WO2004005433A1 - Procede de vapocraquage de charges d'hydrocarbures lourds - Google Patents

Procede de vapocraquage de charges d'hydrocarbures lourds Download PDF

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Publication number
WO2004005433A1
WO2004005433A1 PCT/US2003/020378 US0320378W WO2004005433A1 WO 2004005433 A1 WO2004005433 A1 WO 2004005433A1 US 0320378 W US0320378 W US 0320378W WO 2004005433 A1 WO2004005433 A1 WO 2004005433A1
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WO
WIPO (PCT)
Prior art keywords
mixture
heavy hydrocarbon
vapor phase
process according
furnace
Prior art date
Application number
PCT/US2003/020378
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English (en)
Inventor
Richard C. Stell
Arthur R. Dinicolantonio
James Mitchell Frye
David B. Spicer
James N. Mccoy
Robert D. Strack
Original Assignee
Exxonmobil Chemical Patents Inc.
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Priority claimed from US10/188,901 external-priority patent/US7090765B2/en
Priority claimed from US10/188,461 external-priority patent/US7138047B2/en
Priority claimed from US10/189,618 external-priority patent/US7097758B2/en
Application filed by Exxonmobil Chemical Patents Inc. filed Critical Exxonmobil Chemical Patents Inc.
Priority to KR1020047021682A priority Critical patent/KR100979027B1/ko
Priority to JP2004519669A priority patent/JP5166674B2/ja
Priority to CA2490403A priority patent/CA2490403C/fr
Priority to AU2003247756A priority patent/AU2003247756A1/en
Priority to KR1020047021683A priority patent/KR100945121B1/ko
Priority to EP03763037.3A priority patent/EP1527151B1/fr
Publication of WO2004005433A1 publication Critical patent/WO2004005433A1/fr

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Classifications

    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F28—HEAT EXCHANGE IN GENERAL
    • F28F—DETAILS OF HEAT-EXCHANGE AND HEAT-TRANSFER APPARATUS, OF GENERAL APPLICATION
    • F28F9/00—Casings; Header boxes; Auxiliary supports for elements; Auxiliary members within casings
    • F28F9/02—Header boxes; End plates
    • F28F9/026—Header boxes; End plates with static flow control means, e.g. with means for uniformly distributing heat exchange media into conduits
    • F28F9/0265—Header boxes; End plates with static flow control means, e.g. with means for uniformly distributing heat exchange media into conduits by using guiding means or impingement means inside the header box
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G9/00—Thermal non-catalytic cracking, in the absence of hydrogen, of hydrocarbon oils
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G9/00—Thermal non-catalytic cracking, in the absence of hydrogen, of hydrocarbon oils
    • C10G9/34—Thermal non-catalytic cracking, in the absence of hydrogen, of hydrocarbon oils by direct contact with inert preheated fluids, e.g. with molten metals or salts
    • C10G9/36—Thermal non-catalytic cracking, in the absence of hydrogen, of hydrocarbon oils by direct contact with inert preheated fluids, e.g. with molten metals or salts with heated gases or vapours
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/10—Feedstock materials
    • C10G2300/1022—Fischer-Tropsch products
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/10—Feedstock materials
    • C10G2300/1033—Oil well production fluids
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/10—Feedstock materials
    • C10G2300/1037—Hydrocarbon fractions
    • C10G2300/104—Light gasoline having a boiling range of about 20 - 100 °C
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/10—Feedstock materials
    • C10G2300/1037—Hydrocarbon fractions
    • C10G2300/1044—Heavy gasoline or naphtha having a boiling range of about 100 - 180 °C
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/10—Feedstock materials
    • C10G2300/1037—Hydrocarbon fractions
    • C10G2300/1048—Middle distillates
    • C10G2300/1051—Kerosene having a boiling range of about 180 - 230 °C
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/10—Feedstock materials
    • C10G2300/1037—Hydrocarbon fractions
    • C10G2300/1048—Middle distillates
    • C10G2300/1055—Diesel having a boiling range of about 230 - 330 °C
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/10—Feedstock materials
    • C10G2300/1037—Hydrocarbon fractions
    • C10G2300/1048—Middle distillates
    • C10G2300/1059—Gasoil having a boiling range of about 330 - 427 °C
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/10—Feedstock materials
    • C10G2300/107—Atmospheric residues having a boiling point of at least about 538 °C
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/10—Feedstock materials
    • C10G2300/1074—Vacuum distillates
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/10—Feedstock materials
    • C10G2300/1077—Vacuum residues
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/20—Characteristics of the feedstock or the products
    • C10G2300/30—Physical properties of feedstocks or products
    • C10G2300/301—Boiling range
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/80—Additives
    • C10G2300/805—Water
    • C10G2300/807—Steam
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2400/00—Products obtained by processes covered by groups C10G9/00 - C10G69/14
    • C10G2400/20—C2-C4 olefins

Definitions

  • the present invention relates to the cracking of hydrocarbons that contain relatively non-volatile hydrocarbons and other contaminants.
  • Steam cracking has long been used to crack various hydrocarbon feedstocks into olefins.
  • Conventional steam cracking utilizes a pyrolysis furnace which has two main sections: a convection section and a radiant section.
  • the hydrocarbon feedstock typically enters the convection section of the furnace as a liquid (except for light feedstocks which enter as a vapor) wherein it is typically heated and vaporized by indirect contact with hot flue gas from the radiant section and by direct contact with steam.
  • the vaporized feedstock and steam mixture is then introduced into the radiant section where the cracking takes place.
  • the resulting products including olefins leave the pyrolysis furnace for further downstream processing, such as quenching.
  • U.S. Patent 3,617,493 which is incorporated herein by reference, discloses the use of an external vaporization drum for the crude oil feed and discloses the use of a first flash to remove naphtha as vapor and a second flash to remove vapors with a boiling point between 450 and 1100°F (230 and 600°C).
  • the vapors are cracked in the pyrolysis furnace into olefms and the separated liquids from the two flash tanks are removed, stripped with steam, and used as fuel.
  • U.S. Patent 3,718,709 which is incorporated herein by reference, discloses a process to minimize coke deposition. It describes preheating of heavy feedstock inside or outside a pyrolysis furnace to vaporize about 50% of the heavy feedstock with superheated steam and the removal of the residual, separated liquid. The vaporized hydrocarbons, which contain mostly light volatile hydrocarbons, are subjected to cracking.
  • U.S. Patent 5,190,634 which is incorporated herein by reference, discloses a process for inhibiting coke formation in a furnace by preheating the feedstock in the presence of a small, critical amount of hydrogen in the convection section. The presence of hydrogen in the convection section inhibits the polymerization reaction of the hydrocarbons thereby inhibiting coke formation.
  • U.S. Patent 5,580,443 which is incorporated herein by reference, discloses a process wherein the feedstock is first preheated and then withdrawn from a preheater in the convection section of the pyrolysis furnace. This preheated feedstock is then mixed with a predetermined amount of steam (the dilution steam) and is then introduced into a gas-liquid separator to separate and remove a required proportion of the non-volatiles as liquid from the separator. The separated vapor from the gas-liquid separator is returned to the pyrolysis furnace for heating and cracking.
  • a predetermined amount of steam the dilution steam
  • the present inventors have recognized that in using a flash to separate heavy liquid hydrocarbon fractions from the lighter fractions which can be processed in the pyrolysis furnace, it is important to effect the separation so that most of the non-volatile components will be in the liquid phase. Otherwise, heavy, coke-forming non-volatile components in the vapor are carried into the furnace causing coking problems.
  • the present inventors have also recognized that in using a flash to separate non-volatile components from the lighter fractions of the hydrocarbon feedstock, which can be processed in the pyrolysis furnace without causing coking problems, it is important to carefully control the ratio of vapor to liquid leaving the flash. Otherwise, valuable lighter fractions of the hydrocarbon feedstock could be lost in the liquid hydrocarbon bottoms or heavy, coke-forming components could be vaporized and carried as overhead into the furnace causing coking problems.
  • the control of the ratio of vapor to liquid leaving flash has been found to be difficult because many variables are involved.
  • the ratio of vapor to liquid is a function of the hydrocarbon partial pressure in the flash and also a function of the temperature of the stream entering the flash.
  • the temperature of the stream entering the flash varies as the furnace load changes. The temperature is higher when the furnace is at full load and is lower when the furnace is at partial load.
  • the temperature of the stream entering the flash also varies according to the flue gas temperature in the furnace that heats the feedstock.
  • the flue-gas temperature in turn varies according to the extent of coking that has occurred in the furnace. When the furnace is clean or very lightly coked, the flue-gas temperature is lower than when the furnace is heavily coked.
  • the flue-gas temperature is also a function of the combustion control exercised on the burners of the furnace.
  • the flue gas temperature in the mid to upper zones of the convection section will be lower than that when the furnace is operated with higher levels of excess oxygen in the flue-gas.
  • the present invention offers an advantageously controlled process to optimize the cracking of volatile hydrocarbons contained in the heavy hydrocarbon feedstocks and to reduce and avoid the coking problems.
  • the present invention provides a method to maintain a relatively constant ratio of vapor to liquid leaving the flash by maintaining a relatively constant temperature of the stream entering the flash. More specifically, the constant temperature of the flash stream is maintained by automatically adjusting the amount of a fluid stream mixed with the heavy hydrocarbon feedstock prior to the flash.
  • the fluid optionally is water.
  • the present invention also provides a method to maintain a relatively constant hydrocarbon partial pressure of the flash stream.
  • the constant hydrocarbon partial pressure is maintained by controlling the flash pressure and the ratio of fluid and steam to the hydrocarbon feedstock.
  • the present invention provides a process for heating heavy hydrocarbon feedstock which comprises heating a heavy hydrocarbon, mixing the heavy hydrocarbon with fluid to form a mixture, flashing the mixture to form a vapor phase and a liquid phase, and varying the amount of fluid mixed with the heavy hydrocarbon in accordance with at least one selected operating parameter of the process and feeding the vapor phase to a furnace.
  • the fluid can be a liquid hydrocarbon or water.
  • At least one operating parameter may be the temperature of the heated heavy hydrocarbon before it is flashed. At least one operating parameter may also be at least one of the flash pressure, temperature of the flash stream, flow rate of the flash stream, and excess oxygen in the flue gas.
  • the heavy hydrocarbon is mixed with a primary dilution steam stream before the flash.
  • a secondary dilution steam can be superheated in the furnace and then mixed with the heavy hydrocarbon.
  • the present invention also provides a process for cracking a heavy hydrocarbon feedstock in a furnace which is comprised of radiant section burners which provide radiant heat and hot flue gas and a convection section comprised of multiple banks of heat exchange tubes comprising:
  • Figure 1 illustrates a schematic flow diagram of a process in accordance with the present invention employed with a steam cracking furnace, specifically the convection section.
  • Non-volatile components can be measured as follows: The boiling point distribution of the hydrocarbon feed is measured by
  • Non-volatile components are the fraction of the hydrocarbon with a nominal boiling point above 1100°F (590°C) as measured by ASTM D-6352-98. This invention works very well with non-volatiles having a nominal boiling point above 1400°F (760°C).
  • the present invention relates to a process for heating and steam cracking heavy hydrocarbon feedstock.
  • the process comprises heating a heavy hydrocarbon, mixing the heavy hydrocarbon with a fluid to form a mixture, flashing the mixture to form a vapor phase and a liquid phase, and varying the amount of fluid mixed with the heavy hydrocarbon in accordance with at least one selected operating parameter of the process.
  • the feedstock comprises a large portion, about 5 to 50%, of heavy non-volatile components.
  • Such feedstock could comprise, by way of non-limiting examples, one or more of steam cracked gas oil and residues, gas oils, heating oil, jet fuel, diesel, kerosene, gasoline, coker naphtha, steam cracked naphtha, catalytically cracked naphtha, hydrocrackate, reformate, raffinate reformate, Fischer-Tropsch liquids, Fischer-Tropsch gases, natural gasoline, distillate, virgin naphtha, crude oil, atmospheric pipestill bottoms, vacuum pipestill streams including bottoms, wide boiling range naphtha to gas oil condensates, heavy non-virgin hydrocarbon streams from refineries, vacuum gas oils, heavy gas oil, naphtha contaminated with crude, atmospheric resid, heavy residium, C4's/residue admixture, and naphtha residue admixture.
  • the heavy hydrocarbon feedstock has a nominal end boiling point of at least 600°F (315°C).
  • the preferred feedstocks are low sulfur waxy resids, atmospheric resids, and naphthas contaminated with crude. The most preferred is resid comprising 60-80% components having boiling points below 1100°F
  • the heavy hydrocarbon feedstock is first preheated in the upper convection section 3.
  • the heating of the heavy hydrocarbon feedstock can take any form known by those of ordinary skill in the art. However, it is preferred that the heating comprises indirect contact of the feedstock in the upper convection section 3 of the furnace 1 with hot flue gases from the radiant section of the furnace. This can be accomplished, by way of non-limiting example, by passing the feedstock through a bank of heat exchange tubes 2 located within the convection section 3 of the furnace 1.
  • the preheated feedstock has a temperature between 300 and 500°F (150 and 260°C). Preferably the temperature of the heated feed is about 325 to 450°F (160 to 230°C) and more preferably between 340 and 425°F (170 and 220°C).
  • the preheated heavy hydrocarbon feedstock is mixed with a fluid.
  • the fluid can be a liquid hydrocarbon, water, steam, or mixture thereof.
  • the preferred fluid is water.
  • the temperature of the fluid can be below, equal to or above the temperature of the preheated feedstock.
  • the mixing of the preheated heavy hydrocarbon feedstock and the fluid can occur inside or outside the pyrolysis furnace 1, but preferably it occurs outside the furnace.
  • the mixing can be accomplished using any mixing device known within the art.
  • a first sparger 4 of a double sparger assembly 9 for the mixing.
  • the first sparger 4 preferably comprises an inside perforated conduit 31 surrounded by an outside conduit 32 so as to form an annular flow space 33 between the inside and outside conduit.
  • the preheated heavy hydrocarbon feedstock flows in the annular flow space and the fluid flows through the inside conduit and is injected into the feedstock through the openings in the inside conduit, preferably small circular holes.
  • the first sparger 4 is provided to avoid or to reduce hammering, caused by sudden vaporization of the fluid, upon introduction of the fluid into the preheated heavy hydrocarbon feedstock.
  • the present invention uses steam streams in various parts of the process.
  • the primary dilution steam stream 17 is mixed with the preheated heavy hydrocarbon feedstock as detailed below.
  • a secondary dilution steam stream 18 is treated in the convection section and mixed with the heavy hydrocarbon fluid primary dilution steam mixture before the flash.
  • the secondary dilution steam 18 is optionally split into a bypass steam 21 and a flash steam 19.
  • the primary dilution steam 17 is also mixed with the feedstock.
  • the primary dilution steam stream can be preferably injected into a second sparger 8. It is preferred that the primary dilution steam stream is injected into the heavy hydrocarbon fluid mixture before the resulting stream mixture enters the convection section at 11 for additional heating by radiant section flue gas. Even more preferably, the primary dilution steam is injected directly into the second sparger 8 so that the primary dilution steam passes through the sparger and is injected through small circular flow distribution holes 34 into the hydrocarbon feedstock fluid mixture.
  • the primary dilution steam can have a temperature greater, lower or about the same as heavy hydrocarbon feedstock fluid mixture but preferably greater than that of the mixture and serves to partially vaporize the feedstock/fluid mixture.
  • the primary dilution steam is superheated before being injected into the second sparger 8.
  • the mixture of the fluid, the preheated heavy hydrocarbon feedstock, and the primary dilution steam stream leaving the second sparger 8 is heated again in the pyrolysis furnace 3 before the flash.
  • the heating can be accomplished, by way of non-limiting example, by passing the feedstock mixture through a bank of heat exchange tubes 6 located within the convection section of the furnace and thus heated by the hot flue gas from the radiant section of the furnace.
  • the thus-heated mixture leaves the convection section as a mixture stream 12 to be further mixed with an additional steam stream.
  • the secondary dilution steam stream 18 can be further split into a flash steam stream 19 which is mixed with the heavy hydrocarbon mixture 12 before the flash and a bypass steam stream 21 which bypasses the flash of the heavy hydrocarbon mixture and, instead is mixed with the vapor phase from the flash before the vapor phase is cracked in the radiant section of the furnace.
  • the present invention can operate with all secondary dilution steam 18 used as flash steam 19 with no bypass steam 21.
  • the present invention can be operated with secondary dilution steam 18 directed to bypass steam 21 with no flash steam 19.
  • the ratio of the flash steam stream 19 to bypass steam stream 21 should be preferably 1 :20 to 20:1, and most preferably 1 :2 to 2:1.
  • the flash steam 19 is mixed with the heavy hydrocarbon mixture stream 12 to form a flash stream 20 before the flash in flash drum 5.
  • the secondary dilution steam stream is superheated in a superheater section 16 in the furnace convection before splitting and mixing with the heavy hydrocarbon mixture.
  • the addition of the flash steam stream 19 to the heavy hydrocarbon mixture stream 12 ensures the vaporization of nearly all volatile components of the mixture before the flash stream 20 enters the flash drum 5.
  • the mixture of fluid, feedstock and primary dilution steam stream (the flash stream 20) is then introduced into a flash drum 5 for separation into two phases: a vapor phase comprising predominantly volatile hydrocarbons and a liquid phase comprising predominantly non- volatile hydrocarbons.
  • the vapor phase is preferably removed from the flash drum as an overhead vapor stream 13.
  • the vapor phase preferably, is fed back to the lower convection section 23 of the furnace for optional heating and through crossover pipes to the radiant section of the pyrolysis furnace for cracking.
  • the liquid phase of the separation is removed from the flash drum 5 as a bottoms stream 27.
  • temperature of the mixture stream 12 before the flash drum 5 is used as an indirect parameter to measure, control, and maintain the constant vapor to liquid ratio in the flash drum 5.
  • temperature of the mixture stream 12 before the flash drum 5 is used as an indirect parameter to measure, control, and maintain the constant vapor to liquid ratio in the flash drum 5.
  • the mixture stream temperature is higher, more volatile hydrocarbons will be vaporized and become available, as a vapor phase, for cracking.
  • the mixture stream temperature is too high, more heavy hydrocarbons will be present in the vapor phase and carried over to the convection furnace tubes, eventually coking the tubes. If the mixture stream 12 temperature is too low, hence a low ratio of vapor to liquid in the flash drum 5, more volatile hydrocarbons will remain in liquid phase and thus will not be available for cracking.
  • the mixture stream temperature is limited by highest recovery/vaporization of volatiles in the feedstock while avoiding coking in the furnace tubes or coking in piping and vessels conveying the mixture from the flash drum to the furnace 13.
  • the pressure drop across the piping and vessels conveying the mixture to the lower convection section 13, and the crossover piping 24, and the temperature rise across the lower convection section 23 may be monitored to detect the onset of coking problems. For instance, when the crossover pressure and process inlet pressure to the lower convection section 23 begins to increase rapidly due to coking, the temperature in the flash drum 5 and the mixture stream 12 should be reduced. If coking occurs in the lower convection section, the temperature of the flue gas to the superheater 16 increases, requiring more desuperheater water 26.
  • the selection of the mixture stream 12 temperature is also determined by the composition of the feedstock materials.
  • the temperature of the mixture stream 12 can be set lower.
  • the amount of fluid used in the first sparger 4 is increased and/or the amount of primary dilution steam used in the second sparger 8 is decreased since these amounts directly impact the temperature of the mixture stream 12.
  • the temperature of the mixture stream 12 should be set higher.
  • the amount of fluid used in the first sparger 4 is decreased while the amount of primary dilution steam used in the second sparger 8 is increased.
  • the temperature of the mixture stream 12 is set and controlled at between 600 and 950°F (315 and 510°C), preferably between 700 and 920°F (370 and 490°C), more preferably between 750 and 900°F (400 and 480°C), and most preferably between 810 and 890°F (430 and 475°C). These values will change with the concentrating volatiles in the feedstock as discussed above.
  • the temperature of mixture stream 12 is controlled by a control system 7 which comprises at least a temperature sensor and any known control device, such as a computer application.
  • the temperature sensors are thermocouples.
  • the control system 7 communicates with the fluid valve 14 and the primary dilution steam valve 15 so that the amount of the fluid and the primary dilution steam entering the two spargers is controlled.
  • the present invention operates as follows: When a temperature for the mixture stream 12 before the flash drum 5 is set, the control system 7 automatically controls the fluid valve 14 and primary dilution steam valve 15 on the two spargers. When the control system 7 detects a drop of temperature of the mixture stream, it will cause the fluid valve 14 to reduce the injection of the fluid into the first sparger 4. If the temperature of the mixture stream starts to rise, the fluid valve will be opened wider to increase the injection of the fluid into the first sparger 4. In the preferred embodiment, the fluid latent heat of vaporization controls mixture stream temperature.
  • the temperature control system 7 can also be used to control the primary dilution steam valve 15 to adjust the amount of primary dilution steam stream injected to the second sparger 8. This further reduces the sharp variation of temperature changes in the flash 5.
  • the control system 7 detects a drop of temperature of the mixture stream 12, it will instruct the primary dilution steam valve 15 to increase the injection of the primary dilution steam stream into the second sparger 8 while valve 14 is closed more. If the temperature starts to rise, the primary dilution steam valve will automatically close more to reduce the primary dilution steam stream injected into the second sparger 8 while valve 14 is opened wider.
  • control system 7 can be used to control both the amount of the fluid and the amount of the primary dilution steam stream to be injected into both spargers.
  • the controller varies the amount of water and primary dilution steam to maintain a constant mixture stream temperature 12, while maintaining a constant ratio of water-to-feedstock in the mixture 11.
  • the present invention also preferably utilizes an intermediate desuperheater 25 in the superheating section of the secondary dilution steam in the furnace. This allows the superheater 16 outlet temperature to be controlled at a constant value, independent of furnace load changes, coking extent changes, excess oxygen level changes.
  • this desuperheater 25 ensures that the temperature of the secondary dilution steam is between 800 and 1100°F (430 and 590°), preferably between 850 and 1000°F (450 and 540°), more preferably between 850 and 950°F
  • the desuperheater preferably is a control valve and water atomizer nozzle. After partial preheating, the secondary dilution steam exits the convection section and a fine mist of water 26 is added which rapidly vaporizes and reduces the temperature. The steam is then further heated in the convection section. The amount of water added to the superheater controls the temperature of the steam which is mixed with mixture stream 12.
  • the same control mechanisms can be applied to other parameters at other locations.
  • the flash pressure and the temperature and the flow rate of the flash steam 19 can be changed to effect a change in the vapor to liquid ratio in the flash.
  • excess oxygen in the flue gas can also be a control variable, albeit a slow one.
  • the constant hydrocarbon partial pressure can be maintained by maintaining constant flash drum pressure through the use of control valves 36 on the vapor phase line 13, and by controlling the ratio of steam to hydrocarbon feedstock in stream 20.
  • the hydrocarbon partial pressure of the flash stream in the present invention is set and controlled at between 4 and 25 psia (25 and 175 kPa), preferably between 5 and 15 psia (35 and 100 kPa), most preferably between 6 and 11 psia (40 and 75 kPa).
  • the flash is conducted in at least one flash drum vessel.
  • the flash is a one-stage process with or without reflux.
  • the flash drum is a one-stage process with or without reflux.
  • the pressure of the flash drum vessel is about 40 to 200 psia (275 to 1400 kPa) and the temperature is about 600 to 950°F (310 to 510°C).
  • the pressure of the flash drum vessel is about 85 to 155 psia (600 to 1100 kPa) and the temperature is about 700 to 920°F (370 to 490°C).
  • the pressure of the flash drum vessel is about 105 to 145 psia (700 to 1000 kPa) and the temperature is about 750 to 900°F (400 to 480°C). Most preferably, the pressure of the flash drum vessel is about 105 to 125 psia (700 to 760 kPa) and the temperature is about 810 to 890°F (430 to
  • the temperature of the flash stream usually 50 to 95% of the mixture entering the flash drum 5 is vaporized to the upper portion of the flash drum, preferably 60 to 90%, more preferably 65 to 85%, and most preferably 70 to 85%.
  • the flash drum 5 is operated, in one aspect, to minimize the temperature of the liquid phase at the bottom of the vessel because too much heat may cause coking of the non-volatiles in the liquid phase.
  • Use of the secondary dilution steam stream 18 in the flash stream entering the flash drum lowers the vaporization temperature because it reduces the partial pressure of the hydrocarbons (i.e., larger mole fraction of the vapor is steam) and thus lowers the required liquid phase temperature. It may also be helpful to recycle a portion of the externally cooled flash drum bottoms liquid 30 back to the flash drum vessel to help cool the newly separated liquid phase at the bottom of the flash drum 5.
  • Stream 27 is conveyed from the bottom of the flash drum 5 to the cooler 28 via pump 37.
  • the cooled stream 29 is split into a recycle stream 30 and export stream 22.
  • the temperature of the recycled stream is ideally 500 to 600°F (260 to
  • the amount of recycled stream should be about 80 to 250% of the amount of the newly separated bottom liquid inside the flash drum, preferably 90 to 225%, more preferably 95 to 210%, and most preferably 100 to 200%.
  • the flash drum is also operated, in another aspect, to minimize the liquid retention/holding time in the flash drum.
  • the liquid phase is discharged from the vessel through a small diameter "boot" or cylinder 35 on the bottom of the flash drum.
  • the liquid phase retention time in the drum is less than 75 seconds, preferably less than 60 seconds, more preferably less than 30 seconds, and most preferably less than 15 seconds. The shorter the liquid phase retention/holding time in the flash drum, the less coking occurs in the bottom of the flash drum.
  • the vapor phase 13 usually contains less than 400 ppm of non-volatiles, preferably less than 100 ppm, more preferably less than 80 ppm, and most preferably less than 50 ppm.
  • the vapor phase is very rich in volatile hydrocarbons (for example, 55-70%) and steam (for example, 30-45%).
  • the boiling end point of the vapor phase is normally below 1400°F (760°C), preferably below 1100°F (600°C), more preferably below 1050°F (570°C), and most preferably below 1000°F (540°C).
  • the vapor phase is continuously removed from the flash drum 5 through an overhead pipe which optionally conveys the vapor to a centrifugal separator 38 which removes trace amounts of entrained liquid. The vapor then flows into a manifold that distributes the flow to the convection section of the furnace.
  • the vapor phase stream 13 continuously removed from the flash drum is preferably superheated in the pyrolysis furnace lower convection section
  • the vapor phase stream 13 removed from the flash drum can optionally be mixed with a bypass steam stream 21 before being introduced into the furnace lower convection section 23.
  • the bypass steam stream 21 is a split steam stream from the secondary dilution steam 18.
  • the secondary dilution steam is first heated in the pyrolysis furnace 3 before splitting and mixing with the vapor phase stream removed from the flash 5.
  • the superheating after the mixing of the bypass steam 21 with the vapor phase stream 13 ensures that all but the heaviest components of the mixture in this section of the furnace are vaporized before entering the radiant section.
  • Raising the temperature of vapor phase to 800 to 1200°F (430 to 650°C) in the lower convection section 23 also helps the operation in the radiant section since radiant tube metal temperature can be reduced. This results in less coking potential in the radiant section.
  • the superheated vapor is then cracked in the radiant section of the pyrolysis furnace.
  • Flash Drum Temperature °F (°C) 847 (453) 750 (400) 5 Flash Drum Pressure, psig (kPag) 107 (740) 101 (694) 5 Feed vaporized in flash drum, wt% 74 93 5
  • Table 2 summarizes the simulated performance of the flash for residue admixed with two concentrations of C4's. At a given flash temperature, pressure and steam rate, each percent of C4's admixed with the residue increases the residue vaporized in the flash by about 1/4%. Therefore, the addition of C4's to feed will result in more hydrocarbon from the residue being vaporized.

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  • Mechanical Engineering (AREA)
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  • Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)
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Abstract

L'invention concerne un procédé d'alimentation ou de craquage d'une charge d'hydrocarbures lourds, comprenant les étapes suivantes : chauffage de la charge d'hydrocarbures lourds, mélange de cette charge avec un fluide et/ou un courant de vapeur de dilution primaire pour former un mélange, vaporisation par flash du mélange pour former une phase vapeur et une phase liquide, et variation de la quantité de fluide et/ou du courant de vapeur de dilution primaire mélangé avec la charge d'hydrocarbures lourds, en conformité avec au moins un paramètre de fonctionnement sélectionné du procédé, tel que la température du courant de détente avant l'entrée dans le ballon de détente.
PCT/US2003/020378 2002-07-03 2003-06-27 Procede de vapocraquage de charges d'hydrocarbures lourds WO2004005433A1 (fr)

Priority Applications (6)

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KR1020047021682A KR100979027B1 (ko) 2002-07-03 2003-06-27 중질 탄화수소 공급원료를 수증기 열분해시키는 방법
JP2004519669A JP5166674B2 (ja) 2002-07-03 2003-06-27 重炭化水素供給原料の水蒸気分解処理
CA2490403A CA2490403C (fr) 2002-07-03 2003-06-27 Procede de vapocraquage de charges d'hydrocarbures lourds
AU2003247756A AU2003247756A1 (en) 2002-07-03 2003-06-27 Process for steam cracking heavy hydrocarbon feedstocks
KR1020047021683A KR100945121B1 (ko) 2002-07-03 2003-06-27 열분해 용도에서 연무 흐름을 환상 흐름으로 전환시키는방법
EP03763037.3A EP1527151B1 (fr) 2002-07-03 2003-06-27 Procede de vapocraquage de charges d'hydrocarbures lourds

Applications Claiming Priority (6)

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US10/188,901 2002-07-03
US10/188,901 US7090765B2 (en) 2002-07-03 2002-07-03 Process for cracking hydrocarbon feed with water substitution
US10/188,461 2002-07-03
US10/188,461 US7138047B2 (en) 2002-07-03 2002-07-03 Process for steam cracking heavy hydrocarbon feedstocks
US10/189,618 US7097758B2 (en) 2002-07-03 2002-07-03 Converting mist flow to annular flow in thermal cracking application
US10/189,618 2002-07-03

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PCT/US2003/020375 WO2004005431A1 (fr) 2002-07-03 2003-06-27 Conversion de flux brouillard en flux annulaire pour application de craquage thermique
PCT/US2003/020377 WO2004005432A1 (fr) 2002-07-03 2003-06-27 Procede de craquage d'une charge d'hydrocarbure avec substitution d'eau

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PCT/US2003/020377 WO2004005432A1 (fr) 2002-07-03 2003-06-27 Procede de craquage d'une charge d'hydrocarbure avec substitution d'eau

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US7097758B2 (en) 2002-07-03 2006-08-29 Exxonmobil Chemical Patents Inc. Converting mist flow to annular flow in thermal cracking application
US7138047B2 (en) 2002-07-03 2006-11-21 Exxonmobil Chemical Patents Inc. Process for steam cracking heavy hydrocarbon feedstocks
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US7138047B2 (en) 2002-07-03 2006-11-21 Exxonmobil Chemical Patents Inc. Process for steam cracking heavy hydrocarbon feedstocks
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CN100494318C (zh) 2009-06-03
EP1523534B1 (fr) 2017-07-19
CA2489888A1 (fr) 2004-01-15
CA2490403C (fr) 2011-06-07
KR100979027B1 (ko) 2010-08-30
AU2003247755A1 (en) 2004-01-23
CN1665910A (zh) 2005-09-07
EP1523534A1 (fr) 2005-04-20
CA2489876C (fr) 2011-04-19
JP2005531684A (ja) 2005-10-20
KR100945121B1 (ko) 2010-03-02
EP1527151A1 (fr) 2005-05-04
JP4403071B2 (ja) 2010-01-20
WO2004005432A1 (fr) 2004-01-15
EP1639060B1 (fr) 2008-05-21
JP2005531683A (ja) 2005-10-20
JP5166674B2 (ja) 2013-03-21
CN1281715C (zh) 2006-10-25
EP1527151B1 (fr) 2018-07-18
CA2489888C (fr) 2011-07-12
AU2003247756A1 (en) 2004-01-23
CN100587030C (zh) 2010-02-03
WO2004005431A1 (fr) 2004-01-15
CA2489876A1 (fr) 2004-01-15
KR20050016709A (ko) 2005-02-21
CA2490403A1 (fr) 2004-01-15
CN1665909A (zh) 2005-09-07
CN1665908A (zh) 2005-09-07
ATE396244T1 (de) 2008-06-15
EP1639060A1 (fr) 2006-03-29
JP2006508198A (ja) 2006-03-09
SG177003A1 (en) 2012-01-30
KR20050016708A (ko) 2005-02-21
AU2003281371A1 (en) 2004-01-23
JP4387301B2 (ja) 2009-12-16

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