquid stream 10 serves as a feed to the steam pyrolysis zone 30.

  Typically, the steam pyrolysis zone 30 can be operated based on the convection section 32 and steam pyrolysis unit operation known in the art, i.e. loading the pyrolysis feed into the convection section in the presence of steam. A thermal decomposition unit 34 is included. Further, in certain optional embodiments described herein, gas-liquid separator 36 is provided between portions 32 and 34 (as shown by the dotted lines in FIG. 1). The gas-liquid separation unit 36 through which the heated steam cracking feedstock from the convection unit 32 passes may be a separation device based on physical or mechanical separation of vapor and liquid.

  In one embodiment, the gas-liquid separator is illustrated and described on the basis of FIGS. A similar arrangement of gas-liquid separators is described in US 2011/0247500. This patent is incorporated herein by reference in its entirety. In this device, vapor and liquid pass through a cyclonic array, so that the device operates isothermally and with a very short residence time. In general, the steam is swirled in a circular pattern to create force and heavier drops and liquid are captured and added, for example, to the pyrolysis fuel oil blend and directed to the liquid outlet as fuel oil 38, where the steam is steam It is directed to the pyrolysis section 34 as a charge 37 through the outlet. Vaporization temperatures and fluid velocities are varied to adjust the approximate temperature cutoff point, for example, in certain embodiments, to about 540 ° C., which is compatible with the residual fuel blend.

  The quench zone 40 includes an inlet in fluid communication with the outlet of the steam pyrolysis zone 30, an inlet for receiving the quench solution 42, an outlet that discharges the quench mixed product stream 44, and an outlet that discharges the quench solution 46.

  Typically, the intermediate quench mixed product stream 44 is converted to an intermediate product stream 65 and hydrogen 62, which is purified in this process and used in the hydrogenation reaction zone 4 as recycled hydrogen 2. Typically, the intermediate product stream 65 is fractionated into the final product and residual oil in the separation zone 70. This separation zone may be, for example, one or more separation units such as a plurality of fractionation towers including deethanizers, depropanizers and debutanes, known to those skilled in the art. For example, a suitable apparatus is described in “Ethylene”, Ullmann Encyclopedia of Industrial Chemistry, Volume 12, pages 531-581, in particular in FIGS. 24, 25 and 26. This document is incorporated herein by reference.

  The product separation zone 70 typically includes an inlet in communication with the product stream 65 fluid, and a plurality of product outlets 73-78. These outlets include an outlet 78 for discharging methane, an outlet 77 for discharging ethylene, an outlet 76 for discharging propylene, an outlet 75 for discharging butadiene, an outlet 74 for discharging mixed butylene, and an outlet for discharging pyrolysis gasoline. 73 is included. Further, an outlet for discharging the pyrolysis fuel oil 71 is provided. Optionally, the fuel oil portion 38 from the gas-liquid separator 36 is combined with the pyrolysis fuel oil 71 to form a pyrolysis fuel oil blend 72, for example, a low sulfur fuel oil blend that is further processed at an off-site refinery. Can be recovered as It should be noted that although six product outlets are shown, fewer or more outlets may be provided, depending on, for example, the separation unit configuration employed and the yield and distribution requirements.

  In the process embodiment employing the arrangement shown in FIG. 1, the crude feed 1 is separated into a light fraction 22 and a heavy fraction 21 in an initial separation zone 20. The light fraction 22 is sent to the pyrolysis section 36, i.e., bypassing the hydrotreating zone, and combined with the steam cracked intermediate product portion to produce a mixed product stream as described herein.

  The heavy fraction 21 is mixed with an effective amount of hydrogen 2 and 15 to form a mixed stream 3. Mixture 3 is charged to the inlet of selective hydrogenation reaction zone 4 at a temperature in the range of 300 ° C to 450 ° C. In certain embodiments, the hydrogenation reaction zone 4 is comprised of commonly owned U.S. Patent Publication Nos. 2011/0083996 and International Publication Nos. WO2010 / 009077, WO2010 / 009082, WO2010 / 009089, and WO2009 / 073436. One or more unit operations described in the issue. All these patents are incorporated herein by reference in their entirety. For example, the hydrotreating zone has one or more beds containing an effective amount of hydrodemetallation catalyst and hydrodearomatization, hydrodenitrogenation, hydrodesulfurization and / or hydrocracking functions. One or more beds containing an effective amount of the hydrogenation catalyst can be included. In additional embodiments, the hydrogenation reaction zone 4 may include more than two catalyst beds. In a further embodiment, the hydrogenation reaction zone 4 comprises a plurality of reaction vessels, each containing for example one or more catalyst beds of different functions.

Hydrogenation reaction zone 4 is under parameters effective for hydrodemetallation, hydrodearomatization, hydrodenitrogenation, hydrodesulfurization, and / or hydrocracking of the feed crude feed. Works with. In certain embodiments, the hydrotreatment is performed using the following conditions: operating temperature in the range of 300 ° C. to 450 ° C., operating pressure in the range of 30 bar to 180 bar, and 0.1 h ^{−1 to} 10 h ^−1. Liquid space velocity in the range of.

Reactor effluent 5 from hydroprocessing zone 4 is cooled in an exchanger (not shown) and sent to high pressure cold or hot separator 6. The separator overhead stream 7 is washed in the amine unit 12 and the resulting hydrogen rich gas stream 13 is passed to a recycle compressor 14 and used as recycle gas 15 in the hydrogenation reaction zone 4. The separator bottom stream 8, which is substantially in liquid phase from the high pressure separator 6, is cooled and then introduced into the low pressure cold separator 9. Hydrogen, H 2 _S, NH ₃ and C ₁ -C ₄ residue gas stream 11, such as any of light hydrocarbons may include hydrocarbons can usually discharged from the low pressure cold separator, flare or a fuel gas treatment Sent for further processing. In a particular embodiment of the process, hydrogen is recovered by combining stream 11 (shown in dotted lines) with stream 44 which is the pyrolysis gas from the steam cracker product. The bottom stream 10 from the low pressure separator 9 is sent to the steam pyrolysis zone 30.

  Hydroprocessing effluent 10 has a reduced content of contaminants (ie, metals, sulfur and nitrogen), increased paraffinity, reduced BMCI, and increased American Petroleum Institute (API) specific gravity.

  The hydrotreatment effluent 10 is sent to the convection section 32 in the presence of an effective amount of steam introduced, for example, through a steam inlet (not shown). In the convection section 32, the mixture is heated to a predetermined temperature using, for example, one or more waste heat streams or other suitable heating arrangements. The heated light fraction and vapor stream mixture is sent to the gas-liquid separator 36 where the portion 38 is discharged because it can be used for a fuel oil component suitable for blending with the pyrolysis fuel oil 71. The remaining hydrocarbon portion is sent to the pyrolysis section 34 along with the light fraction 22 from the initial separation zone 20, eg, the naphtha fraction, to produce a mixed product stream 39.

  Steam pyrolysis zone 30 operates under parameters effective to make pyrolysis effluent 10 a desired product such as ethylene, propylene, butadiene, mixed butenes and pyrolysis gasoline. In certain embodiments, steam cracking is performed under the following conditions: temperatures in the range of 400 ° C. to 900 ° C. in the convection and pyrolysis, and in the range of 0.3: 1 to 2: 1 in the convection. Steam / hydrocarbon ratio; and residence time in the convection and pyrolysis section in the range of 0.05 seconds to 2 seconds.

  In certain embodiments, the gas-liquid separator 36 includes one or more gas-liquid separators 80 as shown in FIGS. The gas-liquid separator 80 operates economically and is maintenance-free because it does not require power or chemical supply. Typically, the device 80 includes three ports, an inlet port for receiving a gas-liquid mixture, a vapor outlet port and a liquid outlet port for discharging and collecting separated vapor and liquid, respectively. The apparatus 80 converts the incoming mixture from linear speed to rotational speed by a global flow pre-rotation part (pre-rotation part), a controlled centrifugal effect for pre-separating the vapor from the liquid (residual oil), And a combination of phenomena including a cyclone effect that promotes vapor separation from the liquid (residual oil). In order to achieve these effects, the apparatus 80 includes a pre-rotation section 88, a controlled cyclone vertical section 90 and a liquid collection / sedimentation separation section 92.

As shown in FIG. 2B, the preliminary rotating portion 88 is disposed between the cross section (S1) and the cross section (S2), between the controlled preliminary rotating element, and between the cross section (S2) and the cross section (S3). , Including a connecting element to the controlled cyclonic vertical 90. The gas-liquid mixture coming from the inlet 82 with a diameter (D1) enters the device tangentially at the cross section (S1). The area of the inlet cross-section (S1) for the incoming flow is at least 10% of the area of the inlet 82 according to the following formula:

  The pre-rotating element 88 defines a curvilinear flow path and is characterized by a continuously decreasing or increasing cross section from the inlet cross section S1 to the outlet cross section S2. In a particular embodiment, the ratio (S2 / S1) between the outlet cross section (S2) and the inlet cross section (S1) of the controlled pre-rotating element is in the range of 0.7 to 1.4.

  The rotational speed of the mixture depends on the radius of curvature (R1) of the center line of the pre-rotating element 38, which is defined as a curve connecting the center points of the continuously changing cross section of the pre-rotating element 88. In a specific embodiment, with an open angle (αR1) range of 150 ° to 250 °, the radius of curvature (R1) is in the range of 2-6 as R1 / D1.

  Although the cross-sectional shape of the inlet cross-section S1 is shown as a substantially square shape, it may be a rectangle, a rounded rectangle, a circle, an ellipse, or another straight line-shaped shape, a curved shape, or a combination of the above shapes. In certain embodiments, the cross-sectional shape along the curved flow path of the pre-rotating element 38 through which the fluid passes changes continuously, eg, from approximately square to rectangular. The cross section of the element 88 that continuously changes to a rectangle advantageously maximizes the open area, thus achieving gas separation from the liquid mixture and achieving a uniform velocity profile at an early stage, and shearing in the fluid stream. Enables stress minimization.

  The fluid flow from the section (S2) of the controlled pre-rotating element 88 is sent from the section (S3) via the connecting element to the controlled cyclone vertical section 90. The connecting element includes an open area and is opened and connected to or integrated with the inlet of the controlled cyclonic vertical 90. The fluid flow enters the controlled cyclonic vertical section 90 at a high rotational speed, creating a cyclone effect. In a particular embodiment, the ratio (S3 / S1) of the outlet cross section (S3) to the inlet cross section (S2) of the connecting element is in the range of 2-5.

  The high rotational speed mixture enters the cyclone vertical section 90. The kinetic energy is reduced and the vapor is separated from the liquid by the cyclone effect. The cyclone forms an upper level 90 a and a lower level 90 b in the cyclone type vertical portion 90. At the upper level 90a, the mixture is characterized by a high concentration of vapor, while at the lower level 90b, the mixture is characterized by a high concentration of liquid.

  In a specific embodiment, the inner diameter D2 of the cyclone vertical portion 90 ranges from 2 to 5 as D2 / D1, and may be constant in the direction of its height, and the length (LU) of the upper portion 90a is: LU / D2 is in the range of 1.2 to 3, and the length (LL) of the low portion 90b is in the range of 2 to 5 as LL / D2.

  The end of the cyclonic vertical section 90 proximate to the steam outlet 84 is connected to a partially open discharge riser pipe connected to the pyrolysis section of the steam pyrolysis unit. In certain embodiments, the partially open discharge tube diameter (DV) ranges from 0.05 to 0.4 as DV / D2.

  Thus, in certain embodiments, and depending on the nature of the incoming mixture, a large volume fraction of vapor exits from the outlet 84 of the device 80 through a partially open discharge tube of diameter DV. A low vapor concentration or vapor free liquid phase (eg, residual oil) exits through the bottom portion of the cyclone vertical section 90 of cross-sectional area S4 and is collected in the liquid collector and settling tube 92.

In certain embodiments, the connection area between the cyclonic vertical 90 and the liquid collector and settling tube 92 is at an angle of 90 ^° . In certain embodiments, the internal diameter of the liquid collector and settling tube 92 ranges from 2 to 4 as D3 / D1, is constant throughout the length of the tube, and the length (LH) of the liquid collector and settling tube 92 is , LH / D3 is in the range of 1.2-5. Low vapor volume fraction liquid is withdrawn from the apparatus through a tube 86 of diameter DL. In certain embodiments, the tube 86, as DL / D3, ranges from 0.05 to 0.4 and is located at or near the bottom of the settling tube.

  Although the various members are described separately and together with separate parts, the device 80 can be formed, for example, as a cast or molded unitary structure, or, for example, the members described herein. Those skilled in the art will appreciate that separate parts that may or may not exactly correspond to and parts can be assembled by welding or otherwise joined together.

  While various dimensions are described as diameters, it will be understood that these values may be equivalent effective diameters in embodiments where the component is not cylindrical.

  The mixed product stream 39 is sent to the quench zone 40 inlet with a quench solution 42 (e.g., water and / or pyrolysis fuel oil) introduced via a separate inlet, e.g., at a reduced temperature of about 300 <0> C. An intermediate quench mixed product stream 44 is produced and the consumed quench solution 46 is discharged. In a typical example, the gas mixture effluent 39 from the cracker is a mixture of hydrogen, methane, hydrocarbons, carbon dioxide and hydrogen sulfide. After cooling by water or oil quench, the mixture 44 is typically compressed in a 4-6 multi-stage compressor zone 51 to produce a compressed gas mixture 52. The compressed gas mixture 52 is processed in a caustic processing unit 53 to produce a gas mixture 54 free of hydrogen sulfide and carbon dioxide. The gas mixture 54 is further compressed in the compressor zone 55, and the resulting pyrolysis gas 56 is typically subjected to cryogenic treatment in the unit 57 and dehydrated and further dried using molecular sieves.

  The low-temperature cracked gas stream 58 from the unit 57 is sent to a demethanizer tower 59, from which a top stream 60 containing hydrogen and methane derived from the cracked gas stream is generated. Thereafter, the bottom stream 65 from the demethanizer tower 59 is sent to a product separation zone 70 comprising fractionation towers such as a deethanizer, a depropanizer and a debutane tower for further processing. Process configurations including different arrangements of demethanizer, deethanizer, depropanizer, and debutane towers can also be employed.

  In the process described herein, after separation of methane in the demethanizer 59 and recovery of hydrogen in unit 61, hydrogen 62 is typically obtained with a purity of 80-95 vol%. Recovery methods in unit 61 include cryogenic recovery (eg, at a temperature of about −157 ° C.). Thereafter, the hydrogen stream 62 is sent to a hydrogen purification unit 64 such as a pressure swing adsorption (PSA) unit to obtain a hydrogen stream 2 of 99.9% + purity or sent to a membrane separation unit for about 95. % Purity hydrogen stream 2 is obtained. The purified hydrogen stream 2 is then reused to function as the major component of hydrogen required for the hydroprocessing zone. In addition, a small portion is available for the hydrogenation reaction of acetylene, methylacetylene and propadiene (not shown). Further, in the process described herein, the methane stream 63 can optionally be recycled to the steam cracker and used as fuel for the burner and / or heater.

  The bottom stream 65 from the demethanizer 59 is conveyed to the inlet of the product separation zone 70 and discharged via outlets 78, 77, 76, 75, 74 and 73, respectively, methane, ethylene, propylene, Separated into butadiene, mixed butylene and pyrolysis gasoline. Typically, pyrolysis gasoline contains C5-C9 hydrocarbons, and benzene, toluene and xylene can be extracted from this fraction. Optionally, the portion 38 discharged from the gas-liquid separator 36 is combined with pyrolysis fuel oil 71 (eg, a substance that boils at a temperature above the boiling point of the lowest boiling C10 compound (known as the “C10 +” stream)). This mixed stream can then be removed as a pyrolysis fuel oil blend 72, for example, a low sulfur fuel oil blend that is further processed at an off-site refinery.

Advantages of the system described herein with respect to FIG. 1 include increased hydrogen partial pressure in the reactor and improved efficiency of hydrogen transfer via saturation. Normal,
PT = PA + PB + PC (2)
It is. In this case,
PT = PNaphtha + PH2 + PX + PY (3)
If PNaphta is excluded, PT remains the same, and therefore PH2 (and PX and PY) increase.
Rate (saturation) = kSat [reactant] x [pH 2] (4)

Also, the system described herein reduces dissolution loss and reduces H ₂ consumption. This allows a closed or nearly closed system operation.

  In certain embodiments, the selective hydrotreating or hydrotreating process increases the paraffin content of the feedstock (or reduces BMCI) by saturating aromatics, particularly polycyclic aromatics, followed by mild hydrocracking. Can be lowered). When crude oil is hydrotreated, contaminants such as metals, sulfur and nitrogen can be removed by passing the feed through a series of layered catalysts having catalytic functions of demetallization, desulfurization and / or denitrification.

In one embodiment, the order in which the catalyst performs hydrodemetallation (HDM) and hydrodesulfurization (HDS) is as follows.
a. Hydrodemetallation catalyst. The catalyst in the HDM part is usually supported on a gamma alumina support having a surface area of about 140-240 m ² / g. This catalyst is best described as having a very high pore volume, for example exceeding 1 cm ³ / g. The pore size itself is usually predominantly macroporous. This is necessary to provide a large volume for the incorporation of metals and any dopants on the catalyst surface. In a typical example, the active metal on the catalyst surface is a sulfide of nickel and molybdenum with a Ni / Ni + Mo ratio of less than 0.15. The concentration of nickel on the HDM catalyst is lower than other catalysts because significant nickel and vanadium are expected to deposit from the feedstock itself during removal and function as a catalyst. The dopant used is one or more of phosphorus (see, eg, US Patent Publication No. 2005/0211603, which is incorporated herein by reference), boron, silicon, and halogen. It may be. The catalyst may be in the form of an alumina extrudate or alumina beads. In certain embodiments, alumina beads are used to facilitate removal of the catalytic HDM bed in the reactor, since metal uptake is in the range of 30-100% at the top of the bed.
b. An intermediate catalyst can also be used to make the transition between HDM and HDS functions. It has an intermediate metal filler and a pore size distribution. The catalyst in the HDM / HDS reactor is substantially an alumina support in the form of an extrudate, optionally at least one catalyst metal of Group VI (eg, molybdenum and / or tungsten), and / or VIII. It is composed of at least one catalytic metal of the group (eg nickel and / or cobalt). The catalyst also optionally includes at least one dopant selected from boron, phosphorus, halogen and silicon. Physical properties include a surface area of about 140-200 m ² / g, a pore volume of at least 0.6 cm ³ / g, and mesoporous, including pores in the range of 12-50 nm.
c. The catalysts in the HDS section may include those having a gamma alumina base support material with a typical surface area closer to the higher end of the HDM range, for example, in the range of about 180-240 m ² / g. This required larger surface of HDS results in a relatively small pore volume, eg, less than 1 cm ³ / g. The catalyst includes at least one Group VI element, such as molybdenum, and at least one Group VIII element, such as nickel. The catalyst also contains at least one dopant selected from boron, phosphorus, silicon and halogen. In certain embodiments, cobalt can be used to provide a relatively high level of desulfurization. The metal filler for the active phase is more because the required activity is higher, so that the molar ratio Ni / Ni + Mo is in the range of 0.1 to 0.3, and the (Co + Ni) / Mo molar ratio Is in the range of 0.25 to 0.85.
d. For example, Appl. Catal. As described in A General, 204 (2000) 251, the final catalyst (which may optionally replace the second and third catalysts) is the feedstock (rather than the primary function of hydrodesulfurization). Designed to perform hydrogenation. The catalyst will also be activated by Ni and the support will be large pore gamma alumina. Physical properties include a surface area closer to the higher end of the HDM range, for example, 180-240 m ² / g. This required larger surface of HDS results in a relatively small pore volume, eg, less than 1 cm ³ / g.
The methods and systems described herein provide improvements such as the ability to produce petrochemicals such as olefins and aromatics using crude oil as a feedstock compared to known steam pyrolysis processes. Additional impurities such as metals, sulfur and nitrogen compounds are also significantly removed from the starting feed, eliminating the need for post-treatment of the final product.

  In addition, the hydrogen generated from the steam cracking zone is reused in the hydroprocessing zone, minimizing the demand for new hydrogen. In certain embodiments, the integrated system described herein requires new hydrogen only to begin operation. Once the reaction has reached equilibrium, the hydrogen purification system can provide high purity hydrogen sufficient to maintain the operation of the entire system.

  While the method and system of the present invention have been described above and in the accompanying drawings, modifications will be apparent to those skilled in the art and the scope of protection of the invention should be defined by the following claims.

Claims (7)

An integrated hydroprocessing and steam pyrolysis process for the direct processing of crude oil to produce olefins and aromatic petrochemicals,
a. Separating the crude oil into light and heavy components at a cut point in the range of 180 ° C to 260 ° C ;
b. The step of loading the heavy component and hydrogen, the hydrogenation treatment zone operating under conditions effective to form water hydride treatment effluent,
c. Loading the hydrotreating effluent and steam into a convection section of a steam pyrolysis zone;
d. Heating the mixed compound from step (c), and sends it to the gas-liquid separation unit step,
e. Removing a residual portion derived from the gas-liquid separator from the steam pyrolysis zone;
f. Loading the light component from step (a), the light portion from the gas-liquid separator, and steam into the pyrolysis section of the same steam pyrolysis zone to perform pyrolysis,
g. Recovering the mixed product stream from the steam pyrolysis zone;
h. Separating the pyrolyzed mixed product stream;
i. Purifying the hydrogen recovered in step (h) and reusing it in step ( b );
j. Recovering olefins and aromatics from the separated mixed product stream, and k. The integrated process comprising recovering pyrolysis fuel oil from the separated mixed product stream. Step (h)
Compressing the pyrolysis mixed product stream in multiple compression stages;
Causticizing the compressed pyrolysis mixture product stream to produce a pyrolysis mixture product stream having reduced hydrogen sulfide and carbon dioxide content;
Compressing the pyrolysis mixed product stream having a reduced content of hydrogen sulfide and carbon dioxide;
Dehydrating the compressed pyrolysis mixed product stream having a reduced content of hydrogen sulfide and carbon dioxide;
Steps for recovering hydrogen from hydrogen sulfide and the dehydrated compressed pyrolysis mixed product stream content of carbon dioxide is reduced
Including
The olefins and aromatics from step (j) and the pyrolysis fuel oil from step (k) originated from the remainder of the dehydrated compression pyrolysis mixture product stream with reduced hydrogen sulfide and carbon dioxide content And
Et al <br/> step (i) is of,
The method of claim 1, comprising purifying hydrogen recovered from the dehydrated compressed pyrolysis mixed product stream having a reduced content of hydrogen sulfide and carbon dioxide for reuse in the hydroprocessing zone. Integration process. Recovering hydrogen from the dehydrated compressed pyrolysis mixed product stream with reduced hydrogen sulfide and carbon dioxide content separately recovers methane for use as a fuel for the pyrolysis step burner and / or heater The integration process of claim 2 further comprising the step of:   The integrated process according to claim 1, wherein the remaining portion from the gas-liquid separator is blended with the pyrolysis fuel oil recovered in step (k).   The integrated process of claim 1, wherein the step of separating the heated hydrotreating effluent into a vapor fraction and a liquid fraction is performed using a gas-liquid separation device based on physical and mechanical separation. The gas-liquid separator is
A pre-rotating element for the conversion of the incoming mixture from linear speed to rotational speed, comprising an inlet having an inlet and a curved conduit connected to the inlet and towards the connecting element ;
A controlled cyclone part,
An inlet joined to the pre-rotating element at the connecting element by fusing the curved conduit and the cyclonic mold part;
The cyclonic portion having a riser portion steam disposed at the upper end of the cyclone-type member passes,
And a liquid collector / settler through which the liquid passes,
The integration process of claim 5 comprising: Separating the water hydrogenation treatment zone reactor effluent with high pressure separator, the gas portion to be reused in the hydrogenation process zone washed and as an additional hydrogen source, and recovering the liquid portion, and a low pressure separator The liquid portion from the high pressure separator is separated into a gas portion and a liquid portion, the liquid portion from the low pressure separator is the hydrotreating effluent that has undergone pyrolysis, and the liquid portion from the low pressure separator The integrated process of claim 1, further comprising the step of combining a gas portion with the mixed product stream after the steam pyrolysis zone and prior to the separation of step (h).

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