Patent Publication Number: US-2022220047-A1

Title: Systems and processes for producing olefins from crude oil

Description:
CROSS-REFERENCE TO RELATED APPLICATION 
     This application is a continuation application of U.S. patent application Ser. No. 17/146,901 filed Jan. 12, 2021, the entire disclosure of which is hereby incorporated herein by reference. 
    
    
     BACKGROUND 
     Field 
     The present disclosure relates to systems and processes for separating and upgrading petroleum-based hydrocarbons, in particular, systems and processes for separating and upgrading hydrocarbon feeds, such as crude oil, utilizing a deasphalting process in a solvent deasphalting unit prior to steam catalytic cracking. 
     Technical Background 
     The worldwide increase in demand for light olefins remains a major challenge for many integrated refineries. In particular, the production of some valuable light olefins such as ethylene, propene, and butene has attracted increased attention as purified olefin streams are considered the building blocks for polymer synthesis. The production of light olefins depends on several process variables, such as the feed type, operating conditions, and the type of catalyst. Despite the options available for producing a greater yield of propene and other light olefins, intense research activity in this field is still being conducted. 
     Petrochemical feeds, such as crude oils, can be converted to fuel blending components, chemical products, and intermediates, such as olefins and aromatic compounds, which are basic intermediates for a large portion of the petrochemical industry. Crude oil is conventionally processed by distillation followed by various reforming, solvent treatments, and hydroconversion processes to produce a desired slate of fuels, lubricating oil products, chemicals, chemical feedstocks, and the like. An example of a conventional refinery process includes distillation of crude oil by atmospheric distillation to recover gas oil, naphtha, gaseous products, and an atmospheric residue. Streams recovered from crude oil distillation at the boiling point of fuels have customarily been further processed to produce fuel components or greater value chemical products or intermediates. 
     Conventional refinery systems generally combine multiple complex refinery units with petrochemical plants. For example, conventional refinery systems employ atmospheric and vacuum distillation of crude oil followed by hydrocracking units to produce naphtha, liquefied petroleum gas (LPG), and other light fractions. Then, these materials are further processed in a steam cracker, a naphtha cracker, a reformer unit for benzene, toluene, and xylenes (BTX) production, a fluidized catalytic cracking unit, or a combination of these to produce olefins, such as olefins. 
     SUMMARY 
     Despite conventional refinery systems available for producing petrochemical products and intermediates from hydrocarbon feeds, these complex refinery systems often require many different unit operations for conversion of hydrocarbon feeds, such as crude oil, to greater value petrochemical products and intermediates, such as olefins. 
     Accordingly, there is an ongoing need for systems and processes to convert hydrocarbon feeds to olefins without the complexity of combining several refinery units. These needs are met by embodiments of systems and processes for producing olefins from the hydrocarbon feed described in the present disclosure. The systems and processes of the present disclosure comprise introducing the hydrocarbon feed into a solvent deasphalting unit (SDA) to remove asphaltene from the hydrocarbon feed and thereby producing a deasphalted oil stream. The SDA comprises a solvent that reacts with the hydrocarbon feed, and the deasphalted oil stream comprises from 0.01 weight percent (wt. %) to 18 wt. % asphaltenes. The deasphalted oil stream is introduced into a steam catalytic cracking system where the deasphalted oil stream is steam catalytically cracked in the steam catalytic cracking system in the presence of steam and a nano zeolite cracking catalyst to produce a steam catalytic cracking effluent. The olefins are separated from the steam catalytic cracking effluent. The systems and processes of the present disclosure utilize simple pre-treatment systems that require only one or few steps of pre-treatment prior to direct steam catalytic conversion of a deasphalted oil stream to olefins. Accordingly, the systems and processes of the present disclosure increase yield and production of greater value products and intermediates, such as olefins, with fewer unit operations and processing steps than conventional systems and processes, such as various combinations of hydrotreating units, reformers, aromatic recovery complexes, hydrocracking units, or fluidized catalytic cracking units. The systems and processes of the present disclosure may also increase yields of other valuable petrochemical products and intermediates, such as but not limited to gasoline blending components, benzene, toluene, xylenes, or combinations of these. 
     According to one or more other aspects of the present disclosure, a process for producing olefins from a hydrocarbon feed may include introducing the hydrocarbon feed into a Solvent Deasphalting Unit (SDA) to remove asphaltene from the hydrocarbon feed producing a deasphalted oil stream. The SDA may include a solvent that reacts with the hydrocarbon feed, and the deasphalted oil stream may include from 0.01 weight percent (wt. %) to 18 wt. % asphaltenes. The process may further include introducing the deasphalted oil stream into a steam catalytic cracking system, steam catalytically cracking the deasphalted oil stream in the steam catalytic cracking system in the presence of steam and a nano zeolite cracking catalyst to produce a steam catalytic cracking effluent, and separating the olefins from the steam catalytic cracking effluent. 
     Additional features and advantages of the technology described in this disclosure will be set forth in the detailed description which follows, and in part will be readily apparent to those skilled in the art from the description or recognized by practicing the technology as described in this disclosure, including the detailed description which follows, the claims, as well as the appended drawings. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       The following detailed description of specific embodiments of the present disclosure can be best understood when read in conjunction with the following drawings, where like structure is indicated with like reference numerals and in which: 
         FIG. 1  schematically depicts a generalized flow diagram of a system for separating and upgrading crude oil, according to one or more embodiments shown and described in this disclosure; 
         FIG. 2  schematically depicts a generalized flow diagram of a steam catalytic cracking system and steam catalytic cracking effluent separation system of the system for separating and upgrading crude oil in  FIG. 1 , according to one or more embodiments shown and described in this disclosure; 
         FIG. 3  schematically depicts a generalized flow diagram of another embodiment of a system for separating and upgrading crude oil, according to one or more embodiments shown and described in this disclosure; 
         FIG. 4  schematically depicts a generalized flow diagram of still another embodiment of a system for separating and upgrading crude oil, according to one or more embodiments shown and described in this disclosure; 
         FIG. 5  schematically depicts a generalized flow diagram of another embodiment of a system for separation and upgrading crude oil, according to one or more embodiments shown and described in this disclosure; and 
         FIG. 6  schematically depicts a generalized flow diagram of another embodiment of a system for separation and upgrading crude oil, according to one or more embodiments shown and described in this disclosure. 
     
    
    
     For the purpose of describing the simplified schematic illustrations and descriptions of  FIGS. 1-6 , the numerous valves, temperature sensors, pressure sensors, electronic controllers and the like that may be employed and well known to those of ordinary skill in the art of certain chemical processing operations are not included. Further, accompanying components that are often included in chemical processing operations, such as, for example, air supplies, heat exchangers, surge tanks, or other related systems are not depicted. It would be known that these components are within the spirit and scope of the present embodiments disclosed. However, operational components, such as those described in the present disclosure, may be added to the embodiments described in this disclosure. 
     It should further be noted that arrows in the drawings refer to process streams. However, the arrows may equivalently refer to transfer lines, which may serve to transfer process steams between two or more system components. Additionally, arrows that connect to system components define inlets or outlets in each given system component. The arrow direction corresponds generally with the major direction of movement of the materials of the stream contained within the physical transfer line signified by the arrow. Furthermore, arrows, which do not connect two or more system components, signify a product stream, which exits the depicted system, or a system inlet stream, which enters the depicted system. Product streams may be further processed in accompanying chemical processing systems or may be commercialized as end products. System inlet streams may be streams transferred from accompanying chemical processing systems or may be non-processed feedstock streams. Some arrows may represent recycle streams, which are effluent streams of system components that are recycled back into the system. However, it should be understood that any represented recycle stream, in some embodiments, may be replaced by a system inlet stream of the same material, and that a portion of a recycle stream may exit the system as a system product. 
     Additionally, arrows in the drawings may schematically depict process steps of transporting a stream from one system component to another system component. For example, an arrow from one system component pointing to another system component may represent “passing” a system component effluent to another system component, which may include the contents of a process stream “exiting” or being “removed” from one system component and “introducing” the contents of that product stream to another system component. 
     It should be understood that two or more process streams are “mixed” or “combined” when two or more lines intersect in the schematic flow diagrams of  FIGS. 1-6 . Mixing or combining may also include mixing by directly introducing both streams into the same reactor, separation device, or other system component. For example, it should be understood that when two streams are depicted as being combined directly prior to entering a separation unit or reactor, in some embodiments the streams could equivalently be introduced into the separation unit or reactor individually and be mixed in the reactor. 
     Reference will now be made in greater detail to various embodiments, some embodiments of which are illustrated in the accompanying drawings. Whenever possible, the same reference numerals will be used throughout the drawings to refer to the same or similar parts. 
     DETAILED DESCRIPTION 
     The present disclosure is directed to systems and processes for separating and upgrading hydrocarbon feeds, such as crude oil, to produce more valuable products and chemical intermediates, such as olefins. Referring to  FIG. 1 , one embodiment of a system  100  for upgrading a hydrocarbon feed  101  comprising crude oil or other heavy oil is schematically depicted. The system  100  may include a solvent deasphalting unit (SDA)  10 , which may remove asphaltenes from the hydrocarbon feed  101  producing a deasphalted oil stream  12 . The system  100  may further include a steam catalytic cracking system  20 , which catalytically cracks the deasphalted oil stream  12  in the presence of steam  13  and a nano zeolite cracking catalyst to produce a steam catalytic cracking effluent  21 . The system  100  may further include a steam catalytic cracking effluent separation system  250 . The steam catalytic cracking effluent separation system  250  may include separation units that separate various components of the steam catalytic cracking effluent  21 . According to embodiments, these separation units may include one or both of a gas and liquid separation unit  30 , or a liquid and liquid separation unit  40 . Either of these separation units may be disposed downstream of the steam catalytic cracking system  20 . 
     The system  100  may be utilized in a process for separating and upgrading the hydrocarbon feed  101 . The process for converting the hydrocarbon feed  101  may include introducing the hydrocarbon feed  101  into the SDA  10  to remove asphaltenes from the hydrocarbon feed  101  thereby producing a deasphalted oil stream  12 . The SDA  10  comprises a solvent that reacts with the hydrocarbon feed  101  to aid in the removal of asphaltenes from the hydrocarbon feed  101 . In embodiments, the deasphalted oil stream  12  comprises from 0.01 weight percent (wt. %) to 18 wt. % asphaltenes. The process may further include introducing the deasphalted oil stream  12  into the steam catalytic cracking system  20 , and steam catalytically cracking the deasphalted oil stream  12  in the steam catalytic cracking system  20  in the presence of steam  13  and the nano zeolite cracking catalyst to produce the steam catalytic cracking effluent  21 . The process may further include separating olefins from the steam catalytic cracking effluent  21 . 
     The systems and processes of the present disclosure utilize a simple pre-treatment system that requires only one or few steps of pre-treatment prior to direct steam catalytic conversion of the hydrocarbon feed  101  to olefins. Accordingly, the systems and processes of the present disclosure increase yield and production of valuable products and intermediates, such as olefins including ethylene, propylene, butenes, or combinations of these, with less equipment and process units, such as distillation units, hydrotreating units, hydrocracking units, fluidized catalytic cracking units, or combinations of these. The steam catalytic cracking system  20  may use 25 to 50 times less catalyst and may be operated with a longer time on stream compared to fluidized catalytic cracking units for producing olefins, among other benefits. 
     As used in this disclosure, a “reactor” refers to any vessel, container, or the like, in which one or more chemical reactions may occur between one or more reactants optionally in the presence of one or more catalysts. For example, a reactor may include a tank or tubular reactor configured to operate as a batch reactor, a continuous stirred-tank reactor (CSTR), or a plug flow reactor. Example reactors include packed bed reactors such as fixed bed reactors, and fluidized bed reactors. As used in the present disclosure, the term “fixed bed reactor” may refer to a reactor in which a catalyst is confined within the reactor in a reaction zone in the reactor and is not circulated continuously through a reactor and regenerator system. 
     As used in this disclosure, one or more “reaction zones” may be disposed within a reactor. As used in this disclosure, a “reaction zone” refers to an area in which a particular reaction takes place in a reactor. For example, a packed bed reactor with multiple catalyst beds may have multiple reaction zones, in which each reaction zone is defined by the area of each catalyst bed. 
     As used in this disclosure, a “separation unit” refers to any separation device that at least partially separates one or more chemicals in a mixture from one another. For example, a separation unit may selectively separate different chemical species from one another, forming one or more chemical fractions. Examples of separation units include, without limitation, distillation columns, fractionators, flash drums, knock-out drums, knock-out pots, centrifuges, filtration devices, traps, scrubbers, expansion devices, membranes, solvent extraction devices, high-pressure separators, low-pressure separators, and the like. It should be understood that separation processes described in this disclosure may not completely separate all of one chemical constituent from all of another chemical constituent. It should be understood that the separation processes described in this disclosure “at least partially” separate different chemical components from one another, and that even if not explicitly stated, it should be understood that separation may include only partial separation. As used in this disclosure, one or more chemical constituents may be “separated” from a process stream to form a new process stream. Generally, a process stream may enter a separation unit and be divided or separated into two or more process streams of desired composition. 
     As used in this disclosure, the term “fractionation” may refer to a process of separating one or more constituents of a composition in which the constituents are divided from each other during a phase change based on differences in properties of each of the constituents. As an example, as used in this disclosure, “distillation” refers to separation of constituents of a liquid composition based on differences in the boiling point temperatures of constituents of a composition, either at atmospheric conditions or under negative pressure. As used in this disclosure, the term “vacuum distillation” may refer to distillation conducted under a negative pressure relative to atmospheric pressure. 
     As used in this disclosure, the terms “upstream” and “downstream” may refer to the relative positioning of unit operations with respect to the direction of flow of the process streams. A first unit operation of the system may be considered “upstream” of a second unit operation if process streams flowing through the system encounter the first unit operation before encountering the second unit operation. Likewise, a second unit operation may be considered “downstream” of the first unit operation if the process streams flowing through the system encounter the first unit operation before encountering the second unit operation. 
     As used in the present disclosure, passing a stream or effluent from one unit “directly” to another unit may refer to passing the stream or effluent from the first unit to the second unit without passing the stream or effluent through an intervening reaction system or separation system that substantially changes the composition of the stream or effluent. Heat transfer devices, such as heat exchangers, preheaters, coolers, condensers, or other heat transfer equipment, and pressure devices, such as pumps, pressure regulators, compressors, or other pressure devices, are not considered to be intervening systems that change the composition of a stream or effluent. Combining two streams or effluents together also is not considered to comprise an intervening system that changes the composition of one or both of the streams or effluents being combined. Surge vessels are also not considered to be intervening systems that change the composition of a stream or effluent. 
     As used in this disclosure, the term “initial boiling point” or “IBP” of a composition may refer to the temperature at which the constituents of the composition with the least boiling point temperatures begin to transition from the liquid phase to the vapor phase. As used in this disclosure, the term “end boiling point” or “EBP” of a composition may refer to the temperature at which the greatest boiling temperature constituents of the composition transition from the liquid phase to the vapor phase. A hydrocarbon mixture may be characterized by a distillation profile expressed as boiling point temperatures at which a specific weight percentage of the composition has transitioned from the liquid phase to the vapor phase. 
     As used in this disclosure, the term “atmospheric boiling point temperature” may refer to the boiling point temperature of a compound at atmospheric pressure. 
     As used in this disclosure, the term “effluent” may refer to a stream that is passed out of a reactor, a reaction zone, or a separation unit following a particular reaction or separation. Generally, an effluent has a different composition than the stream that entered the separation unit, reactor, or reaction zone. It should be understood that when an effluent is passed to another system unit, only a portion of that system stream may be passed. For example, a slip stream may carry some of the effluent away, meaning that only a portion of the effluent may enter the downstream system unit. The term “reaction effluent” may more particularly be used to refer to a stream that is passed out of a reactor or reaction zone. 
     As used in this disclosure, a “catalyst” may refer to any substance that increases the rate of a specific chemical reaction. Catalysts described in this disclosure may be utilized to promote various reactions, such as, but not limited to, steam cracking, aromatic cracking, hydrodearylation, hydrotreating, reforming, isomerization, or combinations thereof. However, some catalysts described in the present disclosure may have multiple forms of catalytic activity, and calling a catalyst by one particular function does not render that catalyst incapable of being catalytically active for other functionality. 
     As used in this disclosure, “cracking” generally refers to a chemical reaction where a molecule having carbon-carbon bonds is broken into more than one molecule by the breaking of one or more of the carbon-carbon bonds; where a compound including a cyclic moiety, such as an aromatic compound, is converted to a compound that does not include a cyclic moiety; or where a molecule having carbon-carbon double bonds are reduced to carbon-carbon single bonds. 
     As used in this disclosure, the term “size” or “crystal size” may refer to an average particle diameter of alumina oxide, or nano-zeolite cracking catalyst when the alumina oxide or nano-zeolite cracking catalyst is in the form of spherical particles, or may refer to a length of a major axis of alumina oxide or nano-zeolite cracking catalyst when the alumina oxide or nano-zeolite cracking catalyst is not in a spherical form, for example, in the form of non-spherical particles. 
     As used in this disclosure, the term “crude oil” or “whole crude oil” is to be understood to mean a mixture of petroleum liquids, gases, or combinations of liquids and gases, including, in some embodiments, impurities such as but not limited to sulfur-containing compounds, nitrogen-containing compounds, and metal compounds, that have not undergone significant separation or reaction processes. Crude oils are distinguished from fractions of crude oil. In certain embodiments, the crude oil feedstock may be a minimally treated light crude oil to provide a crude oil feedstock having total metals (Ni+V) content of less than 5 parts per million by weight (ppmw) and Conradson carbon residue of less than 5 wt. %. 
     It should further be understood that streams may be named for the components of the stream, and the component for which the stream is named may be the major component of the stream (such as comprising from 50 wt. %, from 70 wt. %, from 90 wt. %, from 95 wt. %, from 99 wt. %, from 99.5 wt. %, or even from 99.9 wt. % of the contents of the stream to 100 wt. % of the contents of the stream). It should also be understood that components of a stream are disclosed as passing from one system component to another when a stream comprising that component is disclosed as passing from that system component to another. For example, a disclosed “hydrogen stream” passing to a first system component or from a first system component to a second system component should be understood to equivalently disclose “hydrogen” passing to the first system component or passing from a first system component to a second system component. 
     Referring again to  FIG. 1 , an embodiment of the system  100  for separating and upgrading the hydrocarbon feed  101  is schematically depicted. As previously discussed, the system  100  may include the SDA  10  and the steam catalytic cracking system  20  downstream of the SDA  10 . The system  100  may further include the steam catalytic cracking effluent separation system  250 . The steam catalytic cracking effluent separation system  250  may include separation units that separate various components of the steam catalytic cracking effluent  21 . According to embodiments, these separation units may include one or both of a gas and liquid separation unit  30 , or a liquid and liquid separation unit  40 . Either of these separation units may be disposed downstream of the steam catalytic cracking system  20 . 
     The hydrocarbon feed  101  may include one or more heavy oils, such as but not limited to crude oil, vacuum residue, tar sands, bitumen, other heavy oil streams, or combinations of these. It should be understood that, as used in this disclosure, a “heavy oil” may refer to a raw hydrocarbon, such as whole crude oil, which has not been previously processed through distillation, or may refer to a hydrocarbon oil, which has undergone some degree of processing prior to being introduced into the system  100  as the hydrocarbon feed  101 . The hydrocarbon feed  101  may have a density of greater than or equal to 0.80 grams per milliliter. The hydrocarbon feed  101  may have an end boiling point (EBP) of greater than 565° C. The hydrocarbon feed  101  may have a concentration of nitrogen of less than or equal to 3000 parts per million by weight (ppmw). 
     In embodiments, the hydrocarbon feed  101  may be a crude oil, such as a whole crude oil. The crude oil may have an American Petroleum Institute (API) gravity of from 25 degrees to 50 degrees. For example, the hydrocarbon feed  101  may include a light crude oil, a heavy crude oil, or combinations of these. Example properties for an exemplary grade of Arab light crude oil are listed in Table 1. 
     
       
         
           
               
             
               
                 TABLE 1 
               
             
            
               
                   
               
               
                 Example of Arab Light Export Feedstock 
               
            
           
           
               
               
               
               
            
               
                   
                   
                   
                 Test 
               
               
                 Analysis 
                 Units 
                 Value 
                 Method 
               
               
                   
               
            
           
           
               
               
               
               
            
               
                 American Petroleum 
                 degree 
                 33.13 
                 ASTM D287 
               
               
                 Institute (API) 
               
               
                 gravity 
               
               
                 Density 
                 grams per milliliter 
                 0.8595 
                 ASTM D287 
               
               
                   
                 (g/mL) 
               
               
                 Carbon Content 
                 weight percent 
                 85.29 
                 ASTM D5291 
               
               
                   
                 (wt. %) 
               
               
                 Hydrogen Content 
                 wt. % 
                 12.68 
                 ASTM D5292 
               
               
                 Sulfur Content 
                 wt. % 
                 1.94 
                 ASTM D5453 
               
               
                 Nitrogen Content 
                 parts per million by 
                 849 
                 ASTM D4629 
               
               
                   
                 weight (ppmw) 
               
               
                 Asphaltenes 
                 wt. % 
                 1.2 
                 ASTM D6560 
               
               
                 Micro Carbon Residue 
                 wt. % 
                 3.4 
                 ASTM D4530 
               
               
                 (MCR) 
               
               
                 Vanadium (V) Content 
                 ppmw 
                 15 
                 IP 501 
               
               
                 Nickel (Ni) Content 
                 ppmw 
                 12 
                 IP 501 
               
               
                 Arsenic (As) Content 
                 ppmw 
                 0.04 
                 IP 501 
               
            
           
           
               
            
               
                 Boiling Point Distribution 
               
            
           
           
               
               
               
               
            
               
                 Initial Boiling Point 
                 Degrees Celsius 
                 33 
                 ASTM D7169 
               
               
                 (IBP) 
                 (° C.) 
               
               
                 5% Boiling Point (BP) 
                 ° C. 
                 92 
                 ASTM D7169 
               
               
                 10% BP 
                 ° C. 
                 133 
                 ASTM D7169 
               
               
                 20% BP 
                 ° C. 
                 192 
                 ASTM D7169 
               
               
                 30% BP 
                 ° C. 
                 251 
                 ASTM D7169 
               
               
                 40% BP 
                 ° C. 
                 310 
                 ASTM D7169 
               
               
                 50% BP 
                 ° C. 
                 369 
                 ASTM D7169 
               
               
                 60% BP 
                 ° C. 
                 432 
                 ASTM D7169 
               
               
                 70% BP 
                 ° C. 
                 503 
                 ASTM D7169 
               
               
                 80% BP 
                 ° C. 
                 592 
                 ASTM D7169 
               
               
                 90% BP 
                 ° C. 
                 &gt;720 
                 ASTM D7169 
               
               
                 95% BP 
                 ° C. 
                 &gt;720 
                 ASTM D7169 
               
               
                 End Boiling Point 
                 ° C. 
                 &gt;720 
                 ASTM D7169 
               
               
                 (EBP) 
               
               
                 BP range C5-180° C. 
                 wt. % 
                 18.0 
                 ASTM D7169 
               
               
                 BP range 180° C.- 
                 wt. % 
                 28.8 
                 ASTM D7169 
               
               
                 350° C. 
               
               
                 BP range 350° C.- 
                 wt. % 
                 27.4 
                 ASTM D7169 
               
               
                 540° C. 
               
               
                 BP range &gt;540° C. 
                 wt. % 
                 25.8 
                 ASTM D7169 
               
               
                   
               
               
                 Weight percentages in Table 1 are based on the total weight of the crude oil. 
               
            
           
         
       
     
     When the hydrocarbon feed  101  comprises a crude oil, the crude oil may be a whole crude or may be a crude oil that has undergone at some processing, such as desalting, solids separation, or scrubbing. For example, the hydrocarbon feed  101  may be a de-salted crude oil that has been subjected to a de-salting process. In embodiments, the hydrocarbon feed  101  may include a crude oil that has not undergone pretreatment, separation (such as distillation), or other operation that changes the hydrocarbon composition of the crude oil prior to introducing the crude oil to the system  100 . 
     A process for converting a hydrocarbon feed  101  to olefins according to one or more embodiments will now be described with reference again to  FIG. 1 . The hydrocarbon feed  101  may be fluidly coupled to the SDA  10 , so that the hydrocarbon feed  101  may be introduced into the SDA  10 . The SDA  10  may operate to remove asphaltene compounds from the hydrocarbon feed  101  to produce a deasphalted residue stream  11 , and a deasphalted oil stream  12  that may be passed to the steam catalytic cracking system  20 . Passing the deasphalted oil stream  12  to the steam catalytic cracking system  20  may further increase the conversion of the hydrocarbon feed  101  to olefins in the system  100 . The SDA  10  may be disposed upstream of the steam catalytic cracking system  20 . 
     The deasphalted oil stream  12  may have from 0.01 weight percent (wt. %) to 18 wt. % asphaltenes. In embodiments, the deasphalted oil stream  12  may have from 0.1 wt. % to 18 wt. %, from 1 wt. % to 18 wt. %, from 2 wt. % to 18 wt. %, from 5 wt. % to 18 wt. %, from 0.01 wt. % to 15 wt. %, from 1 wt. % to 15 wt. %, from 2 wt. % to 15 wt. %, or from 5 wt. % to 15 wt. % asphaltenes. 
     The SDA  10  contains a solvent. The solvent may comprise propane, butane, pentane, or combinations of these. In embodiments, a solvent-to-oil (hydrocarbon feed  101 ) volume ratio is from 2:1 to 50:1, 3:1 to 50:1, 4:1 to 50:1, 5:1 to 50:1, 2:1 to 45:1, or 2:1 to 40:1. The solvent may, according to embodiments, be selected based upon the feed. For example, propane may be used as the solvent for crude oil, and a mixture of propane and butane may be used as the solvent for oil stripped from LPG. 
     The system  100  includes the steam catalytic cracking system  20 . The steam catalytic cracking system  20  may be disposed downstream of the SDA  10 . The steam catalytic cracking system  20  may operate to contact the deasphalted oil stream  12  with steam  13  in the presence of a nano-zeolite cracking catalyst to produce a steam catalytic cracking effluent  21 . 
     Referring now to  FIG. 2 , a simplified schematic illustration of one particular embodiment of the steam catalytic cracking system  20  is graphically depicted. It should be understood that other configurations of the steam catalytic cracking system  20  may be suitable for incorporation into the system  100  for converting hydrocarbon feeds to olefins. The steam catalytic cracking system  20  may include one or a plurality of steam catalytic cracking reactors  200 . The steam catalytic cracking reactor  200  may be a fixed bed catalytic cracking reactor that includes a cracking catalyst  202  disposed within a steam cracking catalyst zone  204 . The steam catalytic cracking reactor  200  may include a porous packing material  208 , such as silica carbide packing, upstream of the steam cracking catalyst zone  204 . The porous packing material  208  may ensure sufficient heat transfer to the deasphalted oil stream  12  and steam prior to conducting the steam catalytic cracking reaction in the steam cracking catalyst zone  204 . 
     The cracking catalyst may be a nano-zeolite cracking catalyst comprising nano-zeolite particles. A variety of nano-zeolites may be suitable for the steam catalytic cracking reactions in the steam catalytic cracking reactor  200 . The nano-zeolite cracking catalyst may include a structured zeolite, such as an MFI or BEA structured zeolite, for example. In embodiments, the nano-zeolite cracking catalyst may comprise nano ZSM-5 zeolite, nano BEA zeolite, or both. In embodiments, the nano-zeolite cracking catalyst may include a combination of nano ZSM-5 zeolite and nano BEA zeolite. The nano-zeolites, such as nano-ZSM-5, nano Beta zeolite, or both may be in hydrogen form. In hydrogen form, the Brønsted acid sites in the zeolite, also known as bridging O H —H groups, may form hydrogen bonds with other framework oxygen atoms in the zeolite framework. 
     The nano ZSM-5 zeolite, the nano Beta zeolite, or both may have a molar ratio of silica to alumina to provide sufficient acidity to the nano-zeolite cracking catalyst to conduct the steam catalytic cracking reactions. The nano-ZSM-5 zeolite, nano Beta zeolite, or both, may have a molar ratio of silica to alumina of from 10 to 200, from 15 to 200, from 20 to 200, from 10 to 150, from 15 to 150, or from 20 to 150. The nano-ZSM-5 zeolite, nano Beta zeolite, or both combined, may have total acidity in the range of 0.2 to 2.5 mmol/g, 0.3 to 2.5 mmol/g, 0.4 to 2.5 mmol/g, 0.5 to 2.5 mmol/g, 0.2 to 2.0 mmol/g, 0.3 to 2.0 mmol/g, 0.4 to 2.0 mmol/g, or 0.5 to 2.0 mmol/g. The nano-ZSM-5 zeolite, nano Beta zeolite, or both combined, may contain Brønsted acid sites in the range of 0.1 to 1.0 mmol/g, 0.2 to 1.0 mmol/g, 0.3 to 1.0 mmol/g, 0.1 to 0.9 mmol/g, 0.2 to 0.9 mmol/g, or 0.3 to 0.9 mmol/g. The concentration of Brønsted acid sites may be determined by Pyridine Fourier-transform infrared spectroscopy (FTIR) using a pyridine molecule as a probe molecule and introduced to the cell to saturate the sample and was evacuated at 150° C. The obtained peaks at approximately 1540 and 1450 cm −1  represented Brønsted and Lewis acid sites respectively. The nano-ZSM-5 zeolite, nano Beta zeolite, or both, may have an average crystal size of from 50 nanometer (nm) to 600 nm, from 60 nm to 600 nm, from 70 nm to 600 nm, from 80 nm to 600 nm, from 50 nm to 580 nm, or from 50 nm to 550 nm. The average crystal size may be measured using the Scanning Electron Microscopy (SEM) technique. 
     The nano-zeolite cracking catalyst may also include an alumina binder, which may be used to consolidate the nanoparticles of nano ZSM-5 zeolite, nano Beta zeolite, or both to form the nano-zeolite cracking catalyst. The nano-zeolite cracking catalyst may be prepared by combining the nano ZSM-5 zeolite, the nano Beta zeolite, or both with the aluminum binder and extruding the nano-zeolite cracking catalyst to form pellets or other catalyst shapes. The nano-zeolite cracking catalyst may include from 10 weight percent (wt. %) to 80 wt. %, from 10 wt. % to 75 wt. %, from 10 wt. % to 70 wt. %, from 15 wt. % to 80 wt. %, from 15 wt. % to 75 wt. %, or from 15 wt. % to 70 wt. % alumina binder based on the total weight of the nano-zeolite cracking catalyst. The nano-zeolite cracking catalyst may have a mesoporous to microporous volume ratio in the range of from 0.5 to 1.5, from 0.6 to 1.5, from 0.7 to 1.5, from 0.5 to 1.0, from 0.6 to 1.0, or from 0.7 to 1.0. 
     Referring again to  FIG. 2 , the deasphalted oil stream  12  may be introduced to the steam catalytic cracking reactor  200 . Prior to introducing the deasphalted oil stream  12  into the steam catalytic cracking reactor  200 , the deasphalted oil stream  12  may be collected in a crude oil tank  350 , according to one or more embodiments. The deasphalted oil stream  12  may be heated to a temperature of from 35 degrees Celsius (° C.) to 150° C. and then introduced to a feed pump  370  through line  360 . In embodiments, the deasphalted oil stream  12  may be heated from 40° C. to 150° C., from 45° C. to 150° C., from 50° C. to 150° C., from 35° C. to 145° C., from 40° C. to 145° C., from 45° C. to 145° C., from 35° C. to 140° C., from 40° C. to 140° C., or from 45° C. to 140° C. The flowrate of the feed pump  370  may be adjusted so that the deasphalted oil stream  12  is injected into the steam catalytic cracking reactor  200  through line  380  at a gas hourly space velocity of greater than or equal to 0.1 per hour (h −1 ) or greater than or equal to 0.25 h −1 . The deasphalted oil stream  12  may be injected into the steam catalytic cracking reactor  200  at a gas hourly space velocity of less than or equal to 50 h −1 , less than or equal to 25 h −1 , less than or equal to 20 h −1 , less than or equal to 14 h −1 , less than or equal to 9 h −1 , or less than or equal to 5 h −1 . The deasphalted oil stream  12  may be injected into the steam catalytic cracking reactor  200  at a gas hourly space velocity of from 0.1 per hour (h −1 ) to 50 h −1 , from 0.1 h −1  to 25 h −1 , from 0.1 h −1  to 20 h −1 , from 0.1 h −1  to 14 h −1 , from 0.1 h −1  to 9 h −1 , from 0.1 h −1  to 5 h −1 , from 0.1 h −1  to 4 h −1 , from 0.25 h −1  to 50 h −1 , from 0.25 h −1  to 25 h −1 , from 0.25 h −1  to 20 h −1 , from 0.25 h −1  to 14 h −1 , from 0.25 h −1  to 9 h −1 , from 0.25 h −1  to 5 h −1 , from 0.25 h −1  to 4 h −1 , from 1 h −1  to 50 h −1 , from 1 h −1  to 25 h −1 , from 1 h −1  to 20 h −1 , from 1 h −1  to 14 h −1 , from 1 h −1  to 9 h −1 , or from 1 h −1  to 5 h −1  via the preheated line  380 . The deasphalted oil stream  12  may be further pre-heated in the line  380  to a temperature between 100° C. to 250° C. before injecting the deasphalted oil stream  12  into the steam catalytic cracking reactor  200 . 
     Water  120  may be injected to the steam catalytic cracking reactor  200  through lines  160 ,  180  via the water feed pump  170 . Prior to introducing the water  120  into the steam catalytic cracking reactor  200 , the water  120  may be collected in a water tank  150 . The water line  180  may be pre-heated to a temperature of from 50° C. to 75° C., from 50° C. to 70° C., from 55° C. to 75° C., or from 55° C. to 70° C. The water  120  may be converted to steam in water line  180  or upon contacting with the deasphalted oil stream  12  in the steam catalytic cracking reactor  200 . The flowrate of the water feed pump  170  may be adjusted to deliver water  120  (liquid, steam, or both) to the steam catalytic cracking reactor  200  at a gas hourly space velocity of greater than or equal to 0.1 h −1 , greater than or equal to 0.5 h −1 , greater than or equal to 1 h −1 , greater than or equal to 5 h −1 , greater than or equal to 6 h −1 , greater than or equal to 10 h −1 , or even greater than or equal to 15 h −1 . The water  120  may be introduced to the steam catalytic cracking reactor  200  at a gas hourly space velocity of less than or equal to 100 h −1 , less than or equal to 75 h −1 , less than or equal to 50 h −1 , less than or equal to 30 h −1 , or less than or equal to 20 h −1 . The water  120  may be introduced to the steam catalytic cracking reactor  200  at a gas hourly space velocity of from 0.1 h −1  to 100 h −1 , from 0.1 h −1  to 75 h −1 , from 0.1 h −1  to 50 h −1 , from 0.1 h −1  to 30 h −1 , from 0.1 h −1  to 20 h −1 , from 1 h −1  to 100 h −1 , from 1 h −1  to 75 h −1 , from 1 h −1  to 50 h −1 , from 1 h −1  to 30 h −1 , from 1 h −1  to 20 h −1 , from 5 h −1  to 100 h −1 , from 5 h −1  to 75 h −1 , from 5 h −1  to 50 h −1 , from 5 h −1  to 30 h −1 , from 5 h −1  to 20 h −1 , from 6 h −1  to 100 h −1 , from 6 h −1  to 75 h −1 , from 6 h −1  to 50 h −1 , from 6 h −1  to 30 h −1 , from 6 h −1  to 20 h −1 , from 10 h −1  to 100 h −1 , from 10 h −1  to 75 h −1 , from 10 h −1  to 50 h −1 , from 10 h −1  to 30 h −1 , from 10 h −1  to 20 h −1 , from 15 h −1  to 100 h −1 , from 15 h −1  to 75 h −1 , from 15 h −1  to 50 h −1 , from 15 h −1  to 30 h −1 , or from 15 h −1  to 20 h −1  via water line  180 . 
     The steam from injection of the water  120  may reduce the hydrocarbon partial pressure, which may have the dual effects of increasing yields of light olefins (e.g., ethylene, propylene and butylene) as well as reducing coke formation. Light olefins like propylene and butylene are mainly generated from catalytic cracking reactions following the carbonium ion mechanism, and as these are intermediate products, they can undergo secondary reactions such as hydrogen transfer and aromatization (leading to coke formation). The steam may increase the yield of light olefins by suppressing these secondary bi-molecular reactions, and reduce the concentration of reactants and products, which favor selectivity towards light olefins. The steam may also suppress secondary reactions that are responsible for coke formation on catalyst surface, which is good for catalysts to maintain high average activation. These factors may show that a large steam-to-oil weight ratio may be beneficial to the production of light olefins. 
     The gas hourly space velocity of water  120  introduced to the steam catalytic cracking reactor  200  may be greater than the gas hourly space velocity of the deasphalted oil stream  12  passed to the steam catalytic cracking reactor  200 . A ratio of the flowrate (gas hourly space velocity) of steam or water  120  to the flowrate (gas hourly space velocity) of deasphalted oil stream  12  to the steam catalytic cracking reactor  200  may be from 2 to 10 times, from 2 to 8 times, 2 to 6, from 2 to 5.5, from 2 to 5, from 3 to 6, from 3 to 5.5, or from 3 to 5 to improve the steam catalytic cracking process in the presence of the nano-zeolite cracking catalyst. 
     Referring still to  FIG. 2 , the steam catalytic cracking reactor  200  may be operable to contact the deasphalted oil stream  12  with steam (from water  120 ) in the presence of the nano-zeolite cracking catalyst under reaction conditions sufficient to cause at least a portion of the hydrocarbons from the deasphalted oil stream  12  to undergo one or more cracking reactions to produce a steam catalytic cracking effluent  21  comprising one or a plurality of olefins. The olefins may include ethylene, propylene, butenes, or combinations of these. The steam catalytic cracking reactor  200  may be operated at a temperature of greater than or equal to 525° C., greater than or equal to 550° C., or even greater than or equal to 575° C. The steam catalytic cracking reactor  200  may be operated at a temperature of less than or equal to 750° C., less than or equal to 675° C., less than or equal to 650° C., or even less than or equal to 625° C. The steam catalytic cracking reactor  200  may be operated at a temperature of from 525° C. to 750° C., from 525° C. to 675° C., from 525° C. to 650° C., from 525° C. to 625° C., from 550° C. to 675° C., from 550° C. to 650° C., from 550° C. to 625° C., from 575° C. to 675° C., from 575° C. to 650° C., or from 575° C. to 625° C. The process may operate at atmospheric pressure (approximately from 1 to 2 bar). 
     The steam catalytic cracking reactor  200  may be operated in a semi-continuous manner. For example, during a conversion cycle, the steam catalytic cracking reactor  200  may be operated with the deasphalted oil stream  12  and water  120  flowing to the steam catalytic cracking reactor  200  for a period of time, at which point the catalyst may be regenerated. Each conversion cycle of the steam catalytic cracking reactor  200  may be from 1 to 8 hours, from 1 to 6 hours, from 1 to 4 hours, from 2 to 8 hours, from 2 to 6 hours, or from 2 to 4 hours before switching off the feed pump  370  and the water pump  170 . At the end of the conversion cycle, the flow of deasphalted oil stream  12  and water  120  may be stopped and the nano-zeolite cracking catalyst may be regenerated during a regeneration cycle. In embodiments, the steam catalytic cracking system  20  may include a plurality of steam catalytic cracking reactors  200 , which can be operated in parallel or in series. With a plurality of steam catalytic cracking reactors  200  operating in parallel, one or more of the steam catalytic cracking reactors  200  can continue in a conversion cycle while one or more of the other steam catalytic cracking reactors  200  are taken off-line for regeneration of the nano-zeolite cracking catalyst, thus maintaining continuous operation of the steam catalytic cracking system  20 . 
     Referring to  FIG. 2 , during a regeneration cycle, the steam catalytic cracking reactor  200  may be operated to regenerate the nano-zeolite cracking catalyst. The nano-zeolite cracking catalyst may be regenerated to remove coke deposits accumulated during the conversion cycle. To regenerate the nano-zeolite cracking catalyst, hydrocarbon gas and liquid products produced by the steam catalytic cracking process may be evacuated from the steam catalytic cracking reactor  200 . Nitrogen gas may be introduced to the steam catalytic cracking reactor  200  through gas line  14  to evacuate the hydrocarbon gas and liquid products from the fixed bed steam catalytic cracking reactor  200 . Nitrogen may be introduced to the steam catalytic cracking reactor  200  at gas hourly space velocity of from 10 per hour (h −1 ) to 100 h −1 . 
     Following evacuation of the hydrocarbon gases and liquids, air may be introduced to the steam catalytic cracking reactor  200  through gas line  14  at a gas hourly space velocity of from 10 h −1  to 100 h −1 . The air may be passed out of the steam catalytic cracking reactor  200  through line  430 . While passing air through the nano-zeolite cracking catalyst in the steam catalytic cracking reactor  200 , the temperature of the steam catalytic cracking reactor  200  may be increased from the reaction temperature to a regeneration temperature of from 650° C. to 750° C. for a period of from 3 hours to 5 hours. The gas produced by air regeneration of nano-zeolite cracking catalyst may be passed out of the steam catalytic cracking reactor  200  through line  430  and may be analyzed by an in-line gas analyzer connected via line  430  to detect the presence or concentration of carbon dioxide produced through decoking of the nano-zeolite cracking catalyst. Once the carbon dioxide concentration in the gases passing out of the steam catalytic cracking reactor  200  are reduced to less than 0.05% to 0.1% by weight, as determined by the in-line gas analyzer, the temperature of the steam catalytic cracking reactor  200  temperature may be decreased from the regeneration temperature back to the reaction temperature. The airflow through line  14  may be stopped. Nitrogen gas may be passed through the nano-zeolite cracking catalyst for 15 to 30 minutes. Nitrogen gas may be stopped by closing the line  14 . After closing the line  14 , the flow of the deasphalted oil stream  12  and water  120  may be resumed to begin another conversion cycle of steam catalytic cracking reactor  200 . 
     Referring again to  FIG. 2 , the steam catalytic cracking effluent  21  may pass out of the steam catalytic cracking reactor  200 . The steam catalytic cracking effluent  21  may include one or more products and intermediates, such as but not limited to light hydrocarbon gases, olefins, aromatic compounds, pyrolysis oil, or combinations of these. Olefins in the steam catalytic cracking effluent  21  may include ethylene, propylene, butenes, or combinations of these. 
     The steam catalytic cracking system  20  may be disposed upstream of the steam catalytic cracking effluent separation system  250 . When the steam catalytic cracking system  20  includes a plurality of steam catalytic cracking reactors  200 , the steam catalytic cracking effluents  21  from each of the steam catalytic cracking reactors  200  may be passed to a single shared steam catalytic cracking effluent separation system  250 . In embodiments, each steam catalytic cracking reactor  200  may have a dedicated steam catalytic cracking effluent separation system  250 . The steam catalytic cracking effluent  21  may be passed from the steam catalytic cracking reactor  200  directly to the steam catalytic cracking effluent separation system  250 . The steam catalytic cracking effluent separation system  250  may separate the steam catalytic cracking effluent  21  into one or more than one cracking product effluents, which may be gaseous or liquid effluents. 
     In embodiments where the steam catalytic cracking effluent separation system  250  comprises both a gas and liquid separation unit  30  and liquid and liquid separation unit  40 , the liquid and liquid separation unit  40  may be disposed downstream of the gas and liquid separation unit  30 . The gas and liquid separation unit  30  may operate to separate the steam catalytic cracking effluent  21  into a gaseous effluent  31  and liquid effluent  32 . The gas and liquid separation unit  30  may operate to reduce the temperature of the steam catalytic cracking effluent  21  to condense constituents of the steam catalytic cracking effluent  21  having greater than or equal to 5 carbon atoms. The gas and liquid separation unit  30  may operate at a temperature of from 10° C. to 15° C. to ensure that normal pentane and constituents with boiling point temperatures greater than normal pentane are condensed into the liquid effluent  32 . The liquid effluent  32  may include light distillation fractions such as naphtha, kerosene, gas oil, vacuum gas oil; unconverted feedstock; water; or combinations of these. The liquid effluent  32  may include at least 95%, at least 98%, at least 99%, or even at least 99.5% of the hydrocarbon constituents of the steam catalytic cracking effluent  21  having greater than or equal to 5 carbon atoms. The liquid effluent  32  may include at least 95%, at least 98%, at least 99%, or even at least 99.5% of the water from of the steam catalytic cracking effluent  21 . 
     The gaseous effluent  31  may include olefins, such as ethylene, propylene, butenes, or combinations of these; light hydrocarbon gases, such as methane, ethane, propane, n-butane, i-butane, or combinations of these; other gases, such as but not limited to hydrogen; or combinations of these. The gaseous effluent  31  may include the C 2 -C 4  olefin products, such as but not limited to, ethylene, propylene, butenes (1-butene, cis-2-butene, trans-2-butene, isobutene, or combinations of these), or combinations of these, produced in the steam catalytic cracking reactor  200 . The gaseous effluent  31  may include at least 90%, at least 95%, at least 98%, at least 99%, or at least 99.5% of the C 2 -C 4  olefins from the steam catalytic cracking effluent  21 . The gaseous effluent  31  may be passed to a downstream gas separation system for further separation of the gaseous effluent  31  into various product streams, such as but not limited to one or more olefin product streams. 
     The liquid effluent  32 , which includes the aqueous effluent  42  and liquid hydrocarbon effluent  41  having greater than 5 carbon atoms, may be passed to the liquid and liquid separation unit  40 . The liquid and liquid separation unit  40  may operate to separate the liquid effluent  32  into the liquid hydrocarbon effluent  41  and aqueous effluent  42 . The liquid and liquid separation unit  40  may be a centrifuge that is operated at a rotational speed of from 2500 rpm to 5000 rpm, from 2500 rpm to 4500 rpm, from 2500 rpm to 4000 rpm, from 3000 rpm to 5000 rpm, from 3000 rpm to 4500 rpm, or from 3000 rpm to 4000 rpm to separate the hydrocarbon phase from the aqueous phase. 
     The liquid hydrocarbon effluent  41  may include hydrocarbons from the steam catalytic cracking effluent  21  having greater than or equal to 5 carbon atoms. These hydrocarbons may include naphtha, kerosene, diesel, vacuum gas oil (VGO), or combinations of these. The liquid hydrocarbon effluent  41  may include at least 90%, at least 95%, at least 98%, at least 99%, or even at least 99.5% of the hydrocarbon constituents from the liquid effluent  32 . The liquid hydrocarbon effluent  41  may be passed to a downstream treatment process for further conversion or separation. At least a portion of the liquid hydrocarbon effluent  41  may be passed back to the steam catalytic cracking reactor  200  for further conversion to olefins. The aqueous effluent  42  may include water and water soluble constituents from the liquid effluent  32 . The aqueous effluent  42  may include some dissolved hydrocarbons soluble in the aqueous phase of the liquid effluent  32 . The aqueous effluent  42  may include at least 95%, at least 98%, at least 99%, or even at least 99.5% of the water from the liquid effluent  32 . The aqueous effluent  42  may be passed to one or more downstream processes for further treatment. In embodiments, at least a portion of the aqueous effluent  42  may be passed back to the steam catalytic cracking reactor  200  as at least a portion of the water  120  introduced to the steam catalytic cracking reactor  200 . 
     Referring again to  FIG. 1 , the system  100  for converting a hydrocarbon feed  101  to olefins may include the SDA  10 , the steam catalytic cracking system  20  downstream of the SDA  10 , the gas and liquid separation unit  30  downstream of the steam catalytic cracking system  20 , and the liquid and liquid separation unit  40  downstream of the gas and liquid separation unit  30 . The hydrocarbon feed  101  may be introduced into the SDA  10 . As previously discussed, the SDA  10  may operate to separate and remove asphaltene from the hydrocarbon feed  101  producing the deasphalted oil stream  12 . The SDA  10  may be in fluid communication with the steam catalytic cracking system  20  to pass the deasphalted oil stream  12  to the steam catalytic cracking system  20 . The deasphalted oil stream  12  may be introduced into the steam catalytic cracking system  20 . The steam catalytic cracking system  20  may steam catalytic crack the deasphalted oil stream  12  in the presence of steam  13  and the nano-zeolite cracking catalyst to produce the steam catalytic cracking effluent  21 . The gas and liquid separation unit  30  may be in fluid communication with the steam catalytic cracking system  20  to pass the steam catalytic cracking effluent  21  to the gas and liquid separation unit  30 . The steam catalytic cracking effluent  21  may be introduced into the gas and liquid separation unit  30  to separate the gas effluent  31  and liquid effluent  32 . The gas effluent  31  may include olefins. The liquid and liquid separation unit  40  may be in fluid communication with the gas and liquid separation unit  30  to pass the liquid effluent  32  to the liquid and liquid separation unit  40 . The liquid effluent  32  may be introduced to the liquid and liquid separation unit  40  to separate the liquid effluent  32  into the liquid hydrocarbon effluent  41  and aqueous effluent  42 . 
     The processes according to embodiments shown in  FIG. 1  may achieve an olefin yield of from 40 to 80 wt. %, 40 to 70 wt. %, or 40 to 60 wt. %. The process may produce the volume ratio of propylene to ethylene from 0.5 to 3.0, 0.5 to 2.5, 1.0 to 3.0 or 1.0 to 2.5. The process may produce surplus hydrogen in the range of 1 to 15 wt. %, 5 to 10 wt. %, 10 to 15 wt. % of the steam catalytic cracking effluent  21 . 
     Referring now to  FIG. 3 , the system  100  may further include an ultra deasphalting unit  50 . The ultra deasphalting unit  50  may be disposed downstream of the SDA  10 . The ultra deasphalting unit  50  may be disposed upstream of the steam catalytic cracking system  20 . The ultra deasphalting unit  50  may operate to remove at least a portion of asphaltenes in the deasphalted oil stream  12  to produce an ultra deasphalted oil stream  51 . The ultra deasphalting unit  50  may be in fluid communication with the steam catalytic cracking system  20  to pass the ultra deasphalted oil stream  51  to the steam catalytic cracking system  20 . The steam catalytic cracking system  20  operates in the same manner as described above, except that the ultra deasphalted oil stream  51  is introduced to the catalytic cracking system  20  in place of the deasphalted oil stream depicted in  FIG. 2 . 
     The ultra-deasphalting unit  50  contains adsorption solid material. The ultra-deasphalting unit  50  may contain adsorption solid material including alumina coated with nickel oxide or alumina oxide coated with nickel oxide. The alumina or the alumina oxide may be beads ranging in size from 1 to 10 mm, 2 to 10 mm, 3 to 10 mm, 1 to 9 mm, 2 to 9 mm, 3 to 9 mm, 1 to 8 mm, 2 to 8 mm, or 3 to 8 mm. The nickel oxide may be present in an amount from at least 5 to 30 wt. %, 5 to 25 wt. %, 5 to 20 wt. %, 10 to 30 wt. %, 10 to 25 wt. %, 10 to 20 wt. % of the adsorption solid material. 
     The ultra-deasphalting unit  50  may adsorb asphaltene from the deasphalted oil stream  12  in the range of 100 ppm to 3000 ppm, 200 ppm to 3000 ppm, 300 ppm to 3000 ppm, 400 ppm to 3000 ppm, 500 ppm to 3000 ppm, 100 ppm to 2500 ppm, 200 ppm to 2500 ppm, 300 ppm to 2500 ppm, 400 ppm to 2500 ppm, or 500 ppm to 2500 ppm. 
     The weight ratio of the adsorption solid material to the deasphalted oil stream  12  in the ultra-deasphalting unit  50  may be from 0.001 to 0.02, from 0.002 to 0.02, from 0.005 to 0.02, from 0.002 to 0.01, or from 0.05 to 0.01. 
     Still referring to  FIG. 3 , in operation of the system  100  for converting the hydrocarbon feed  101  to olefins, the hydrocarbon feed  101  may be introduced into the SDA  10 . The SDA  10  may operate to separate and remove asphaltene from the hydrocarbon feed  101  producing the deasphalted oil stream  12 . The SDA  10  may be in fluid communication with the ultra deasphalting unit  50  to pass the deasphalted oil stream  12  to the ultra deasphalting unit  50 . The ultra deasphalting unit  50  may operate to remove at least a portion of asphaltenes in the deasphalted oil stream  12  to produce the ultra deasphalted oil stream  51 . The ultra deasphalting unit  50  may be in fluid communication with the steam catalytic cracking system  20  to pass the ultra deasphalted oil stream  51  to the steam catalytic cracking system  20 . The steam catalytic cracking system  20  may steam catalytic crack the ultra deasphalted oil stream  51  in the presence of steam  13  and the nano-zeolite cracking catalyst to produce the steam catalytic cracking effluent  21 . The gas and liquid separation unit  30  may be in fluid communication with the steam catalytic cracking system  20  to pass the steam catalytic cracking effluent  21  to the gas and liquid separation unit  30 . The steam catalytic cracking effluent  21  may be introduced into the gas and liquid separation unit  30  to separate the gas effluent  31  and liquid effluent  32 . The gas effluent  31  may include olefins. The liquid and liquid separation unit  40  may be in fluid communication with the gas and liquid separation unit  30  to pass the liquid effluent  32  to the liquid and liquid separation unit  40 . The liquid effluent  32  may be introduced to the liquid and liquid separation unit  40  to separate the liquid effluent  32  into the liquid hydrocarbon fractions  41  and aqueous effluent  42 . 
     The processes according to embodiments shown in  FIG. 3  may achieve an olefin yield of from 40 to 80 wt. %, 40 to 70 wt. %, or 40 to 60 wt. %. The process may produce the volume ratio of propylene to ethylene from 0.5 to 3.0, 0.5 to 2.5, 1.0 to 3.0 or 1.0 to 2.5. The process may produce surplus hydrogen in the range of 1 to 15 wt. %, 5 to 10 wt. %, 10 to 15 wt. % of the steam catalytic cracking effluent  21 . 
     Referring now to  FIG. 4 , the system  100  may further include a gas plant  60  and a feed blending unit  70 . The gas plant  60  may be disposed upstream of the feed blending unit  70 . The gas plant  60  may operate to introduce a gas condensate  61  to the feed blending unit  70 . The gas plant  60  may be in fluid communication with the feed blending unit  70  to pass the gas condensate  61  to the feed blending unit  70 . 
     The feed blending unit  70  may operate to mix the gas condensate  61  and the deasphalted oil stream  12  producing the blended deasphalted oil stream  71 . The mixture of the gas condensate  61  and the deasphalted oil stream  12  may enhance the yield of olefins as well as the selectivity of propylene and butenes. The mixture of the gas condensate  61  and the deasphalted oil stream  12  may increase the ratio of propylene/ethylene. 
     The gas condensate  61  may be a liquid hydrocarbon stream. The gas condensate  61  may comprise distillation fractions, such as naphtha, kerosene, gas oil, or combinations thereof. In embodiments, the gas condensate  61  may be a gas condensate produced from the Khuff geological formation. When the gas condensate  61  comprises a Khuff gas condensate, the gas condensate  61  may include about 3.6 wt. % C4 fraction, 15.5 wt. % light naphtha, 28.3 wt. % middle naphtha, 15 wt. % heavy naphtha fraction, 15.7 wt. % kerosene, and 21.9 wt. % gas oil. The gas condensate  61  may have an API gravity of from 50 degrees to 60 degrees, or from 50 degrees to 58 degrees. The gas condensate  61  may have sulfur content of from 0.01 to 0.2 wt. %, from 0.02 to 0.2 wt. %, or from 0.01 to 0.1 wt. %. When the gas condensate  61  comprises a Khuff gas condensate, the gas condensate  61  may have an API gravity of 53.9 degrees and sulfur content of 0.04 wt. %. 
     Referring again to  FIG. 4 , the total feed to the steam catalytic cracking system  20  may include from 5 wt. % to 50 wt. % gas condensate  61  based on the total flow rate of hydrocarbons (gas condensate  61  and the deasphalted oil stream  12 ) passed to the steam catalytic cracking system  20 . In embodiments, the total hydrocarbon feed to the steam catalytic cracking system  20  may include from 10 wt. % to 50 wt. %, from 15 wt. % to 50 wt. %, from 20 wt. % to 50 wt. %, from 5 wt. % to 45 wt. %, from 5 wt. % to 40 wt. %, from 10 wt. % to 45 wt. %, from 10 wt. % to 40 wt. %, from 15 wt. % to 45 wt. %, or from 15 wt. % to 40 wt. % gas condensate  61  based on the total flow rate of gas condensate  61  and deasphalted oil stream  12  passed to the steam catalytic cracking system  20 . 
     The feed blending unit  70  may be disposed downstream of the SDA  10 . The feed blending unit  70  may be upstream of the steam catalytic cracking system  20 . The feed blending unit  70  may operate to blend the gas condensate  61  and the deasphalted oil stream  12  to produce the blended deasphalted oil stream  71 . 
     Still referring to  FIG. 4 , in operation of the system  100  for converting the hydrocarbon feed  101  to olefins, the hydrocarbon feed  101  may be introduced into the SDA  10 . The SDA  10  may operate to separate and remove asphaltene from the hydrocarbon feed  101  producing the deasphalted oil stream  12 . The SDA  10  may be in fluid communication with the feed blending unit  70  to pass the deasphalted oil stream  12  to the feed blending unit  70 . The gas plant  60  may be in fluid communication with the feed blending unit  70  to pass the gas condensate  61  to the feed blending unit  70 . The deasphalted oil stream  12  and the gas condensate  61  may be blended in the feed blending unit  70  to produce the blended deasphalted oil stream  71 . The feed blending unit  70  may be in fluid communication with the steam catalytic cracking system  20  to pass the blended deasphalted oil stream  71  to the steam catalytic cracking system  20 . The steam catalytic cracking system  20  may steam catalytic crack the blended deasphalted oil stream  71  in the presence of steam  13  and the nano-zeolite cracking catalyst to produce the steam catalytic cracking effluent  21 . The gas and liquid separation unit  30  may be in fluid communication with the steam catalytic cracking system  20  to pass the steam catalytic cracking effluent  21  to the gas and liquid separation unit  30 . The steam catalytic cracking effluent  21  may be introduced into the gas and liquid separation unit  30  to separate the gas effluent  31  and liquid effluent  32 . The gas effluent  31  may include olefins. The liquid and liquid separation unit  40  may be in fluid communication with the gas and liquid separation unit  30  to pass the liquid effluent  32  to the liquid and liquid separation unit  40 . The liquid effluent  32  may be introduced to the liquid and liquid separation unit  40  to separate the liquid effluent  32  into the liquid hydrocarbon fractions  41  and aqueous effluent  42 . 
     The processes according to embodiments shown in  FIG. 4  may achieve an olefin yield of from 40 to 80 wt. %, 40 to 70 wt. %, or 40 to 60 wt. %. The process may produce the volume ratio of propylene to ethylene from 0.5 to 3.0, 0.5 to 2.5, 1.0 to 3.0 or 1.0 to 2.5. The process may produce surplus hydrogen in the range of 1 to 15 wt. %, 5 to 10 wt. %, 10 to 15 wt. % of the steam catalytic cracking effluent  21 . 
     Referring now to  FIG. 5 , the system  100  may further include a feed topping unit  80 . The feed topping unit  80  may be disposed upstream of the SDA  10  and the feed blending unit  70 . The other units in the system  100  depicted in  FIG. 5  (i.e., the SDA  10 , the feed blending unit  70 , the steam catalytic cracking system  20 , the gas and liquid separation unit  30 , and the liquid and liquid separation unit  40 ) operate as described above. 
     According to embodiments, the feed topping unit  80  may operate to conduct distillation at 90 to 100° C., or 90 to 95° C. to separate hydrocarbon feed  101  into a low boiling point fraction  81 , such as a light naphtha fraction, and a high boiling point fraction  82 , such as a reduced hydrocarbon feed. The amount of low boiling point fraction  81  may be 5 to 15 wt. %, or 5 to 10 wt. %. The amount of high boiling point fraction  82  may be 85 to 95 wt. %, or 85 to 90 wt. %. In one or more embodiments, the feed topping unit  80  may operate to conduct distillation at 150 to 170° C., or 150 to 160° C. to separate hydrocarbon feed  101  into a low boiling point fraction  81 , such as the light and middle naphtha fraction, and high boiling point fraction  82 , such as reduced hydrocarbon feed. The amount of low boiling point fraction  81  may be 25 to 35 wt. %, or 25 to 30 wt. %. The amount of high boiling point fraction  82  may be 65 to 75 wt. %, or 65 to 70 wt. %. In embodiments, the feed topping unit  80  may operate to conduct distillation at 195 to 205° C., or 195 to 200° C. to separate hydrocarbon feed  101  into a low boiling point fraction  81 , such as the light, middle, and heavy naphtha fraction, and high boiling point fraction  82 , such as reduced hydrocarbon feed. The amount of low boiling point fraction  81  may be 35 to 45 wt. %, or 35 to 40 wt. %. The amount of high boiling point fraction  82  may be 55 to 65 wt. %, or 55 to 60 wt. %. 
     The feed topping unit  80  may be in fluid communication with the feed blending unit  70  to pass the low boiling point fraction  81  directly to the feed blending unit  70 , thereby the low boiling point fraction  81  is not introduced into the SDA  10 . The feed topping unit  80  may be in fluid communication with the SDA  10  to pass the high boiling point fraction  82  to the SDA  10 . 
     The cut temperature or “cut point” (that is, the approximate atmospheric boiling point temperature separating the low boiling point fraction  81  and the high boiling point fraction  82 ) of the feed topping unit  80  may be from 93 degrees Celsius (° C.) to 205° C. As such, all components of the low boiling point fraction  81  may have a boiling point (at atmospheric pressure) of less than or equal to 205° C., less than or equal to 200° C., less than or equal to 150° C., less than or equal to 100° C., or less than or equal to 95° C., or even less than or equal to 93° C., and all components of the high boiling point fraction  82  may have a boiling point (at atmospheric pressure) of at least 93° C., at least 95° C., at least 100° C., at least 150° C., or at least 200° C., or even at least 205° C. 
     Still referring to  FIG. 5 , in operation of the system  100  for converting the hydrocarbon feed  101  to olefins, the hydrocarbon feed  101  may be introduced into the feed topping unit  80 . The feed topping unit  80  may separate the hydrocarbon feed  101  into the low boiling point fraction  81  and high boiling point fraction  82 . The high boiling point fraction  82  may be introduced into the SDA  10 . The SDA  10  may operate to separate and remove asphaltene from the high boiling point fraction  82  producing the deasphalted oil stream  12 . The SDA  10  may be in fluid communication with the feed blending unit  70  to pass the deasphalted oil stream  12  to the feed blending unit  70 . The feed blending unit  70  may be operated to mix the deasphalted oil stream  12  and the low boiling point fraction  81  producing the blended deasphalted oil stream  71 . The feed blending unit  70  may be in fluid communication with the steam catalytic cracking system  20  to pass the blended deasphalted oil stream  71  to the steam catalytic cracking system  20 . The steam catalytic cracking system  20  may steam catalytic crack the blended deasphalted oil stream  71  in the presence of steam  13  and the nano-zeolite cracking catalyst to produce the steam catalytic cracking effluent  21 . The steam catalytic cracking effluent  21  may be introduced into the gas and liquid separation unit  30  to separate the gas effluent  31  and liquid effluent  32 . The gas effluent  31  may include olefins. The liquid and liquid separation unit  40  may be in fluid communication with the gas and liquid separation unit  30  to pass the liquid effluent  32  to the liquid and liquid separation unit  40 . The liquid effluent  32  may be introduced to the liquid and liquid separation unit  40  to separate the liquid effluent  32  into the liquid hydrocarbon fractions  41  and aqueous effluent  42 . 
     The processes according to embodiments shown in  FIG. 5  may achieve an olefin yield of from 40 to 80 wt. %, 40 to 70 wt. %, or 40 to 60 wt. %. The process may produce the volume ratio of propylene to ethylene from 0.5 to 3.0, 0.5 to 2.5, 1.0 to 3.0 or 1.0 to 2.5. The process may produce surplus hydrogen in the range of 1 to 15 wt. %, 5 to 10 wt. %, 10 to 15 wt. % of the steam catalytic cracking effluent  21 . 
     Referring to  FIG. 6 , the hydrocarbon feed may be asphaltene-free whole crude oil  15 . The asphaltene-free whole crude oil  15  may be introduced into the steam catalytic cracking system  20 , which operates as described herein. 
     In embodiments, the asphaltene-free whole crude oil  15  may have an American Petroleum Institute (API) gravity of more than 40. The asphaltene-free whole crude oil  15  may have an API gravity between 26 and 52, 28 and 52, 26 and 50, or 28 and 50. 
     Still referring to  FIG. 6 , in operation of the system  100  for converting the hydrocarbon feed  101  to olefins, the asphaltene-free whole crude oil  15  may be introduced into the steam catalytic cracking system  20 . The steam catalytic cracking system  20  may steam catalytic crack the asphaltene-free whole crude oil  15  in the presence of steam  13  and the nano-zeolite cracking catalyst to produce the steam catalytic cracking effluent  21 . The gas and liquid separation unit  30  may be in fluid communication with the steam catalytic cracking system  20  to pass the steam catalytic cracking effluent  21  to the gas and liquid separation unit  30 . The steam catalytic cracking effluent  21  may be introduced into the gas and liquid separation unit  30  to separate the gas effluent  31  and liquid effluent  32 . The gas effluent  31  may include olefins. The liquid and liquid separation unit  40  may be in fluid communication with the gas and liquid separation unit  30  to pass the liquid effluent  32  to the liquid and liquid separation unit  40 . The liquid effluent  32  may be introduced to the liquid and liquid separation unit  40  to separate the liquid effluent  32  into the liquid hydrocarbon fractions  41  and aqueous effluent  42 . 
     The processes according to embodiments shown in  FIG. 6  may achieve an olefin yield of from 40 to 80 wt. %, 40 to 70 wt. %, or 40 to 60 wt. %. The process may produce the volume ratio of propylene to ethylene from 0.5 to 3.0, 0.5 to 2.5, 1.0 to 3.0 or 1.0 to 2.5. The process may produce surplus hydrogen in the range of 1 to 15 wt. %, 5 to 10 wt. %, 10 to 15 wt. % of the steam catalytic cracking effluent  21 . 
     EXAMPLES 
     The various embodiments of methods and systems for the processing of a hydrocarbon feed to produce olefins will be further clarified by the following examples. The examples are illustrative in nature, and should not be understood to limit the subject matter of the present disclosure. 
     Example 1: Converting Whole Crude Oil to Olefins 
     In Example 1, the steam catalytic cracking system was utilized to convert a crude oil with an API gravity of 32 to olefins. Crude oil was subjected to crude oil topping at 150° C. The crude oil was deasphalted at the SDA to produce the deasphalted oil stream. The deasphalted oil stream was sent to the steam catalytic cracking reactor. The deasphalted oil stream was steam catalytically cracked in the fixed bed reactor at 600° C. with the steam and the nano-zeolite cracking catalyst. The nano ZSM-5 with 40% alumina binder was used as the nano-zeolite cracking catalyst. The pre-heated feed at 100° C. was introduced to the reactor at a space velocity of 1 hourly (h −1 ) and steam was injected at space velocity of 3 hourly (h −1 ). As shown in Table 2, the high yield of olefins (50%) was achieved with propylene/ethylene ratio of 1 and propylene/butenes ratio of 3.3. Furthermore, the process produced a surplus of hydrogen (approximately 7%) and NGL+ethane in the range of approximately 7%. The whole crude oil conversion via nano zeolite steam catalytic process was performed for 230 minutes time on stream as a one conversion cycle and showed high performance and stability sustaining high olefins yield around 50%. 
     Example 2: Converting Whole Crude Oil to Olefins 
     In Example 2, the steam catalytic cracking process was utilized to convert a crude oil with an API gravity of 32 to olefins. Crude oil was subjected to crude oil topping at 150° C. The crude oil was deasphalted at the SDA to produce the deasphalted oil stream. The deasphalted oil stream was sent to the feed blending unit and mixed with the 20 wt. % of gas condensate to produce the blended deasphalted oil stream. The blended deasphalted oil stream was sent to the steam catalytic cracking unit. The blended deasphalted oil stream was steam catalytically cracked in the fixed bed reactor at 600° C. with the steam and the nano-zeolite cracking catalyst. The nano ZSM-5 with 40% alumina binder was used as the nano-zeolite cracking catalyst. The pre-heated feed at 100° C. was introduced to the reactor at a space velocity of 1 hourly (h −1 ) and steam was injected at space velocity of 3 hourly (h −1 ). As shown in Table 2, high yield of olefins (55%) was attained with propylene/ethylene ratio of 1.8 and propylene/butenes ratio of 2.5. Also, a hydrogen surplus (approximately 8%) was produced and about 7% NGL+ethane. The deasphalted whole crude oil blended with 20% condensate conversion via nano zeolite steam catalytic process was performed for 230 minutes time on stream as a one conversion cycle and showed high performance and stability sustaining high olefins yield around 55%. 
     
       
         
           
               
             
               
                 TABLE 2 
               
             
            
               
                   
               
               
                 Composition of steam catalytic cracking 
               
               
                 effluent from Example 1, and Example 2 
               
            
           
           
               
               
               
               
            
               
                   
                   
                 Example 1 
                 Example 2 
               
               
                   
                 Constituent 
                 Yield (wt. %) 
                 Yield (wt. %) 
               
               
                   
                   
               
            
           
           
               
               
               
               
            
               
                   
                 Naphtha, % 
                 3.5 
                 2.5 
               
               
                   
                 Kerosene, % 
                 7.0 
                 5.3 
               
               
                   
                 Diesel, % 
                 5.8 
                 4.5 
               
               
                   
                 VGO, % 
                 6.3 
                 3.8 
               
               
                   
                 Olefins, % 
                 50 
                 55.3 
               
               
                   
                 Ethylene, % 
                 22.1 
                 15.9 
               
               
                   
                 Propylene, % 
                 22.5 
                 28 
               
               
                   
                 Butenes, % 
                 6.8 
                 11.3 
               
               
                   
                 P/E 
                 1 
                 1.8 
               
               
                   
                 H 2 , % 
                 7.1 
                 8.8 
               
               
                   
                 Methane, % 
                 3 
                 2.8 
               
               
                   
                 NGL + Ethane gas, % 
                 7.4 
                 7 
               
               
                   
                 Coke 
                 3.3 
                 1.4 
               
               
                   
                   
               
            
           
         
       
     
     A first aspect of the present disclosure is directed to a process for producing olefins from a hydrocarbon feed that may include introducing the hydrocarbon feed into a Solvent Deasphalting Unit (SDA) to remove asphaltene from the hydrocarbon feed producing a deasphalted oil stream, wherein the SDA comprises a solvent that reacts with the hydrocarbon feed, and the deasphalted oil stream comprises from 0.01 weight percent (wt. %) to 18 wt. % asphaltenes; introducing the deasphalted oil stream into a steam catalytic cracking system; steam catalytically cracking the deasphalted oil stream in the steam catalytic cracking system in the presence of steam and a nano zeolite cracking catalyst to produce a steam catalytic cracking effluent; and separating the olefins from the steam catalytic cracking effluent. 
     A second aspect of the present disclosure may include the first aspect, wherein a solvent-to-hydrocarbon feed volume ratio in the SDA is from 2:1 to 50:1. 
     A third aspect of the present disclosure may include either one of the first or second aspects, wherein the deasphalted oil stream has an American Petroleum Institute (API) gravity between 26 and 52. 
     A fourth aspect of the present disclosure may include any one of the first through third aspects, wherein the deasphalted oil stream is steam catalytically cracked at a reaction temperature of from 550 degrees Celsius (° C.) to 750° C. 
     A fifth aspect of the present disclosure may include any one of the first through fourth aspects, wherein the nano zeolite cracking catalyst comprises nano ZSM-5 zeolite, nano BEA zeolite, or a combination thereof. 
     A sixth aspect of the present disclosure may include any one of the first through fifth aspects, wherein the nano zeolite cracking catalyst has a silica to alumina molar ratio from 10:1 to 200:1. 
     A seventh aspect of the present disclosure may include any one of the first through sixth aspects, wherein a crystal size of the nano zeolite cracking catalyst is from 50 nanometer (nm) to 600 nm. 
     An eighth aspect of the present disclosure may include any one of the first through seventh aspects, wherein an olefin yield from the process is from 40 mol. % to 80 mol. %. 
     A ninth aspect of the present disclosure may include any one of the first through eighth aspects, wherein the olefins comprise ethylene, propylene, butene, and combinations thereof. 
     A tenth aspect of the present disclosure may include any one of the first through ninth aspects, wherein the olefins comprise propylene and butene, and a volume ratio of propylene to butene is from 0.5 to 3.0. 
     An eleventh aspect of the present disclosure may include any one of the first through tenth aspects, further comprising: introducing the deasphalted oil stream into an ultra deasphalting unit to remove at least a portion of asphaltenes in the deasphalted oil stream to produce an ultra deasphalted oil stream, wherein the ultra deasphalted oil stream has an asphaltene content in a range of 100 parts per million (ppm) to 3000 ppm upon exiting the ultra deasphalting unit. 
     A twelfth aspect of the present disclosure may include the eleventh aspect, wherein the ultra deasphalting unit contains adsorption solid material comprising alumina coated with nickel oxide, or alumina oxide coated with nickel oxide, wherein the nickel oxide is present in an amount from at least 5 to 30 wt. % of the adsorption solid material. 
     A thirteenth aspect of the present disclosure may include the twelfth aspect, wherein the alumina oxide has a size of from 1 millimeter (mm) to 10 mm. 
     A fourteenth aspect of the present disclosure may include the twelfth aspect, wherein a weight ratio of the adsorption solid material to the deasphalted oil stream is from 0.001 to 0.02. 
     A fifteenth aspect of the present disclosure may include any one of the first through fourteenth aspects, further comprising: mixing the deasphalted oil stream with a gas condensate upstream from the steam catalytically cracking of the deasphalted oil stream, wherein the content of the gas condensate is from 5 wt. % to 25 wt. % of the deasphalted oil stream. 
     A sixteenth aspect of the present disclosure may include any one of the first through fifteenth aspects, further comprising: separating the hydrocarbon feed into at least a low boiling point fraction and a high boiling point fraction; introducing the high boiling point fraction into the SDA to remove asphaltene from the high boiling point fraction thereby producing a deasphalted oil stream, wherein the SDA comprises a solvent that reacts with the high boiling point fraction, and the deasphalted oil stream comprises from 0.01 wt. % to 18 wt. %; and mixing the deasphalted oil stream with the low boiling point fraction upstream from steam catalytically cracking of the deasphalted oil stream. 
     A seventeenth aspect of the present disclosure may include the sixteenth aspect, wherein a cut point of the low boiling point fraction and the high boiling point fraction is from 93° C. to 205° C. 
     An eighteenth aspect of the present disclosure may include any one of the first through seventeenth aspects, wherein the separating the olefins comprises: separating gas effluent and liquid effluent from the steam catalytic cracking effluent, wherein the gas effluent comprises the olefins, methane, ethane, propane, butane, or combinations thereof; and separating liquid hydrocarbon effluent and aqueous effluent from the liquid effluent, where the liquid hydrocarbon effluent comprises naphtha, kerosene, diesel, vacuum gas oil, or combinations thereof. 
     It is noted that one or more of the following claims utilize the term “where” as a transitional phrase. For the purposes of defining the present technology, it is noted that this term is introduced in the claims as an open-ended transitional phrase that is used to introduce a recitation of a series of characteristics of the structure and should be interpreted in like manner as the more commonly used open-ended preamble term “comprising.” 
     It should be understood that any two quantitative values assigned to a property may constitute a range of that property, and all combinations of ranges formed from all stated quantitative values of a given property are contemplated in this disclosure. 
     Having described the subject matter of the present disclosure in detail and by reference to specific embodiments, it is noted that the various details described in this disclosure should not be taken to imply that these details relate to elements that are essential components of the various embodiments described in this disclosure, even in cases where a particular element is illustrated in each of the drawings that accompany the present description. Rather, the claims appended hereto should be taken as the sole representation of the breadth of the present disclosure and the corresponding scope of the various embodiments described in this disclosure. Further, it will be apparent that modifications and variations are possible without departing from the scope of the appended claims.