Methods and systems for producing chemicals and fuels from gas condensates

Abstract

The disclosure provides methods and systems for producing chemicals and fuels from gas condensates. One such method includes distilling a gas condensate feedstock to produce a light product stream having C2-C4 compounds, a first naphtha stream, a distillate stream, and a heavy residue stream, hydrotreating the distillate stream to produce a hydrotreated distillate stream, distilling the heavy residue stream under vacuum pressure to produce a gas oil stream, hydrocracking the gas oil stream to produce a second naphtha stream and an unconverted oil stream, and steam cracking the light product stream, the first naphtha stream, the hydrotreated distillate stream, the second naphtha stream, and the unconverted oil stream to produce one or more high value chemical product streams comprising ethene and propene.

Description

23 CHEM0021 -WO-ORDMETHODS AND SYSTEMS FOR PRODUCING CHEMICALS AND FUELS FROM GAS CONDENSATESTECHNICAL FIELD

[0001] The present disclosure generally relates to methods and systems for producing chemicals and fuels from gas condensates. More specifically, the present disclosure relates to methods and systems for producing chemicals and fuels from gas condensates using fluid catalytic cracking processes.BACKGROUND

[0002] Gas condensate, or natural gas condensate, is a hydrocarbon liquid having low-density compounds therein that are gaseous in their raw state within natural gas fields and condensable into liquid when separated from lighter, raw natural gas. Gas condensate is a common by-product of both gas and oil production. Globally, the production of condensates has been steadily increasing over recent decades and this trend is expected to continue. As such, it would be beneficial to maximize the use of condensates to produce more valuable products whenever possible. Therefore, there remains a need for innovative systems and methods are desired to maximize the conversion of gas condensates to produce more valuable products, such as ethene and propene.SUMMARY

[0003] Embodiments of the present disclosure contain processing configurations that condition gas condensate heavy cuts to be suitable for a steam cracker feedstock, which can be converted to high value chemicals such as ethene and propene. Applicant has recognized that olefin complex systems may be utilized to beneficially maximize the conversion of gas condensates to produce more valuable products. Additionally, existing olefin complex systems may be operated to condition gas condensates into desirable steam cracker feedstocks for increased product yield and reduced capital expenditures.

[0004] Embodiments of the disclosure, for example, contain a method that includes distilling a gas condensate feedstock to produce a light product stream having C2-C4 compounds, a first naphtha stream, a distillate stream, and a heavy residue stream, hydrotreating the distillate stream to produce a hydrotreated distillate stream, distilling the heavy residue stream under vacuum pressure to produce a gas oil stream, hydrocracking the gas oil stream to produce a second naphtha stream and an unconverted oil stream, and steam cracking the light product stream, the first naphtha stream, the23 CHEM0021 -WO-ORDhydrotreated distillate stream, the second naphtha stream, and the unconverted oil stream to produce one or more high value chemical product streams comprising ethene and propene.

[0005] Embodiments of the disclosure, for example, include a method comprising the steps of distilling a gas condensate feedstock to produce a light product stream having C2-C4 compounds, a first naphtha stream, a distillate stream, and a heavy residue stream containing alkanes up to C24 hydrocarbons. The method further includes hydrotreating the distillate stream to produce a hydrotreated distillate stream; distilling the heavy residue stream under vacuum pressure to produce a gas oil stream; hydrocracking the gas oil stream to produce a second naphtha stream and an unconverted oil stream; and steam cracking the light product stream, the first naphtha stream, the hydrotreated distillate stream, the second naphtha stream, and the unconverted oil stream to produce one or more high value chemical product streams comprising ethene and propene. The gas condensate feedstock can have an API gravity ranging from about 43 to about 50, and the gas condensate may be sourced from a gas field exploration and has about 2 wt.% to about 3 wt.% vacuum residue. Certain embodiments of the method further include distilling the gas condensate feedstock is performed at an operating pressure of about 0.01 bar to about 3 bar. These embodiments include the light product stream with a cut point of 150 °C or less; the first naphtha stream with a cut point between 150 °C and 205 °C; the distillate stream with a cut point between 150 °C and 350 °C; and the gas oil stream with a cut point between 350 °C and 565 °C; and the gas condensate feedstock can have an API gravity ranging from about 43 to about 44. Certain embodiments of the method further include hydrotreating the distillate stream to produce a third naphtha stream, and steam cracking the third naphtha stream. Certain embodiments of the method further include hydrotreating the distillate stream while maintaining an operating pressure between 10 bar and 50 bar. Certain embodiments of the method further include hydrocracking the gas oil stream at an operating pressure between 100 bar and 200 bar. In certain embodiments, the operating pressure is between 135 and 170 bar. Certain embodiments of the method further include the gas condensate feedstock being a blend produced from a mixture of light crude oil and a raw gas condensate. Certain embodiments of the method further include hydrotreating the distillate stream produces a first diesel product stream; hydrocracking the gas oil stream produces a second diesel product stream; and outputting the first diesel product stream and the second diesel product stream. Certain embodiments of the method further include hydrocracking the gas oil stream produces a purge gas, steam cracking the purge gas to facilitate recovery of the one or more high value chemical product streams. Hydrotreating of the distillate23 CHEM0021 -WO-ORDstream further produces a hydrotreated kerosene stream to be steam cracked when the hydrotreating and the hydrocracking steps are not in operation.

[0006] Embodiment also include systems with a crude distillation unit operable to receive a gas condensate feedstock having an API gravity ranging from about 43 to about 50 and split the gas condensate feedstock using an operating pressure of about 0.01 bar to about 3 bar into at least a light product stream having a cut point of 150 °C or less; a first naphtha stream having a cut point between 150 °C and 205 °C; a distillate stream having a cut point between 105 °C and 350 °C; and a heavy residue stream comprising alkanes up to C24 hydrocarbons. These systems also include a vacuum distillation unit operable to receive the heavy residue stream from the crude distillation unit and split the heavy residue stream into a gas oil stream having a cut point of about 350 °C to about 565 °C and a vacuum residue stream having a cut point of about 350 °C or higher. These systems also include a diesel hydrotreater unit operable to receive the distillate stream and to produce a hydrotreated distillate stream and a first diesel stream; a hydrocracker unit operable to receive the gas oil stream and to produce a second naphtha stream, an unconverted oil stream, and a second diesel stream; and a mixed feed steam cracker operable to receive the light product stream, the first naphtha stream, the hydrotreated distillate stream, the second naphtha stream, and the unconverted oil stream and to produce one or more high value chemical product streams comprising ethene and propene. Certain embodiments of the systems include the hydrocracker unit being operated at a temperature of about 300 °C to about 500 °C. In certain embodiments, the gas condensate is sourced from a gas field. Certain embodiments of the systems include the diesel hydrotreater unit at an operating pressure between 10 bar and 50 bar. Certain embodiments of the systems include the diesel hydrotreater unit being operable to produce a hydrotreated kerosene stream supplied to the mixed feed steam cracker when the vacuum distillation unit and the hydrocracker unit are not in operation. Certain embodiments of the systems include the hydrocracker unit at an operating pressure between 135 bar and 170 bar. Certain embodiments of the systems include the one or more high value chemical product streams containing one or more of hydrogen, ethene, propene, buta- 1,3 -diene, butene- 1, methyl t-butyl ether, benzene, toluene, one or more xylenes, pyrolysis oil, or a combination thereof. Certain embodiments of the systems include the one or more high value chemical product streams containing the pyrolysis oil, and the hydrocracker unit being operable to receive at least a portion of the pyrolysis oil.

[0007] In another embodiment of the present disclosure, for example, a system includes a crude distillation unit operable to receive a gas condensate feedstock having an API gravity ranging from23 CHEM0021 -WO-ORDabout 43 to about 50 and split the gas condensate feedstock using an operating pressure of about 0.01 bar to about 3 bar into at least a light product stream having a cut point of 150 °C or less; a first naphtha stream having a cut point between 150 °C and 205 °C; a kerosene stream having a cut point between 150 °C and 350 °C; a straight run diesel stream; and an atmospheric residue stream. Further, the system includes a diesel hydrotreater unit operable to receive the kerosene stream and the straight run diesel stream and to produce a second naphtha stream comprising hydrotreated naphtha, a hydrotreated kerosene stream, and a hydrotreated diesel stream. Further, the system includes a mixed feed steam cracker operable to receive the light product stream, the first naphtha stream, the second naphtha stream, the hydrotreated kerosene stream, and the hydrotreated diesel stream and to produce one or more high value chemical product streams comprising ethene and propene.

[0008] In another embodiment of the present disclosure, for example, a system includes a crude distillation unit operable to receive a gas condensate feedstock having an API gravity ranging from about 43 to about 50 and split the gas condensate feedstock into at least: (a) a light product stream having a cut point of 150 °C or less, (b) a first naphtha stream having a cut point between 150 °C and 205 °C, (c) a distillate stream having a cut point between 105 °C and 350 °C, and (d) a heavy residue stream. Further, the system includes a vacuum distillation unit operable to receive the heavy residue stream from the crude distillation unit and split the heavy residue stream into a gas oil stream having a cut point of about 350 °C to about 565 °C and a vacuum residue stream having a cut point of about 350 °C or higher, a diesel hydrotreater unit operable to receive the distillate stream and produce a hydrotreated distillate stream and a first diesel stream, a hydrocracker unit operable to receive the gas oil stream and produce a second naphtha stream, an unconverted oil stream, and a second diesel stream, and a mixed feed steam cracker operable to receive the light product stream, the first naphtha stream, the hydrotreated distillate stream, the second naphtha stream, and the unconverted oil stream and to produce one or more high value chemical product streams comprising ethene, propene, C4 products, and aromatics.

[0009] Aspects and advantages of these exemplary embodiments and other embodiments, are discussed in detail herein. Moreover, it is to be understood that both the foregoing information and the following detailed description provide merely illustrative examples of various aspects and embodiments, and are intended to provide an overview or framework for understanding the nature and character of the claimed aspects and embodiments. Accordingly, these and other objects, along with advantages and features of the present disclosure, will become apparent through reference to the23 CHEM0021 -WO-ORDfollowing description and the accompanying drawings. Furthermore, it is to be understood that the features of the various embodiments described herein are not mutually exclusive and may exist in various combinations and permutations.BRIEF DESCRIPTION OF THE DRAWINGS

[0010] The accompanying drawings, which are included to provide a further understanding of the embodiments of the present disclosure, are incorporated in and constitute a part of this specification, illustrate embodiments of the present disclosure, and together with the detailed description, serve to explain principles of the embodiments discussed herein. No attempt is made to show structural details of this disclosure in more detail than may be necessary for a fundamental understanding of the embodiments discussed herein and the various ways in which they may be practiced. According to common practice, the various features of the drawings discussed below are not necessarily drawn to scale. Dimensions of various features and elements in the drawings may be expanded or reduced to illustrate embodiments of the disclosure more clearly.

[0011] FIG. 1 is a schematic example of an embodiment of an olefin complex system including at least a crude distillation unit, a vacuum distillation unit, a diesel hydrotreater unit, and a hydrocracker unit to condition a gas condensate feedstock to produce chemical product streams from a mixed feed steam cracker, according to an example of the present disclosure.

[0012] FIG. 2 is a schematic example of an embodiment of an olefin complex system including at least a crude distillation unit, a vacuum distillation unit, and a hydrocracker unit to condition a gas condensate feedstock to produce chemical product streams from a mixed feed steam cracker, according to an example of the present disclosure.

[0013] FIG. 3 is a schematic example of an embodiment of an olefin complex system including at least a crude distillation unit and diesel hydrotreater unit to condition a gas condensate feedstock to produce chemical product streams from a mixed feed steam cracker, according to an example of the present disclosure.

[0014] FIG. 4 is a flow chart of a method to process gas condensate in an olefin complex system, according to an example of the present disclosure.

[0015] To facilitate understanding, identical reference numerals have been used, where possible, to designate identical elements that are common to the figures. It is contemplated that elements and features of one embodiment may be beneficially incorporated into other embodiments without further recitation.23 CHEM0021 -WO-ORDDETAILED DESCRIPTION

[0016] Conventionally, gas condensate is considered a less desirable option as a feed to a steam cracker as chemical product yield is less than other conventional feeds. Per unit carbon, there is a lower hydrogen content in a gas condensate feed as compared to other desirable feeds like ethane and propane derived from crude oils. As a result, when converting gas condensates to chemicals, via a steam cracker, only a low amount of gas condensate is converted to hydrogen-rich ethene and propene products. The remaining amount of the gas condensate feed becomes hydrogen-lean requiring an additional hydrogen consumption to perform the conversion to the chemicals desired. To facilitate understanding, the selectivity to ethene and propene is higher with hydrogen-rich feeds like ethane and propane. Therefore, a greater volume of gas condensate and hydrogen gas is necessary to be processed for the same yield of ethene and propene as produced by smaller volumes conventional feeds, such as crude oil. As such, the present disclosure contains innovative systems and methods to maximize the conversion of gas condensates to produce more valuable products, such as ethene and propene.

[0017] So that the manner in which the features and advantages of the examples of the systems and methods disclosed herein, as well as others that will become apparent, may be understood in more detail, a more particular description of examples of systems and methods briefly summarized above may be had by reference to the following detailed description of examples thereof, in which one or more are further illustrated in the appended drawings, which form a part of this specification. It is to be noted, however, that the drawings illustrate only various examples of the systems and methods disclosed herein and are therefore not to be considered limiting of the scope of the methods and systems disclosed herein as it may include other effective examples as well.

[0018] The description may use the phrases “in certain embodiments,” “in various embodiments,” “in an embodiment,” or “in embodiments,” which may each refer to one or more of the same or different embodiments. Furthermore, the terms “comprising,” “including,” “having,” and the like, as used with respect to embodiments of the present disclosure, are synonymous. The term “about” refers to a range of values including the specified value, which a person of ordinary skill in the art would consider reasonably similar to the specified value. In embodiments, “about” refers to values within a standard deviation using measurements generally acceptable in the art. In one non-limiting embodiment, when the term “about” is used with a particular value, then “about” refers to a range extending to ±10% of the specified value, alternatively ±5% of the specified value, or alternatively23 CHEM0021 -WO-ORD±1% of the specified value, or alternatively ±0.5% of the specified value. In embodiments, “about” refers to the specified value.

[0019] The terms “removing,” “removed,” “reducing,” “reduced,” or any variation thereof, when used in the claims and / or the specification includes any measurable decrease of one or more components in a mixture to achieve a desired result. The use of the words “a” or “an” when used in conjunction with any of the terms “comprising,” “including,” “containing,” or “having,” in the claims or the specification may mean “one,” but it is also consistent with the meaning of “one or more,” “at least one,” and “one or more than one.” The term “plurality” as used herein refers to two or more items or components. The terms “wt.%”, “vol.%”, or “mol.%” refers to a weight, volume, or molar percentage of a component, respectively, based on the total weight, the total volume of material, or total moles, which includes the component. In a non-limiting example, 10 grams of component in 100 grams of the material is 10 wt.% of component.

[0020] As used herein, the term “Cx-y compounds,” in which x and y are positive integer values, refers to hydrocarbon-based compounds, each compound containing between x and y carbon atoms, x and y inclusive. For example, a C3-5 fraction or stream refers to a mixture that substantially contains or entirely contains hydrocarbon-based compounds, each compound containing 3, 4, or 5 carbon atoms. Additionally, it may be noted that, in certain cases, a Cx-y fraction or stream may not include a respective compound having each of the referenced integer values. As one example, a C4-8 fraction can be a stream that contains compounds of 4, 5, and 7 carbon atoms, without any compounds of 6 or 8 carbon atoms. As another example, a C4-5 stream can include compounds having only 4 carbon atoms, only 5 carbon atoms, or a mixture of both.

[0021] As used herein, the term “Cx+ compounds,” in which x is a positive integer value, refers to hydrocarbon-based compounds, each compound containing at least x carbon atoms. For example, a C3+ fraction refers to a mixture that substantially contains or entirely contains hydrocarbon-based compounds, each compound containing 3 or more (e.g., 3, 4, 5, 6, and so forth) carbon atoms. As used herein, the term “Cx- compounds,” in which x is a positive integer value, refers to hydrocarbonbased compounds, each compound containing no more than x carbon atoms. For example, a C4-fraction refers to a mixture that substantially contains or entirely contains hydrocarbon-based compounds, each compound containing 4, 3, 2, or 1 carbon atoms. It may be noted that, in certain cases, a “Cx- fraction” may also include hydrogen (H2), in addition to hydrocarbons having x or fewer carbon atoms.23 CHEM0021 -WO-ORD

[0022] As used herein, when a first component is described as receiving (or being configured to receive) a stream from a second component, or when a first component is described as providing (or being configured to provide) a stream to a second component, the first and second components may be alternatively described as being in fluid communication, or in fluid connection, with one another. For the various streams discussed herein, a given stream substantially contains the compound or class of compounds in the name of the stream (e.g., an ethene product stream substantially contains ethene, a C4 olefin stream substantially contains C4 olefins), and the stream may also include other components.

[0023] Embodiments of the present disclosure implement innovative treatments of gas condensate to increase additional yield of valuable products from a steam cracker. Thus, various examples related to methods and systems for improved production of chemical products based on the integrated processing of gas condensate feedstocks are presented below. Gas condensate may be a byproduct of new gas field explorations with unexplored opportunity of additional product yield due to conventional disposal. Instead, gas condensate processing systems may implement the innovative treatments of the present disclosure to salvage, or repurpose, gas condensate from, for example, new gas field explorations, within an olefin complex system to advantageously utilize existing crude oil processing equipment to further condition additional feedstocks, such as gas condensate, thereby to enable a steam cracker to produce increased product. In some embodiments, gas condensates refer to hydrocarbons separated from a natural gas stream. Moreover, present examples explore and analyze various optimized ranges for converting condensate to chemicals, including desired balance between capital expenditure and carbon efficiency. As described herein, the conversion methods and systems disclosed herein can upgrade gas condensate into various chemicals via a crude distillation unit, a vacuum distillation unit, a distillate hydrotreater, a hydrocracker, a mixed feed steam cracker, or a combination thereof.

[0024] Embodiment also include systems with a crude distillation unit operable to receive a gas condensate feedstock having an API gravity ranging from about 43 to about 50 and split the gas condensate feedstock using an operating pressure of about 0.01 bar to about 3 bar into at least a light product stream having a cut point of 150 °C or less; a first naphtha stream having a cut point between 150 °C and 205 °C; a distillate stream having a cut point between 105 °C and 350 °C; and a heavy residue stream comprising alkanes. These systems also include a vacuum distillation unit operable to receive the heavy residue stream from the crude distillation unit and split the heavy residue stream23 CHEM0021 -WO-ORDinto a gas oil stream having a cut point of about 350 °C to about 565 °C and a vacuum residue stream having a cut point of about 350 °C or higher. These systems also include a diesel hydrotreater unit operable to receive the distillate stream and to produce a hydrotreated distillate stream and a first diesel stream; a hydrocracker unit operable to receive the gas oil stream and to produce a second naphtha stream, an unconverted oil stream, and a second diesel stream; and a mixed feed steam cracker operable to receive the light product stream, the first naphtha stream, the hydrotreated distillate stream, the second naphtha stream, and the unconverted oil stream and to produce one or more high value chemical product streams comprising ethene and propene. Certain embodiments of the systems include the hydrocracker unit being operated at a temperature of about 300 °C to about 500 °C. In certain embodiments, the gas condensate is sourced from a gas field. Certain embodiments of the systems include the diesel hydrotreater unit at an operating pressure between 10 bar and 50 bar. Certain embodiments of the systems include the diesel hydrotreater unit being operable to produce a hydrotreated kerosene stream supplied to the mixed feed steam cracker when the vacuum distillation unit and the hydrocracker unit are not in operation. Certain embodiments of the systems include the hydrocracker unit at an operating pressure between 135 bar and 170 bar. Certain embodiments of the systems include the one or more high value chemical product streams containing one or more of hydrogen, ethene, propene, buta- 1,3 -diene, butene- 1, methyl t-butyl ether, benzene, toluene, one or more xylenes, pyrolysis oil, or a combination thereof. Certain embodiments of the systems include the one or more high value chemical product streams containing the pyrolysis oil, and the hydrocracker unit being operable to receive at least a portion of the pyrolysis oil.

[0025] In another embodiment of the present disclosure, for example, a system includes a crude distillation unit operable to receive a gas condensate feedstock having an API gravity ranging from about 43 to about 50 and split the gas condensate feedstock using an operating pressure of about 0.01 bar to about 3 bar into at least a light product stream having a cut point of 150 °C or less; a first naphtha stream having a cut point between 150 °C and 205 °C; a kerosene stream having a cut point between 150 °C and 350 °C; a straight run diesel stream; and an atmospheric residue stream. Further, the system includes a diesel hydrotreater unit operable to receive the kerosene stream and the straight run diesel stream and to produce a second naphtha stream comprising hydrotreated naphtha, a hydrotreated kerosene stream, and a hydrotreated diesel stream. Further, the system includes a mixed feed steam cracker operable to receive the light product stream, the first naphtha stream, the second23 CHEM0021 -WO-ORDnaphtha stream, the hydrotreated kerosene stream, and the hydrotreated diesel stream and to produce one or more high value chemical product streams comprising ethene and propene.

[0026] In another embodiment of the present disclosure, for example, a system includes a crude distillation unit operable to receive a gas condensate feedstock having an API gravity ranging from about 43 to about 50 and split the gas condensate feedstock into at least: (a) a light product stream having a cut point of 150 °C or less, (b) a first naphtha stream having a cut point between 150 °C and 205 °C, (c) a distillate stream having a cut point between 105 °C and 350 °C, and (d) a heavy residue stream. Further, the system includes a vacuum distillation unit operable to receive the heavy residue stream from the crude distillation unit and split the heavy residue stream into a gas oil stream having a cut point of about 350 °C to about 565 °C and a vacuum residue stream having a cut point of about 350 °C or higher, a diesel hydrotreater unit operable to receive the distillate stream and produce a hydrotreated distillate stream and a first diesel stream, a hydrocracker unit operable to receive the gas oil stream and produce a second naphtha stream, an unconverted oil stream, and a second diesel stream, and a mixed feed steam cracker operable to receive the light product stream, the first naphtha stream, the hydrotreated distillate stream, the second naphtha stream, and the unconverted oil stream and to produce one or more high value chemical product streams comprising ethene, propene, C4 products, and aromatics.

[0027] FIG. 1 is a schematic example of an embodiment of an olefin complex system 100 including at least a crude distillation unit (CDU) 102, a vacuum distillation unit (VDU) 104, a diesel hydrotreater unit (DHT) 106, and a hydrocracker unit (HCR) 108 to condition a gas condensate feedstock to produce chemical product streams from a mixed feed steam cracker (MFSC) 110, according to an example of the present disclosure. The olefin complex system 100 additionally includes other units or areas such as an off-site area 142. Each of the aforementioned units may be utilized to produce a conditioned feed to the MFSC 110. The olefin complex system 100 further includes various streams, such as streams 112, 114, 116, 118, 120, 122, 124, 126, 128, 130, 132, 134, 136, 138, and optional stream 140. The MFSC 110 produces various valuable chemical and fuel products such as, but not limited to, fuel gas, ethene, propene, buta- 1,3 -diene, 2-methoxy-2-m ethylpropane (or commonly referred to as “MTBE”), butene- 1, benzene, toluene, mixed dimethylbenzene (or commonly referred to as “mixed xylenes”), or pyrolysis oil (pyoil). The example of FIG. 1 omits various principle and auxiliary streams necessary for operation to facilitate more efficient understanding of the present examples. However, the example of FIG. 1 may be used to23 CHEM0021 -WO-ORDunderstand the complexity of an olefin complex system, such as olefin complex system 100, and various products that may be produced from the MFSC 110.

[0028] The various aforementioned units of the olefin complex system 100 may be operable to provide various conditioned feed streams to the MFSC 110. As illustrated, the conditioned streams 114, 116, 126, 128, 132, and 134 may be independently fed to the MFSC 110. In some examples, streams 116 and 126, for example, may be combined to feed the MFSC 110.

[0029] The gas condensate feedstock 112 can have an American Petroleum Institute (API) gravity of about 43 to about 50, such as about 43 to about 48, such as about 43 to about 46, such as about 43 to about 44, or such as about 44 to about 50, such as about 45 to about 50, such as about 47 to about 50, such as about 49 to about 50, or such as about 44 to about 49, such as about 46 to about 49, such as about 47 to about 48, or such as about 46.1 to about 48.3, or such as greater than an API gravity of about 43, such as greater than an API of about 50. In the aforementioned embodiments of gas condensate feedstock 112 having a lower API of about 43 to about 44, the feedstock 112 may be a blend of a virgin (e.g., unprocessed or raw), gas condensate with a light crude oil stream 190. The light crude oil, within the light crude oil stream 190, may have an API of about 38 to about 43. While not illustrated, the light crude oil and gas condensate blending may be performed by flashing the mixture to obtain the desired API into the CDU 102. In these embodiments, the blended feed is advantageous to increase, or maximize, the production of olefins and other petrochemical feedstock, as desired.

[0030] The CDU 102 may be operable to receive a gas condensate feedstock 112 and to produce a light product stream 114, a naphtha stream 116, a distillate stream 118, and a heavy residue stream 120. Further, the CDU 102 may be in fluid communication with the MFSC 110, the DHT 106, and the VDU 104. The CDU 102 processes the gas condensate feedstock 112 at an operational pressure of about 0.01 bar to about 3 bar in at least a distillation column. In some examples, the light product stream 114 may contain C3 and C4 hydrocarbons separated by distillation from the gas condensate feedstock 112 by the CDU 102. The light product stream 114 may be distillation of products from the gas condensate feedstock 112 taken at an operational cut temperature, or “cut point”, of less than about 150 degrees Celsius (°C). The final boiling point (FBP) of the light product stream 114 may have a range of about 120 °C to 180 °C, such as less than about 180 °C, less than about 160 °C, or less than about 150 °C. In other examples, the naphtha stream 116 may be straight run naphtha. The naphtha stream 116 may be distillation of products from the gas condensate feedstock 112 taken at23 CHEM0021 -WO-ORDan operational cut temperature of about 150 °C to about 205 °C. The FBP of the naphtha stream 116 may have a range of about 120 to 235 °C, such as about 150 to 205 °C, about 170 °C to about 195 °C, or another suitable temperature range. In some examples, the distillate stream 118 may be a straight run distillate taken at an operational cut temperature of the CDU 102 of about 150 °C to about 350 °C. The FBP of the distillate stream 118 may have a range of about 120 °C to about 380 °C, such as about 150 °C to about 350 °C, such as about 180 °C to about 320 °C. In other examples, the heavy residue stream 120 may have a boiling point greater than the distillate stream 118. The heavy residue stream 120 may contain C2-24, such as from C2 hydrocarbons to long chain alkanes, such as up to C24.

[0031] The VDU 104 may be operable to receive the heavy residue stream 120 and to produce a gas oil stream 122 and a vacuum residue stream 124 under vacuum pressure, or low pressure, distillation. The VDU 104 may operate at a pressure of about 0.01 bar to about 3 bar in at least a vacuum distillation column. Further, the VDU 104 may be in fluid communication with the CDU 102, the HCR 108, and the off-site area 142. In some examples, the gas oil stream 122 may be vacuum, or low pressure, distillation of products from the heavy residue stream 120 taken at an operational cut temperature range of about 350 °C to about 565 °C. The FBP of the gas oil stream 122 may have a range of about 320 °C to about 595 °C, such as about 350 °C to about 565 °C, such as about 380 °C to about 535 °C. In some examples, the vacuum residue stream 124 may be vacuum, or low pressure, distillation of products from the heavy residue stream 120 taken at an operational cut temperature of greater than about 350 °C. The FBP of the vacuum residue stream 124 may be about greater than 320 °C, such as greater than about 350 °C, such as greater than about 380 °C.

[0032] The DHT 106 may be operable to receive the distillate stream 118 from the CDU 102 and to produce a hydrotreated naphtha stream 126, a hydrotreated distillate stream 128, and a diesel stream 130. The DHT 106 may be operable to remove components, such as sulfur, from the distillate stream 118. Additionally, the DHT 106 may be in fluid communication with the CDU 102, the MF SC 110, and a diesel unit (not illustrated). The DHT 106 may operate at a pressure of about 10 bar to about 80 bar, such as about 10 bar to about 50 bar, such as about 10 bar to about 47 bar, such as less than about 50 bar. Further, the DHT 106 may operate at a temperature of about 260 °C to about 500 °C, such as about 290 °C to about 470 °C. The hydrotreated naphtha stream 126 may be a second naphtha stream produced by the olefin complex system 100. In some examples, the hydrotreated naphtha stream 126 may be combined with the naphtha stream 116 (the first naphtha stream produced by the olefin complex system 100) from the CDU 102. Alternatively, the hydrotreated naphtha stream 126 may be23 CHEM0021 -WO-ORDdirectly fed to the MFSC 110. Similarly, the hydrotreated distillate stream 128 may be directly fed to the MFSC 110. In some examples, the diesel stream 130, a first diesel stream produced by the olefin complex system 100) may be provided to a diesel unit for storage, consumption, processing, transport, sale, or the like.

[0033] The HCR 108 may be operable to receive the gas oil stream 122 from the VDU 104 and to produce a hydrocracked naphtha stream 132, an unconverted oil stream 134, and a diesel stream 136. In some embodiments, the HCR 108 may be operable to receive a pyoil stream 140 from the MFSC 110 for additional product recovery with the intent to convert pyoil to low boiling fractions suitable for recovery. The pyoil stream 140 may be a portion of the pyoil stream 138 produced by the MFSC 110 or may be entirely directed to the HCR 108. The HCR 108 may be in fluid communication with the VDU 104, the MFSC 110, and a diesel unit (not illustrated). The HCR 108 may operate at a pressure of about 100 bar to about 200 bar, such as about 135 bar to about 170 bar, such as about 137 bar to about 170 bar. Further, the HCR 108 may operate at a temperature of about 300 °C to about 500 °C. The hydrocracked naphtha stream 132 may be a third naphtha stream produced by the olefin complex system 100. The hydrocracked naphtha stream 132 may be directly fed to the MFSC 110. Similarly, the unconverted oil stream 134 may be directly fed to the MFSC 110. In some examples, the diesel stream 136, a second diesel stream produced by the olefin complex system 100, may be provided to a diesel unit for storage, consumption, processing, transport, sale, or the like.

[0034] While not illustrated, the components made within a hydrocracker, positioned in the HCR 108, may be further separated in the HCR 108, or use a combined gas plant, to be combined with the light product stream 114 from the CDU 102 to segregate <C4, C4, and C4+. It has been observed that improved steam cracker performance is enabled by cracking <C4 streams at different temperatures as compared to >C4 components. Additionally, purge gas from the hydrocrackers, positioned in the HCR 108, may be routed to the MFSC 110 for recovery of useful components in chemical production, via steam cracking.

[0035] The MFSC 110 may be operable to receive the light product stream 114, the naphtha stream 116, the hydrotreated naphtha stream 126, the hydrotreated distillate stream 128, the hydrocracked naphtha stream 132, and the unconverted oil stream 134 and to produce one or more high value chemical product streams, such as, but not limited to, fuel gas, ethene, propene, buta- 1,3 -diene, MTBE, butene-1, benzene, toluene, mixed xylenes, pyoil, or a combination thereof. The MFSC 110 may operate with a coil outlet temperature (COT) of about 700 °C to about 800 °C.23 CHEM0021 -WO-ORD

[0036] The off-site area 142 may be a unit positioned outside of a battery limit of the olefin complex system 100 operable to receive pyoil or vacuum residue containing streams, either independently or combined, with the intent of integration to a refinery or any adjacent oil to chemical complex.

[0037] The olefin complex system 100 of FIG. 1 is advantageous in the processing of gas condensate as gas condensate contains lower vacuum residue (in a fraction higher than 550 °C), such as vacuum residue stream 124, than crude oil and thus produces less vacuum residue. For comparison, gas condensate contains about 2 wt.% to about 3 wt.% of vacuum residue, whereas typical sweet crude oil contains about 12 wt.% to about 16 wt.%. In some examples, gas condensate feedstocks may contain about 0 wt.% vacuum residue. Reducing vacuum residue is advantageous as reduced vacuum residue is directly related to a reduction of energy required to further treat vacuum residue, resulting in decreased operational costs. The nature of gas condensate will yield more lighter feedstock, which increases the yields of olefins than crude oil based petrochemical production. Hence, vacuum residue processes may be much smaller or eliminated for gas condensate feed over crude oil.

[0038] FIG. 2 is a schematic example of an embodiment of an olefin complex system 200 including at least a CDU 202, a VDU 204, and an HCR 208 to condition a gas condensate feedstock 212 to produce chemical product streams from a MF SC 210, according to an example of the present disclosure. These aforementioned units are similarly labeled as compared to FIG. 1, and their descriptions are not repeated in detail for improved clarity, unless otherwise noted. FIG. 2 illustrates exemplary details of an alternative system to process gas condensate so as to produce increase yield of MFSC 210 products. The olefin complex system 200 of FIG. 2 differs from the olefin complex system 100 of FIG. 1 such that FIG. 2 shuts down, bypasses, or omits, the DHT 106 of FIG. 1.

[0039] The CDU 202 may be operable to receive a gas condensate feedstock 212 and to produce a light product stream 214, a naphtha stream 216, a distillate stream 218, and a heavy residue stream 220. The CDU 202 may be in fluid communication with the HCR 208, the VDU 204, and the MFSC 210. As illustrated, the distillate stream 218 may be routed to feed the HCR 208 for additional conditioning of the distillate stream 218. The distillate stream 218 may contain kerosene or gas oil suitable for processing via the HCR 208.

[0040] The gas condensate feedstock can have an American Petroleum Institute (API) gravity of about 43 to about 50, such as about 43 to about 48, such as about 43 to about 46, such as about 43 to about 44, or such as about 44 to about 50, such as about 45 to about 50, such as about 47 to about 50, such as about 49 to about 50, or such as about 44 to about 49, such as about 46 to about 49, such as23 CHEM0021 -WO-ORDabout 47 to about 48, or such as about 46.1 to about 48.3, or such as greater than an API gravity of about 43, such as greater than an API of about 50. In the aforementioned embodiments of gas condensate feedstock having a lower API of about 43 to about 44, the feedstock may be a blend of a virgin (e.g., unprocessed or raw), gas condensate with a light crude oil stream 190. The light crude oil, within the light crude oil stream 190, may have an API of about 38 to about 43. While not illustrated, the light crude oil and gas condensate blending may be performed by flashing the mixture to obtain the desired API into the CDU 102. In these embodiments, the blended feed is advantageous to increase, or maximize, the production of olefins and other petrochemical feedstock, as desired.

[0041] The HCR 208 may be operable to receive the gas oil stream 222 from the VDU 204 and the distillate stream 218 from the CDU 202 and to produce a hydrocracked naphtha stream 232, an unconverted oil stream 234, and a diesel stream 236. The HCR 208 may be in fluid communication with the CDU 202, the VDU 204, the MFSC 210, and a diesel unit (not illustrated). The HCR 208 may operate at a pressure of about 100 bar to about 200 bar, such as about 135 bar to about 170 bar, such as about 137 bar to about 170 bar. Further, the HCR 208 may operate at a temperature of about 300 °C to about 500 °C.

[0042] The MFSC 210 may be operable to receive the light product stream 214, the naphtha stream 216, the hydrocracked naphtha stream 232, and the unconverted oil stream 234 and to produce one or more high value chemical product streams, such as, but not limited to, fuel gas, ethene, propene, buta-1,3-diene, MTBE, butene-1, benzene, toluene, mixed xylenes, pyoil, or a combination thereof. The MFSC 110 may operate with a coil outlet temperature (COT) of about 700 °C to about 800 °C.

[0043] FIG. 3 is a schematic example of an embodiment of an olefin complex system 300 including at least a CDU 302 and a DHT 306 to condition a gas condensate feedstock 312 to produce chemical product streams from a MFSC 310, according to an example of the present disclosure. The aforementioned unit is similarly labeled as compared to FIG. 1, and their descriptions are not repeated in detail for improved clarity, unless otherwise noted. FIG. 3 illustrates exemplary details of an alternative system to process gas condensate so as to produce increase yield of MFSC 310 products. The olefin complex system 300 of FIG. 3 differs from the olefin complex system 100 of FIG. 1 such that FIG. 3 shuts down, bypasses, or omits, both the VDU 104 and the HCR 108 of FIG. 1.

[0044] The CDU 302 may be operable to receive a gas condensate feedstock 312 and to produce a light product stream 314, a naphtha stream 316, a kerosene stream 344, a straight run diesel stream 346, and an atmospheric residue stream 348. The CDU 302 may be in fluid communication with the23 CHEM0021 -WO-ORDDHT 308, the MFSC 210, and an off-site area 342. The CDU 302 processes the gas condensate feedstock 312 at an operational pressure of about 0.01 bar to about 3 bar in at least a distillation column. In some examples, the light product stream 314 may contain C2, C3, and C4 hydrocarbon compounds separated by distillation from the gas condensate feedstock 312 by the CDU 302. The light product stream 314 may be distillation of products from the gas condensate feedstock 312 taken at an operational cut temperature of less than about 150 °C. The FBP of the light product stream 314 may have a range of about 120 °C to 180 °C, such as less than about 180 °C, less than about 160 °C, or less than about 150 °C. In other examples, the naphtha stream 316 may be straight run naphtha. The naphtha stream 316 may be distillation of products from the gas condensate feedstock 312 taken at an operational cut temperature of about 150 °C to about 205 °C. The FBP of the naphtha stream 316 may have a range of about 120 °C to about 235 °C, such as about 150 °C to about 205 °C, such as about 170 °C to about 195 °C, or another suitable temperature range. In some examples, the kerosene stream 344 may be taken at an operational cut temperature of the CDU 302 of about 150 °C to about 350 °C. The FBP of the kerosene stream 344 may have a range of about 120 °C to about 380 °C, such as about 150 °C to about 350 °C, such as about 180 °C to about 320 °C. In other examples, the atmospheric residue stream 348 may be distillation of products from the gas condensate feedstock 312 taken at an operational cut temperature of greater than about 350 °C.

[0045] The DHT 306 may be operable to receive the kerosene stream 344 and the straight run diesel stream 346 and to produce a hydrotreated naphtha stream 326, a hydrotreated kerosene stream 328, a stream 352, and a hydrotreated diesel stream 330. The DHT 306 may be operable to remove components, such as sulfur, from both the kerosene stream 344 and the straight run diesel stream 346. Additionally, the DHT 306 may be in fluid communication with the CDU 302 and the MFSC 310. The DHT 306 may operate at a pressure of about 10 bar to about 50 bar, such as about 10 bar to about 47 bar, such as about 10 bar to about 40 bar, or such as less than about 50 bar. The hydrotreated naphtha stream 326 and the stream 352 may be independently fed to the MFSC 310 or may be combined with the naphtha stream 316 produced form the CDU 316. In some examples, either of the hydrotreated naphtha stream 326 or the stream 352 may be combined with the naphtha stream 316 while the other is directly fed to the MFSC 310.

[0046] The MFSC 310 may be operable to receive the light product stream 314, the naphtha stream 316, the hydrotreated naphtha stream 326, the stream 352, the hydrotreated kerosene stream 328, and the hydrotreated diesel stream 330 and to produce one or more high value chemical product streams,23 CHEM0021 -WO-ORDsuch as, but not limited to, fuel gas, ethene, propene, buta- 1,3 -diene, MTBE, butene- 1, benzene, toluene, mixed xylenes, pyoil, or a combination thereof. The MF SC 310 may operate with a coil outlet temperature (COT) of about 700 °C to about 800 °C.

[0047] The off-site area 342 may be a unit positioned outside of a battery limit of the olefin complex system 300 operable to receive pyoil, straight run diesel, or atmospheric residue containing streams. In some examples, the straight run diesel stream 346 and the atmospheric residue stream 348 may be independently fed to the off-site area 342. In other examples, the straight run diesel stream 346 and the atmospheric residue stream 348 may be combined prior to delivery to the off-site area 342.

[0048] Embodiments of the disclosure, for example, include a method comprising the steps of distilling a gas condensate feedstock to produce a light product stream having C2-C4 compounds, a first naphtha stream, a distillate stream, and a heavy residue stream containing alkanes up to C24 hydrocarbons. The method further includes hydrotreating the distillate stream to produce a hydrotreated distillate stream; distilling the heavy residue stream under vacuum pressure to produce a gas oil stream; hydrocracking the gas oil stream to produce a second naphtha stream and an unconverted oil stream; and steam cracking the light product stream, the first naphtha stream, the hydrotreated distillate stream, the second naphtha stream, and the unconverted oil stream to produce one or more high value chemical product streams comprising ethene and propene. The gas condensate feedstock can have an API gravity ranging from about 43 to about 50, and the gas condensate may be sourced from a gas field exploration and has about 2 wt.% to about 3 wt.% vacuum residue. Certain embodiments of the method further include distilling the gas condensate feedstock is performed at an operating pressure of about 0.01 bar to about 3 bar. These embodiments include the light product stream with a cut point of 150 °C or less; the first naphtha stream with a cut point between 150 °C and 205 °C; the distillate stream with a cut point between 150 °C and 350 °C; and the gas oil stream with a cut point between 350 °C and 565 °C; and the gas condensate feedstock can have an API gravity ranging from about 43 to about 44. Certain embodiments of the method further include hydrotreating the distillate stream to produce a third naphtha stream, and steam cracking the third naphtha stream. Certain embodiments of the method further include hydrotreating the distillate stream while maintaining an operating pressure between 10 bar and 50 bar. Certain embodiments of the method further include hydrocracking the gas oil stream at an operating pressure between 100 bar and 200 bar. In certain embodiments, the operating pressure is between 135 and 170 bar. Certain embodiments of the method further include the gas condensate feedstock being a blend produced23 CHEM0021 -WO-ORDfrom a mixture of light crude oil and a raw gas condensate. Certain embodiments of the method further include hydrotreating the distillate stream produces a first diesel product stream; hydrocracking the gas oil stream produces a second diesel product stream; and outputting the first diesel product stream and the second diesel product stream.

[0049] Certain embodiments of the method further include hydrocracking the gas oil stream produces a purge gas, steam cracking the purge gas to facilitate recovery of the one or more high value chemical product streams. Hydrotreating of the distillate stream further produces a hydrotreated kerosene stream to be steam cracked when the hydrotreating and the hydrocracking steps are not in operation.

[0050] FIG. 4 is a flow chart of a method 400 to process gas condensate in an olefin complex system, according to an example of the present disclosure. The method 400 details exemplary operations, via blocks, for conditioning gas condensate for increased yield of high value chemical products from a MFSC 110, as discussed above. The below disclosure of method 400 will reference the system components of the olefin complex system 100 of FIG. 1, however, it is to be understood, the method 400 may be tailored to describe the examples of FIGS. 2 or 3, which omit, or bypass units, as discussed above. Furthermore, unless specified, the descriptions, properties, operating conditions, layout, connections, and the like, of FIGS. 1, 2 and 3, are applicable to a respective method 400 applicable to each of the example systems of FIGS. 1, 2 or 3, without descriptions to each method of FIGS. 2 or 3, for example.

[0051] The method 400 begins at block 402 by distilling a gas condensate feedstock 112 in the CDU 102 to produce a light product stream 114 having C2-C4 compounds, a first naphtha stream, such as naphtha stream 116, a distillate stream 118, and a heavy residue stream 120. Both the light product stream 114 and the naphtha stream 116 may be fed to the MFSC 110. The distillate stream 118 may be fed to the DHT 106 and the heavy residue stream 120 may be fed to the VDU 104.

[0052] The method 400 continues at block 404 by hydrotreating the distillate stream 118 in the DHT 106 to produce a hydrotreated distillate stream 128, a second naphtha stream, such as the hydrotreated naphtha stream 126, and a first diesel stream, such as the diesel stream 130. The hydrotreated naphtha stream 126 may be combined with the naphtha stream 116 or may be independently fed to the MFSC 110. The hydrotreated distillate stream 128 may be fed to the MFSC 110. The diesel stream 130 may be provided to the diesel unit (not illustrated).23 CHEM0021 -WO-ORD

[0053] At block 406, the method 400 continues by distilling the heavy residue stream 120 in the VDU 104 to produce a vacuum residue stream 124 and a gas oil stream 122. The vacuum residue stream 124 may be provided to the off-site area 142 and the gas oil stream 122 may be fed to the HCR 108. The method 400 may continue at block 408 by hydrocracking the gas oil stream 122, and optionally at least a portion of the pyoil stream 138 produced by the MFSC 110, in the HCR 108 to produce a third naphtha stream, such as the hydrocracked naphtha stream 132, the unconverted oil stream 134, and a second diesel stream, such as the diesel stream 136. At block 410, the various conditioned streams may be steam cracked to produce high value chemical product streams. For example, the method 400 may specifically steam crack the light product stream 114, the naphtha stream 116, the hydrotreated distillate stream 128, the hydrotreated naphtha stream 126, and the hydrocracked naphtha stream 132, and the unconverted oil stream 134 in the MFSC 110 to produce aforementioned high value chemical products, including, but not limited to, comprising ethene and propene. As mentioned above, example methods may be tailored to each olefin complex system 200 of FIG. 2 or olefin complex system 300 of FIG. 3.EXAMPLES

[0054] The following examples are put forth so as to provide those of ordinary skill in the art with a complete disclosure and description of how the compounds, compositions, articles, devices and / or methods claimed herein are made and evaluated and, therefore, are intended to be purely exemplary and are not intended to limit the disclosure. Efforts have been made to ensure accuracy with respect to numbers (such as amounts, temperature, and so forth), but some deviations should be accounted for. There are numerous variations and combinations of reaction conditions, for example, component concentrations, desired solvents, solvent mixtures, temperatures, pressures and other reaction ranges and conditions that can be used to optimize the product purity and yield obtained from the described process. Only reasonable and routine experimentation will be required to optimize such process conditions.

[0055] Example 1

[0056] The following is an example of an assay composition that may be utilized to obtain gas condensate for chemical production via the systems described above. The table below illustrates values that correlate to an assay obtained from exploration. It is to be understood, various values and calculations may be obtained or performed from the combination of value below to further supplement the disclosure above.23 CHEM0021 -WO-ORD

[0057] Table 1: Assay Summary

[0058] As discussed above, the API of the gas condensate feedstock 112 (or gas condensate feedstock 212, 312) may be between 43 to about 50, such as about 46.1 to about 48.3. Further, the gas condensate has a light hydrocarbon composition as shown in Table 2 below.

[0059] Table 2: Light Hydrocarbon Distribution

[0060] Table 3 : Whole Crude Properties<<23 CHEM0021 -WO-ORD&<

[0061] For complete disclosure, whole crude properties are shown above in Table 3.

[0062] When ranges are disclosed herein, ranges from any lower limit may be combined with any upper limit to recite a range not explicitly recited, as well as, ranges from any lower limit may be combined with any other lower limit to recite a range not explicitly recited, in the same way, ranges from any upper limit may be combined with any other upper limit to recite a range not explicitly recited. Additionally, reference to values stated in ranges includes each and every value within that range, even though not explicitly recited. Thus, every point or individual value may serve as its own lower or upper limit combined with any other point or individual value or any other lower or upper limit, to recite a range not explicitly recited.

[0063] Other objects, features and advantages of the disclosure will become apparent from the foregoing figures, detailed description, and examples. It should be understood, however, that the figures, detailed description, and examples, while indicating specific embodiments of the disclosure, are given by way of illustration only and are not meant to be limiting. Additionally, it is contemplated that changes and modifications within the spirit and scope of the disclosure will become apparent to those skilled in the art from the detailed description. In further embodiments, features from specific embodiments may be combined with features from other embodiments. For example, features from one embodiment may be combined with features from any of the other embodiments. In further embodiments, additional features may be added to the specific embodiments described herein.

Claims

23 CHEM0021 -WO-ORDCLAIMS1. A method comprising:distilling a gas condensate feedstock to produce a light product stream having C2-C4 compounds, a first naphtha stream, a distillate stream, and a heavy residue stream containing alkanes up to C24 hydrocarbons;hydrotreating the distillate stream to produce a hydrotreated distillate stream; distilling the heavy residue stream under vacuum pressure to produce a gas oil stream; hydrocracking the gas oil stream to produce a second naphtha stream and an unconverted oil stream; andsteam cracking the light product stream, the first naphtha stream, the hydrotreated distillate stream, the second naphtha stream, and the unconverted oil stream to produce one or more high value chemical product streams comprising ethene and propene.

2. The method of claim 1, wherein the gas condensate feedstock has an API gravity ranging from about 43 to about 50, and wherein the gas condensate is sourced from a gas field exploration and has about 2 wt.% to about 3 wt.% vacuum residue.

3. The method of claim 1, wherein:distilling the gas condensate feedstock at an operating pressure of about 0.01 bar to about 3 bar;the light product stream with a cut point of 150 °C or less;the first naphtha stream with a cut point between 150 °C and 205 °C;the distillate stream with a cut point between 150 °C and 350 °C; andthe gas oil stream with a cut point between 350 °C and 565 °C; andwherein the gas condensate feedstock has an API gravity ranging from about 43 to about 44.

4. The method of one of claims 1-3, wherein hydrotreating the distillate stream produces a third naphtha stream, and wherein the method further comprises steam cracking the third naphtha stream.23 CHEM0021 -WO-ORD5. The method of one of claims 1-4, wherein hydrotreating the distillate stream includes maintaining an operating pressure between 10 bar and 50 bar.

6. The method of one of claims 1-5, wherein hydrocracking the gas oil stream includes maintaining an operating pressure between 100 bar and 200 bar.

7. The method of claim 6, wherein the operating pressure is between 135 and 170 bar, and wherein the gas condensate feedstock is a blend produced from a mixture of light crude oil and a raw gas condensate.

8. The method of one of claims 1-7, wherein:hydrotreating the distillate stream produces a first diesel product stream; hydrocracking the gas oil stream produces a second diesel product stream; and the method comprises combining the first diesel product stream and the second diesel product stream.

9. The method of one of claims 1-8, wherein hydrocracking the gas oil stream produces a purge gas, and wherein the method comprises steam cracking the purge gas to facilitate recovery of the one or more high value chemical product streams, and wherein hydrotreating the distillate stream further produces a hydrotreated kerosene stream to be steam cracked when the hydrotreating and the hydrocracking steps are not in operation.

10. A system comprising:a crude distillation unit operable to receive a gas condensate feedstock having an API gravity ranging from about 43 to about 50 and split the gas condensate feedstock at an operating pressure of about 0.01 bar to about 3 bar into at least:a light product stream having a cut point of 150 °C or less;a first naphtha stream having a cut point between 150 °C and 205 °C; a distillate stream having a cut point between 105 °C and 350 °C; and a heavy residue stream comprising alkanes;23 CHEM0021 -WO-ORDa vacuum distillation unit operable to receive the heavy residue stream from the crude distillation unit and split the heavy residue stream into a gas oil stream having a cut point of about 350 °C to about 565 °C and a vacuum residue stream having a cut point of about 350 °C or higher;a diesel hydrotreater unit operable to receive the distillate stream and to produce a hydrotreated distillate stream and a first diesel stream;a hydrocracker unit operable to receive the gas oil stream and to produce a second naphtha stream, an unconverted oil stream, and a second diesel stream; and a mixed feed steam cracker operable to receive the light product stream, the first naphtha stream, the hydrotreated distillate stream, the second naphtha stream, and the unconverted oil stream and to produce one or more high value chemical product streams comprising ethene and propene.

11. The system of claim 10, wherein the hydrocracker unit operates at a temperature of about 300 °C to about 500 °C, and wherein the gas condensate is sourced from a gas field.

12. The system of one of claims 10 or 11, wherein the diesel hydrotreater unit is operated at an operating pressure between 10 bar and 50 bar, and wherein the diesel hydrotreater unit is operable to produce a hydrotreated kerosene stream supplied to the mixed feed steam cracker when the vacuum distillation unit and the hydrocracker unit are not in operation.

13. The system of one of claims 10-12, wherein the hydrocracker unit is operated at an operating pressure between 135 bar and 170 bar.

14. The system of one of claims 10-13, wherein the one or more high value chemical product streams comprise one or more of hydrogen, ethene, propene, buta- 1,3 -diene, butene-1, methyl t-butyl ether, benzene, toluene, one or more xylenes, or pyrolysis oil.

15. The system of one of claims 10-14, wherein the one or more high value chemical product streams comprise the pyrolysis oil, and wherein the hydrocracker unit is operable to receive at least a portion of the pyrolysis oil.3 CHEM0021 -WO-ORD16. A system comprising:a crude distillation unit operable to receive a gas condensate feedstock having an API gravity ranging from about 43 to about 50 and split the gas condensate feedstock at an operating pressure of about 0.01 bar to about 3 bar into at least:a light product stream having a cut point of 150 °C or less;a first naphtha stream having a cut point between 150 °C and 205 °C; a kerosene stream having a cut point between 150 °C and 350 °C;a straight run diesel stream; andan atmospheric residue stream;a diesel hydrotreater unit operable to receive the kerosene stream and the straight run diesel stream and to produce a second naphtha stream comprising hydrotreated naphtha, a hydrotreated kerosene stream, and a hydrotreated diesel stream; and a mixed feed steam cracker operable to receive the light product stream, the first naphtha stream, the second naphtha stream, the hydrotreated kerosene stream, and the hydrotreated diesel stream and to produce one or more high value chemical product streams comprising ethene, propene, or both.

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