US20080277314A1

US20080277314A1 - Olefin production utilizing whole crude oil/condensate feedstock and hydrotreating

Info

Publication number: US20080277314A1
Application number: US11/800,824
Authority: US
Inventors: Richard B. Halsey
Original assignee: Individual
Current assignee: Equistar Chemicals LP
Priority date: 2007-05-08
Filing date: 2007-05-08
Publication date: 2008-11-13

Abstract

A method for thermally cracking a feed composed of whole crude oil and/or natural gas condensate using a vaporizer to vaporize the feed before cracking same, recovering pyrolysis gas oil from the cracked feed, subjecting the recovered pyrolysis gas oil to hydrotreating to form a hydrotreated product, and passing the hydrotreated product to the vaporizer as additional thermal cracking feed.

Description

BACKGROUND OF INVENTION

1. Field of Invention
This invention relates to the formation of olefins by thermal cracking of liquid whole crude oil and/or condensate derived from natural gas in a manner that is integrated with a hydrotreating operation. More particularly, this invention relates to utilizing whole crude oil and/or natural gas condensate as a feedstock for an olefin production plant that employs hydrocarbon thermal cracking in a pyrolysis furnace in combination with a hydrotreating operation in a manner that reduces the sulfur content of the products of that plant.
2. Description of the Prior Art
Thermal (pyrolysis) cracking of hydrocarbons is a non-catalytic petrochemical process that is widely used to produce olefins such as ethylene, propylene, butenes, butadiene, and aromatics such as benzene, toluene, and xylenes.
Basically, a hydrocarbon feedstock such as naphtha, gas oil, or other fractions of whole crude oil that are produced by distilling or otherwise fractionating whole crude oil, is mixed with steam which serves as a diluent to keep the hydrocarbon molecules separated. The steam/hydrocarbon mixture is preheated to from about 900 to about 1,000 degrees Fahrenheit (° F. or F.), and then enters the reaction zone where it is very quickly heated to a severe hydrocarbon thermal cracking temperature in the range of from about 1,450 to about 1,550 F Thermal cracking is accomplished without the aid of any catalyst.
This process is carried out in a pyrolysis furnace (steam cracker) at pressures in the reaction zone ranging from about 10 to about 30 psig. Pyrolysis furnaces have internally thereof a convection section and a radiant section. Preheating is accomplished in the convection section, while severe cracking occurs in the radiant section.
After severe thermal cracking, the effluent from the pyrolysis furnace contains gaseous hydrocarbons of great variety, e.g., from one to thirty-five carbon atoms per molecule. These gaseous hydrocarbons can be saturated, monounsaturated, and polyunsaturated, and can be aliphatic, alicyclics, and/or aromatic. The cracked gas also contains significant amounts of molecular hydrogen (hydrogen).
Thus, conventional steam (thermal) cracking, as carried out in a commercial olefin production plant, employs a fraction of whole crude and totally vaporizes that fraction while thermally cracking same.
The cracked product is then further processed in the olefin production plant to produce, as products of the plant, various separate individual streams of high purity such as hydrogen, ethylene, propylene, mixed hydrocarbons having four carbon atoms per molecule, fuel oil, and pyrolysis gasoline. Each separate individual stream aforesaid is a valuable commercial product in its own right. Thus, an olefin production plant currently takes a part (fraction) of a whole crude stream and generates therefrom a plurality of separate, valuable products.
Natural gas and whole crude oil(s) were formed naturally in a number of subterranean geologic formations (formations) of widely varying porosities. Many of these formations were capped by impervious layers of rock. Natural gas and whole crude oil (crude oil) also accumulated in various stratigraphic traps below the earth's surface. Vast amounts of both natural gas and/or crude oil were thus collected to form hydrocarbon bearing formations at varying depths below the earth's surface. Much of this natural gas was in close physical contact with crude oil, and, therefore, absorbed a number of lighter molecules from the crude oil.
When a well bore is drilled into the earth and pierces one or more of such hydrocarbon bearing formations, natural gas and/or crude oil can be recovered through that well bore to the earth's surface.
The terms “whole crude oil” and “crude oil” as used herein means liquid (at normally prevailing conditions of temperature and pressure at the earth's surface) crude oil as it issues from a wellhead separate from any natural gas that may be present, and excepting any treatment such crude oil may receive to render it acceptable for transport to a crude oil refinery and/or conventional distillation in such a refinery. This treatment would include such steps as desalting. Thus, it is crude oil that is suitable for distillation or other fractionation in a refinery, but which has not undergone any such distillation or fractionation. It could include, but does not necessarily always include, non-boiling entities such as asphaltenes or tar. As such, it is difficult if not impossible to provide a boiling range for whole crude oil. Accordingly, whole crude oil could be one or more crude oils straight from an oil field pipeline and/or conventional crude oil storage facility, as availability dictates, without any prior fractionation thereof.
Natural gas, like crude oil, can vary widely in its composition as produced to the earth's surface, but generally contains a significant amount, most often a major amount, i.e., greater than about 50 weight percent (wt. %), methane. Natural gas often also carries minor amounts (less than about 50 wt. %), often less than about 20 wt. %, of one or more of ethane, propane, butane, nitrogen, carbon dioxide, hydrogen sulfide, and the like. Many, but not all, natural gas streams as produced from the earth can contain minor amounts (less than about 50 wt. %), often less than about 20 wt. %, of hydrocarbons having from 5 to 12, inclusive, carbon atoms per molecule (C5 to C12) that are not normally gaseous at generally prevailing ambient atmospheric conditions of temperature and pressure at the earth's surface, and that can condense out of the natural gas once it is produced to the earth's surface. All wt. % are based on the total weight of the natural gas stream in question.
When various natural gas streams are produced to the earth's surface, a hydrocarbon composition often naturally condenses out of the thus produced natural gas stream under the then prevailing conditions of temperature and pressure at the earth's surface where that stream is collected. There is thus produced a normally liquid hydrocarbonaceous condensate separate from the normally gaseous natural gas under the same prevailing conditions. The normally gaseous natural gas can contain methane, ethane, propane, and butane. The normally liquid hydrocarbon fraction that condenses from the produced natural gas stream is generally referred to as “condensate,” and generally contains molecules heavier than butane (C5 to about C20 or slightly higher). After separation from the produced natural gas, this liquid condensate fraction is processed separately from the remaining gaseous fraction that is normally referred to as natural gas.
Thus, condensate recovered from a natural gas stream as first produced to the earth's surface is not the exact same material, composition wise, as natural gas (primarily methane). Neither is it the same material, composition wise, as crude oil. Condensate occupies a niche between normally gaseous natural gas and normally liquid whole crude oil. Condensate contains hydrocarbons heavier than normally gaseous natural gas, and a range of hydrocarbons that are at the lightest end of whole crude oil.
Condensate, unlike crude oil, can be characterized by way of its boiling point range. Condensates normally boil in the range of from about 100 to about 650 degrees Fahrenheit (F.). With this boiling range, condensates contain a wide variety of hydrocarbonaceous materials. These materials can include compounds that make up fractions that are commonly referred to as naphtha, kerosene, diesel fuel(s), and gas oil (fuel oil, furnace oil, heating oil, and the like). Naphtha and associated lighter boiling materials (naphtha) are in the C5 to C10, inclusive, range, and are the lightest boiling range fractions in condensate, boiling in the range of from about 100 to about 400 F Petroleum middle distillates (kerosene, diesel, atmospheric gas oil) are generally in the C10 to about C20 or slightly higher range, and generally boil, in their majority, in the range of from about 350 to about 650 F They are, individually and collectively, referred to herein as “distillate” or “distillates.” It should be noted that various distillate compositions can have a boiling point lower than 350 F and/or higher than 650 F, and such distillates are included in the 350-650 F range aforesaid, and in this invention.
The starting feedstock for a conventional olefin production plant, as described above, has first been subjected to substantial, expensive processing before it reaches that plant. Normally, condensate and whole crude oil is distilled or otherwise fractionated in a crude oil refinery into a plurality of fractions such as gasoline, naphtha, kerosene, gas oil (vacuum or atmospheric) and the like, including, in the case of crude oil and not natural gas, a high boiling residuum. Thereafter any of these fractions, other than the residuum, are normally passed to an olefin production plant as the starting feedstock for that plant.
It would be desirable to be able to forego the capital and operating cost of a refinery distillation unit (whole crude processing unit) that processes condensate and/or crude oil to generate a hydrocarbonaceous fraction that serves as the starting feedstock for conventional olefin producing plants. However, the prior art, until recently, taught away from even hydrocarbon cuts (fractions) that have too broad a boiling range distribution. For example, see U.S. Pat. No. 5,817,226 to Lenglet.
Recently, U.S. Pat. No. 6,743,961 (hereafter “USP '961” issued to Donald H. Powers. This patent relates to cracking whole crude oil by employing a vaporization/mild cracking zone that contains packing. This zone is operated in a manner such that the liquid phase of the whole crude that has not already been vaporized is held in that zone until cracking/vaporization of the more tenacious hydrocarbon liquid components is maximized. This allows only a minimum of solid residue formation which residue remains behind as a deposit on the packing. This residue is later burned off the packing by conventional steam air decoking, ideally during the normal furnace decoking cycle, see column 7, lines 50-58 of that patent. Thus, the second zone 9 of that patent serves as a trap for components, including hydrocarbonaceous materials, of the crude oil feed that cannot be cracked or vaporized under the conditions employed in the process, see column 8, lines 60-64 of that patent.
Still more recently, U.S. Pat. No. 7,019,187 issued to Donald H. Powers. This patent is directed to the process disclosed in USP '961, but employs a mildly acidic cracking catalyst to drive the overall function of the vaporization/mild cracking unit more toward the mild cracking end of the vaporization (without prior mild cracking)—mild cracking (followed by vaporization) spectrum.
The disclosures of the foregoing patents, in their entirety, are incorporated herein by reference.
One skilled in the art would first subject the feed to be cracked to a conventional distillation column to distill the distillate from the cracking feed. This approach would require a substantial amount of capital to build the column and outfit it with the normal reboiler and overhead condensation equipment that goes with such a column. In this invention, a splitter is employed in a manner such that much greater energy efficiency at lower capital cost is realized over a distillation column. By use of this splitter, reboilers, overhead condensers, and related distillation column equipment are eliminated without eliminating the functions thereof, thus saving considerably in capital costs. Further, this invention exhibits much greater energy efficiency in operation than a distillation column because the extra energy that would be required by a distillation column is not required by this invention since this invention instead utilizes for its splitting function the energy that is already going to be expended in the operation of the cracking furnace (as opposed to energy expended to operate a standalone distillation column upstream of the cracking furnace), and the vapor product of the splitter goes directly to the cracking section of the furnace.
Finally, this invention integrates the foregoing splitter process with conventional hydrotreating.

SUMMARY OF THE INVENTION

In accordance with this invention, there is provided a process for utilizing whole crude oil and/or natural gas condensate as the feedstock for an olefin plant, as defined above, in combination with a hydrotreating process in a manner which increases the productivity of the cracking process and at the same time reduces the sulfur content of various products recovered from that olefin plant.

DESCRIPTION OF THE DRAWING

FIG. 1 shows a simplified flow sheet for a process within this invention.

DETAILED DESCRIPTION OF THE INVENTION

The terms “hydrocarbon,” “hydrocarbons,” and “hydrocarbonaceous” as used herein do not mean materials strictly or only containing hydrogen atoms and carbon atoms. Such terms include materials that are hydrocarbonaceous in nature in that they primarily or essentially are composed of hydrogen and carbon atoms, but can contain other elements such as oxygen, sulfur, nitrogen, metals, inorganic salts, and the like, even in significant amounts.
An olefin producing plant useful with this invention would include a pyrolysis (thermal cracking) furnace for initially receiving and cracking the feed. Pyrolysis furnaces for steam cracking of hydrocarbons heat by means of convection and radiation, and comprise a series of preheating, circulation, and cracking tubes, usually bundles of such tubes, for preheating, transporting, and cracking the hydrocarbon feed. The high cracking heat is supplied by burners disposed in the radiant section (sometimes called “radiation section”) of the furnace. The waste gas from these burners is circulated through the convection section of the furnace to provide the heat necessary for preheating the incoming hydrocarbon feed. The convection and radiant sections of the furnace are joined at the “cross-over,” and the tubes referred to hereinabove carry the hydrocarbon feed from the interior of one section to the interior of the next.
Cracking furnaces are designed for rapid heating in the radiant section starting at the radiant tube (coil) inlet where reaction velocity constants are low because of low temperature. Most of the heat transferred simply raises the hydrocarbons from the inlet temperature to the reaction temperature. In the middle of the coil, the rate of temperature rise is lower but the cracking rates are appreciable.
At the coil outlet, the rate of temperature rise increases somewhat but not as rapidly as at the inlet.
Steam dilution of the feed hydrocarbon lowers the hydrocarbon partial pressure, enhances olefin formation, and reduces any tendency toward coke formation in the radiant tubes.
Radiant coils in the furnace heat the hydrocarbons to from about 1,450° F. to about 1,550° F. and thereby subject the hydrocarbons to severe cracking.
Hydrocarbon feed to the furnace is preheated to from about 900° F. to about 1,000° F. in the convection section by convectional heating from the flue gas from the radiant section, steam dilution of the feed in the convection section, or the like. After preheating in a conventional commercial furnace, the feed is ready for entry into the radiant section.
The cracked gaseous hydrocarbons leaving the radiant section are rapidly reduced in temperature to prevent destruction of the cracking pattern. Cooling of the cracked gases before further processing of same downstream in the olefin production plant recovers a large amount of energy as high pressure steam for re-use in the furnace and/or olefin plant. This is often accomplished with the use of transfer-line exchangers that are well known in the art.
Downstream processing of the cracked hydrocarbons issuing from the furnace varies considerably, and particularly based on whether the initial hydrocarbon feed was a gas or a liquid. Since this invention uses whole crude oil and/or liquid natural gas condensate as a feed, downstream processing herein will be described for a liquid fed olefin plant. Downstream processing of cracked gaseous hydrocarbons from liquid feedstock, naphtha through gas oil for the prior art, and crude oil and/or condensate for this invention, is more complex than for gaseous feedstock because of the heavier hydrocarbon components present in the liquid feedstocks.
With a liquid hydrocarbon feedstock downstream processing, although it can vary from plant to plant, typically employs termination of the cracking function by a transfer-line exchanger followed by oil and water quenches of the furnace effluent. Thereafter, the cracked hydrocarbon stream is subjected to fractionation to remove heavy liquids, followed by compression of uncondensed hydrocarbons, and acid gas and water removal therefrom. Various desired products are then individually separated, e.g., ethylene, propylene, a mixture of hydrocarbons having four carbon atoms per molecule, fuel oil, pyrolysis gasoline, and a high purity hydrogen stream.
In accordance with this invention, a process is provided which utilizes crude oil and/or condensate liquid that has not been subjected to fractionation, distillation, and the like, as the primary (initial) feedstock for the olefin plant pyrolysis furnace in whole or in substantial part. By so doing, this invention eliminates the need for costly distillation of the condensate into various fractions, e.g., from naphtha, kerosene, gas oil, and the like, to serve as the primary feedstock for a furnace as is done by the prior art as first described hereinabove.
This invention can be carried out using, for example, the apparatus disclosed in USP '961. Thus, this invention is carried out using a self-contained vaporization facility that operates separately from and independently of the convection and radiant sections of the furnace. When employed outside the furnace, crude oil and/or condensate primary feed is preheated in the convection section of the furnace, passed out of the convection section and the furnace to a standalone vaporization facility. The vaporous hydrocarbon product of this standalone facility is then passed back into the furnace to enter the radiant section thereof. Preheating can be carried out other than in the convection section of the furnace if desired or in any combination inside and/or outside the furnace and still be within the scope of this invention.
The vaporization unit of this invention (for example section 3 of USP '961) receives the condensate feed that may or may not have been preheated, for example, from about ambient to about 350 F, preferably from about 200 to about 350 F This is a lower temperature range than what is required for complete vaporization of the feed. Any preheating preferably, though not necessarily, takes place in the convection section of the same furnace for which such condensate is the primary feed.
Thus, the first zone in the vaporization operation step of this invention (zone 4 in USP '961) employs vapor/liquid separation wherein vaporous hydrocarbons and other gases, if any, in the preheated feed stream are separated from those distillate components that remain liquid after preheating. The aforesaid gases are removed from the vapor/liquid separation section and passed on to the radiant section of the furnace.
Vapor/liquid separation in this first, e.g., upper, zone knocks out distillate liquid in any conventional manner, numerous ways and means of which are well known and obvious in the art.
Liquid thus separated from the aforesaid vapors moves into a second, e.g., lower, zone (zone 9 in USP '961). This can be accomplished by external piping. Alternatively this can be accomplished internally of the vaporization unit. The liquid entering and traveling along the length of this second zone meets oncoming, e.g., rising, steam. This liquid, absent the removed gases, receives the full impact of the oncoming steam's thermal energy and diluting effect.
This second zone can carry at least one liquid distribution device such as a perforated plate(s), trough distributor, dual flow tray(s), chimney tray(s), spray nozzle(s), and the like.
This second zone can also carry in a portion thereof one or more conventional tower packing materials and/or trays for promoting intimate mixing of liquid and vapor in the second zone.
As the remaining liquid hydrocarbon travels (falls) through this second zone, lighter materials such as gasoline or naphtha that may be present can be vaporized in substantial part by the high energy steam with which it comes into contact. This enables the hydrocarbon components that are more difficult to vaporize to continue to fall and be subjected to higher and higher steam to liquid hydrocarbon ratios and temperatures to enable them to be vaporized by both the energy of the steam and the decreased liquid hydrocarbon partial pressure with increased steam partial pressure.
FIG. 1 shows one embodiment of the process of this invention in diagrammatic form for sake of simplicity and brevity.
FIG. 1 shows a conventional cracking furnace 1 wherein a crude oil and/or condensate primary feed 2 is passed in to the preheat section 3 of the convection section of furnace 1. Steam 6 is also superheated in this section of the furnace for use in the process of this invention.
The pre-heated cracking feed is then passed by way of pipe (line) 10 to the aforesaid vaporization unit 11, which unit is separated into an upper vaporization zone 12 and a lower zone 13. This unit 11 achieves primarily (predominately) vaporization with or without mild cracking of at least a significant portion of the naphtha and gasoline boiling range and lighter materials that remain in the liquid state after the pre-heating step. Gaseous materials that are associated with the preheated feed as received by unit 11, and additional gaseous materials formed in zone 12, are removed from zone 12 by way of line 14. Thus, line 14 carries away essentially all the lighter hydrocarbon vapors, e.g., naphtha and gasoline boiling range and lighter, that are present in zone 12. Liquid distillate present in zone 12, with or without some liquid gasoline and/or naphtha, is removed therefrom via line 15 and passed into the upper interior of lower zone 13. Zones 12 and 13, in this embodiment, are separated from fluid communication with one another by an impermeable wall 16, which can be a solid tray. Line 15 represents external fluid down flow communication between zones 12 and 13. In lieu thereof, or in addition thereto, zones 12 and 13 can have internal fluid communication there between by modifying wall 16 to be at least in part liquid permeable by use of one or more trays designed to allow liquid to pass down into the interior of zone 13 and vapor up into the interior of zone 12. For example, instead of an impermeable wall 16, a chimney tray could be used in which case vapor carried by line 17 would pass internally within unit 11 down into section 13 instead of externally of unit 11 via line 15. In this internal down flow case, distributor 18 becomes optional.
By whatever way liquid is removed from zone 12 to zone 13, that liquid moves downwardly into zone 13, and thus can encounter at least one liquid distribution device 18. Device 18 evenly distributes liquid across the transverse cross section of unit 11 so that the liquid will flow uniformly across the width of the tower into contact with packing 19.
Dilution steam 6 passes through superheat zone 20, and then, via line 21 into a lower portion 22 of zone 13 below packing 19. In packing 19 liquid and steam from line 21 intimately mix with one another thus vaporizing some of liquid 15. This newly formed vapor, along with dilution steam 21, is removed from zone 13 via line 17 and added to the vapor in line 14 to form a combined hydrocarbon vapor product in line 25. Stream 25 can contain essentially hydrocarbon vapor from feed 2, e.g., gasoline and naphtha, and steam.
Stream 17 thus represents a part of feed stream 2 plus dilution steam 21 less liquid distillate(s) and heavier from feed 2 that are present in bottoms stream 26.
Stream 25 is passed through a mixed feed preheat zone 27 in a hotter (lower) section of the convection zone of furnace 1 to further increase the temperature of all materials present, and then via cross over line 28 into the radiant coils (tubes) 29 in the radiant firebox of furnace 1. Line 28 can be internal or external of furnace conduit 30. Line 44 removes from stripper 11 the residuum, if any, from feed 2.
Steam 6 can be employed entirely in zone 13, or a part thereof can be employed in either line 14 and/or line 25 to aid in the prevention of the formation of liquid in lines 14 or 25.
In the radiant firebox section of furnace 1, feed from line 28 which contains numerous varying hydrocarbon components is subjected to severe thermal cracking conditions as aforesaid.
The cracked product leaves the radiant fire box section of furnace 1 by way of line 31 for further processing in the remainder of the olefin plant downstream of furnace 1 as shown in USP '961.
In a conventional olefin production plant, the preheated feed 10 would be mixed with dilution steam 21, and this mixture would then be passed directly from preheat zone 3 into the radiant section 29 of furnace 1, and subjected to severe thermal cracking conditions. In contrast, this invention instead passes the preheated feed at, for example, a temperature of from about 200 to about 350 F, into standalone unit 11 which is physically located outside of furnace 1.
In the embodiment of FIG. 1, cracked furnace product 31 is passed to at least one transfer line exchanger 32 (TLE in FIG. 1) wherein it is cooled sufficiently to terminate the thermal cracking function. The cracked gas product is removed by way of line 33 and further cooled by injection of recycled quench oil 34 immediately downstream of TLE 32. The quench oil/cracked gas mixture passes via line 33 to oil quench tower 35. In tower 35 this mixture is contacted with a hydrocarbonaceous liquid quench material such as pyrolysis gasoline which boils in the range of from about 100 to about 420 F Pyrolysis gasoline is provided from line 36 to further cool the cracked gas furnace product as well as condense and recover additional fuel oil product for line 34. Cracked gas product is removed from tower 35 via line 37 and passed to water quench tower 38 wherein it is contacted with recycled and cooled water 39 that is recovered from a lower portion of tower 38. Water 39 condenses liquid pyrolysis gasoline in tower 38 which is, in part, employed as liquid quench material 36, and, in part, removed via line 40 for other processing elsewhere.
The thus processed cracked gas product is removed from tower 38 via line 41 and passed to compression and fractionation facility 42 wherein individual product streams aforesaid are recovered as products of the cracking plant, such individual product streams being collectively represented by way of line 43.
In tower 35 there is present a hydrocarbonaceous fraction known as pyrolysis gas oil. Pyrolysis gas oil boils in a temperature range of from about 380 to about 700 F Normally pyrolysis gas oil is separated from the process and used or sold as fuel oil. However, with this invention pyrolysis gas oil is used to provide additional feed for the cracking process. Since the process of this invention uses whole crude oil and/or natural gas condensate as its primary feed material, significantly more quantities of pyrolysis gas oil are produced, and this invention takes advantage of this result.
Pursuant to this invention, a side draw stream 50 is taken from tower 35 which stream is essentially pyrolysis gas oil. Stream 50 is then fed to a conventional hydrotreating operation 51, and the hydrotreated product, at least in part, recycled via line 52 to stream 2 to provide more feed to be subjected to thermal cracking, thereby improving the overall product yield per unit of feed 2 of the thermal cracking process represented in FIG. 1. In addition, the hydrotreated product in line 52 has, by virtue of the hydrotreating process, been substantially reduced in sulfur content thereby reducing the overall sulfur content of the various products 40 and 43 of the plant. The hydrotreated product in line 52 can, in part, be removed from the process and sent to a refinery as feed to one or more of a distillation tower, a conversion process such as a fluid catalytic cracker or reformer, distillation blending operations, gasoline blending operations, and the like.
Optionally, pursuant to this invention, a side draw stream 53 can be taken from stripper 11 and passed to hydrotreating operation 51 thereby additionally enhancing the overall productivity and sulfur reduction advantages of this invention for the cracking process. Stream 53 can be gaseous, liquid or a combination thereof. Stream 53 can be subjected to a distillation step, if desired, to remove material that is undesirable in a hydrotreating process.
Feed 2 can enter furnace 1 at a temperature of from about ambient up to about 300 F at a pressure from slightly above atmospheric up to about 100 psig (hereafter “atmospheric to 100 psig”). Feed 2 can enter zone 12 via line 10 at a 3.0 temperature of from about ambient to about 500 F at a pressure of from atmospheric to 100 psig.
Stream 14 can be essentially all hydrocarbon vapor formed from feed 2 and is at a temperature of from about 500 to about 750 F at a pressure of from atmospheric to 100 psig.
Stream 15 can be essentially all the remaining liquid from feed 2 less that which was vaporized in pre-heater 3 and is at a temperature of from about 500 to about 750 F at a pressure of from atmospheric to 100 psig.
The combination of streams 14 and 17, as represented by stream 25, can be at a temperature of from about 650 to about 800 F at a pressure of from atmospheric to 100 psig, and contain, for example, an overall steam/hydrocarbon ratio of from about 0.1 to about 2.
Stream 28 can be at a temperature of from about 900 to about 1,100 F at a pressure of from atmospheric to 100 psig.
In zone 13, dilution ratios (hot gas/liquid droplets) will vary widely because the composition of condensate varies widely. Generally, the hot gas 21, e.g., steam, to hydrocarbon ratio at the top of zone 13 can be from about 0.1/1 to about 5/1, preferably from about 0.1/1 to about 1.2/1, more preferably from about 0.1/1 to about 1/1.
Steam is an example of a suitable hot gas introduced by way of line 21. Other materials can be present in the steam employed. Stream 6 can be that type of steam normally used in a conventional cracking plant. Such gases are preferably at a temperature sufficient to volatilize a substantial fraction of the liquid hydrocarbon that enters zone 13. Generally, the gas entering zone 13 from conduit 21 will be at least about 350 F, preferably from about 650 to about 1,000 F at from atmospheric to 100 psig.
Stream 17 can be a mixture of steam and hydrocarbon vapor that has a boiling point lower than about 350 F It should be noted that there may be situations where the operator desires to allow some distillate to enter stream 17, and such situations are within the scope of this invention. Stream 17 can be at a temperature of from about 600 to about 800 F at a pressure of from atmospheric to 100 psig.
It can be seen that steam from line 21 does not serve just as a diluent for partial pressure purposes as does diluent steam that may be introduced, for example, into conduit 2 (not shown). Rather, steam from line 21 provides not only a diluting function, but also additional vaporizing energy for the hydrocarbons that remain in the liquid state. This is accomplished with just sufficient energy to achieve vaporization of heavier hydrocarbon components and by controlling the energy input. For example, by using steam in line 21, substantial vaporization of feed 2 liquid is achieved. The very high steam dilution ratio and the highest temperature steam are thereby provided where they are needed most as liquid hydrocarbon droplets move progressively lower in zone 13.
The term “hydrotreating” refers to a process of treating a feed with hydrogen for a period of time and at a temperature sufficient to render a product wherein less than or equal to 7 weight percent of the product has a boiling point less than 390 F It typically consists of three operations. First, metals such as vanadium and nickel are removed from the feed using separate or mixed catalyst beds. Second, sulfur, oxygen, and/or nitrogen are removed from or minimized in the feed. Third, polynuclear aromatic compounds are saturated.
Preferably, metals removal and hydrodesulfurization/hydrodenitrification are carried out in separate beds in series with recycled hydrogen containing progressively higher concentrations of hydrogen sulfide and ammonia, and the aromatics saturation process is carried out in a second stage with hydrogen containing minimal hydrogen sulfide.
In general hydrotreating consists of first removing from the feed metals and heterocyclic atoms, such as nitrogen, oxygen and sulfur prior to the entry of the feed into the aromatic saturation section. The process next includes the saturation of polynuclear aromatics in the feed. During treatment in the aromatic saturation section, breaking of the carbon-carbon bonds of the aromatic compounds is not intended. It is not necessary for monoaromatic compounds to be entirely saturated. It is preferred to operate the treatment so that less than 5 wt.% of the treated product converted from the feed has a boiling point range of less than about 390 F
Preferably, metals removal and hydrodesulfurization/hydronitrification are carried out in separate beds; and the saturation process is carried out in a third stage with hydrogen containing minimal hydrogen sulfide in counter current or concurrent flow.
It is desirable to minimize the amount of cracking that occurs in the feed during treatment. While a limited amount of hydrodealkylation may be both unavoidable and tolerated, severe cracking of the product requires unnecessarily greater quantities of hydrogen and forms products which may have a poorer overall olefin yield profile. The third step serves to saturate the polynuclear aromatics.
Useful catalyst compositions are well known in the art, and commercially available. Metal oxide catalysts are cobalt-molybdenum, nickel-tungsten, and nickel-molybdenum supported catalysts, usually on alumina.
The same catalysts can be used for demetallization, desulfurization/denitrification, and saturation. Any catalyst which is capable of removing most metals and substantially all sulfur and nitrogen content from the feed can be used.
In addition, the catalyst selected should be capable of catalyzing the hydrogenation of compounds containing aromatic rings without substantial structural alteration or breakdown. Suitable catalysts include cobalt/molybdenum/alumina, nickel/cobalt/molybdenum/alumina, cobalt/molybdenum/alumina, nickel/molybdenum/alumina, and cobalt/tungsten/alumina. Such catalysts can also be used in their sulfided form.
The catalysts are prepared by impregnating a catalyst support with an aqueous solution of a salt of the metal, either consecutively or simultaneously.
Nickel can be added in the form of nickel nitrate, tungsten as ammonium metatungstate, cobalt as cobalt nitrate, acetate, etc., and molybdenum and ammonium molybdate. It is convenient to impregnate the support first with the salt of the metal that is to be present in the highest concentration in the finished catalyst. Other methods include precipitating the metals on the support from a solution of their salts and co-precipitation of the metals with the hydrated support.
For maximum effectiveness, the metal oxide catalysts should be converted at least in part to metal sulfides. The metal oxide can be sulfided by contact at elevated temperatures with hydrogen sulfide or a sulfur-containing oil. Alternatively, a commercially available metal oxide having sulfur incorporated therein can be used.
These presulfurized catalysts can be loaded into the treatment unit and brought up to reaction conditions in the presence of hydrogen causing the sulfur to react with the hydrogen. The metal oxides are thereby converted to sulfides.
Preferably, the catalysts are activated before use in the reaction by contact with a stream of hydrogen containing hydrogen sulfide at a temperature in the range of from about 212 to about 1,472 F for from about 1 minute to 24 hours. The sulfided form of the catalyst can be prepared by passing hydrogen through liquid tetrahydrothiophene and then over the catalyst maintained at a temperature in the range of from about 212 to about 1,472 F for from about 1 minute to about 24 hours.
Hydrotreating is conducted at high temperatures and high pressures. Typically, the temperature in the hydrogenation chamber is in the range of from about 640 to about 840 F, and a pressure in the range of from about 1,200 to about 5,000 psig. The hydrocarbon Weight Hourly Space Velocity can be in the range of from about 0.1 to about 5.0. Hydrogen supply can be in the range of from about 100 to about 2,000 cubic meters per ton of the hydrocarbon feed.
Hydrogen can be passed through scrubbers to remove hydrogen sulfide and ammonia before recycle. Hydrogenation can be carried out in a series of two or more operations using the same or different catalysts though single stage hydrogenation may be acceptable. Hydrogen flow can be in the co-current or counter current direction.

EXAMPLE

A natural gas condensate stream 5 characterized as Oso condensate from Nigeria is removed from a storage tank and fed directly into the convection section of a pyrolysis furnace 1 at ambient conditions of temperature and pressure. In this convection section, this condensate initial feed is preheated to about 350 F at about 60 psig, and then passed into a vaporization unit 11 wherein a mixture of gasoline and naphtha gases at about 350 F and 60 psig are separated from distillate liquids in zone 12 of that unit. The separated gases are removed from zone 12 for transfer to the radiant section of the same furnace for severe cracking in a temperature range of 1,450° F. to 1,550° F. at the outlet of radiant coil 29.
The hydrocarbon liquid remaining from feed 2, after separation from accompanying hydrocarbon gases aforesaid, is transferred to lower section 13 and allowed to fall downwardly in that section toward the bottom thereof. Preheated steam 21 at about 1,000 F is introduced near the bottom of zone 13 to give a steam to hydrocarbon ratio in section 22 of about 0.5. The falling liquid droplets are in counter current flow with the steam that is rising from the bottom of zone 13 toward the top thereof. With respect to the liquid falling downwardly in zone 13, the steam to liquid hydrocarbon ratio increases from the top to bottom of section 19.
A mixture of steam and naphtha vapor 17 at about 340 F is withdrawn from near the top of zone 13 and mixed with the gases earlier removed from zone 12 via line 14 to form a composite steam/hydrocarbon vapor stream 25 containing about 0.5 pounds of steam per pound of hydrocarbon present. This composite stream is preheated in zone 27 to about 1,000 F at less than about 50 psig, and introduced into the radiant firebox section of furnace 1.
Bottoms product 44 of unit 11 is removed at a temperature of about 460 F, and pressure of about 60 psig.
Oil quench tower 35 is operated at a bottom temperature of about 450 F at about 10 psig. Side draw stream 50 is withdrawn and passed to hydrotreating unit 51 which contains nickel/molybdenum catalyst and is maintained at a temperature of about 650 F and pressure of about 2,900 psig. The product of unit 51 is returned to cracking feed line 2.

Claims

1. In a method for operating an olefin production plant that employs a pyrolysis furnace to severely thermally crack hydrocarbon containing material for subsequent processing of the thus cracked product in said plant which method of plant operation includes 1) providing at least one of whole crude oil and natural gas condensate as said hydrocarbon containing material, 2) submitting said whole crude/condensate feed to a vaporization step wherein said feed is substantially vaporized, and 3) feeding said substantially vaporized feed to said pyrolysis furnace, said plant further employing an oil quench step on said cracked material product to form a pyrolysis gas oil stream, the improvement comprising passing at least part of said pyrolysis gas oil stream to a hydrotreating step, hydrotreating said pyrolysis gas oil to form a hydrotreated product, and returning at least part of said hydrotreated product as feed to said vaporization step.

2. The method of claim 1 wherein a liquid stream is removed from said vaporization step and passed as feed to said hydrotreating step.

3. The method of claim 1 wherein said pyrolysis gas oil stream boils in the range of from about 380 to about 700 F

4. The method of claim 1 wherein said hydrotreating step is carried out at a temperature of from about 640 to about 840 F, pressure of from about 1,200 to about 5,000 psig, weight hourly space velocity of from about 0.1 to about 5, and hydrogen flow of from about 100 to about 200 cubic meters per ton of hydrocarbon feed.