PROCESS FOR OLEFIN PRODUCTION

BACKGROUND OF THE INVENTION FIELD OF THE INVENTION

[0001] Embodiments of the present invention generally relate to methods for processing hydrocarbons. More particularly, embodiments of the present invention relate to steam cracking processes for producing olefins from hydrocarbon feedstocks. DESCRIPTION OF THE RELATED ART

[0002] Steam cracking has long been used to crack various hydrocarbon feedstocks into olefins. Conventional steam cracking utilizes a pyrolysis furnace having 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) where the hydrocarbon is heated and vaporized by indirect contact with hot flue gas from the radiant section and by direct contact with steam that is added to the convection section. The vaporized feedstock and steam mixture is then introduced into the radiant section where the feedstock is cracked into olefmic products. The resulting products leave the furnace for further downstream processing.

[0003] Conventional steam cracking systems have been effective for cracking high- quality feedstocks that contain a large fraction of light volatile hydrocarbons, such as gas oil and naphtha. Lower cost heavy feedstocks such as crude oil and atmospheric resid can be also cracked using a pyrolysis furnace as described above. However, crude oil and atmospheric resid contain high molecular weight, non-volatile components with boiling points in excess of 1100 ⁰ F (590 ⁰ C) that accumulate as coke in the convection section of the pyrolysis furnace. Thus, only low levels of such non- volatile components can be tolerated in the convection section downstream of the point where the lighter components have fully vaporized.

[0004] During transport, it is not uncommon for the high-quality feedstocks (i.e. naphthas and other light volatile hydrocarbons) to become contaminated with heavy crude oil containing non- volatile components. As mentioned, such non- volatile components can cause problems for conventional pyrolysis furnaces. Accordingly, efforts have been directed to treating the non-volatile components prior to cracking. For example, US Patent No. 3,617,493 discloses an external vaporization drum for crude oil feed and a first flash to

remove naphtha as a vapor and a second flash to remove volatiles with a boiling point between 450 to 1100 ⁰ F (230 to 600 ⁰ C). The vapors are cracked in the pyrolysis furnace into olefins and the separated liquids from the two flash tanks are removed, stripped with steam, and used as fuel. [0005] US Patent No. 3,718,709 discloses a process to minimize coke deposition by preheating a 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 then cracked. [0006] US Patent No. 5,190,634 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. [0007] US Patent No. 5,580,443 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. Other processes are described in US Patent Nos. 7,090,765; 7,097,758; and 7,138,047.

[0008] There is a need, therefore, for improved methods for removing non-volatile components from hydrocarbon feedstocks prior to pyrolysis cracking. There is also a need for improved methods for processing hydrocarbon feedstocks to produce one or more olefins therefrom. SUMMARY OF THE INVENTION

[0009] A process for processing a hydrocarbon feed to produce one or more olefins therefrom is provided. In at least one specific embodiment, a hydrocarbon feed can be preheated to a temperature sufficient to selectively separate the hydrocarbon feed into a heavy cut stream and a light cut stream, wherein at least a portion of the preheating is provided by heat from either the heavy cut stream or the light cut stream. The heavy cut stream can be heated at conditions sufficient to provide a heated heavy cut stream having a vapor phase and a liquid phase. The vapor phase can be separated from the liquid phase to

provide a vapor phase stream and a liquid phase stream. The vapor phase stream can then be thermally cracked to provide a first product stream comprising one or more olefins. [0010] In at least one other specific embodiment, a hydrocarbon feed can be preheated to a temperature sufficient to selectively separate the hydrocarbon feed into a heavy cut stream and a light cut stream consisting essentially of vaporized hydrocarbons, wherein at least a portion of the preheating is provided by heat from the heavy cut stream. The heavy cut stream can be heated at conditions sufficient to provide a heated heavy cut stream having a vapor phase and a liquid phase. The vapor phase can be separated from the liquid phase to provide a vapor phase stream and a liquid phase stream, and the vapor phase stream can be thermally cracked to provide a first product stream comprising one or more olefins.

[0011] In at least one other specific embodiment, a hydrocarbon feed can be preheated to a temperature sufficient to selectively separate the hydrocarbon feed into a heavy cut stream and a light cut stream. The light cut stream can be thermally cracked in a first cracking zone at conditions sufficient to provide a first product stream comprising one or more olefins. The heavy cut stream can be heated in a second cracking zone at conditions sufficient to provide a heated heavy cut stream having a vapor phase and a liquid phase. At least a portion of the heated heavy cut stream having the vapor phase and the liquid phase can be removed from the second cracking zone. The vapor phase can be separated from the liquid phase to provide a vapor phase stream and a liquid phase stream. At least a portion of the vapor phase stream can be returned to the second cracking zone, and the vapor phase stream can be thermally cracked to provide a second product stream comprising one or more olefins. [0012] A system for processing a hydrocarbon feed to produce one or more olefins therefrom is provided. In at least one specific embodiment, the system can include one or more heat exchangers, furnaces, and means for separating a vapor phase from a liquid phase. The one or more heat exchangers can be operated at a temperature sufficient to selectively separate the hydrocarbon feed into a heavy cut stream and a light cut stream, wherein at least a portion of the heat is provided by heat from the heavy cut stream. A first furnace can be operated at conditions sufficient to thermally crack the light cut stream to form a first product stream comprising one or more olefins. A second furnace can include at least one convection section and at least one radiant section, the convection section operated at conditions to heat the heavy cut stream to provide a vapor phase and a liquid phase. The means for separating the vapor phase from the liquid phase can provide a vapor phase stream and a liquid phase

stream, wherein the vapor phase stream is thermally cracked within the radiant section to provide a second product stream comprising one or more olefins. BRIEF DESCRIPTION OF THE DRAWINGS

[0013] So that the manner in which the above recited features of the present invention can be understood in detail, a more particular description of the invention, briefly summarized above, may be had by reference to embodiments, some of which are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate only typical embodiments of this invention and are therefore not to be considered limiting of its scope, for the invention may admit to other equally effective embodiments. [0014] Figure 1 schematically depicts a process for processing hydrocarbons to produce one or more olefins according to one or more embodiments described.

[0015] Figure 2 depicts a schematic process flow diagram of an illustrative hydrocarbon process to produce one or more olefins from a resulting heavy cut stream according to one or more embodiments described. [0016] Figure 3 depicts a schematic process flow diagram of an illustrative hydrocarbon process to produce one or more olefins from a resulting light cut stream according to one or more embodiments described.

[0017] Figure 4 schematically depicts another illustrative process for processing hydrocarbons to produce one or more olefins according to one or more embodiments described.

DETAILED DESCRIPTION

[0018] A detailed description will now be provided. Each of the appended claims defines a separate invention, which for infringement purposes is recognized as including equivalents to the various elements or limitations specified in the claims. Depending on the context, all references below to the "invention" may in some cases refer to certain specific embodiments only. In other cases it will be recognized that references to the "invention" will refer to subject matter recited in one or more, but not necessarily all, of the claims. Each of the inventions will now be described in greater detail below, including specific embodiments, versions and examples, but the inventions are not limited to these embodiments, versions or examples, which are included to enable a person having ordinary skill in the art to make and use the inventions, when the information in this patent is combined with available information and technology.

[0019] Figure 1 schematically depicts a process 100 for processing hydrocarbons to produce one or more olefins according to one or more embodiments described. In one or more embodiments, a feed stream 105 to be processed (i.e. cracked or otherwise altered) is fed to a flash drum or other vessel 130 that is operated at conditions sufficient for separating the feed stream 105 into a vapor ("light cut") stream 132 and a liquid ("heavy cut") stream 137. Preferably, the flash drum 105 operates at an elevated temperature to assist the separation of the hydrocarbon into the light cut stream 132 and the heavy cut stream 137. Heat from the heavy cut stream 132 can be conserved or utilized in the process 100, and the heavy cut stream 132 can be further processed (i.e. cracked) into one or more useful products, including one or more olefins. Similarly, heat from the light cut stream 137 can be conserved or utilized in the process 100, and the light cut stream 137 can be further processed (i.e. cracked) into one or more useful products, including one or more olefins. [0020] In one or more embodiments, the flash drum 130 can operate at a temperature ranging from a low of about 200 ⁰ C, 250 ⁰ C, or 290 ⁰ C to a high of about 300 ⁰ C, 360 ⁰ C, or 400 ⁰ C. The pressure of the flash drum 130 can range from a low of about 175 kPa(a), 200 kPa(a), or 250 kPa(a) to a high of about 280 kPa(a), 325 kPa(a), or 400 kPa(a). The heat required to separate or otherwise flash the hydrocarbons from the feed stream 105 into the heavy and light streams 132, 137 can be provided from within the process 100. In one or more embodiments, one or more heat exchangers (three are shown) 110, 115, and 120 can be used to heat the feed stream 105 prior to separation within the flash drum 130. In one or more embodiments, the heat exchangers 110, 115, and 120 can be used in conjunction with one or more condensers 140, 150 to take a heat credit from the light cut stream 132 from the over head of the flash drum 130. [0021] In at least one specific embodiment, the feed stream 105 can be pre-heated within the one or more pre-heaters (i.e. heat exchangers) 110 against the heavy cut stream 137. The heavy cut stream 137 can be consequently cooled to provide a cooled heavy cut steam 165. The heated feed stream 105 exits the pre-heater 110 as stream 112 which can be further heated against steam or some other heating medium generated from the flash drum 130 overhead condenser 140. Boiler feed water, for example, from stream 142 can be heated within the overhead condenser 140 to generate steam that can be used via stream 144 to heat the stream 112 within the heater 115. The energy required to heat the boiler feed water stream 142 within the condenser 140 can be supplied from the light cut stream 132 exiting the overhead of the flash drum 130. From the pre-heater 115, the heated feed stream 117 can be

further heated within one or more heaters (i.e. heat exchangers) 120 to provide a heated stream 125 at a temperature sufficient to selectively separate the more volatiles hydrocarbons therein from the less volatile hydrocarbons, providing the streams 132 and 137. As mentioned, the light cut stream 132 can be cooled against stream 142 to provide a cooled light cut stream 145 which can then be further cooled in one or more exchangers 150 to provide a cooled light cut stream 155. Such heat exchangers, condensers, coolers, heaters, and pre -heaters are known in the art and can be of any type including shell and tubes, for example. As mentioned, the cooled heavy cut stream 165 and the cooled light cut stream 155 can be further processed into one or more useful products, including one or more olefinic products.

[0022] In one or more embodiments, the feed stream 105 includes one or more hydrocarbons having varying boiling points. For example, the feed stream 105 can include 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 residuum, C4's/residue admixture, naphtha residue admixture, derivatives thereof, and any combinations thereof. In one or more embodiments, the feed stream 105 can consist essentially of crude oil. In one or more embodiments, the feed stream 105 can include low sulfur waxy resids, atmospheric resids, and naphthas contaminated with crude. In one or more embodiments, the feed stream 105 can contain resid with 60 to 80 wt% of its components having boiling points below 1,100 ⁰ F (590 ⁰ C), for example, low sulfur waxy resids. In one or more embodiments, the feed stream 105 has a nominal boiling point of at least 600 ⁰ F (315°C). In one or more embodiments, the feed stream 105 has a nominal boiling point of about 800 ⁰ F (426°C) or more. In one or more embodiments, about sixty percent (60%) to about eighty percent (80%) of the feed stream 105 has a boiling point below about 1100 ⁰ F (590 ⁰ C). [0023] In one or more embodiments, the feed stream 105 can enter the pre-heater 110 at any temperature. Such temperature can vary depending on the source of the feed, such as whether the feed derives from any upstream treatment or processing such as desalting or from storage, for example. In one or more embodiments, the feed stream 105 temperature can

range from a low of about room temperature, 50 ⁰ C or 80 ⁰ C to a high of about 130 ⁰ C, 200 ⁰ C, or 300 ⁰ C. When the feed derives from a desalter, the feed stream 105 temperature may be of from about 100 ⁰ C to 150 ⁰ C. In one or more embodiments, the feed stream 105 can exit the pre-heater 110 as stream 112 at a temperature ranging from a low of about 100 ⁰ C, 150 ⁰ C, or 200 ⁰ C to a high of about 250 ⁰ C, 350 ⁰ C, or 400 ⁰ C. In one or more embodiments, the temperature of stream 112 can be about 200 ⁰ C to about 250 ⁰ C.

[0024] In one or more embodiments, the stream 112 can exit the pre-heater 115 as stream 117. Stream 117 can have a temperature ranging from a low of about 150 ⁰ C, 200 ⁰ C, or 250 ⁰ C to a high of about 270 ⁰ C, 350 ⁰ C, or 400 ⁰ C. In one or more embodiments, the temperature of stream 112 can range from about 300 ⁰ C to about 400 ⁰ C.

[0025] In one or more embodiments, the stream 117 can exit the heater 120 as stream 125. Stream 125 can have a temperature ranging from a low of about 200 ⁰ C, 250 ⁰ C, or 300 ⁰ C to a high of about 325°C, 375°C, or 400 ⁰ C. In one or more embodiments, the temperature of stream 117 can range from about 300 ⁰ C to about 400 ⁰ C. [0026] The pressure of the streams 105, 112, 117 and 125 can vary depending on the flash drum 130 and downstream processing requirements. Pressures can also vary depending on the types and/or classes of hydrocarbon in the feed stream 130 as well as the types and/or classes of product to be had. By way of example, the pressure of the streams 105, 112, 117 and 125 can range from a low of about 175 kPa(a), 200 kPa(a), or 250 kPa(a) to a high of about 280 kPa(a), 325 kPa(a), or 400 kPa(a).

[0027] Considering the light cut stream 155 and the heavy cut stream 165 in more detail, the cooled light cut stream 155 can include one or more hydrocarbons having a boiling point of about 895°F (480 ⁰ C) or less. In one or more embodiments, the cooled light cut stream 155 can include one or more hydrocarbons having a boiling point of about 800 ⁰ F (430 ⁰ C) or less. The cooled heavy cut stream 165 can include one or more hydrocarbons having a boiling point of about 750 ⁰ F (400 ⁰ C) or more. In one or more embodiments, the cooled heavy cut stream 165 can include one or more hydrocarbons having a boiling point of about 1000 ⁰ F (535°C) or more. As mentioned, the cooled light cut stream 155 and the cooled heavy cut stream 165 can be further processed into one or more useful products, including one or more olefins.

[0028] In one or more embodiments, the cooled light cut stream 155 and/or the cooled heavy cut stream 165 can be processed using traditional techniques known in the art, including thermal cracking and/or catalytic cracking techniques, for example. In one or more

embodiments, the cooled light cut stream 155 and/or the cooled heavy cut stream 165 can be processed utilizing steam cracking techniques. In one or more embodiments, the cooled light cut stream 155 and/or the cooled heavy cut stream 165 can be processed utilizing steam cracking techniques. In one or more embodiments, at least one of the cooled light cut stream 155 and the cooled heavy cut stream 165 can be processed utilizing a steam cracking furnace equipped with one or more external separation vessels to at least partially remove any nonvolatile components therein to prevent or minimize fouling within the furnace. The following Figures 2-4 illustrate various processes for processing the hydrocarbons of the cooled light cut stream 155 and/or the cooled heavy cut stream 165, according to embodiments described. [0029] Also as used herein, the term "non- volatile components" refers to a boiling point distribution of the hydrocarbon feed measured by Gas Chromatograph Distillation (GCD) by ASTM D-6352-98 or another suitable method. The non-volatile components are the fraction of the hydrocarbon with a nominal boiling point above 1100 ⁰ F (590 ⁰ C) as measured by ASTM D-6352-98. More preferably, non-volatiles have a nominal boiling point above 1400 ⁰ F (760 ⁰ C).

[0030] Figure 2 depicts a schematic process flow diagram of an illustrative hydrocarbon process 200 to produce one or more olefins from a resulting heavy cut stream according to one or more embodiments described. In one or more embodiments, the heavy cut stream 165 can be processed within a steam cracker or pyro lysis furnace 210 to provide a product stream 175 A having one or more olefins therein. The furnace 210 can include at least one convection section 215 and at least one radiant section 220. The furnace 210 can also include at least one external separator 230, such as a flash drum or other vertical vessel, in fluid communication with the convection section 215. The separator 230 helps remove or at least substantially remove any non-volatiles in the heavy cut stream 165 that could potentially coke or otherwise foul the furnace 210.

[0031] In one or more embodiments, the heavy cut stream 165 enters the furnace 210 via the convection section 210. The convection section 215 can be operated at conditions to heat the stream 165 to provide a preheated stream 166. For example, the stream 165 can be heated by indirect contact with hot flue gases emitted from the radiant section 220 of the furnace 210. This can be accomplished, by way of non-limiting example, by passing the stream 165 through a bank of heat exchange tubes or coils 225 disposed within the convection section 215 of the furnace 210.

[0032] The preheated stream 166 is preferably heated to a temperature sufficient to form a vapor phase and liquid phase therein. For example, the preheated stream 166 can have a temperature between about 300 ⁰ F and about 500 ⁰ F (150 ⁰ C to 260 ⁰ C). Preferably, the temperature of the preheated stream 166 is about 325°F to about 450 ⁰ F (160 ⁰ C to 230 ⁰ C) and more preferably between about 340 ⁰ F and about 425°F (170 ⁰ C to 220 ⁰ C).

[0033] To facilitate the formation of a liquid and vapor phase, the preheated stream 166 can be mixed with one or more fluid streams 212. The temperature of the fluid stream 212 can be below, equal to or above the temperature of the preheated stream 166. The fluid stream 212 can include a liquid hydrocarbon, water, steam, or any mixture thereof. Preferably, the fluid stream 212 is or includes water.

[0034] The mixing of the preheated stream 166 and the fluid stream 212 can occur inside or outside the furnace 210, but preferably outside the furnace 210 as depicted. The mixing can be accomplished using any mixing device known within the art such as a nozzle or sparger. An illustrative sparger can have concentric conduits, including an inside perforated conduit surrounded by an outside conduit so as to form an annular space therebetween. In one or more embodiments, the preheated stream 166 flows in the annulus and the fluid stream 212 flows through the inside conduit and is mixed into the preheated stream 166 within the annulus via the perforations formed in the inside conduit, preferably small circular holes. Such sparger configuration helps avoid or reduce hammering, caused by sudden vaporization of the fluid within the fluid stream 212, upon introduction of the fluid stream 212 into the preheated stream 166.

[0035] In one or more embodiments, the mixed stream of the preheated stream 166 and fluid stream 212 can be contacted with one or more steam dilution streams 217 before returning to the furnace 210 for additional heating by radiant section flue gas. In one or more embodiments, the fluid stream 212 and the steam dilution stream 217 can be injected into the preheated stream 166 using a double sparger assembly 240, as depicted in Figure 2. The double sparger assembly 240 can include a first sparger 242 in fluid communication with a second sparger 247. Each sparger 242, 247 can include two or more concentric conduits having an annular space therebetween. The inner concentric tube preferably includes a plurality of holes or openings to form a plurality of flow paths therethrough. Additional details of a suitable double sparger assembly can found in US Patent No. 7,138,047. [0036] In operation, the preheated stream 166 enters the double sparger assembly 240 and is mixed with the fluid stream 212. The resulting combined or mixed stream then enters the

second sparger 247 and is mixed with the steam dilution stream 217. The resulting mixture stream 167 enters the convection section 215 for additional heating by radiant section flue gas within the furnace 210. The preheated stream 166 can enter either the inner or outer conduit of the first sparger 242. Preferably, the fluid stream 212 flows through the inner conduit and is dispersed through the plurality of openings into the outer conduit to mix with the preheated stream 166. The resulting mixture can enter either the inner or outer conduit of the second sparger 247. Preferably, the resulting mixture flows through the outer conduit and the steam dilution stream 217 flows through the inner conduit and is dispersed through the plurality of openings into the annulus with the hydrocarbon/fluid mixture from the first sparger 242. [0037] The dilution stream 217 can have a temperature greater, lower or about the same as the hydrocarbon/fluid mixture but preferably greater than that of the mixture and serves to partially vaporize the mixture. In one or more embodiments, the dilution steam stream 217 is superheated prior to injection into the second sparger 247 to facilitate vaporization and the formation of a liquid and vapor phase within the resulting stream 167. [0038] As mentioned, the resulting mixture of the fluid, the preheated hydrocarbon, and the dilution steam leaving the second sparger 247 (i.e. stream 167) can be heated again in the furnace 210 before the separator 230. The heating can be accomplished by passing the feedstock mixture through a second bank of heat exchange tubes or coils 226 located within the convection section 215 of the furnace 210 and thus heated by the hot flue gas emitted from the radiant section 220. The thus-heated mixture leaves the convection section 210 as a two phase stream 214.

[0039] In one or more embodiments, the two phase stream 214 exiting the furnace 210 can be mixed with a dilution steam stream 218 prior to flashing within the separator 230. In one or more embodiments, the steam stream 218 can be split into a flash stream 219 which is mixed with the two phase stream 214 before the flash and a bypass stream 221 which bypasses the flash of the two phase stream 214 and, instead is mixed with vapor stream 213 from the separator 230 before the vapor stream 213 is returned to a third bank of heat exchange tubes or coils 223 located within a lower portion of the convection section 215, and the hydrocarbons are cracked in the radiant section 220 of the furnace 210. In one or more embodiments, a ratio of the flash stream 219 to bypass stream 221 can be 1 :20 to 20:1, and most preferably 1 :2 to 2:1. In one or more embodiments, the steam stream 218 can be superheated in a superheater section 227 in the furnace 200 before splitting and mixing with the two phase stream 214. The addition of the flash stream 219 to the two phase stream 214

ensures the vaporization of nearly all volatile components before the two phase stream 214 enters the separator 230.

[0040] The separator 230 can be operated at conditions sufficient to separate the mixture of the fluid, feedstock and dilution steam (i.e. the two phase stream 214) into a vapor phase stream 213 and a liquid phase stream 232. The vapor phase steam 213 from the overhead of the separator 230 includes the volatilized hydrocarbons from the mixture stream 214, and the liquid phase stream 232 includes the non-volatilized hydrocarbons from the mixture stream 214. The vapor phase stream 213 can be returned to a lower portion of the convection section 215 of the furnace 210 for optional heating and through crossover pipes to the radiant section 220 for cracking. The liquid phase stream 232 can be re-boiled and returned to the separator 230 or collected from the separator as bottoms stream 233. The bottoms stream 233 can include hydrocarbons having a boiling point ranging from 850 ⁰ F (400 ⁰ C) to 1495°F (820 ⁰ C). In one or more embodiments, the bottom stream 233 can be of from 5 wt% to 40 wt% of the feed to the furnace 210 (heavy cut stream 165). [0041] It is preferred to maintain a predetermined constant ratio of vapor to liquid in the separator 230. But such ratio is difficult to measure and control. In one or more embodiments, the temperature of the two phase stream 214 upstream of the separator 230 can be used as an indirect parameter to measure, control, and maintain the constant vapor to liquid ratio in the separator 230. Ideally, when the two phase stream 214 temperature is higher, more volatile hydrocarbons will be vaporized and become available, as a vapor phase, for cracking. However, when the two phase stream 214 temperature is too high, more heavy hydrocarbons will be present in the vapor phase stream 213 and carried over to the convection section 215, eventually coking the tubes 223. If the two phase stream 214 temperature is too low, hence a low ratio of vapor to liquid in the separator 230, more volatile hydrocarbons will remain in liquid phase and thus will not be available for cracking.

[0042] Typically, the temperature of the two phase stream 214 is set and controlled at between 600 ⁰ F and 950 ⁰ F (310 ⁰ C and 510 ⁰ C), preferably between 700 and 920 ⁰ F (370 and 490 ⁰ C), more preferably between 750 ⁰ F and 900 ⁰ F (400 ⁰ C and 480 ⁰ C), and most preferably between 810 ⁰ F and 890 ⁰ F. (430 ⁰ C and 475°C). These values will change with the concentrating volatiles in the feedstock as discussed above.

[0043] In one or more embodiments, the temperature of the two phase stream 214 can be controlled by a control system 260. The control system 260 can include at least a temperature sensor and any known control device, such as a computer application.

Preferably, the temperature sensors are thermocouples. The control system 260 can communicate with one or more flow valves 262, 264 so that a sufficient amount of the fluid and the steam entering the sparger assembly 240 is controlled. This can control both the fluid-to-feedstock ratio as well as the temperature of the resulting mixture stream 167 exiting the sparger assembly 240.

[0044] In one or more embodiments, one or more intermediate desuperheaters 266 can be used to control the temperature of the steam stream 218 to the separator 230 at a constant value, independent of furnace load changes, coking extent changes, excess oxygen level changes. Preferably, the desuperheater 266 maintains the temperature of the dilution steam stream 218 between about 800 and about 1100 ⁰ F (430 to 590 ⁰ C), preferably between about 850 and about 1000 ⁰ F. (450 to 540 ⁰ C), more preferably between about 850 and about 950 ⁰ F (450 to 510 ⁰ C), and most preferably between about 875 and about 925°F (470 to 500 ⁰ C). The desuperheater 266 preferably is a control valve and water atomizer nozzle. After partial preheating, the dilution steam stream 218 exits the convection section 215 and a fine mist of water is added which can vaporize and reduce the temperature thereof. As such, the amount of water added to the superheater 266 can control the temperature of the steam stream 218. [0045] In addition to maintaining a constant temperature of the two phase stream 214 entering the separator 230, the hydrocarbon partial pressure of the two phase stream 214 can be maintained constant in order to maintain a constant ratio of vapor to liquid in the flash. By way of example, the constant hydrocarbon partial pressure can be maintained by maintaining constant pressure in the separator 230 through the use of one or more control valves 268 on the vapor phase stream 213, and by controlling the ratio of steam from stream 219 to hydrocarbon in stream 214. Preferably, the hydrocarbon partial pressure of the two phase stream 214 is between about 4 psia and about 25 psia (25 kPa and 175 kPa), preferably between about 5 psia and about 15 psia (35 kPa to 100 kPa), most preferably between about 6 psia and about 11 psia (40 kPa and 75 kPa).

[0046] The flash can be conducted in at least one flash drum or separator 230. Preferably, the flash is a one-stage process with or without reflux. The pressure of the separator 230 can be about 40 psia to 200 psia (275 kPa(a) to 1400 kPa(a)) and the temperature can be about 600 ⁰ F to 950 ⁰ F (310 ⁰ C to 510 ⁰ C). Preferably, the pressure of the separator 230 is about 85 to 155 psia (600 to 1100 kPa) and the temperature is about 700 to 920 ⁰ F (370 to 490 ⁰ C). More preferably, the pressure of the separator 230 is about 105 to 145 psia (700 to 1000 kPa) and the temperature is about 750 to 900 ⁰ F (400 to 480 ⁰ C). Most preferably, the pressure of the

separator 230 is about 105 to 125 psia (700 to 760 kPa) and the temperature is about 810 to 890 ⁰ F (430 to 480 ⁰ C). Depending on the temperature of the flash stream, usually 50 to 95% of the mixture entering the separator 230 is vaporized to the upper portion of the flash drum, preferably 60 to 90% and more preferably 65 to 85%, and most preferably 70 to 85%. In one or more embodiments, the vapor phase of the heated mixture preferably has a nominal boiling point below about 1400 ⁰ F (760 ⁰ C).

[0047] In one or more embodiments, the separator 230 can be operated to minimize the temperature of the liquid phase at the bottom of the separator 230 because too much heat may cause coking of the non-volatiles in the liquid phase. Use of the secondary dilution steam stream 218 in the separator 230 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. A portion of bottoms liquid stream 232 can be recycled to the separator 230 to help cool the separated liquid phase at the bottom of the separator 230. The temperature of the recycled stream is ideally 500 ⁰ F to 600 ⁰ F (260 ⁰ C to 320 ⁰ C), preferably 505 ⁰ F to 575°F (263°C to 302 ⁰ C), more preferably 515°F to 565°F (268°C to 296°C), and most preferably 520 ⁰ F to 550 ⁰ F (270 ⁰ C to 288°C). [0048] In the flash, the vapor phase stream 213 can contain 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 ⁰ F (760 ⁰ C), preferably below 1100 ⁰ F (600 ⁰ C), more preferably below 1050 ⁰ F (570 ⁰ C), and most preferably below 1000 ⁰ F (540 ⁰ C). The vapor phase can be continuously removed from the separator 230 through an overhead pipe which optionally conveys the vapor to a centrifugal separator 235 which removes trace amounts of entrained liquid. The vapor then flows into a manifold that distributes the flow to the convection section 215 of the furnace 210.

[0049] As mentioned, the vapor phase stream 213 can be continuously removed from the separator 230 and superheated in the lower portion of the convection section 215 of the furnace 210. In one or more embodiments, the vapor phase stream 213 can be heated to a temperature of about 800 ⁰ F to 1200 ⁰ F (430 ⁰ C to 650 ⁰ C) by the flue gas from the radiant section 220 of the furnace 210. The vapor is then introduced to the radiant section 220 of the furnace 210 to be cracked.

[0050] The vapor phase stream 213 removed from the flash drum can optionally be mixed with the bypass steam stream 221 before being introduced into the convection section 215. The bypass steam stream 221 can be a split steam stream from the secondary dilution steam 218. Preferably, the secondary dilution steam 218 is first heated in the furnace 210 before splitting and mixing with the vapor phase stream 213 removed from the separator 230. In some applications, it may be possible to superheat the bypass steam stream 221 again after the splitting from the secondary dilution steam but before mixing with the vapor phase stream 213. The superheating after the mixing of the bypass steam stream 221 with the vapor phase stream 213 ensures that all but the heaviest components of the mixture in this section of the furnace 210 are vaporized before entering the radiant section 220.

[0051] Figure 3 depicts a schematic process flow diagram of an illustrative hydrocarbon process 300 to produce one or more olefins from a resulting light cut stream according to one or more embodiments described. As depicted, the light cut stream 155 from Figure 1 can be processed using a traditional steam cracker 310 to provide a product stream 175B containing one or more olefins. Because the heavy fraction of the feedstock 105 has been previously removed or at least substantially removed, the resulting light cut stream 155 can be thermally cracked without additional measures for handling non-volatiles. In one or more embodiments, the light cut stream 155 enters the convections section 315 of the furnace 310 via one or more tubes or coils 325. The light cut stream 155 is heated within the tubes 325 via heat emitted from the radiant section 320. The heated hydrocarbons pass through the convection section 315 to the radiant section 320 where the hydrocarbons are cracked to form one or more olefins within the resulting product stream 175B. Although not shown, one or more steam streams are in fluid communication with the hydrocarbons passing through the coils 315 of the convection section 315. [0052] In one or more embodiments, the convection section 315 can be operated at a temperature ranging from a low of about 55°C, 65°C, or 75°C to about a high of about 500 ⁰ C, 650 ⁰ C, or 800 ⁰ C. Preferably, the convection section 315 can be operated at a temperature of from 65°C to about 700 ⁰ C. More preferably, the convection section 315 can be operated at a temperature of from about 130 ⁰ C to about 650 ⁰ C. [0053] In one or more embodiments, the radiant section 320 can be operated at a temperature ranging from a low of about 600 ⁰ C, 700 ⁰ C, or 750 ⁰ C to about a high of about 800 ⁰ C , 900 ⁰ C, or 940 ⁰ C. Preferably, the radiant section 320 can be operated at a

temperature of from 750 ⁰ C to about 900 ⁰ C. More preferably, the radiant section 320 can be operated at a temperature of from 800 ⁰ C to about 850 ⁰ C.

[0054] In one or more embodiments, the product streams 175 A, 175B can include of from 50 wt% to 70 wt% of one or more olefins having 2 to 6 carbon atoms. In one or more embodiments, the product streams 175 A, 175B can include of from 20 wt% to 50 wt% of one or more olefins having 2 carbon atoms. In one or more embodiments, the product streams 175 A, 175B can include of from 5 wt% to 20 wt% of one or more olefins having 3 carbon atoms. In one or more embodiments, the product streams 175 A, 175B can include of from 5 wt% to 20 wt% of one or more olefins having 4 carbon atoms. In one or more embodiments, the product streams 175 A, 175B can include of from 1 wt% to 10 wt% of one or more olefins having 5 carbon atoms. In one or more embodiments, the product streams 175 A, 175B can include of from 1 wt% to 10 wt% of one or more olefins having 6 carbon atoms. [0055] Figure 4 schematically depicts another illustrative process 400 for processing hydrocarbons to produce one or more olefins according to one or more embodiments described. The process 400 can take the feed stream 105 to be processed (i.e. cracked) and separates the feed stream 105 into a vapor ("light cut") stream 155 and a liquid ("heavy cut") stream 165 within the separator 130. The heavy cut stream 165 is cracked within a first cracking zone (e.g. the furnace 210 equipped with an external separator 230 as shown and described with reference to Figure 2) to provide a first product stream 175 A containing one or more olefins. The light cut stream 155 is cracked within a second cracking zone (e.g. the furnace 310 shown and described with reference to Figure 3) to provide a second product stream 175B containing one or more olefins. The product streams 175 A, 175B can then be fed to a transfer line exchanger (TLE) 400 to recover and utilize the heat of the product streams 175 A, 175B exiting their respective furnaces. In one or more embodiments, a liquid stream 402, such as boiler feed water, can be heated against the product streams 175 A, 175B within the TLE 400 to provide a steam stream 403 and cooled product streams 405, 415. Such steam stream 403 can be used during start-up to provide the requisite heat to heat the feed stream 105 prior to separation within the separator 130, as depicted in Figure 1. In one or more embodiments, the product stream 405 can be further cooled within one or more heat exchangers 425 to provide a cooled product stream 430.

[0056] In another embodiment, the present invention relates to:

1. A process for processing a hydrocarbon feed to produce one or more olefins, comprising:

preheating the hydrocarbon feed to a temperature sufficient to selectively separate the hydrocarbon feed into a heavy cut stream and a light cut stream, wherein at least a portion of the preheating is provided by heat from either the heavy cut stream or the light cut stream; heating the heavy cut stream at conditions sufficient to provide a heated heavy cut stream having a vapor phase and a liquid phase; separating the vapor phase from the liquid phase to provide a vapor phase stream and a liquid phase stream; and thermally cracking the vapor phase stream to provide a first product stream comprising one or more olefins. 2. The process according to paragraph 1, further comprising thermally cracking the light cut stream to provide a second product stream.

3. The process according to paragraphs 1 or 2, wherein the hydrocarbon feed has a final boiling point of about 800 ⁰ F (426°C) or more.

4. The process according to any of paragraphs 1 to 3, wherein the hydrocarbon feed consists essentially of crude oil.

5. The process according to any of paragraphs 1 to 4, wherein the vapor phase stream comprises of from about 50 wt% to about 95 wt% of the hydrocarbons in the hydrocarbon feed.

6. The process according to any of paragraphs 1 to 5, wherein the hydrocarbon feed comprises at least one of steam cracked gas oil and residues, gas oils, heating oil, jet fuel, diesel, kerosene, gasoline, coker naptha, steam cracked naphtha, catalytically cracked naphtha, hydrocrackate, reformate, raffmate 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 condensate, heavy non-virgin hydrocarbon streams from refineries, vacuum gas oils, heavy gas oil, naphtha contaminated with crude, atmospheric resid, heavy residuum, C4's/residue admixture, or naphtha residue admixture.

7. The process according to any of paragraphs 1 to 6, wherein the hydrocarbon feed comprises low sulfur waxy resid. 8. The process according to any of paragraphs 1 to 7, wherein about 60 wt% to about 80 wt% of the heavy cut stream has a final boiling point below about 1100 ⁰ F (590 ⁰ C). 9. The process according to any of paragraphs 1 to 8, wherein the hydrocarbon feed has a final boiling point of at least about 600 ⁰ F (315°C).

10. The process according to any of paragraphs 1 to 9, wherein the vapor phase from the heavy cut stream has a final boiling point below about 1400 ⁰ F (760 ⁰ C).

11. The process according to any of paragraphs 1 to 10, wherein the heavy cut stream or the light cut stream is recycled after the hydrocarbon feed is selectively separated to indirectly heat fresh hydrocarbon feed.

12. A process for processing a hydrocarbon feed to produce one or more olefins, comprising: preheating the hydrocarbon feed to a temperature sufficient to selectively separate the hydrocarbon feed into a heavy cut stream and a light cut stream consisting essentially of vaporized hydrocarbons, wherein at least a portion of the preheating is provided by heat from the heavy cut stream; heating the heavy cut stream at conditions sufficient to provide a heated heavy cut stream having a vapor phase and a liquid phase; separating the vapor phase from the liquid phase to provide a vapor phase stream and a liquid phase stream; and thermally cracking the vapor phase stream to provide a first product stream comprising one or more olefins.

13. The process according to paragraph 12, further comprising thermally cracking the light cut stream to provide a second product stream. 14. The process according to paragraphs 12 or 13, further comprising heating the hydrocarbon feed against steam after preheating the hydrocarbon feed against the heavy cut stream.

15. The process according to any of paragraphs 12 to 14, wherein the hydrocarbon feed has a final boiling point of about 800 ⁰ F (426°C) or more. 16. The process according to any of paragraphs 12 to 15, wherein the hydrocarbon feed consists essentially of crude oil.

17. The process according to any of paragraphs 12 to 16, wherein the vapor phase stream comprises of from about 50 wt% to about 95 wt% of the hydrocarbons in the hydrocarbon feed. 18. The process according to any of paragraphs 12 to 17, wherein the hydrocarbon feed comprises at least one of steam cracked gas oil and residues, gas oils, heating oil, jet fuel, diesel, kerosene, gasoline, coker naptha, steam cracked naphtha, catalytically cracked naphtha, hydrocrackate, reformate, raffmate 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 condensate, heavy non-virgin hydrocarbon streams from refineries, vacuum gas oils, heavy gas oil, naphtha contaminated with crude, atmospheric resid, heavy residuum, C4's/residue admixture, or naphtha residue admixture.

19. The process according to any of paragraphs 12 to 18, wherein the hydrocarbon feed comprises low sulfur waxy resid.

20. The process according to any of paragraphs 12 to 19, wherein about 60 wt% to about 80 wt% of the heavy cut stream has a final boiling point below about 1100 ⁰ F (590 ⁰ C). 21. The process according to any of paragraphs 12 to 20, wherein the hydrocarbon feed has a final boiling point of at least about 600 ⁰ F (315°C).

22. The process according to any of paragraphs 12 to 21, wherein the vapor phase from the heated heavy cut stream has a final boiling point below about 1400 ⁰ F (760 ⁰ C).

23. The process according to any of paragraphs 12 to 22, wherein separating the vapor phase from the liquid phase occurs at a pressure of about 280 kPa to about 1380 kPa.

24. A process for processing a hydrocarbon feed to produce one or more olefins, comprising: preheating the hydrocarbon feed to a temperature sufficient to selectively separate the hydrocarbon feed into a heavy cut stream and a light cut stream; thermally cracking the light cut stream in a first cracking zone at conditions sufficient to provide a first product stream comprising one or more olefins; heating the heavy cut stream in a second cracking zone at conditions sufficient to provide a heated heavy cut stream having a vapor phase and a liquid phase; removing at least a portion of the heated heavy cut stream having the vapor phase and the liquid phase from the second cracking zone; separating the vapor phase from the liquid phase to provide a vapor phase stream and a liquid phase stream; returning at least a portion of the vapor phase stream to the second cracking zone; and thermally cracking the vapor phase stream to provide a second product stream comprising one or more olefins.

25. The process according to paragraph 24, wherein preheating the hydrocarbon feed to a temperature sufficient to selectively separate the hydrocarbon feed into a heavy cut stream

and a light cut stream comprises heating the hydrocarbon feed against the heavy cut stream or against steam or both.

26. The process according to paragraphs 24 or 25, further comprising heating the hydrocarbon feed against steam after preheating the hydrocarbon feed against the heavy cut stream.

27. The process according to any of paragraphs 24 to 26, wherein the hydrocarbon feed consists essentially of crude oil.

28. The process according to any of paragraphs 24 to 27, wherein the water consists essentially of steam. 29. The process according to any of paragraphs 24 to 28, wherein the hydrocarbon feed has a final boiling point of about 800 ⁰ F (426°C) or more.

30. The process according to any of paragraphs 24 to 29, wherein the light cut stream is substantially condensed prior to thermally cracking the light cut stream in the first cracking zone. 31. The process according to any of paragraphs 24 to 30, wherein preheating the hydrocarbon feed to a temperature sufficient to selectively separate the hydrocarbon feed into a heavy cut stream and a light cut stream comprises heating the hydrocarbon feed against the heavy cut stream and further heated against steam; and wherein the light cut stream is substantially condensed prior to thermally cracking the light cut stream in the first cracking zone, and the energy from the condensation provides the steam to heat the hydrocarbon feed.

32. The process according to any of paragraphs 24 to 31 , further comprising introducing water to form a heated mixture comprising the water and the heavy cut stream.

33. The process according to any of paragraphs 32, further comprising monitoring a ratio of the separated vapor phase to the separated liquid phase by monitoring the temperature of the heated mixture.

34. The process according to any of paragraphs 32 to 33, further comprising maintaining the hydrocarbon partial pressure of the mixture substantially constant.

35. The process according to any of paragraphs 32 to 34, further comprising using the heat of vaporization of the water to control the temperature of the heated mixture. 36. The process according to any of paragraphs 32 to 35, wherein a secondary dilution steam is superheated and then mixed with the heated mixture.

37. The process according to any of paragraphs 32 to 36, wherein a secondary dilution steam is superheated, and a first portion of the superheated secondary dilution steam is mixed

with the heated mixture and a second portion of the superheated secondary dilution steam is mixed with the vapor phase stream.

38. The process according to any of paragraphs 24 to 37, wherein the hydrocarbon feed comprises low sulfur waxy resid. 39. The process according to any of paragraphs 24 to 38, wherein about 60 wt% to about 80 wt% of the heavy cut stream has a final boiling point below about 1100 ⁰ F (590 ⁰ C).

40. The process according to any of paragraphs 24 to 39, wherein the hydrocarbon feed has a final boiling point of at least about 600 ⁰ F (315°C).

41. The process according to any of paragraphs 24 to 40, wherein the hydrocarbon feed comprises at least one of steam cracked gas oil and residues, gas oils, heating oil, jet fuel, diesel, kerosene, gasoline, coker naptha, steam cracked naphtha, catalytically cracked naphtha, hydrocrackate, reformate, raffmate 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 condensate, heavy non- virgin hydrocarbon streams from refineries, vacuum gas oils, heavy gas oil, naphtha contaminated with crude, atmospheric resid, heavy residuum, C4's/residue admixture, or naphtha residue admixture.

42. The process according to any of paragraphs 24 to 41, wherein the vapor phase stream comprises of from about 50 wt% to about 95 wt% of the hydrocarbons in the hydrocarbon feed.

43. A system for processing a hydrocarbon feed to produce one or more olefins, comprising: one or more heat exchangers operated at a temperature sufficient to selectively separate the hydrocarbon feed into a heavy cut stream and a light cut stream, wherein at least a portion of the heat is provided by heat from the heavy cut stream; a first furnace operated at conditions sufficient to thermally crack the light cut stream to form a first product stream comprising one or more olefins; a second furnace comprising at least one convection section and at least one radiant section, the convection section operated at conditions to heat the heavy cut stream to provide a vapor phase and a liquid phase; and means for separating the vapor phase from the liquid phase to provide a vapor phase stream and a liquid phase stream, wherein the vapor phase stream is thermally cracked within the radiant section to provide a second product stream comprising one or more olefins.

44. The system according to paragraph 43, wherein the means for separating the vapor phase from the liquid phase comprises one or more flash drum.

45. The system according to paragraph 43 or 44, wherein the one or more flash drums are located external to the second furnace. 46. The system according to any of paragraphs 43 to 45, further comprising one or more spargers to introduce water to the heated heavy cut stream within the convection section to form a mixture.

47. The system according to any of paragraphs 43 to 46, wherein the convection section is adapted to heat at least a portion of the vapor phase stream, and wherein the heated vapor phase stream is fed to the radiant section.

48. The system according to any of paragraphs 43 to 47, wherein the one or more heat exchangers comprises at least one preheater arranged in series with at least one steam heater.

49. The system according to any of paragraphs 43 to 48, wherein the one or more heat exchangers comprises at least one preheater arranged in series with at least one steam heater, wherein the hydrocarbon feed is heated within the at least one preheater against the heavy cut stream and then further heated within the at least one steam heater against steam.

50. The system according to any of paragraphs 43 to 49, further comprising at least one condenser for substantially cooling the light cut stream prior to feeding the light cut stream to the first furnace, wherein the energy from the condensation provides the steam for the at least one steam heater.

[0057] Certain embodiments and features have been described using a set of numerical upper limits and a set of numerical lower limits. It should be appreciated that ranges from any lower limit to any upper limit are contemplated unless otherwise indicated. Certain lower limits, upper limits and ranges appear in one or more claims below. All numerical values are "about" or "approximately" the indicated value, and take into account experimental error and variations that would be expected by a person having ordinary skill in the art.

[0058] Various terms have been defined above. To the extent a term used in a claim is not defined above, it should be given the broadest definition persons in the pertinent art have given that term as reflected in at least one printed publication or issued patent. Furthermore, all patents, test procedures, and other documents cited in this application are fully incorporated by reference to the extent such disclosure is not inconsistent with this application and for all jurisdictions in which such incorporation is permitted.

[0059] While the foregoing is directed to embodiments of the present invention, other and further embodiments of the invention may be devised without departing from the basic scope thereof, and the scope thereof is determined by the claims that follow.