US20110094937A1 - Residuum Oil Supercritical Extraction Process - Google Patents

Residuum Oil Supercritical Extraction Process Download PDF

Info

Publication number
US20110094937A1
US20110094937A1 US12/606,896 US60689609A US2011094937A1 US 20110094937 A1 US20110094937 A1 US 20110094937A1 US 60689609 A US60689609 A US 60689609A US 2011094937 A1 US2011094937 A1 US 2011094937A1
Authority
US
United States
Prior art keywords
units
embodiments
hydrocarbon
line
solvent
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Abandoned
Application number
US12/606,896
Inventor
Anand Subramanian
Raymond Floyd
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Kellogg Brown and Root LLC
Original Assignee
Kellogg Brown and Root LLC
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Kellogg Brown and Root LLC filed Critical Kellogg Brown and Root LLC
Priority to US12/606,896 priority Critical patent/US20110094937A1/en
Assigned to KELLOGG BROWN & ROOT LLC reassignment KELLOGG BROWN & ROOT LLC ASSIGNMENT OF ASSIGNORS INTEREST (SEE DOCUMENT FOR DETAILS). Assignors: FLOYD, RAYMOND, MR., SUBRAMANIAN, ANAND, MR.
Publication of US20110094937A1 publication Critical patent/US20110094937A1/en
Assigned to BANK OF AMERICA, N.A., AS ADMINISTRATIVE AGENT reassignment BANK OF AMERICA, N.A., AS ADMINISTRATIVE AGENT SECURITY INTEREST (SEE DOCUMENT FOR DETAILS). Assignors: KELLOGG BROWN & ROOT LLC
Abandoned legal-status Critical Current

Links

Images

Classifications

    • CCHEMISTRY; METALLURGY
    • C10PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10GCRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G21/00Refining of hydrocarbon oils in the absence of hydrogen, by extraction with selective solvents
    • C10G21/003Solvent de-asphalting

Abstract

Systems and methods for processing one or more hydrocarbons are provided. A hydrocarbon can be selectively separated to provide one or more finished products and an asphaltenic hydrocarbon using a pretreatment process. The asphaltenic hydrocarbon can be selectively separated to provide a deasphalted oil and one or more asphaltenes. At least a portion of the deasphalted oil can be converted to one or more first products using a first post-treatment process. At least a portion of the one or more asphaltenes can be converted to one or more second products using a second post-treatment process.

Description

    BACKGROUND
  • 1. Field
  • Embodiments of the present invention generally relate to extraction processes for processing hydrocarbons. More particularly, embodiments of the present invention relate to processes for upgrading one or more hydrocarbons using a solvent de-asphalting unit.
  • 2. Description of the Related Art
  • Solvent de-asphalting (“SDA”) processes have been used to treat residuum (“residual”) oil. Traditional refinery distillation processes separate light hydrocarbon compounds from feedstocks, leaving a large volume of residual oil that is primarily heavy hydrocarbons. SDA processes have been used to treat the heavy hydrocarbons with a solvent to generate asphaltenic and de-asphalted oil (“DAO”) products. The asphaltenic and DAO products are typically treated and/or processed into useful products.
  • DAO can be economically attractive when downstream treatment facilities such as hydrotreating or fluid catalytic cracking (“FCC”) are adequately sized to process the large volume of DAO generated when treating residuum. However, hydrocracking the DAO requires a capital intensive, high-pressure, system to fractionate the large quantity of DAO, especially when intermediate products such as diesel, gas oil, and/or kerosene are preferred.
  • A need, therefore, exists for an improved process for upgrading residuum hydrocarbons while minimizing capital investment.
  • BRIEF DESCRIPTION OF THE DRAWINGS
  • So that the manner in which the above recited features of the present invention can be understood in detail, a more particular description of the invention, briefly summarized above, may be had by reference to embodiments, some of which are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate only typical embodiments of this invention and are therefore not to be considered limiting of its scope, for the invention may admit to other equally effective embodiments.
  • FIG. 1 depicts an illustrative two-stage solvent extraction system according to one or more embodiments described.
  • FIG. 2 depicts an illustrative three-stage separator/solvent extraction system according to one or more embodiments described.
  • FIG. 3 depicts an illustrative solvent dewatering system integrated with one or more separator/solvent extraction systems, according to one or more embodiments described.
  • FIG. 4 depicts an illustrative flash evaporation system integrated with one or more separator/solvent extraction systems, according to one or more embodiments described.
  • FIG. 5 depicts an illustrative distillation system integrated with one or more separator/solvent extraction systems, according to one or more embodiments described.
  • FIG. 6 depicts an illustrative hydrotreating system integrated with one or more separator/solvent extraction systems, according to one or more embodiments described.
  • FIG. 7 depicts an illustrative integrated vacuum separation and hydrogenation system integrated with one or more separator/solvent extraction systems, according to one or more embodiments described.
  • FIG. 8 depicts an illustrative integrated gasification and separation system integrated with one or more separator/solvent extraction systems, according to one or more embodiments described.
  • FIG. 9 depicts an illustrative tank cleaning and separation system integrated with one or more separator/solvent extraction systems, according to one or more embodiments described.
  • FIG. 10 depicts an illustrative distillation based fractionation system integrated with one or more separator/solvent extraction systems, according to one or more embodiments described.
  • FIG. 11 depicts an illustrative hydrogenation system integrated with one or more separator/solvent extraction systems, according to one or more embodiments described.
  • FIG. 12 depicts an illustrative thermal treatment system integrated with one or more separator/solvent extraction systems, according to one or more embodiments described.
  • FIG. 13 depicts an illustrative extraction system integrated with one or more separator/solvent extraction systems, according to one or more embodiments described.
  • FIG. 14 depicts an illustrative solids removal system integrated with one or more separator/solvent extraction systems, according to one or more embodiments described.
  • FIG. 15 depicts an illustrative demetallization system integrated with one or more separator/solvent extraction systems, according to one or more embodiments described.
  • FIG. 16 depicts an illustrative solids separation and hydrocarbon recovery system integrated with one or more separator/solvent extraction systems, according to one or more embodiments described.
  • FIG. 17 depicts an illustrative emissions reduction system integrated with one or more separator/solvent extraction systems, according to one or more embodiments described.
  • FIG. 18 depicts another illustrative distillation system integrated with one or more separator/solvent extraction systems, according to one or more embodiments described.
  • FIG. 19 depicts an illustrative asphaltene blending system integrated with one or more separator/solvent extraction systems, according to one or more embodiments described.
  • FIG. 20 depicts an illustrative fractionating and hydrorefining system integrated with one or more separator/solvent extraction systems, according to one or more embodiments described.
  • DETAILED DESCRIPTION
  • A detailed description will now be provided. Each of the appended claims defines a separate invention, which for infringement purposes is recognized as including equivalents to the various elements or limitations specified in the claims. Depending on the context, all references below to the “invention” may in some cases refer to certain specific embodiments only. In other cases it will be recognized that references to the “invention” will refer to subject matter recited in one or more, but not necessarily all, of the claims. Each of the inventions will now be described in greater detail below, including specific embodiments, versions and examples, but the inventions are not limited to these embodiments, versions or examples, which are included to enable a person having ordinary skill in the art to make and use the inventions, when the information in this patent is combined with available information and technology.
  • Systems and methods for processing one or more hydrocarbons are provided. A hydrocarbon can be selectively separated to provide one or more finished products and an asphaltenic hydrocarbon using a pretreatment process. The asphaltenic hydrocarbon can be selectively separated to provide a deasphalted oil and one or more asphaltenes. At least a portion of the deasphalted oil can be converted to one or more first products using a first post-treatment process. At least a portion of the one or more asphaltenes can be converted to one or more second products using a second post-treatment process.
  • As used herein, the terms “solvent” and “solvents” can refer to one or more alkane or alkene hydrocarbons having three to seven carbon atoms (C3 to C7), mixtures thereof, derivatives thereof and combinations thereof. In one or more embodiments, the solvent can have a normal boiling point (for pure solvents) or bulk normal boiling point (for solvent mixtures) of less than 538° C.
  • As used herein, the terms “asphaltene,” “asphaltenes,” “asphaltenic hydrocarbon,” and “asphaltenic hydrocarbons” can refer to one or more hydrocarbons that are insoluble in n-alkanes but are totally or partially soluble in aromatics such as benzene and/or toluene. Asphaltenes can consist primarily of carbon, hydrogen, nitrogen, oxygen, and sulfur, as well as trace amounts of vanadium and nickel. Asphaltenes can have a carbon-to-hydrogen (“C:H”) ratio of about 1:2, about 1:1.5, about 1:1.2, or about 1:1. In one or more embodiments, asphaltenes can be an n-heptane (C7H16) insoluble and toluene (C6H5CH3) soluble component of a carbonaceous material such as crude oil, bitumen or coal. In one or more embodiments, asphaltenes can have a molecular mass distribution in the range of from about 400 u to about 1500 u.
  • The terms “light deasphalted oil” and “L-DAO” as used herein can refer to a solution or mixture containing one or more hydrocarbons sharing similar physical properties and containing less than about 5% wt, less than about 4% wt, less than about 3% wt, less than about 2% wt, or less than about 1% asphaltenic hydrocarbons. In one or more embodiments, the L-DAO can have a boiling point ranging from a low of about 250° C., about 275° C., or about 315° C. to a high of about 600° C., about 675° C., about 750° C., or more. In one or more embodiments, the L-DAO can have a viscosity (at 50° C.) of about 30 cSt to about 75 cSt, about 35 cSt to about 70 cSt, or about 40 cSt to about 65 cSt. In one or more embodiments, the L-DAO can have a flash point greater than about 110° C., greater than about 115° C., greater than about 120° C., greater than about 130° C., or more.
  • The terms “heavy deasphalted oil” and “H-DAO” as used herein can refer to a solution or mixture containing one or more hydrocarbons sharing similar physical properties and containing less than about 5% wt, less than about 4% wt, less than about 3% wt, less than about 2% wt, or less than about 1% asphaltenic hydrocarbons. In one or more embodiments, the H-DAO can have a boiling point of about 300° C. to about 900° C., about 350° C. to about 850° C., or about 400° C. to about 800° C. In one or more embodiments, the H-DAO can have a viscosity (at 50° C.) of about 40 cSt to about 190 cSt, about 45 cSt to about 180 cSt, or about 50 cSt to about 170 cSt. In one or more embodiments, the H-DAO can have a flash point greater than about 135° C., greater than about 140° C., greater than about 145° C., greater than about 150° C., or more.
  • The terms “deasphalted oil” and “DAO” as used herein refer to a mixture of light deasphalted and heavy deasphalted oils.
  • FIG. 1 depicts an illustrative two-stage solvent extraction system 100 according to one or more embodiments. The two-stage solvent extraction system 100 can include one or more mixers 110, separators 120, 150, and strippers 130, 160. Any number of mixers, separators, and strippers can be used depending on the amount of the hydrocarbon to be processed. In one or more embodiments, a hydrocarbon via line 105 and a solvent via line 177 can be mixed or otherwise combined within the one or more mixers 110 to provide a hydrocarbon mixture via line 112. The solvent-to-hydrocarbon weight ratio can vary depending upon the physical properties and/or composition of the hydrocarbon. For example, a high boiling point hydrocarbon can require greater dilution with low boiling point solvent to obtain the desired bulk boiling point for the resultant mixture. The hydrocarbon mixture in line 112 can have a solvent-to-hydrocarbon dilution ratio of about 1:1 to about 100:1, about 2:1 to about 10:1, or about 3:1 to about 6:1.
  • In one or more embodiments, the hydrocarbon in line 105 can include, but is not limited to, one or more carbon-containing materials whether solid, liquid, gas, or any combination thereof. The carbon-containing materials can include but are not limited to, whole crude oil, crude oil, vacuum gas oil, heavy gas oil, residuum, atmospheric tower bottoms, vacuum tower bottoms, distillates, paraffins, aromatic rich material from solvent deasphalting units, aromatic hydrocarbons, naphthenes, oil shales, oil sands, tars, bitumens, kerogen, waste oils, derivatives thereof, or mixtures thereof. In one or more embodiments, the hydrocarbon in line 105 can have an API Gravity at 15.6° C. ranging from a low of about −12, about 0, about 5, or about 10 to a high of about 20, about 25, about 30, or about 35. In one or more embodiments, the hydrocarbon in line 105 can have an API Gravity at 15.6° C. of from about −12 to about 20, or from about 5 to about 23, or from about 10 to about 30. In one or more embodiments, the paraffin content of the hydrocarbon in line 105 can range from a low of about 30% vol, about 35% vol, or about 40% vol to a high of about 55% vol, about 60% vol, or about 65% vol. In one or more embodiments, the aromatic hydrocarbon content of the hydrocarbon in line 105 can range from a low of about 2% vol, about 7% vol, or about 12% vol to a high of about 20% vol, about 50% vol, or about 80% vol. In one or more embodiments, the naphthene content of the hydrocarbon in line 105 can range from a low of about 0% vol, about 10% vol, or about 20% vol to a high of about 25% vol, about 30% vol, or about 35% vol. In one or more embodiments, the hydrocarbon in line 105 can have a C:H ratio of from about 0.8:1, about 1:1, about 1:1.1, about 1:1.2, about 1:1.3, or about 1:1.4.
  • The one or more mixers 110 can be one or more system, device, or combination of systems and/or devices suitable for batch, intermittent, and/or continuous mixing of the hydrocarbon and the solvent. The mixer 110 can be capable of homogenizing immiscible fluids. Illustrative mixers can include but are not limited to ejectors, inline static mixers, inline mechanical/power mixers, homogenizers, or combinations thereof. The mixer 110 can operate at temperatures of about 25° C. to about 600° C., about 25° C. to about 500° C., or about 25° C. to about 300° C. The mixer 110 can operate at a pressure slightly higher than the pressure of the separator 120. In one or more embodiments, the mixer can operate at a pressure of about 101 kPa to about 2,100 kPa above the critical pressure of the solvent (“PC,S”), about PC,S−700 kPa to about PC,S+2,100 kPa, about PC,S−500 kPa to about PC,S+1,500 kPa, about PC,S−300 kPa to about PC,S+700 kPa.
  • The hydrocarbon mixture in line 112 can be introduced to the one or more separators (“asphaltene separators”) 120 to provide a deasphalted oil (“DAO”) mixture via line 122 and an asphaltenic mixture via line 128. The DAO mixture in line 122 can contain deasphalted oil and a first portion of the solvent. The asphaltenic mixture in line 128 can contain insoluble asphaltenes and the balance of the solvent. In one or more embodiments, the DAO concentration in line 122 can range from about 1% wt to about 50% wt, about 5% wt to about 40% wt, or about 14% wt to about 34% wt. In one or more embodiments, the solvent concentration in line 122 can range from about 50% wt to about 99% wt, about 60% wt to about 95% wt, or about 66% wt to about 86% wt. In one or more embodiments, the specific gravity (API density@15.6° C.) of the DAO mixture in line 122 can range from about 10° API to about 100° API, about 30° API to about 100° API, or about 50° API to about 100° API.
  • In one or more embodiments, the asphaltenic mixture in line 128 can have an asphaltene concentration of from about 10% wt to about 99% wt, about 30% wt to about 95% wt, or about 50% wt to about 90% wt. In one or more embodiments, the asphaltenic mixture in line 128 can have a solvent concentration of from about 1% wt to about 90% wt, about 5% wt to about 70% wt, or about 10% wt to about 50% wt.
  • The one or more separators 120 can include one or more systems, devices, or combination of systems and/or devices suitable for separating one or more asphaltenes from the hydrocarbon and solvent mixture to provide deasphalted oil via line 122 and asphaltenes via line 128. In one or more embodiments, the one or more separators 120 can contain one or more internal structures including, but not limited to bubble trays, packing elements such as rings or saddles, structured packing, or combinations thereof. In one or more embodiments, the one or more separators 120 can be an open column without internals. In one or more embodiments, the one or more separators 120 can be one or more partially empty columns containing one or more internal structures. In one or more embodiments, the separators 120 can operate at a temperature of about 15° C. to about 150° C. above the critical temperature of the one or more solvent (“TC,S”), about 15° C. to about TC,S+100° C., or about 15° C. to about TC,S+50° C. In one or more embodiments, the separators 120 can operate at a pressure of about 101 kPa to about 2,100 kPa above the critical pressure of the solvent (“PC,S”), about PC,S−700 kPa to about PC,S+2,100 kPa, about PC,S−500 kPa to about PC,S+1,500 kPa, about PC,S−300 kPa to about PC,S+700 kPa.
  • In one or more embodiments, the asphaltenes in line 128 can be heated using one or more heat exchangers 115, prior to introduction to the one or more strippers 130. In one or more embodiments, the asphaltenes in line 128 can be heated to a temperature of about 100° C. to about TC,S+150° C., about 150° C. to about TC,S+100° C., or about 300° C. to about TC,S+50° C. using one or more heat exchangers 115.
  • The one or more heat exchangers 115 can include one or more systems, devices, or combination of systems and/or devices suitable for increasing the temperature of the asphaltenes in line 128. Illustrative heat exchanger systems or devices can include, but are not limited to shell-and-tube exchangers, plate and frame exchangers, spiral wound exchangers, or any combination thereof. In one or more embodiments, a heat transfer medium such as steam, hot oil, hot process fluids, electric resistance heat, hot waste fluids, or combinations thereof can be used to transfer heat to the asphaltenes in line 128. In one or more embodiments, the one or more heat exchangers 115 can be a direct fired heater or the equivalent. In one or more embodiments, the one or more heat exchangers 115 can operate at a temperature of about 25° C. to about TC,S+150° C., about 25° C. to about TC,S+100° C., or about 25° C. to about TC,S+50° C. In one or more embodiments, the one or more heat exchangers 115 can operate at a pressure of about 101 kPa to about PC,S+2,100 kPa, about 101 kPa to about PC,S+1,500 kPa, or about 101 kPa to about PC,S+700 kPa.
  • Within the stripper 130, the solvent in the asphaltenes in line 128 can be selectively separated to provide a recovered solvent via line 132 and asphaltenes (“asphaltene product”) via line 133. In one or more embodiments, the recovered solvent in line 132 can contain a first portion of the solvent and small quantities of residual DAO, and the asphaltenes in line 133 can contain a mixture of insoluble asphaltenes and the balance of the solvent. In one or more embodiments, the recovered solvent in line 132 can have a solvent concentration ranging from a low of about 50% wt, about 70% wt, or about 80% wt to a high of about 90% wt, about 95% wt, about 99% wt, or more. In one or more embodiments, the recovered solvent in line 132 can contain less about 5% wt, less than about 3% wt, less than about 1% wt, or less than about 0.5% wt DAO. In one or more embodiments, the asphaltene product in line 133 can have an asphaltene concentration ranging from a low of about 20% wt, about 40% wt, or about 50% wt to a high of about 75% wt, about 80% wt, about 95% wt, or more.
  • In one or more embodiments, steam, for example saturated or superheated, can be injected into the one or more strippers 130 via line 134 to further enhance the separation of the asphaltenes from the solvent. In one or more embodiments, the steam in introduced to the one or more strippers 130 via line 134 can be at a pressure ranging from about 200 kPa to about 2,160 kPa, from about 300 kPa to about 1,475 kPa, or from about 400 kPa to about 1,130 kPa.
  • In one or more embodiments, the asphaltene product in line 133 can have a solvent concentration ranging from a low of about 1% wt, about 5% wt, about 10% wt, or about 20% wt to a high of about 50% wt, about 60% wt, about 70% wt, or about 80% wt. In one or more embodiments, the specific gravity (at 15.6° C.) of the asphaltene product in line 133 can range from a low of about −15° API, about −10°, or about −5° to a high of about 5°, about 10°, or about 15° or more. In one or more embodiments, at least a portion of the asphaltene product in line 133 can be dried and pelletized. In one or more embodiments, at least a portion of the asphaltene product in line 133 can be gasified to provide one or more gas products for power generation, process heating, or combinations thereof. In one or more embodiments, at least a portion of the asphaltene product in line 133 can be combusted or otherwise converted to provide steam, mechanical power, electrical power, or any combination thereof.
  • The one or more strippers 130 can include one or more systems, devices, or combination of systems and/or devices suitable for selectively separating the asphaltenes in line 128 to provide the recovered solvent via line 132 and the asphaltene product via line 133. In one or more embodiments, the one or more strippers 130 can contain one or more internal structures including, but not limited to bubble trays, packing elements such as rings or saddles, structured packing, or combinations thereof. In one or more embodiments, the one or more strippers 130 can be an open column without internals. In one or more embodiments, the one or more strippers 130 can be one or more partially empty columns containing one or more internal structures. In one or more embodiments, the one or more strippers 130 can operate at a temperature of about 30° C. to about 600° C., about 100° C. to about 550° C., or about 300° C. to about 550° C. In one or more embodiments, the one or more strippers 130 can operate close to zero pressure, for example at about 0.1 kPa. In one or more embodiments, the one or more strippers 130 can operate at a pressure ranging from a low of about 30 kPa, about 100 kPa, about 500 kPa, or about 1,000 kPa to a high of about 2,500 kPa, about 3,300 kPa, about 4,000 kPa, or about 4,500 kPa.
  • Referring again to the one or more asphaltene strippers 120, the DAO mixture in line 122 can be heated using one or more heat exchangers 145, 148 to provide a heated DAO mixture via line 124. In one or more embodiments, the temperature of the heated DAO mixture in line 124 can be increased above the critical temperature of the solvent TC,S. In one or more embodiments, the heated DAO mixture in line 124 can have a temperature of from about 25° C. to about TC,S+150° C., about TC,S−100° C. to about TC,S+100° C., or about TC,S−50° C. to about TC,S+50° C.
  • The one or more heat exchangers 145, 148 can include one or more systems, devices, or combination of systems and/or devices suitable for increasing the temperature of the DAO mixture in line 122. In one or more embodiments, the heat exchanger 145 can be a regenerative type heat exchanger using a high temperature process stream to heat the DAO mixture in line 122 prior to introduction to the separator 150. In one or more embodiments, a recovered solvent via line 152 can be introduced to the heat exchanger 145 to heat the DAO mixture introduced via line 122. In one or more embodiments, the one or more heat exchangers 145, 148 can operate at a pressure of about 101 kPa to about PC,S+2,100 kPa, about 101 kPa to about PC,S+1,500 kPa, or about 101 kPa to about PC,S+700 kPa.
  • The heated DAO mixture via line 124 can be introduced to the one or more separators 150 and selectively separated therein to provide a recovered solvent via line 152 and DAO via line 158. In one or more embodiments, the recovered solvent in line 152 can contain a first portion of the solvent, and the deasphalted oil in line 158 can contain DAO and the balance of the solvent. In one or more embodiments, the recovered solvent in line 152 can have a solvent concentration ranging from a low of about 50% wt, about 70% wt, or about 85% wt to a high of about 95% wt, about 98%, about 99%, or more, with the balance being DAO. In one or more embodiments, in the deasphalted oil in line 158 can have a DAO concentration ranging from a low of about 20% wt, 40% wt, or about 50% wt to a high of about 80% wt, 90% wt, about 95% wt, or more, with the balance being the solvent. In one or more embodiments, the deasphalted oil in line 158 can have a specific gravity (API density at 15.6° C.) ranging from a low of about 5°, about 10°, or about 12° to a high of about 20°, about 25°, about 30°, or more.
  • The one or more separators 150 can include one or more systems, devices, or combination of systems and/or devices suitable for separating the DAO mixture introduced via line 122 to provide a the recovered solvent in line 152 and the DAO in line 158. In one or more embodiments, the one or more separators 150 can contain one or more internal structures including, but not limited to bubble trays, packing elements such as rings or saddles, structured packing, or combinations thereof. In one or more embodiments, the one or more separators 150 can be an open column without internals. In one or more embodiments, the one or more separators 150 can be one or more partially empty columns containing one or more internal structures. In one or more embodiments, the one or more separators 150 can operate at a temperature of about 15° C. to about 600° C., about 15° C. to about 500° C., or about 15° C. to about 400° C. In one or more embodiments, the one or more separators 150 can operate at a pressure of about PC,S−700 kPa to about PC,S+2,100 kPa, about PC,S−500 kPa to about PC,S+1,500 kPa, or about PC,S−300 kPa to about PC,S+700 kPa.
  • In one or more embodiments, at least a portion of the DAO in line 158 can be directed to the one or more strippers 160 and selectively separated therein to provide a recovered solvent via line 162 and DAO (“DAO product”) via line 163. In one or more embodiments, the recovered solvent in line 162 can contain a first portion of the solvent, and the DAO product in line 163 can contain DAO and the balance of the solvent. In one or more embodiments, the recovered solvent in line 162 can have a solvent concentration of from about 70% wt to about 100% wt, about 85% wt to about 99.9% wt, or about 90% wt to about 99.9% wt or more, with the DAO providing the balance. In one or more embodiments, the DAO product in line 163 can have a DAO concentration of from about 20% wt to about 100% wt, about 40% wt to about 97% wt, or about 50% wt to about 95% wt, with the solvent providing the balance. In one or more embodiments, the specific gravity (API density at 15.6° C.) of the DAO product in line 163 can range from about 5° API to about 30° API, about 5° API to about 20° API, or about 5° API to about 15° API.
  • In one or more embodiments, steam, for example saturated or superheated, can be introduced via line 164 to the stripper 160 to further enhance the separation of the DAO from the solvent. In one or more embodiments, the steam in line 164 can be at a pressure ranging from about 200 kPa to about 2,160 kPa, from about 300 kPa to about 1,475 kPa, or from about 400 kPa to about 1,130 kPa.
  • The one or more strippers 160 can include one or more systems, devices, or combination of systems and/or devices suitable for separating DAO mixture in line 158 to provide the recovered solvent via line 162 and the DAO product via line 163. In one or more embodiments, the one or more strippers 160 can contain one or more internal structures including, but not limited to bubble trays, packing elements such as rings or saddles, structured packing, or combinations thereof. In one or more embodiments, the one or more strippers 160 can be an open column without internals. In one or more embodiments, the one or more strippers 160 can be one or more partially empty columns containing one or more internal structures. In one or more embodiments, the one or more strippers 160 can operate at a temperature of about 15° C. to about 600° C., about 15° C. to about 500° C., or about 15° C. to about 400° C. In one or more embodiments, the pressure in the one or more strippers 160 can operate close to zero pressure, for example at about 0.1 kPa. In one or more embodiments, the one or more strippers 160 can operate at a pressure ranging from a low of about 30 kPa, about 100 kPa, about 500 kPa, or about 1,000 kPa to a high of about 2,500 kPa, about 3,300 kPa, about 4,000 kPa, or about 4,500 kPa.
  • In one or more embodiments, at least a portion of the recovered solvent in lines 132 and 162 can be combined to provide a recycled solvent via line 138. Although not shown, at least a portion of the recovered solvent in line 152 can be combined with at least a portion of the recovered solvent in line 132 and/or at least a portion of the recovered solvent in line 162 to provide the recycled solvent in line 138. In one or more embodiments, the recycled solvent in line 138 can be a two phase mixture containing both liquid and vapor. In one or more embodiments, the temperature of the recycled solvent in line 138 can range from about 30° C. to about 600° C., about 100° C. to about 550° C., or about 300° C. to about 500° C.
  • In one or more embodiments, the recycled solvent in line 138 can be condensed using the one or more condensers 135, to provide a condensed solvent in line 139. In one or more embodiments, the cooled solvent in line 139 can have a temperature ranging from a low of about 10° C., about 20° C., or about 30° C. to a high of about 100° C., about 200° C., about 400° C., or more. The solvent concentration in line 139 can range from a low of about 80% wt, about 85% wt, or about 90% wt to a high of about 95% wt, about 98% wt, about 99% wt, or more.
  • The one or more condensers 135 can include one or more systems, devices, or combination of systems and/or devices suitable for decreasing the temperature of the recycled solvent in line 138 to provide a condensed solvent via line 139. In one or more embodiments, the condenser 135 can include, but is not limited to liquid or air cooled shell-and-tube, plate and frame, fin-fan, and/or spiral wound cooler designs. In one or more embodiments, a cooling medium such as water, refrigerant, air, or combinations thereof can be used to remove the necessary heat from the recycled solvent in line 138. In one or more embodiments, the one or more condensers 135 can operate at a temperature of about −20° C. to about TC,S° C., about −10° C. to about 300° C., or about 0° C. to about 300° C. In one or more embodiments, the one or more condensers 135 can operate close to zero pressure, for example at about 0.1 kPa. In one or more embodiments, the one or more condensers 135 can operate at a pressure of about 30 kPa to about PC,S+700 kPa, or about 100 kPa to about PC,S+500 kPa, or about 100 kPa to about PC,S+300 kPa.
  • In one or more embodiments, at least a portion of the condensed solvent in line 139 can be stored in the one or more reservoirs 140. At least a portion of the solvent in the one or more reservoirs 140 can be recycled via line 186 using one or more pumps 192. The recycled solvent in line 186 can be combined with at least a portion of the recovered solvent in line 152 to provide a solvent recycle via line 177. A first portion of the solvent recycle in line 177 can be recycled to the mixer 110 in the two-stage solvent extraction system 100.
  • A second portion of the solvent in line 177 can be recycled via line 178 to one or more external systems, for example one or more solvent dewatering systems described in detail with reference to FIG. 3. The temperature of the recycled solvent in line 178 can be adjusted by passing an appropriate amount of a heating or cooling medium through one or more heat exchangers 175. In one or more embodiments, the solvent in line 178 or 179, depending upon whether the heat exchanger 175 is used, can have a temperature ranging from a low of about 10° C., about 20° C., or about 30° C. to a high of about 100° C., about 200° C., about 400° C., or more.
  • The one or more heat exchangers 175 can include, but is not limited to liquid or air cooled shell-and-tube, plate and frame, fin-fan, or spiral wound cooler designs. In one or more embodiments, the one or more heat exchangers 175 can operate at a temperature of about −20° C. to about TC,S° C., about −10° C. to about 300° C., or about 0° C. to about 300° C. In one or more embodiments, the one or more condensers 175 can operate can operate close to zero pressure, for example at about 0.1 kPa. In one or more embodiments, the one or more condensers 175 can operate at a pressure of about 30 kPa to about PC,S+700 kPa, or about 100 kPa to about PC,S+500 kPa, or about 100 kPa to about PC,S+300 kPa.
  • In one or more embodiments, the DAO product in line 163 can be introduced to one or more post treatment processes 180 to provide one or more products via line 185. In one or more embodiments, all or a portion of the DAO product in line 163 can be combusted in one or more combustion and/or heat recovery systems 180 to provide heat and/or steam via line 185. In one or more embodiments, the steam produced by combusting the deasphalted oil can be used to provide at least a portion of the thermal energy required in the two-stage separator/solvent extraction system 100, to provide at least a portion of the steam required for stimulation of additional crude hydrocarbons, for example through steam-assisted gravity drainage (“SAGD”) as disclosed in U.S. Pat. Nos. 6,257,334; 5,626,193; 5,318,124; and/or U.S. Patent Publication No.: 2008/0000644, to provide at least a portion of the electrical energy required, for example through the use of one or more steam turbine generators, or any combination thereof.
  • In one or more embodiments, one or more thermal and/or catalytic post-treatment processes 180 can be used to crack, react, or otherwise convert the DAO product in line 163 to provide one or more finished products via line 185. In one or more embodiments, all or a portion of the DAO product in line 163 can be thermally cracked to provide one or more finished products via line 185. Typical, non-limiting, thermal cracking processes are disclosed in U.S. Pat. Nos. 6,547,956; 6,514,403; 6,303,842 and 6,183,627. In one or more embodiments, all or a portion of the DAO product in line 163 can be reacted with hydrogen using one or more hydrotreaters to provide one or more finished products via line 185. Typical, non-limiting, hydrotreatment and/or hydrocracking processes are disclosed in U.S. Pat. Nos. 7,169,291; 7,094,332; 7,048,845; 6,689,273; 6,315,889; 6,312,586; 6,294,080; 6,294,079; 6,235,190; 6,217,746; 6,113,775; 5,985,132; 5,980,732; 5,904,835; 5,888,377; 5,885,440; 5,565,088; 5,385,663; 5,393,409; 5,244,565; 5,171,727; 5,164,070; 5,120,427; 5,114,562; and 5,098,994; 5,026,472 and U.S. Publication Nos.: 2006/0175229; 2006/0118466; 2004/0168956; and 2004/0031725.
  • In one or more embodiments, all or a portion of the DAO product in line 163 can be mixed or otherwise combined with one or more catalysts, for example one or more zeolite catalysts, and cracked using one or more fluidized catalytic cracking (“FCC”) systems 180 to provide one or more light hydrocarbon products via line 185. Typical, non-limiting, FCC treatment processes are disclosed in U.S. Pat. Nos. 6,001,162; 5,601,697; 5,135,640; 4,940,529; 4,359,379 and U.S. Publication Nos.: 2007/0034550 and 2006/0042999.
  • In one or more embodiments, all or a portion of the DAO product in line 163 can be gasified using one or more hydrocarbon gasification systems 180 to provide one or more products, including, but not limited to hydrogen, carbon monoxide, carbon dioxide, mixtures thereof, or any combination thereof via line 185. In one or more embodiments, all or a portion of the DAO product in line 163 can be fractionated using one or more fractionation systems 180 to provide one or more fractionated hydrocarbon products via line 185. In one or more embodiments, all or a portion of the DAO product in line 163 can be selectively separated using one or more visbreaking units 180 to provide one or more products via line 185. In one or more embodiments, all or a portion of the DAO product in line 163 can be desulfurized using one or more desulfurization units 180 to provide one or more low-sulfur and/or ultra low-sulfur products via line 185. In one or more embodiments, all or a portion of the DAO product in line 185 can be hydro-desulfurized using one or more hydro-desulfurization units 180 to provide one or more low-sulfur and/or ultra low-sulfur products via line 185.
  • In one or more embodiments, the asphaltene product in line 133 can be introduced to one or more post treatment processes 190 to provide one or more finished products via line 195. In one or more embodiments, all or a portion of the asphaltene product in line 133 can be combusted in one or more combustion and/or heat recovery systems 190 to provide heat and/or steam via line 195. In one or more embodiments, the steam can be used to provide at least a portion of the thermal energy required in the two-stage separator/solvent extraction system 100, to provide at least a portion of the steam required for stimulation of additional crude hydrocarbons, for example through SAGD, to provide at least a portion of the electrical energy required, for example through the use of one or more steam turbine generators, or any combination thereof.
  • In one or more embodiments, all or a portion of the asphaltene product in line 133 can be introduced to one or more treatment processes 190 to provide one or more finished products via line 195. In one or more embodiments, the treatment process 190 can include pelletizing all or a portion of the asphaltenes present in the asphaltene product in line 133. Various pelletization processes are described in U.S. Pat. Nos. 7,101,499; 6,499,979; 6,361,682; 6,331,245; 4,931,231 and 3,847,751. In one or more embodiments, at least a portion of the asphaltene product introduced via line 133 to the treatment process 190 can be used to produce one or more hydrocarbon based catalysts via line 195. Various processes for the production of one or more hydrocarbon catalysts are disclosed in U.S. Pat. Nos. 5,288,681 and 5,171,727. In one or more embodiments, at least a portion of the asphaltene product introduced via line 133 to the treatment process 190 can be used to produce one or more asphalt based building products. A process for the production of asphalt building products is disclosed in U.S. Pat. No. 6,899,839. In one or more embodiments, at least a portion of the asphaltene product introduced to the treatment process 190 can be gasified to produce hydrogen, carbon monoxide, carbon dioxide, or any combination thereof via line 195. A process for the gasification of an asphaltenic hydrocarbon is disclosed in U.S. Pat. No. 6,773,630. In one or more embodiments, at least a portion of the asphaltene product introduced via line 133 to the treatment process 190 can be converted to provide one or more olefinic hydrocarbons via line 195. A process for the conversion of an asphaltenic hydrocarbon to olefinic hydrocarbons is disclosed in U.S. Pat. No. 6,303,842. In one or more embodiments, at least a portion of the asphaltene product introduced via line 133 to the treatment process 190 can be catalytically converted to provide one or more lighter hydrocarbons via line 195 using an FCC. A process for the catalytic conversion of an asphaltenic hydrocarbon to lighter hydrocarbons in an FCC is disclosed in U.S. Pat. No. 5,328,591.
  • FIG. 2 depicts an illustrative three-stage separator/solvent extraction system 200 according to one or more embodiments. In addition to the system 200 shown and described above with reference to FIG. 1, the extraction system 200 can further include one or more separators 270 and strippers 280 for the selective separation of the DAO mixture in line 122 into a heavy deasphalted oil (“H-DAO”) product via line 205 and a light deasphalted oil (“L-DAO”) product via line 288. In one or more embodiments, the extraction system 200 can include one or more heat exchangers (two are shown 215, 225). The hydrocarbon in line 105 can be as discussed and described above with reference to FIG. 1.
  • In one or more embodiments, the temperature of the DAO mixture in line 122 can be increased using one or more heat exchangers 145 to provide a heated DAO mixture via line 124. In one or more embodiments, the temperature of the heated DAO mixture in line 124 can be less than the critical temperature (“TC,S”) of the solvent introduced via line 177 to the hydrocarbon. In one or more embodiments, the temperature of the heated DAO mixture in line 124 can be at or above the critical temperature of the solvent introduced via line 177 to the hydrocarbon.
  • In one or more embodiments, the temperature of the heated DAO mixture in line 124 can be at or above the critical temperature of the solvent using the one or more heaters 145. Increasing the temperature of the heated DAO mixture in line 124 above the critical temperature of the solvent can promote the separation of the DAO mixture into two distinct phases, a L-DAO phase containing essentially L-DAO and a H-DAO phase containing essentially H-DAO. In one or more embodiments, the temperature of the heated DAO in line 124 can range from about 15° C. to about TC,S+150° C., about 15° C. to about TC,S+100° C., or about 15° C. to about TC,S+50° C.
  • The heated DAO mixture in line 124 can be and introduced to the one or more separators 150 wherein the L-DAO and H-DAO phases can separate to provide a L-DAO phase containing L-DAO and at least a portion of the solvent, and a H-DAO phase containing H-DAO and the balance of the solvent. In one or more embodiments, the L-DAO phase can be recovered from the separator 150 via line 210. In one or more embodiments, the H-DAO phase can be recovered from the separator 150 via line 158.
  • The L-DAO phase in line 210 can have an L-DAO concentration ranging from a low of about 1% wt, about 5% wt, or about 10% wt to a high of about 30% wt, about 40% wt, about 50% wt, or more. In one or more embodiments, the L-DAO phase in line 210 can have a solvent concentration ranging from a low of about 50% wt, about 60% wt, or about 70% wt to a high of about 90% wt, about 95% wt, or about 99% wt. In one or more embodiments, the L-DAO phase in line 210 can have an H-DAO concentration of about 20% wt or less, about 15% wt or less, about 10% wt or less, about 5% wt or less, about 1% wt or less.
  • The H-DAO phase in line 158 can have an H-DAO concentration ranging from a low of about 10% wt, about 25% wt, or about 40% wt to a high of about 70% wt, about 80% wt, about 90% wt, or more. The H-DAO phase in line 158 can have a solvent concentration ranging from a low of about 10% wt, about 20% wt, or about 30% wt to a high of about 60% wt, about 75% wt, or about 90% wt. In one or more embodiments, the H-DAO phase in line 158 can have a L-DAO concentration of about 20% wt or less, about 15% wt or less, about 10% wt or less, about 5% wt or less, about 1% wt or less.
  • The one or more separators 150 can include one or more systems, devices, or combination of systems and/or devices suitable for separating the heated DAO in line 124 to provide a L-DAO phase in line 210 and a H-DAO phase in line 158. In one or more embodiments, the one or more separators 150 can contain one or more internal structures including, but not limited to bubble trays, packing elements such as rings or saddles, structured packing, or combinations thereof. In one or more embodiments, the one or more separators 150 can be an open column without internals. In one or more embodiments, the one or more separators 150 can be one or more partially empty columns containing one or more internal structures. In one or more embodiments, the one or more separators 150 can be a partially or completely open column without internals. In one or more embodiments, the one or more separators 150 can have an operating temperature of from about 15° C. to about TC,S+150° C., about 15° C. to about TC,S+100° C., or about 15° C. to about TC,S+50° C. In one or more embodiments, the one or more separators 150 can have an operating pressure of from about 100 kPa to about PC,S+2,100 kPa, about PC,S−700 kPa to about PC,S+1,500 kPa, or about PC,S−300 kPa to about PC,S+700 kPa.
  • The H-DAO phase via line 158 can be introduced into the one or more strippers 160 and selectively separated therein to provide a recovered solvent via line 162 and H-DAO (“H-DAO product”) via line 205. In one or more embodiments, steam, for example saturated or superheated, can be introduced via line 164 to the stripper 160 to further enhance the separation of the H-DAO from the solvent. In one or more embodiments, the recovered solvent in line 162 can have a solvent concentration ranging from a low of about 50% wt, about 70% wt, or about 80% wt to a high of about 90% wt, about 95% wt, about 99% wt, or more, with the balance being H-DAO. In one or more embodiments, the H-DAO in line 205 can have an H-DAO concentration ranging from a low of about 20% wt, about 40% wt, or about 50% wt to a high of about 80% wt, about 90% wt, about 95% wt, or more, with the balance being the solvent and/or L-DAO. In one or more embodiments, the H-DAO in line 205 can have a specific gravity (API density@15.6° C.) ranging from a low of about 5°, about 7°, or about 10° to a high of about 20°, about 25°, about 30°, or more.
  • The one or more strippers 160 can include one or more systems, devices, or combination of systems and/or devices suitable for separating the H-DAO phase in line 158 to provide the recovered solvent via line 162 and the H-DAO via line 205. In one or more embodiments, the one or more strippers 160 can contain one or more internal structures including, but not limited to bubble trays, packing elements such as rings or saddles, structured packing, or combinations thereof. In one or more embodiments, the one or more strippers 160 can be an open column without internals. In one or more embodiments, the one or more strippers 160 can be one or more partially empty columns containing one or more internal structures. In one or more embodiments, the one or more strippers 160 can be a partially or completely open column without internals. In one or more embodiments, the one or more strippers 160 can have an operating temperature of from about 15° C. to about 600° C., about 15° C. to about 500° C., or about 15° C. to about 400° C. In one or more embodiments, the one or more strippers 160 can operate can operate close to zero pressure, for example at about 0.1 kPa. In one or more embodiments, the one or more strippers 160 can have an operating pressure of from about 100 kPa to about 4,000 kPa, about 500 kPa to about 3,300 kPa, or about 1,000 kPa to about 2,500 kPa.
  • Referring again to the one or more separators 150, in one or more embodiments, the L-DAO phase via line 210 can be heated using one or more heat exchangers (two are shown 215, 225) to provide a heated L-DAO in line 230. In one or more embodiments, the heated L-DAO in line 230 can be at a temperature of from about 15° C. to about TC,S+150° C., about 15° C. to about TC,S+100° C., or about 15° C. to about TC,S+50° C. In one or more embodiments, a recovered solvent in line 272 can be introduced in series or in parallel to the one or more heat exchangers 215, 225 to provide the heated L-DAO in line 230 and a cooled recovered solvent via line 274.
  • In one or more embodiments, the one or more heat exchangers 215 and 225 can have an operating temperature of from about 15° C. to about TC,S+150° C., about 15° C. to about TC,S+100° C., or about 15° C. to about TC,S+50° C. In one or more embodiments, the one or more heat exchangers 215 and 225 can have an operating pressure of from about 100 kPa to about PC,S+2,100 kPa, about 100 kPa to about PC,S+1,500 kPa, or about 100 kPa to about PC,S+700 kPa.
  • In one or more embodiments, the heated L-DAO in line 230 can be introduced to the one or more separators 270 and selectively separated therein to provide the recovered solvent via line 272 and L-DAO via line 278. The recovered solvent in line 272 can have a solvent concentration ranging from a low of about 50% wt, about 70% wt, or about 85% wt to a high of about 90% wt, about 95% wt, about 99% wt, or more, with the balance being L-DAO. In one or more embodiments, the L-DAO in line 278 can have an L-DAO concentration ranging from a low of about 20% wt, about 20% wt, or about 40% wt to a high of about 70% wt, about 80% wt, about 90% wt, or more, with the balance being the solvent.
  • The one or more separators 270 can include one or more systems, devices, or combination of systems and/or devices suitable for separating the heated L-DAO phase in line 230 to provide the recovered solvent via line 272 and the L-DAO via line 278. In one or more embodiments, the separator 270 can include one or more multi-staged extractors having alternate segmental baffle trays, packing, structured packing, perforated trays, and combinations thereof. In one or more embodiments, the separator 270 can be a partially or completely open column without internals. In one or more embodiments, the one or more separators 270 can have an operating temperature of from about 15° C. to about TC,S+150° C., about 15° C. to about TC,S+150° C., or about 15° C. to about TC,S+50° C. In one or more embodiments, the one or more separators 270 can have an operating pressure of from about 100 kPa to about PC,S+700 kPa, about PC,S−700 kPa to about PC,S+700 kPa, or about PC,S−300 kPa to about PC,S+300 kPa.
  • In one or more embodiments, the L-DAO in line 278 can be introduced to the one or more strippers 280 and selectively separated therein to provide a recovered solvent via line 282 and an L-DAO product via line 288. In one or more embodiments, steam, for example saturated or superheated, can be introduced via line 284 to the stripper 280 to further enhance the separation of the L-DAO from the solvent. In one or more embodiments, the recovered solvent in line 282 can have a solvent concentration ranging from a low of about 50% wt, about 70% wt, or about 85% wt to a high of about 90% wt, about 95% wt, about 99% wt or more, with the balance being L-DAO. In one or more embodiments, the L-DAO product in line 288 can have an L-DAO concentration ranging from a low of about 30% wt, about 40% wt, or about 50% wt to a high of about 85% wt, about 90% wt, about 95% wt, or more, with the balance being the solvent and/or H-DAO. In one or more embodiments, the light deasphalted product in line 288 can have an L-DAO concentration of about 97% wt or more, about 95% wt or more, about 99% wt or more. In one or more embodiments, the L-DAO product in line 288 can have a specific gravity (API density@15.6° C.) ranging from a low of about 10°, about 20°, or about 25° to a high of about 35°, about 45°, about 60°, or more.
  • The one or more strippers 280 can include one or more systems, devices, or combination of systems and/or devices suitable for separating L-DAO in line 278 to provide the recovered solvent via line 282 and the L-DAO product via line 288. In one or more embodiments, the one or more strippers 280 can contain one or more internal structures including, but not limited to bubble trays, packing elements such as rings or saddles, structured packing, or combinations thereof. In one or more embodiments, the one or more strippers 280 can be an open column without internals. In one or more embodiments, the one or more strippers 280 can be one or more partially empty columns containing one or more internal structures. In one or more embodiments, the one or more strippers 280 can operate at a temperature of about 15° C. to about 600° C., about 15° C. to about 500° C., or about 15° C. to about 400° C. In one or more embodiments, the one or more strippers 280 can operate can operate close to zero pressure, for example at about 0.1 kPa. In one or more embodiments, the one or more strippers 280 can have an operating pressure of from about 30 kPa to about 4,000 kPa, about 500 kPa to about 3,300 kPa, or about 1,000 kPa to about 2,500 kPa.
  • In one or more embodiments, at least a portion of the solvent in line 132, 162, and/or 282 can be combined to provide a combined solvent in line 138. Although not shown, in or more embodiments at least a portion of the recovered solvent in line 272 can be combined with at least a portion of the recovered solvent in line 132, 162, and/or 282 to provide the combined solvent in line 138. In one or more embodiments, the solvent in line 138 can be present as a two phase liquid/vapor mixture. In one or more embodiments, the combined solvent overhead in line 138 can have a temperature ranging from a low of about 30° C., about 100° C., or about 200° C. to a high of about 400° C., about 500° C., about 600° C., or more.
  • In one or more embodiments, the combined solvent in line 138 can be partially or completely condensed using one or more condensers 135 to provide a condensed solvent via line 139. In one or more embodiments, the condensed solvent in line 139 can have a temperature ranging from a low of about 10° C., about 20° C., or about 30° C. to a high of about 100° C., about 200° C., about 400° C., or more. In one or more embodiments, the condensed solvent in line 139 can have a solvent concentration ranging from a low of about 80% wt, about 85% wt, or about 90% wt to a high of about 95% wt, about 97% wt, about 99% wt, or more.
  • The one or more condensers 135 can include one or more systems, devices, or combination of systems and/or devices suitable for decreasing the temperature of the solvent in line 138. In one or more embodiments, condenser 135 can include, but is not limited to liquid or air cooled shell-and-tube, plate and frame, fin-fan, or spiral wound cooler designs. In one or more embodiments, a cooling medium such as water, refrigerant, air, or combinations thereof can be used to remove the necessary heat from the solvent in line 138. In one or more embodiments, the one or more condensers 135 can have an operating temperature of from about −20° C. to about TC,S° C., about −10° C. to about 300° C., or about 0° C. to about 300° C. In one or more embodiments, the one or more condensers 135 can operate can operate close to zero pressure, for example at about 0.1 kPa. In one or more embodiments, the one or more condensers 135 can have an operating pressure of from about 100 kPa to about PC,S+700 kPa, about 100 kPa to about PC,S+500 kPa, or about 100 kPa to about PC,S+300 kPa.
  • In one or more embodiments the condensed solvent in line 139 can be stored or accumulated in one or more reservoirs 140. In one or more embodiments, the solvent in the reservoir 140 can be transferred using one or more solvent pumps 192 and recycle lines 186. Recycling at least a portion of the solvent to either the solvent deasphalting process 200 can decrease the quantity of fresh solvent make-up required. In one or more embodiments, all or a portion of the solvent in the one or more reservoirs can be transferred via line 135 to one or more systems, for example a solvent dewatering system as discussed in greater detail with respect to FIG. 3.
  • Referring again to the one or more separators 270, in one or more embodiments, at least a portion of the recovered solvent in line 272 can be cooled using one or more heat exchangers 145 and 215 to provide a cooled solvent in line 274. In one or more embodiments, about 1% wt to about 95% wt, about 5% wt to about 55% wt, or about 1% wt to about 25% wt of the solvent in line 272 can be cooled using one or more heat exchangers 215 and 145. In one or more embodiments, the solvent in line 274 can be at a temperature of from about 25° C. to about 400° C., about 50° C. to about 300° C., or about 100° C. to about 250° C. In one or more embodiments, at least a portion of the cooled solvent in line 274 can be combined with at least a portion of the recycled solvent in line 186 for recycle to the one or more mixers 110 via line 177. In one or more embodiments, all or a portion of the solvent in line 177 can be introduced to one or more external systems via line 279.
  • In one or more embodiments, the L-DAO product in line 288 can be introduced to one or more post treatment processes 270 to provide one or more products via line 275. In one or more embodiments, the H-DAO product in line 205 can be introduced to one or more post treatment processes 250 to provide one or more products via line 255. For clarity, conciseness, and ease of description, the treatment processes 270 will be described below with reference to the L-DAO product in line 288 as the hydrocarbon. It should be understood that any one or more of the post-treatment processes 270 described below can provide an equally effective process for post treatment processing of the H-DAO product in line 205 via post-treatment system 250.
  • In one or more embodiments, all or a portion of the L-DAO product can be combusted using one or more combustion and/or heat recovery systems 270 to provide heat and/or steam via line 275. In one or more embodiments, the steam produced by combusting the L-DAO product can be used to provide at least a portion of the thermal energy required in the three-stage separator/solvent extraction system 200, to provide at least a portion of the steam required for stimulation of additional crude hydrocarbons, for example through SAGD, to provide at least a portion of the electrical energy required, for example through the use of one or more steam turbine generators, or any combination thereof.
  • In one or more embodiments, one or more thermal and/or catalytic post-treatment processes 270 can be used to crack, react, or otherwise convert the L-DAO product in line 288 to one or more finished products via line 275. In one or more embodiments, all or a portion of the L-DAO product in line 288 can be thermally cracked to provide one or more finished products via line 275. In one or more embodiments, all or a portion of the L-DAO product in line 288 can be reacted with hydrogen using one or more hydrotreaters to provide one or more finished products via line 275.
  • In one or more embodiments, all or a portion of the L-DAO product in line 288 can be mixed or otherwise combined with one or more catalysts, for example one or more zeolite catalysts, and cracked using one or more fluidized catalytic cracking systems 270 to provide one or more light hydrocarbon products via line 275. In one or more embodiments, all or a portion of the L-DAO product in line 288 can be gasified using one or more hydrocarbon gasification systems 270 to provide one or more products, including, but not limited to hydrogen, carbon monoxide, carbon dioxide, mixtures thereof, or any combination thereof via line 275. In one or more embodiments, all or a portion of the L-DAO product in line 288 can be fractionated using one or more fractionation systems 270 to provide one or more fractionated hydrocarbon products via line 275. In one or more embodiments, all or a portion of the L-DAO product in line 288 can be selectively separated using one or more visbreaking units 270 to provide one or more products via line 275. In one or more embodiments, all or a portion of the L-DAO product in line 288 can be desulfurized using one or more desulfurization units 270 to provide one or more low-sulfur and/or ultra low-sulfur products via line 275. In one or more embodiments, all or a portion of the L-DAO product in line 288 can be hydro-desulfurized using one or more hydro-desulfurization units 270 to provide one or more low-sulfur and/or ultra low-sulfur products via line 275.
  • In one or more embodiments, the asphaltene product in line 233 can be introduced to one or more post treatment processes 290 to provide one or more finished products via line 295. In one or more embodiments, all or a portion of the asphaltene product in line 233 can be combusted to provide heat and/or steam. In one or more embodiments, the steam can be used to provide at least a portion of the thermal energy required in the three-stage separator/solvent extraction system 200, to provide at least a portion of the steam required for stimulation of additional crude hydrocarbons, for example through SAGD, to provide at least a portion of the electrical energy required, for example through the use of one or more steam turbine generators, or any combination thereof.
  • In one or more embodiments, all or a portion of the asphaltene product in line 233 can be introduced to one or more treatment processes 290 to provide one or more finished products via line 295. In one or more embodiments, the treatment process 290 can include pelletizing all or a portion of the asphaltenes present in the asphaltene product in line 233. In one or more embodiments, at least a portion of the asphaltene product introduced via line 233 to the treatment process 290 can be used to produce one or more hydrocarbon based catalysts via line 295. In one or more embodiments, at least a portion of the asphaltene product introduced via line 233 to the treatment process 290 can be used to produce one or more asphalt based building products via line 295. In one or more embodiments, at least a portion of the asphaltene product introduced via line 233 to the treatment process 290 can be gasified to produce hydrogen, carbon monoxide, carbon dioxide, or any combination thereof via line 295. In one or more embodiments, at least a portion of the asphaltene product introduced via line 233 to the treatment process 290 can be converted into one or more olefinic hydrocarbons via line 295. In one or more embodiments, at least a portion of the asphaltene product introduced via line 233 to the treatment process 290 can be catalytically converted into one or more lighter hydrocarbons via line 295 using a fluidized catalytic cracker.
  • FIG. 3 depicts an illustrative solvent dewatering system integrated with one or more separator/solvent extraction systems 100, 200, according to one or more embodiments. The hydrocarbon treatment system 300 can include one or more contactors 310, one or more separators 320, and one or more solvent extraction systems 100, 200. A hydrocarbon that can contain water can be introduced via line 305 to the one or more contactors 310. In one or more embodiments, solvent via line 179 from the separator/solvent extraction system 100 and/or solvent via line 279 from the separator/solvent extraction system 200 can be introduced via line 303 to the contactor 310 to provide a solvent/hydrocarbon mixture. In one or more embodiments solvent via line 301 can be introduced in place of or in addition to solvent from either line 279 and/or 179.
  • The hydrocarbon in line 305 can be or include, but are not limited to whole crude oil, crude oil, oil shales, oil sands, tars, bitumens, combinations thereof, derivatives thereof, or mixtures thereof. In one or more embodiments, the hydrocarbon in line 305 can include one or more particulate components, such as carbon or coke, ash, clays, inorganic compounds, metals, metal oxides, such as SiO2, Al2O3, and the oxides and oxysulfides of metals such as Fe and Ca. These particulate components may originate from the producing formation as sand or clays or may have been picked up by the high viscosity oil during transportation and processing. Residual oils or oils having prior treatment may also contain residual catalyst fines. Such catalysts typically comprise metals of the group VIA or the group VIII of the Periodic Table supported on a supporter comprising an iron-containing aluminosilicate and inorganic oxides.
  • The hydrocarbon in line 305 can include one or more inert materials, water, gases, and the like. In one or more embodiments, the hydrocarbon in line 305 can be a mixture containing one or more hydrocarbons having an API specific gravity (API@15.6° C.—ASTM D4052) of about 35° or less, about 30° or less, about 25° or less, or about 20° or less. In one or more embodiments, the hydrocarbon in line 305 can have an API specific gravity (API@15.6° C.—ASTM D4052) of from about 6° to about 25°, about 7° to about 23°, about 8° to about 19°, or about 8° to about 15°. In one or more embodiments, the hydrocarbon in line 305 can be or include one or more hydrocarbons having a normal, atmospheric, boiling point of less than about 1,090° C., less than about 1,000° C., less than about 900° C., less than about 800° C., less than about 700° C., or less.
  • In one or more embodiments, the hydrocarbon in line 305 can have an asphaltene concentration of about 5% wt or more, about 10% wt or more, about 15% wt or more, about 20% wt or more, about 25% wt or more, or about 30% wt or more. In one or more embodiments, the hydrocarbon in line 305 can include a mixture of inert material and hydrocarbons, for example a tar sand containing bitumen combined with one or more inert materials. In one or more embodiments, the hydrocarbon in line 305 can include about 5% vol to about 25% vol naphthenes, or from about 10% vol to about 20% vol naphthenes, or from about 13% vol to about 18% vol naphthenes. The hydrocarbon in line 305 can include about 5% vol to about 25% vol aromatic hydrocarbons, or from about 10% vol to about 20% vol aromatic hydrocarbons, or from about 13% vol to about 18% vol aromatic hydrocarbons. The hydrocarbon in line 305 can include about 50% vol to about 85% vol paraffins, or from about 60% vol to about 75% vol paraffins, or from about 63% vol to about 70% vol paraffins. The hydrocarbon in line 305 can include from about 25 ppmw to about 400 ppmw or more nickel and from about 200 ppmw to about 1,000 ppmw or more vanadium.
  • In one or more embodiments, the one or more inert materials can include, but are not limited to sands, clays, silt, mud, or any combination thereof. In one or more embodiments, the concentration of inert materials can range from a low of about 1% wt, about 2% wt, about 5% wt, or about 10% wt to a high of about 35% wt, about 40% wt, about 50% wt, or about 70% wt. In one or more embodiments, the hydrocarbon in line 305 can include one or more tar sands saturated with a relatively heavy, viscous bitumen in quantities ranging from a low of about 1% wt, about 5% wt, or about 10% wt to a high of about 20% wt, about 25% wt, or about 30% wt. The bitumen can have a sulfur content of about 2% wt, about 3% wt, about 4% wt, about 5% wt, or about 6% wt. In one or more embodiments, the bitumen can have an aromatics content of about 20% wt, about 25% wt, about 30% wt, about 35% wt, or about 40% wt.
  • The contactor 310 can include any system, device, or combination of systems and/or devices suitable for mixing or otherwise combining the solvent introduced via line 303 with the hydrocarbon introduced via line 305. In one or more embodiments, the one or more contactors 310 can contain internals such as rings, saddles, structured packing, balls, irregular sheets, tubes, spirals, trays, baffles, or any combinations thereof. In one or more embodiments, the contactor 310 can be a partially or completely open column without internals. In one or more embodiments, the one or more contactors 310 can include but are not limited to ejectors, inline static mixers, inline mechanical/power mixers, homogenizers, or combinations thereof. In one or more embodiments, the one or more contactors 310 can have an operating temperature of from about 0° C. to about 95° C., about 5° C. to about 80° C., or about 10° C. to about 70° C. In one or more embodiments, the one or more contactors 310 can have an operating pressure of from about 100 kPa to about 1,150 kPa, about 200 kPa to about 1,000 kPa, or about 500 kPa to about 800 kPa.
  • The mixing or combining of the solvent in line 303 and the hydrocarbon in line 305 permits the separation of water contained in the hydrocarbon to separate, forming a plurality of discrete hydrocarbon and aqueous phases. Any solvent that can differentiate the density of the oil and water to facilitate a phase separation therebetween can be used. Suitable solvents can include, but are not limited to aliphatic hydrocarbons, cycloaliphatic hydrocarbons, and aromatic hydrocarbons, and mixtures thereof. In one or more embodiments, the solvent can include propane, butane, pentane, benzene, or mixtures thereof. In one or more embodiments, the solvent can include at least 90% wt, at least 95% wt, or at least 99% wt of one or more hydrocarbons having a normal boiling point below 538° C. In one or more embodiments, the solvent can include one or more gas condensates having a boiling range of about 27° C. to about 121° C., one or more light naphthas having a boiling range of about 32° C. to about 82° C., one or more heavy naphthas having a boiling range of about 82° C. to about 221° C., or mixtures thereof. In one or more embodiments, the solvent can have a critical temperature of about 90° C. to about 538° C., about 90° C. to about 400° C., or about 90° C. to about 300° C. In one or more embodiments, the solvent can have a critical pressure of about 2,000 kPa to about 6,000 kPa, about 2,300 kPa to about 5,800 kPa, or about 2,600 kPa to about 5,600 kPa.
  • The solvent and hydrocarbon mixture can be recovered via line 315 from the one or more contactors 310 and can be introduced to the one or more separators 320. The separator 320 can be one or more systems, devices, or combination of systems and/or devices suitable for selectively separating the aqueous and hydrocarbon phases formed by combining the solvent with the hydrocarbon in the contactor 310. For example, the separator 320 can be or include any one or more gravity separators and coalescer-assisted separators. In one or more embodiments, chemical-assisted and/or plate assisted separators can be used. In one or more embodiments, the solvent and hydrocarbon mixture in line 315 can be heated and/or cooled to further differentiate the specific gravity of the hydrocarbon and aqueous phases to improve the overall separation efficiency within the separator 320.
  • Within the one or more separators 320, the density difference between the hydrocarbon and aqueous phases can permit a phase separation to occur. In one or more embodiments, the phase separation can be gravity based. In one or more embodiments, the phase separation can be mechanically assisted, for example through centrifugal and/or cyclonic separation. Although not shown, the aqueous phase recovered from the separator 320 via line 327 can be further processed and/or treated to remove entrained hydrocarbons and other contaminants prior to recycle, reuse, and/or disposal. The hydrocarbon can be recovered via line 105 from the one or more separators 320. The hydrocarbon in line 105 can be as discussed and described above with reference to FIGS. 1 and 2.
  • In one or more embodiments, the hydrocarbon in line 105 can be selectively separated within the two-stage separator/solvent extraction system 100 to provide the asphaltene product via line 133 and the DAO product via line 163 as discussed and described above with reference to FIG. 1. In one or more embodiments, the hydrocarbon in line 105 can be selectively separated within the three-stage separator/solvent extraction system 200 to provide the asphaltene product via line 233, the H-DAO product via line 205 and the L-DAO product via line 288. In one or more embodiments, all or a portion of the solvent recovered from the extraction unit 100, 200 can be recycled to the contactor 310 via lines 179, 279, respectively. In one or more embodiments, the one or more two-stage and/or three-stage solvent extraction systems 100, 200 can operate at sub-critical, critical, or supercritical temperatures and/or pressures with respect to the solvent to permit separation of the asphaltenes from the hydrocarbon phase in line 105. In one or more embodiments, the asphaltene product provided via line 133 and or 233, the DAO product via line 163, the H-DAO product via line 205, and/or the L-DAO product via line 288 can be further processed as discussed and described above with reference to FIGS. 1 and 2.
  • FIG. 4 depicts an illustrative flash evaporation system integrated with one or more separator/solvent extraction systems 100, 200, according to one or more embodiments. In one or more embodiments, the hydrocarbon treatment system 400 can include one or more heaters 410, one or more pressure control devices 430, one or more evaporators 450, and one or more separator/solvent extraction systems 100, 200. In one or more embodiments, a hydrocarbon mixture containing one or more hydrocarbons and asphaltenes, can be introduced via line 405 to the one or more heaters 410. The hydrocarbon in line 405 can be as similar to the hydrocarbon in line 105 and/or 305 discussed and described above with reference to FIGS. 1-3.
  • In one or more embodiments, the temperature of the hydrocarbon in line 405 can range from a low of about 0° C., about 10° C., about 30° C., about 50° C., or about 75° C. to a high of about 80° C., about 100° C., about 120° C., or about 150° C. In one or more embodiments the pressure of the hydrocarbon in line 305 can range from a low of about 150 kPa, about 300 kPa, about 450 kPa, or about 600 kPa to a high of about 750 kPa, about 900 kPa, about 1,050 kPa, or about 1,200 kPa.
  • Passage of the hydrocarbon through the one or more heaters 410 can increase the temperature of the hydrocarbon by about 50° C., about 100° C., about 200° C., about 300° C., or more. The heated hydrocarbon can exit the one or more heaters 410 via line 415. In one or more embodiments, the temperature of the heated hydrocarbon in line 415 can range from a low of about 50° C., about 60° C., about 80° C., about 100° C., or about 125° C. to a high of about 380° C., about 400° C., about 420° C., or about 450° C. In one or more embodiments, the heating of the hydrocarbon in the one or more heaters 410 can vaporize at least a portion of one or more light hydrocarbons contained in the hydrocarbon. The vaporization of at least a portion of the one or more light hydrocarbons can increase the pressure of the heated hydrocarbon in line 415. In one or more embodiments, the pressure of the one or more heated hydrocarbon in line 415 can range from a low of about 350 kPa, about 500 kPa, about 650 kPa, or about 800 kPa to a high of about 1,150 kPa, about 1,300 kPa, about 1,450 kPa, or about 1,600 kPa.
  • The one or more heaters 410 can include any system, device or combination of systems and/or devices suitable for heating a high viscosity, hydrocarbon containing asphaltenes. In one or more embodiments, the one or more heaters 410 can include one or more direct fired heaters. In one or more embodiments, the one or more heaters 410 can include one or more non-contact heaters including, but not limited to one or more plate and frame heat exchangers, one or more spiral wound heat exchangers, one or more shell and tube heat exchangers, or any combination thereof. In one or more embodiments, a hot fluid can be passed through the non-contact heater to warm the crude hydrocarbon therein. Suitable hot fluids can include, but are not limited to heat transfer fluids, such as Radtherm® and Dowtherm® heat transfer fluids, hot process fluids, hot waste fluids, such as furnace effluents or combustion exhausts. In one or more embodiments, the one or more heaters 410 can include one or more contact heaters in which one or more high temperature fluids are mixed or otherwise combined with the hydrocarbon to increase the bulk temperature of the mixture. In one or more embodiments, the one or more heaters 410 can include one or more direct fired heaters, one or more contact heat exchangers, and/or one or more non-contact heat exchangers in any combination and/or frequency.
  • The heated hydrocarbon in line 415 can flow through the one or more pressure control devices 430 to provide a hydrocarbon in line 435 having a reduced and/or increased pressure. In one or more embodiments, the hydrocarbon in line 435 can be introduced to the one or more separators 450. The one or more separators 450 can be maintained at a pressure less than the pressure of the crude hydrocarbons within line 415. In one or more embodiments, the pressure differential between the pressure within the separators 450 and the pressure within line 415 can be about 150 kPa, about 200 kPa, about 400 kPa, about 800 kPa, or more. In one or more embodiments, the operating pressure of the one or more separators 450 can range from a low of about 50 kPa, about 250 kPa, about 400 kPa, or about 600 kPa to a high of about 750 kPa, about 900 kPa, about 1,050 kPa, or about 1,200 kPa. Introducing the heated hydrocarbon to the reduced pressure environment of the one or more separators 450 the vaporized light hydrocarbon can volatilize and “flash” from the heated hydrocarbon within the separator 450. In one or more embodiments, the flashed light hydrocarbon can be recovered via line 460 from the one or more separators 450. The residual hydrocarbons can be recovered from the one or more separators 450 via line 105.
  • In one or more embodiments, the vaporized light hydrocarbon recovered via line 460 from the one or more separators 450 can include C1-C20 hydrocarbons. For example, the vaporized light hydrocarbons recovered via line 460 from the one or more separators 450 can include, but are not limited to one or more C1 to C8 alkanes, one or more C1 to C8 alkenes, C1 to C8 alkynes, one or more naphthas, one or more aromatics, mixtures thereof, derivatives thereof, or any combination thereof. The pressure of the vaporized light hydrocarbon in line 460 can range from a low of about 50 kPa, about 100 kPa, about 400 kPa, or about 600 kPa to a high of about 750 kPa, about 900 kPa, about 1,050 kPa, or about 1,200 kPa. In one or more embodiments, the temperature of the vaporized light hydrocarbon in line 460 can range from a low of about 25° C., about 40° C., about 50° C., about 70° C., or about 90° C. to a high of about 200° C., about 250° C., about 300° C., or about 350° C. In one or more embodiments, the vaporized light hydrocarbon in line 460 can be further reacted, converted, fractionated and/or separated into one or more finished products.
  • In one or more embodiments, the hydrocarbon in line 105 can be selectively separated within the two-stage separator/solvent extraction system 100 to provide the asphaltene product via line 133 and the DAO product via line 163, as discussed and described above with reference to FIG. 1. In one or more embodiments, the hydrocarbon in line 105 can be selectively separated within the three-stage separator/solvent extraction system 200 to provide the asphaltene product via line 233, the H-DAO product via line 205 and the L-DAO product via line 288, as discussed and described above with reference to FIG. 2.
  • The pressure of the residual hydrocarbons in line 105 can range from a low of about 150 kPa, about 250 kPa, about 400 kPa, or about 600 kPa to a high of about 750 kPa, about 900 kPa, about 1,050 kPa, or about 1,200 kPa. The temperature of the residual hydrocarbons in line 105 can be lower than the temperature of the hydrocarbon in line 415 due to the evaporative cooling which occurs within the one or more separators 450. In one or more embodiments, the temperature of the residual hydrocarbon in line 105 can range from a low of about 25° C., about 40° C., about 50° C., about 70° C., or about 90° C. to a high of about 200° C., about 250° C., about 300° C., or about 350° C.
  • FIG. 5 depicts an illustrative distillation system integrated with one or more separator/solvent extraction systems 100, 200, according to one or more embodiments. The hydrocarbon treatment system 500 can include one or more topping towers 510, one or more distillation units 530, and one or more separator/solvent extraction systems 100, 200. In one or more embodiments the one or more distillation units 530 can include one or more atmospheric distillation units, one or more vacuum distillation units, or any combination thereof. In one or more embodiments, a hydrocarbon, which can be as discussed and described above with reference to FIG. 3 can be introduced via line 305 to the one or more topping towers 510.
  • The topping tower 510 can separate the hydrocarbon into a naphtha product via line 520 and a residue via line 515. In one or more embodiments, the naphtha product via line 520 can be introduced to a hydrotreater (not shown) to provide a hydrotreated naphtha product. The hydrotreated naphtha product can be introduced to one or more reformers to provide a reformed naphtha product. The reformed naphtha product can be introduced to the one or more Benzene, Toluene, Xylene (“BTX”) units (not shown) to provide a BTX product.
  • In one or more embodiments, the residue via line 515 can be introduced to the one or more distillation units 530 to provide a distillate or light distillate via line 535, a gas oil or heavy distillate via line 540, and a hydrocarbon via line 105. The hydrocarbon in line 105 can be as discussed and described above with reference to FIGS. 1 and 2. In one or more embodiments, the light distillate in line 535 can have a boiling point of about 296° C. or less, about 285° C. or less, or about 274° C. or less. In one or more embodiments, the gas oil in line 540 can have a boiling point of about 274° C. or more, about 285° C. or more, or about 296° C. or more. In one or more embodiments, the residue in line 105 can have a boiling point of about 343° C. or more, about 358° C. or more, or about 374° C. or more.
  • In one or more embodiments, the one or more distillation units 530 can be designed to process about 100,000 BPSD or more, about 120,000 BPSD or more, about 150,000 BPSD or more, about 175,000 BPSD or more, or about 200,000 BPSD or more or more topped crude. In one or more embodiments, the one or more distillation units 530 can include one or more systems, devices, or combination of systems and/or devices suitable for distilling or separating two or more hydrocarbons or groups of hydrocarbons. In one or more embodiments, the one or more distillation units 530 can include one or more crude preheat exchangers, a furnace, a crude fractionator, and/or a gas oil stripper.
  • In one or more embodiments, all or a portion of the gas oil or heavy distillate in line 540 can be combined with the DAO provided via line 163 from the one or more two-stage separator/solvent extraction systems 100. In one or more embodiments, all or a portion of the gas oil or heavy distillate in line 540 can be combined with the H-DAO provided via line 205 from the one or more three-stage separator/solvent extraction systems 200. In one or more embodiments, all or a portion of the light distillate in line 535 can be combined with the L-DAO provided via line 288 from the one or more three-stage separator/solvent extraction systems 200.
  • In one or more embodiments, the hydrocarbon in line 105 can be selectively separated within the two-stage separator/solvent extraction system 100 to provide the asphaltene product via line 133 and the DAO product via line 163, as discussed and described above with reference to FIG. 1. In one or more embodiments, the hydrocarbon in line 105 can be selectively separated within the three-stage separator/solvent extraction system 200 to provide the asphaltene product via line 233, the H-DAO product via line 205 and the L-DAO product via line 288, as discussed and described above with reference to FIG. 2.
  • FIG. 6 depicts an illustrative hydrotreating system integrated with one or more separator/solvent extraction systems 100, 200, according to one or more embodiments. The hydrocarbon treatment system 600 can include one or more hydrotreaters (four are shown: a first-stage, 610, a second-stage, 630, a third-stage, 650, and a fourth-stage, 670), and one or more separator/solvent extraction systems 100, 200. In one or more embodiments, the hydrocarbon treatment system 600 can include one or more systems as disclosed in U.S. Pat. No. 5,980,732. In one or more embodiments, a hydrocarbon via line 305, which can be as discussed and described above with reference to FIG. 3 and hydrogen via line 605 can be introduced to the one or more first-stage hydrotreaters 610. In one or more embodiments, the hydrogen in line 605 can be introduced directly into the hydrocarbon in line 305 prior to introducing the mixture to the one or more hydrotreaters 610.
  • In one or more embodiments, the hydrogen in line 605 can contain a mixture of hydrogen, carbon monoxide, carbon dioxide, or any combination thereof, for example a synthesis gas (syngas') provided from one or more gasifiers. In one or more embodiments, the hydrogen in line 605 can have a hydrogen concentration of about 5% mol or more, about 10% mol or more, about 25% mol or more, about 50% mol or more, about 75% mol or more, about 90% mol or more, about 95% mol or more. In one or more embodiments, the hydrogen in line 605 can have a carbon monoxide concentration of about 5% mol or more, about 10% mol or more, about 25% mol or more, about 50% mol or more, about 75% mol or more, about 90% mol or more, about 95% mol or more. In one or more embodiments, the hydrogen in line 605 can have a carbon dioxide concentration of about 5% mol or more, about 10% mol or more, about 25% mol or more, about 50% mol or more, about 75% mol or more, about 90% mol or more, about 95% mol or more. In one or more embodiments, the hydrogen in line 605 can contain purified hydrogen, having a hydrogen concentration of about 90% mol or more, about 95% mol or more, about 99% mol or more, or about 99.9% mol or more.
  • In one or more embodiments, the one or more hydrotreaters 610, 630, 650, and 670 can be any suitable hydrotreating system, device, or combination of systems and/or devices. For example, the one or more hydrotreaters 610, 630, 650, and 670 can include, but are not limited to hydrodesulfurization, hydrotreating, hydrocracking, hydrogenation of aromatics, hydroisomerization, hydrodewaxing, metal removal, ammonia removal, and the like. In one or more embodiments, the one or more hydrotreaters 610, 630, 650, and can reduce the sulfur content of the hydrocarbon to provide a de-sulfurized and/or hydrogenated hydrocarbon.
  • In one or more embodiments, the one or more hydrotreaters 610, 630, 650 and 670 can have an operating temperature of from about 300° C. to about 600° C., about 325° C. to about 535° C., or about 330° C. to about 460° C. In one or more embodiments, the one or more hydrotreaters 610, 630, 650 and 670 can have an operating pressure of from about 1,000 kPa to about 30,000 kPa, about 4,500 kPa to about 27,500 kPa, about 5,000 kPa to about 25,000 kPa, or about 5,520 kPa to about 24,100 kPa. In one or more embodiments, the one or more hydrotreaters 610, 630, 650, and 670 can have a hydrogen circulation rate of from about 1,000 standard cubic feet per barrel (“SCF/B”) to about 18,000 SCF/B, about 1,000 SCF/B to about 15,500 SCF/B, or from about 1,000 SCF/B to about 10,000 SCF/B. In one or more embodiments, the one or more hydrotreaters 610, 630, 650, 670 can have a space velocity of from about 0.05/hr−1 to about 4.00/hr−1, about 0.75/hr−1 to about 3.00/hr−1, or about 0.10/hr−1 to about 2.00/hr−1.
  • In one or more embodiments, the partially hydrotreated hydrocarbons can be recovered via line 615 from the one or more first-stage hydrotreaters 610. In one or more embodiments, the partially hydrotreated hydrocarbon in line 615 can be introduced to one or more second-stage hydrotreaters 630. The partially hydrotreated hydrocarbons can be recovered via line 635 from the one or more second-stage hydrotreaters 630. In one or more embodiments, the partially treated hydrocarbon in line 635 can be introduced to the one or more third-stage hydrotreaters 650. In one or more embodiments, the partially hydrotreated hydrocarbon can be recovered via line 105 from the one or more third-stage hydrotreaters.
  • In one or more embodiments, the first-stage hydrotreater 610, second-stage hydrotreater 630, and third-stage hydrotreater 650 can be operated at the same or different conditions. In one or more embodiments, all or a portion of the partially hydrotreated hydrocarbon provided via line 105 from the one or more third-stage hydrotreaters 650 can be introduced to one or more the two-stage separator/solvent extraction systems 100. In one or more embodiments, all or a portion of the partially hydrotreated hydrocarbon provided via line 105 from the one or more third-stage hydrotreaters 650 can be introduced to the one or more three-stage separator/solvent extraction systems 200. The separator/solvent extraction systems 100 and 200 can be as discussed and described above with reference to FIGS. 1 and 2.
  • In one or more embodiments, all or a portion of the DAO provided via line 163 from the two-stage separator/solvent extraction system 100 can be introduced via line 655 to the fourth-stage hydrotreater 670. In one or more embodiments, all or a portion of the H-DAO provided via line 205 from the three-stage separator/solvent extraction system 200 can be introduced via line 665 to the fourth-stage hydrotreater 670. The hydrotreated hydrocarbons can exit the fourth-stage hydrotreater 670 via line 675.
  • FIG. 7 depicts an illustrative integrated vacuum separation and hydrogenation system integrated with one or more separator/solvent extraction systems 100, 200, according to one or more embodiments. The hydrocarbon treatment system 700 can include one or more vacuum separation units 710, one or more flash separation units 770, and one or more separator/solvent extraction systems 100, 200. In one or more embodiments, the hydrocarbon treatment system 600 can include one or more systems as disclosed in U.S. Pat. No. 5,244,565. In one or more embodiments, a hydrocarbon via line 305, which can be as discussed and described above with reference to FIG. 3 can be introduced to the one or more vacuum separation units 710 to provide one or more vaporized hydrocarbons via line 715 and one or more residual hydrocarbons via line 720.
  • In one or more embodiments, all or a portion of the residual hydrocarbons in line 720 can provide, via line 730, at least a portion of the hydrocarbons in line 105. In one or more embodiments, all or a portion of the residual hydrocarbons in line 720 can be introduced, via line 725 to one or more flash separation units 770. In one or more embodiments, one or more waste oils via line 735 can be introduced to the one or more flash separation units 770. In one or more embodiments, a high-temperature hydrogen-rich gas via line 740 can be introduced to the one or more flash-separation units 770. In one or more embodiments, the high-temperature hydrogen-rich gas in line 740 can have a temperature of from about 93° C. to about 815° C., about 93° C. to about 760° C., or about 93° C. to about 649° C.
  • In one or more embodiments, the waste oil can include, but is not limited to hydraulic fluids, heat transfer fluids, used lubricating oil, used cutting oils, used motor oils, used solvents, or any combination thereof. In one or more embodiments, the waste oil in line 735 can contain non-distillable components which include, for example, organometallic compounds, inorganic metallic compounds, finely divided particulate matter and non-distillable carbonaceous compounds.
  • In one or more embodiments, the residual hydrocarbons in line 720 can have a temperature of from about 93° C. to about 593° C., about 121° C. to about 538° C., or about 149° C. to about 482° C. In one or more embodiments, the volumetric feed ratio of waste oil-to-residual can range from a low of about 1:1, about 2:3 or about 1:3 to a high of about 400:1, about 300:1, or about 200:1.
  • In one or more embodiments, the flash separation unit 770 can have an operating temperature of from about 50° C. to about 600° C., about 55° C. to about 500° C., or about 65° C. to about 460° C. In one or more embodiments, the flash separation unit 770 can have an operating pressure of from about 101 kPa to about 17,000 kPa, about 101 kPa to about 15,500 kPa, or about 101 kPa to about 13,800 kPa. In one or more embodiments, the flash separation unit 770 can have a hydrogen circulation rate of from about 100 standard cubic meters per cubic meter of waste oil feed (“SCM/m3”) to about 15,000 SCM/m3, about 130 SCM/m3 to about 13,000 SCM/m3, about 170 SCM/m3 to about 10,100 SCM/m3. In one or more embodiments the residence time of the high-temperature hydrogen-rich gas in line 740, the residual hydrocarbons in line 720, and the waste oils in line 735 within the flash separation unit 770 can range from a low of about 0.1 sec, about 1 sec., or about 5 sec., to a high of about 10 sec., about 30 sec., about 50 sec., or more.
  • The simultaneous introduction of the high-temperature hydrogen-rich gas in line 740, the residual hydrocarbons in line 720, and/or the waste oil in line 735 to the flash separation unit 770 can vaporize at least a portion of the hydrocarbon. In one or more embodiments, all or a portion of the vaporized hydrocarbon via line 775 can be recovered from the flash separation unit 770. In one or more embodiments, all or a portion of the residual hydrocarbon in the flash separation unit 770 can be recovered via line 780. In one or more embodiments, all or a portion of the residual hydrocarbons recovered from the flash separation unit 770 via line 780 can provide at least a portion of the hydrocarbons in line 105.
  • In one or more embodiments, the hydrocarbon in line 105 can be selectively separated within the two-stage separator/solvent extraction system 100 to provide the asphaltene product via line 133 and the DAO product via line 163, as discussed and described above with reference to FIG. 1. In one or more embodiments, the hydrocarbon in line 105 can be selectively separated within the three-stage separator/solvent extraction system 200 to provide the asphaltene product via line 233, the H-DAO product via line 205 and the L-DAO product via line 288, as discussed and described above with reference to FIG. 2.
  • FIG. 8 depicts an illustrative integrated gasification and separation system integrated with one or more separator/solvent extraction systems 100, 200, according to one or more embodiments. The hydrocarbon treatment system 800 can include one or more gasifiers 810, one or more separators 830, one or more fractionators 850, one or more regenerators 870, and one or more separator/solvent extraction systems 100, 200. In one or more embodiments, the hydrocarbon treatment system 800 can include one or more systems as disclosed in U.S. Pat. No. 7,033,486. In one or more embodiments, a hydrocarbon via line 305, which can be as discussed and described above with reference to FIG. 3, can be introduced to the one or more gasifiers 810 to provide a suspension of coke-covered solids and one or more gasified hydrocarbons via line 815.
  • In one or more embodiments, one or more solids introduced to the gasifier 810 via line 875 can include, but are not limited to refractory particulates, such as alumina, alpha alumina, zirconia, titania, hafnia, silica, rare earth modified refractory metal oxides, where the rare earth may be any rare earth metal (e.g. lanthanum or yttrium), alkali earth metal modified refractory oxides, magnesia, a mullite; synthetically prepared or naturally occurring material such as pumice, ash, clay, kieselguhr, diatomaceous earth, bauxite, derivatives thereof, or mixtures thereof.
  • In one or more embodiments, all or a portion of the one or more solids can be inert. The solids can have a substantially stable surface area at reaction conditions, for example, a surface area that is not substantially reactive at the operating conditions, e.g. temperature and pressure. In one or more embodiments, all or a portion of the one or more solids can be catalytic. In one or more embodiments, the one or more solids in line 875 can have an average particle size of about 40 microns to about 2,000 microns, about 45 microns to about 1,500 microns, or about 50 microns to about 800 microns. In one or more embodiments, the one or more solids can be heated prior to being introduced to the gasifier 810. In one or more embodiments, the one or more solids in line 875 can have a temperature of from about 450° C. to about 700° C., about 500° C. to about 675° C., or about 550° C. to about 650° C.
  • In one or more embodiments, the hydrocarbon in line 305 can have a residence time in the gasifier 810 of from about 0.1 sec. to about 15 sec., about 0.25 sec. to about 10 sec., or about 0.5 sec. to about 5 sec. In one or more embodiments, the solids in line 875 can have a residence time in the gasifier 810 of from about 5 sec. to about 60 sec., about 7 sec. to about 45 sec., or about 10 sec. to about 30 sec. In one or more embodiments, the residence time of the hydrocarbon within the gasifier 810 and the residence time of the one or more solids in the gasifier 810 can be independently controlled. In one or more embodiments, the solids-to-hydrocarbon weight ratio can range from about 1:1 to about 20:1, about 3:1 to about 15:1, or about 5:1 to about 10:1.
  • The temperature of the suspension of coke-covered solids and one or more gasified hydrocarbons recovered via line 815 from the gasifier 810 can be reduced to minimize or stop thermal cracking of the hydrocarbons contained therein. In one or more embodiments, the temperature of the suspension in line 815 can be reduced to below about 500° C., about 450° C., or about 350° C. In one or more embodiments the suspension in line 815 can be introduced to the one or more separators 830 to provide a solids-lean vaporized hydrocarbon via line 835 and coke covered solids via line 840. In one or more embodiments, the solids-lean vaporized hydrocarbons in line 835 can have a solids concentration of about 5% wt or less, about 3% wt or less, about 2% wt or less, about 1% wt or less, about 0.75% wt or less, or about 0.5% wt or less.
  • In one or more embodiments, the solids-lean vaporized hydrocarbons in line 835 can be introduced to one or more fractionators 850 to provide a vaporized overhead fraction via line 855 and a condensed bottom fraction via line 105. In one or more embodiments, the overhead fraction in line 855 can have a normal boiling point of about 460° C. or less, about 480° C. or less, or about 510° C. or less. In one or more embodiments, the bottom fraction in line 105 can have a normal boiling point of about 460° C. or more, about 480° C. or more, or about 510° C. or more. The hydrocarbon in line 105 can be as discussed and described above with reference to FIGS. 1 and 2.
  • In one or more embodiments, the hydrocarbon in line 105 can be selectively separated within the two-stage separator/solvent extraction system 100 to provide the asphaltene product via line 133 and the DAO product via line 163, as discussed and described above with reference to FIG. 1. In one or more embodiments, the hydrocarbon in line 105 can be selectively separated within the three-stage separator/solvent extraction system 200 to provide the asphaltene product via line 233, the H-DAO product via line 205 and the L-DAO product via line 288, as discussed and described above with reference to FIG. 2.
  • FIG. 9 depicts an illustrative tank cleaning and separation system integrated with one or more separator/solvent extraction systems 100, 200, according to one or more embodiments. The hydrocarbon treatment system 900 can include one or more hydrocarbon storage units 910, one or more separators 950, and one or more separator/solvent extraction systems 100, 200. In one or more embodiments, the hydrocarbon treatment system 900 can include one or more systems as disclosed in U.S. Pat. No. 6,673,231. In one or more embodiments, one or more heated hydrocarbons via line 305 can be introduced to the one or more hydrocarbon storage units 910 to melt any thickened and/or solidified hydrocarbons 907 within the one or more hydrocarbon storage unit 910 to provide a flowable hydrocarbon via line 915. In one or more embodiments, the thickened and/or solidified hydrocarbons can include asphaltenes, waxes, bitumens, and insoluble inorganic components and/or particulates such as rust, clays, metals, and other inorganic compounds.
  • In one or more embodiments, the hydrocarbon in line 305 can be as discussed and described above with reference to FIG. 3. In one or more embodiments, the heated hydrocarbons in line 305 can have a temperature of about 100° C., about 150° C., about 200° C., about 300° C., or about 400° C. In one or more embodiments, the heated hydrocarbons in line 305 can include one or more atmospheric residues, vacuum residues, vacuum gas oils, light cycle oils, light gas oils, kerosene, mixtures thereof, derivatives thereof, or any combination thereof. In one or more embodiments, the weight ratio of the heated hydrocarbons-to-hydrocarbon solids can range from about 1:1 to about 30:1, about 2:1 to about 25:1, or about 3:1 to about 20:1. In one or more embodiments, the heated hydrocarbons in line 305 can have a high boiling point, high flash point and low vapor pressure. In one or more embodiments, the heated hydrocarbons in line 305 can contain a small quantity of paraffinic hydrocarbons.
  • In one or more embodiments, after fluidizing, dissolving, and/or solubilizing all or a portion of the hydrocarbons in the hydrocarbon storage unit 910, the hydrocarbon mixture can be withdrawn from the hydrocarbon storage unit 910 via line 915. The hydrocarbon mixture in line 915 can include, but is not limited to all or a portion of the elevated temperature hydrocarbons introduced via line 905, all or a portion of the fluidized, dissolved, and/or solubilized hydrocarbons from the hydrocarbon storage unit 910, one or more insoluble particulates the hydrocarbon storage unit 910, or any combination thereof. In one or more embodiments, the hydrocarbon mixture in line 915 can have a temperature of from about 30° C. to about 250° C., about 40° C. to about 200° C., or about 50° C. to about 150° C.
  • In one or more embodiments, the hydrocarbon mixture in line 915 can be introduced to the one or more separators 950 to provide a hydrocarbon mixture via line 105 and a solids slurry via line 955. In one or more embodiments, the solids slurry in line 955 can have a minimum solids concentration of about 5% wt, about 10% wt, about 25% wt, or about 50% wt. The one or more separators 950 can be maintained at or above a minimum temperature to promote the separation of the hydrocarbon mixture into two or more phases. In one or more embodiments, the one or more separators can be maintained at a minimum temperature of about 50° C., about 60° C., about 70° C., or about 75° C. In one or more embodiments, the separation of the hydrocarbon mixture within the one or more separators can be a batch process where the hydrocarbon mixture in line 915 is introduced to the one or more separators 950 and allowed to settle for an extended period of time. In one or more embodiments, the settling time within the one or more separators can be a minimum of about 6 hours, about 8 hours, about 10 hours or about 12 hours.
  • In one or more embodiments, the inorganic components and other insoluble components can be recovered via line 955 and treated, disposed of, or further processed. In one or more embodiments, the hydrocarbon in line 105 can be as discussed and described above with reference to FIGS. 1 and 2. In one or more embodiments, the hydrocarbon in line 105 can be selectively separated within the two-stage separator/solvent extraction system 100 to provide the asphaltene product via line 133 and the DAO product via line 163, as discussed and described above with reference to FIG. 1. In one or more embodiments, the hydrocarbon in line 105 can be selectively separated within the three-stage separator/solvent extraction system 200 to provide the asphaltene product via line 233, the H-DAO product via line 205 and the L-DAO product via line 288, as discussed and described above with reference to FIG. 2.
  • FIG. 10 depicts an illustrative distillation based fractionation system integrated with one or more separator/solvent extraction systems 100, 200, according to one or more embodiments. The hydrocarbon treatment system 1000 can include one or more distillation units 1010 and one or more separator/solvent extraction systems 100, 200. In one or more embodiments, the hydrocarbon treatment system 1000 can include one or more systems as disclosed in U.S. Pat. No. 6,702,936. In one or more embodiments, a hydrocarbon via line 305, which can be as discussed and described above with reference to FIG. 3, can be introduced to the one or more distillation units 1010 to vaporize all or a portion of the light hydrocarbons present in the hydrocarbon in line 305.
  • The one or more distillation units 1010 can include one or more distillation units operating at atmospheric and/or sub-atmospheric pressures. In one or more embodiments, the one or more distillation unit 1010 can provide an overhead vapor containing one or more light hydrocarbons via line 1015. In one or more embodiments, the distillation unit 1010 can provide one or more fractionated products, for example one or more heavy gas oils via line 1040, one or more light gas oils via line 1035, one or more naphthas via line 1030 and one or more light ends via line 1015. In one or more embodiments, the residual, high boiling point hydrocarbons can exit the distillation unit 1010 via line 105, which can be as discussed and described above with reference to FIGS. 1 and 2.
  • In one or more embodiments, the hydrocarbon in line 105 can be selectively separated within the two-stage separator/solvent extraction system 100 to provide the asphaltene product via line 133 and the DAO product via line 163, as discussed and described above with reference to FIG. 1. In one or more embodiments, the hydrocarbon in line 105 can be selectively separated within the three-stage separator/solvent extraction system 200 to provide the asphaltene product via line 233, the H-DAO product via line 205 and the L-DAO product via line 288, as discussed and described above with reference to FIG. 2.
  • In one or more embodiments, all or a portion of the asphaltenes exiting the one or more separator/solvent extraction systems 100 and/or 200 via lines 133 and/or 233, respectively, can be combined to provide an asphaltene feed via line 1050. In one or more embodiments, the asphaltenes in line 1050 can be introduced to one or more gasifiers and gasified therein to provide one or more products including, but not limited to hydrogen, carbon monoxide, carbon dioxide, or any combination thereof.
  • In one or more embodiments, all or a portion of the DAO recovered via line 163 from the separator/solvent extraction system 100, and/or all or a portion of the H-DAO recovered via line 205 from the separator/solvent extraction system 200 can be combined to provide a combined DAO in line 1060. In one or more embodiments, all or a portion of the combined DAO in line 1060 can be introduced to one or more upgraders, for example one or more cracking units (not shown).
  • FIG. 11 depicts an illustrative hydrogenation system integrated with one or more separator/solvent extraction systems 100, 200, according to one or more embodiments. The hydrocarbon treatment system 1100 can include one or more hydrogenation units 1110 and one or more separator/solvent extraction systems 100, 200. In one or more embodiments, the hydrocarbon treatment system 1100 can include one or more systems as disclosed in U.S. Pat. No. 6,645,369. In one or more embodiments, a hydrocarbon via line 305 and hydrogen via line 1105 can be introduced to the one or more hydrogenation units 1110. In one or more embodiments, the hydrocarbon in line 305 can be as discussed and described above with reference to FIG. 3.
  • In one or more embodiments, the hydrogen in line 1105 can contain a mixture of hydrogen, carbon monoxide, carbon dioxide, or any combination thereof, for example a syngas provided from one or more gasifiers. In one or more embodiments, the hydrogen in line 1105 can have a hydrogen concentration of about 5% mol or more, about 10% mol or more, about 25% mol or more, about 50% mol or more, about 75% mol or more, about 90% mol or more, about 95% mol or more. In one or more embodiments, the hydrogen in line 1105 can have a carbon monoxide concentration of about 5% mol or more, about 10% mol or more, about 25% mol or more, about 50% mol or more, about 75% mol or more, about 90% mol or more, about 95% mol or more. In one or more embodiments, the hydrogen in line 1105 can have a carbon dioxide concentration of about 5% mol or more, about 10% mol or more, about 25% mol or more, about 50% mol or more, about 75% mol or more, about 90% mol or more, about 95% mol or more. In one or more embodiments, the hydrogen in line 1105 can contain purified hydrogen, having a hydrogen concentration of about 90% mol or more, about 95% mol or more, about 99% mol or more, or about 99.9% mol or more.
  • Within the hydrogenation unit 1110, the hydrogen introduced via line 1105 can contact the liquid hydrocarbons introduced via line 305 to provide one or more vaporized hydrocarbons via line 1120 and one or more residual hydrocarbons via line 105. The residence time within the hydrogenation unit can range from a low of about 30 seconds, about 60 seconds, about 90 seconds, or about 120 seconds, to a high of about 2 minutes, about 3 minutes, about 5 minutes, or about 10 minutes. In one or more embodiments, the weight ratio of the hydrogen gas flow to the hydrocarbon flow can range from a low of about 0.1:1, about 0.5:1, or about 1:1 to a high of about 2:1, about 3:1, about 5:1, or about 10:1.
  • In one or more embodiments, the hydrocarbon in line 305 can be introduced to the hydrogenation system at an elevated temperature. In one or more embodiments, the temperature of the hydrocarbon in line 305 can range from a low of about 20° C., about 75° C., about 150° C., or about 200° C. to a high of about 450° C., about 500° C., about 550° C., or about 600° C.
  • In one or more embodiments, the hydrocarbon in line 105 can be selectively separated within the two-stage separator/solvent extraction system 100 to provide the asphaltene product via line 133 and the DAO product via line 163, as discussed and described above with reference to FIG. 1. In one or more embodiments, the hydrocarbon in line 105 can be selectively separated within the three-stage separator/solvent extraction system 200 to provide the asphaltene product via line 233, the H-DAO product via line 205 and the L-DAO product via line 288, as discussed and described above with reference to FIG. 2.
  • FIG. 12 depicts an illustrative thermal treatment system integrated with one or more separator/solvent extraction systems 100, 200, according to one or more embodiments. The hydrocarbon treatment system 1200 can include one or more visbreakers 1210, one or more heat exchangers 1230, one or more separators 1250, and one or more solvent extraction systems 100, 200. In one or more embodiments, the hydrocarbon treatment system 1200 can include one or more systems as disclosed in U.S. Pat. No. 6,524,469.
  • In one or more embodiments, a hydrocarbon via line 305 and hydrogen via line 1205 can be introduced to the one or more visbreakers 1210. In one or more embodiments, the hydrocarbon in line 305 can be as discussed and described above with reference to FIG. 3. In one or more embodiments, the hydrocarbon can be preheated prior to introduction to the one or more visbreakers 1210. In one or more embodiments, the hydrocarbon in line 305 can have a temperature of about 300° C. or more, about 350° C. or more, about 400° C. or more, about 450° C. or more, or about 500° C. or more.
  • In one or more embodiments, the hydrogen in line 1205 can contain a mixture of hydrogen, carbon monoxide, carbon dioxide, or any combination thereof, for example a syngas provided from one or more gasifiers. In one or more embodiments, the hydrogen in line 1205 can have a hydrogen concentration of about 5% mol or more, about 10% mol or more, about 25% mol or more, about 50% mol or more, about 75% mol or more, about 90% mol or more, about 95% mol or more. In one or more embodiments, the hydrogen in line 605 can have a carbon monoxide concentration of about 5% mol or more, about 10% mol or more, about 25% mol or more, about 50% mol or more, about 75% mol or more, about 90% mol or more, about 95% mol or more. In one or more embodiments, the hydrogen in line 1205 can have a carbon dioxide concentration of about 5% mol or more, about 10% mol or more, about 25% mol or more, about 50% mol or more, about 75% mol or more, about 90% mol or more, about 95% mol or more. In one or more embodiments, the hydrogen in line 1205 can contain purified hydrogen, having a hydrogen concentration of about 90% mol or more, about 95% mol or more, about 99% mol or more, or about 99.9% mol or more.
  • In one or more embodiments, the hydrogen in line 1205 can have a pressure of from about 650 kPa, to about 10,000 kPa, about 1,000 kPa to about 7,000 kPa, or about 1,400 kPa to about 5,500 kPa. The severity in visbreakers can be measured in “equivalent seconds” at some reference temperature, for example 90 seconds at 469° C. In one or more embodiments, the cracking severity within the one or more visbreakers 1210 (at about 469° C.) can be about 30 equivalent seconds to about 120 equivalent seconds, about 40 equivalent seconds to about 105 equivalent seconds, or about 60 equivalent seconds to about 90 equivalent seconds.
  • The cracked hydrocarbons recovered via line 1215 from the one or more visbreakers 1210 can be introduced to the one or more heat exchangers 1230. Within the one or more heat exchangers 1230, the temperature of the cracked hydrocarbons can be reduced to provide a cooled hydrocarbon via line 1235. In one or more embodiments, the cooled hydrocarbon in line 1235 can have a temperature of from about 170° C. to about 250° C., about 180° C. to about 240° C., or about 190° C. to about 230° C.
  • In one or more embodiments, at least a portion of the cooled hydrocarbons in line 1235 can be introduced to one or more separators 1250 wherein at least a portion of the lighter hydrocarbons can vaporize or flash, to provide one or more vaporized hydrocarbons via line 1255 and one or more non-vaporized hydrocarbons via line 105. In one or more embodiments, the hydrocarbon in line 105 can be similar to the hydrocarbon in line 105 discussed and described above with reference to FIGS. 1 and 2.
  • In one or more embodiments, the hydrocarbon in line 105 can be selectively separated within the two-stage separator/solvent extraction system 100 to provide the asphaltene product via line 133 and the DAO product via line 163, as discussed and described above with reference to FIG. 1. In one or more embodiments, the hydrocarbon in line 105 can be selectively separated within the three-stage separator/solvent extraction system 200 to provide the asphaltene product via line 233, the H-DAO product via line 205 and the L-DAO product via line 288, as discussed and described above with reference to FIG. 2.
  • FIG. 13 depicts an illustrative extraction system integrated with one or more separator/solvent extraction systems 100, 200, according to one or more embodiments. The hydrocarbon treatment system 1300 can include one or more mixers 1310, one or more heat exchangers 1330, one or more separators 1350, and one or more separator/solvent extraction systems 100, 200. In one or more embodiments, the hydrocarbon treatment system 1300 can include one or more butoxy-ethanol extraction systems as disclosed in U.S. Pat. No. 6,464,856.
  • In one or more embodiments, the hydrocarbon in line 305 and solvent in line 1305 can be mixed or otherwise combined using the mixer 1310 to provide a mixture. In one or more embodiments, the hydrocarbon in line 305 can be as discussed and described above with reference to FIG. 3. In one or more embodiments, the solvent in line 1305 can be a mixture of butoxy-ethanol and water. The butoxy-ethanol concentration in the solvent in line 1305 can be about 5% wt or more, about 10% wt or more, about 20% wt or more, about 25% wt or more, or about 30% wt or more, with the balance water. In one or more embodiments, the hydrocarbon to solvent weight ratio can be about 0.5:1 or more, about 1:1 or more, about 2:1 or more, about 3:1 or more, or about 5:1 or more. The hydrocarbon and solvent mixture can exit the one or more mixers 1310 via line 1315.
  • The mixture in line 1315 can be introduced to one or more heaters 1330 to provide a heated mixture via line 1335. The temperature of the heated mixture in line 1335 can range from a low of about 35° C., about 40° C., about 45° C., or about 50° C. to a high of about 80° C., about 85° C., about 90° C., or about 95° C. Heating the mixture above about 40° C. can promote the separation of the mixture into two or more phases.
  • The heated mixture in line 1335 can be introduced to the one or more separators 1350. Within the one or more separators 1350, the mixture can separate into two or more phases, with hydrocarbons collecting on the top of an upper phase and within the interface region between the upper phase and a lower phase. In one or more embodiments, the upper phase can have a butoxy-ethanol concentration of about 50% wt or more, about 55% wt or more, about 60% wt or more, about 65% wt or more, about 70% wt or more with the balance water. In one or more embodiments, the lower phase can have a butoxy-ethanol concentration of less than about 20% wt, about 15% wt, about 10% wt, about 5% wt with the balance water.
  • The surface and interface hydrocarbons can be withdrawn from the separator via line 105. The butoxy-ethanol rich upper layer can be withdrawn via line 1355. In one or more embodiments, all or a portion of the butoxy-ethanol rich upper layer in line 1355 can be withdrawn from the separator 1350 and recycled for reuse or recovery. The water-rich lower layer can be withdrawn from the separator 1350 via line 1360. In one or more embodiments, the water-rich lower layer can be treated prior to disposal or recycle.
  • In one or more embodiments, the hydrocarbon via line 105, which can be as discussed and described above with reference to FIGS. 1 and 2. In one or more embodiments, the hydrocarbon in line 105 can be selectively separated within the two-stage separator/solvent extraction system 100 to provide the asphaltene product via line 133 and the DAO product via line 163, as discussed and described above with reference to FIG. 1. In one or more embodiments, the hydrocarbon in line 105 can be selectively separated within the three-stage separator/solvent extraction system 200 to provide the asphaltene product via line 233, the H-DAO product via line 205 and the L-DAO product via line 288, as discussed and described above with reference to FIG. 2.
  • FIG. 14 depicts an illustrative solids removal system integrated with one or more separator/solvent extraction systems 100, 200, according to one or more embodiments. The hydrocarbon treatment system 1400 can include one or more mixers 1410, one or more separation units 1430, and one or more separator/solvent extraction systems 100, 200. In one or more embodiments, the hydrocarbon treatment system 1400 can include one or more solids removal systems as disclosed in U.S. Pat. No. 6,274,030.
  • In one or more embodiments a hydrocarbon via line 305 and solvent via line 1405 can be mixed or otherwise combined using the one or more mixers 1410. The hydrocarbon in line 305 can be as discussed and described above with reference to FIG. 3. In one or more embodiments, the solvent can be an alkane solvent having an alkane concentration of about 70% wt or more, about 75% wt or more, about 80% wt or more, about 85% wt or more, about 90% wt or more. In one or more embodiments, the solvent can include, but is not limited to propane, butane, pentane, hexane, heptane, mixtures thereof, or any combination thereof. In one or more specific embodiments, the solvent can include propane and butane. In one or more embodiments, the solvent can have a propane concentration of about 5% wt or more, about 25% wt or more, about 50% wt or more, about 75% wt or more, about 95% wt or more with the balance butane.
  • In one or more embodiments, mixing of the solvent with the hydrocarbon within the one or more mixers 1410 can sufficiently reduce the viscosity of the hydrocarbon to permit the selective separation of the solids present in the hydrocarbon. The mixture can exit the one or more mixers 1410 via line 1420. In one or more embodiments, the solvent/hydrocarbon mixture in line 1420 can have a temperature of from about 50° C. to about 370° C., about 55° C. to about 300° C., or about 60° C. to about 200° C.
  • In one or more embodiments, the mixture in line 1420 can be introduced to one or more separation units 1430. Within the one or more separation units 1430, all or a portion of the solids present in the mixture can be selectively separated. A slurry containing the recovered solids can be withdrawn from the separation unit 1430 via line 1435, while the mixture can be withdrawn via line 105. In one or more embodiments, the solids recovered from the hydrocarbon can include, but are not limited to silica, alumina, iron, clays, suspended catalyst fines, entrained catalyst fines, or any combination thereof. In one or more embodiments, the filter can remove solids of about 25 microns and larger, about 50 microns and larger, about 100 microns and larger, about 200 microns and larger, about 400 microns and larger, about 800 microns and larger, or about 1,000 microns and larger.
  • In one or more embodiments, the mixture can contain less than about 50% wt solids, less than about 30% wt solids, less than about 20% wt solids, less than about 10% wt solids, less than about 5% wt solids, less than about 3% wt solids, or less than about 1% wt solids.
  • In one or more embodiments, the one or more separation units 1430 can be any system, device, or any combination of systems and/or devices suitable for separating at least a portion of the solids from the mixture. In one or more embodiments, the one or more separation units 1430 can include a filter, a gravity separator, a centrifuge, a cyclone, or combinations thereof. In one or more embodiments, the one or more separation units 1430 can include a ceramic filter that can be similar to the filter described in U.S. Pat. No. 5,785,860. In one or more embodiments, the solids can be separated by other suitable methods in lieu of the filter 1430 or in addition to the filter 1430. Another method may be an electrodynamic method in which a strong electric field is imposed to collect solids, as described in U.S. Pat. No. 5,843,301. Another method can include a magnetic method in which a strong magnetic field is imposed to collect solids, as described in U.S. Pat. No. 5,607,575.
  • In one or more embodiments, the hydrocarbon in line 105 can be selectively separated within the two-stage separator/solvent extraction system 100 to provide the asphaltene product via line 133 and the DAO product via line 163, as discussed and described above with reference to FIG. 1. In one or more embodiments, the hydrocarbon in line 105 can be selectively separated within the three-stage separator/solvent extraction system 200 to provide the asphaltene product via line 233, the H-DAO product via line 205 and the L-DAO product via line 288, as discussed and described above with reference to FIG. 2. In one or more embodiments, the recovered solvent in line 279 and/or the recovered solvent in line 179 can be recycled or otherwise introduced via line 1405 to the one or more mixers 1410 to provide at least a portion of the solvent introduced to the one or more mixers 1410.
  • FIG. 15 depicts an illustrative demetallization system integrated with one or more separator/solvent extraction systems 100, 200, according to one or more. The hydrocarbon treatment system 1500 can include one or more mixers 1510 and one or more separator/solvent extraction systems 100, 200. In one or more embodiments, the hydrocarbon treatment system 1500 can include one or more demetallization systems as disclosed in U.S. Pat. No. 6,245,222.
  • In one or more embodiments, the hydrocarbon in line 305 and an additive via line 1515 can be introduced to one or more mixers 1510. In one or more embodiments, the hydrocarbon in line 305 can be as discussed and described above with reference to FIG. 3. In one or more embodiments, the additive can be a metal-complexing additive. In one or more embodiments, the additive in line 1515 can include one or more alkane-insoluble polyoxy-alkylene group containing additives, for example an alky (polyoxyalkylene) moiety. In one or more embodiments, the additive can be selected from a group of compounds insoluble in the solvent used in the one or more separator/solvent extraction systems 100, 200. The additive can be introduced to the one or more mixers 1510 ranging from a low of about 0.25% wt, about 0.5% wt, about 1.0% wt, or about 1.5% wt, or about 2.0% wt to a high of about 5.0% wt, about 10.0% wt, or about 20.0% wt based upon the weight of the hydrocarbon in line 305. In one or more embodiments, the mixer 1510 can operate at a temperature of from about 20° C. to about 200° C., about 50° C. to about 150° C., or about 75° C. to about 125° C.
  • When mixed or otherwise combined with the hydrocarbon in the mixer 1510, the additive can combine with the metals present in the hydrocarbon in line 305, including, but not limited to organo-metallic compounds, such as organo-nickel, organo-vanadium, organo-iron, heteroatoms, derivatives thereof, or any combination thereof. The metal-complexing additive can combine with all or a portion of the metals present in the hydrocarbon in line 305, forming one or more insoluble organo-metallic complexes.
  • In one or more embodiments, a hydrocarbon mixture that can include the insoluble organo-metallic complexes can be recovered via line 105 from the mixer 1510. In one or more embodiments, the hydrocarbon in line 105 can be selectively separated within the two-stage separator/solvent extraction system 100 to provide the asphaltene product via line 133 and the DAO product via line 163, as discussed and described above with reference to FIG. 1. In one or more embodiments, the hydrocarbon in line 105 can be selectively separated within the three-stage separator/solvent extraction system 200 to provide the asphaltene product via line 233, the H-DAO product via line 205 and the L-DAO product via line 288, as discussed and described above with reference to FIG. 2.
  • FIG. 16 depicts an illustrative solids separation and hydrocarbon recovery system integrated with one or more separator/solvent extraction systems 100, 200, according to one or more embodiments. The hydrocarbon treatment system 1600 can include one or more primary separators 1610, one or more secondary separators 1650, and one or more separator/solvent extraction systems 100, 200. In one or more embodiments, the hydrocarbon treatment system 1600 can include one or more solids separation and hydrocarbon recovery systems as disclosed in U.S. Publication No.: 2006/0249439. In one or more embodiments, the hydrocarbon in line 305, which can be as discussed and described above with reference to FIG. 3, can be mixed or otherwise contacted with a diluent introduced via line 1605 and optionally one or more recycled hydrocarbons introduced via line 1655.
  • In one or more embodiments, the diluent introduced via line 1605 can include a solvent, including, but not limited to light naphthas, heavy naphthas, whole naphthas, paraffinic hydrocarbons, alkane hydrocarbons, mixtures thereof, derivatives thereof, or any combination thereof. In one or more embodiments, the hydrocarbon in line 305 can be mixed or otherwise combined with the solvent in line 1605 and, optionally, one or more recycled hydrocarbons via line 1655 to provide a diluted hydrocarbon in line 1607. The addition of the solvent to the hydrocarbon can reduce the viscosity of the hydrocarbon, permitting the settling of any solids present in the hydrocarbon.
  • The diluted hydrocarbon in line 1607 can be introduced to one or more primary separators 1610 where at least a portion of any solids present in the hydrocarbon can settle. The settled solids can be recovered via line 1615 from the primary separator 1610. The hydrocarbons can be recovered via line 105 from the primary separator 1610. In one or more embodiments, the settled solids in line 1615 can have a solids concentration of about 10% wt or more, about 20% wt or more, about 30% wt or more, about 40% wt or more, about 50% wt or more.
  • In one or more embodiments, the solids in line 1615 can be introduced to the one or more secondary separators 1650 to provide further separate additional hydrocarbons from the solids. In one or more embodiments, the one or more secondary separators 1650 can include one or more centrifugal separators, for example one or more cyclones. The solids can be recovered via line 1660 from the secondary separator 1650. The separated hydrocarbons can be recovered via line 1655 from the secondary separator 1650. In one or more embodiments, the solids in line 1660 can have a solids concentration of about 10% wt or more, about 20% wt or more, about 30% wt or more, about 40% wt or more, about 50% wt or more. In one or more embodiments, the recovered hydrocarbons in line 1655 can have a solids concentration of about 20% wt or less, about 15% wt or less, about 10% wt or less, about 5% wt or less, about 3% wt or less, about 1% wt or less, about 0.5% wt or less.
  • In one or more embodiments, at least a portion of the recovered hydrocarbons can be recycled via line 1655 to the hydrocarbon in line 305. In one or more embodiments, at least a portion of the recovered hydrocarbons via line 1655 can be introduced to the separated hydrocarbons in line 105.
  • In one or more embodiments, the hydrocarbon in line 105 can be selectively separated within the two-stage separator/solvent extraction system 100 to provide the asphaltene product via line 133 and the DAO product via line 163, as discussed and described above with reference to FIG. 1. In one or more embodiments, the hydrocarbon in line 105 can be selectively separated within the three-stage separator/solvent extraction system 200 to provide the asphaltene product via line 233, the H-DAO product via line 205 and the L-DAO product via line 288, as discussed and described above with reference to FIG. 2.
  • FIG. 17 depicts an illustrative emissions reduction system integrated with one or more separator/solvent extraction systems 100, 200, according to one or more embodiments. The hydrocarbon treatment system 1700 can include one or more mixers 1710, and one or more separator/solvent extraction systems 100, 200. In one or more embodiments, the hydrocarbon treatment system 1700 can include one or more emissions reduction systems as disclosed in U.S. Publication No.: 2006/0116450. In one or more embodiments, a hydrocarbon in line 305, which can be as discussed and described above with reference to FIG. 3, can be mixed or otherwise combined with an emissions reducing additive (“ERA”) introduced via line 1705.
  • The ERA can include one or more metal oxides suspended in a hydrocarbon carrier. In one or more embodiments, the one or more metal oxides can include one or more transition metal oxides, including but not limited to zinc oxide, copper oxide, iron oxide, aluminum oxide, or any combination thereof. In one or more embodiments, the ERA can be in the form of a powder, flake or granule. In one or more embodiments, the ERA can be dispersed, suspended, emulsified, or otherwise mixed in a diluent hydrocarbon having a flash point less than the flash point of the hydrocarbon in line 305, for example mineral oil, Sunpave 125, Hydrolene, light flux oils or the like. Where the diluent hydrocarbon has a flash point less than the hydrocarbon in line 305, the ERA concentration in the diluent hydrocarbon can be about 5% wt or more, about 10% wt or more, about 15% wt or more, about 20% wt or more, about 25% wt or more, about 30% wt or more, 50% wt or more, or about 60% wt or more.
  • In one or more embodiments, one or more additives, in addition to the ERA, such as sulfonating agents and/or crosslinking agents can be introduced via line 1705. The cross-linking agents can be activators, e.g., zinc oxide, accelerators, such as sulfur compounds, e.g., mercaptobenzothizole (MBT) or both accelerators and activators, such as a zinc salt of MBT, for example. In one embodiment, the cross-linking agent can be a metal oxide. Although the metal oxide can be the same or a different metal oxide than the ERA, such cross-linking metal oxide can be added in addition to the metal oxide ERA, when used. In another embodiment, the cross-linking agent can be a sulfur containing compound. The additives can further include unsaturated functional monomers, unsaturated carboxylic acids, unsaturated dicarboxylic acids, unsaturated anhydrides, unsaturated esters and/or unsaturated amides, for example.
  • The ERA/diluent hydrocarbon solution and/or one or more additional additives in line 1750 and the hydrocarbon in line 305 can be mixed or otherwise combined to provide one or more reduced emissions hydrocarbons via line 105. In one or more embodiments, the reduced emissions hydrocarbons in line 105 can have an ERA concentration of from about 0.05% wt to about 2% wt, about 0.07% wt to about 1% wt, or about 0.05% wt to about 0.09% wt, or about 0.1% wt to about 0.2% wt. In one or more embodiments, the one or more mixers 1710 can have an operating temperature of from about 100° C. to about 300° C., about 150° C. to about 250° C., or about 175° C. to about 225° C.
  • In one or more embodiments, the hydrocarbon in line 105 can be selectively separated within the two-stage separator/solvent extraction system 100 to provide the asphaltene product via line 133 and the DAO product via line 163, as discussed and described above with reference to FIG. 1. In one or more embodiments, the hydrocarbon in line 105 can be selectively separated within the three-stage separator/solvent extraction system 200 to provide the asphaltene product via line 233, the H-DAO product via line 205 and the L-DAO product via line 288, as discussed and described above with reference to FIG. 2.
  • FIG. 18 depicts another illustrative distillation system integrated with one or more separator/solvent extraction systems 100, 200, according to one or more embodiments. The hydrocarbon treatment system 1800 can include one or more heat exchangers (two are shown, 1810 and 1850), one or more atmospheric distillation units (“ADUs”) 1830, one or more vacuum distillation units (“VDUs”) 1870, and one or more separator/solvent extraction systems 100, 200. In one or more embodiments, the distillation system can include one or more distillation systems as disclosed in U.S. Publication No.: 2006/0032789.
  • In one or more embodiments, a hydrocarbon in line 305, which can be as discussed and described above with reference to FIG. 3, can be heated using the one or more heat exchangers 1810 to provide a heated hydrocarbon via line 1815. In one or more embodiments, the temperature of the heated hydrocarbon in line 1815 can be about 100° C. or more, about 150° C. or more, about 200° C. or more, about 300° C. or more, or about 400° C. or more.
  • The heated hydrocarbon in line 1815 can be introduced to one or more atmospheric distillation units 1830, where at least a portion of the hydrocarbons can vaporize to provide a vaporized hydrocarbon mixture via line 1840. In one or more embodiments, the vaporized hydrocarbon mixture in line 1840 can be selectively separated or otherwise fractionated to provide one or more finished hydrocarbon products including, but not limited to light naphthas, full-range naphthas, C6 and lighter alkanes, or any combination thereof. In one or more embodiments, non-vaporized, residual hydrocarbons can be recovered via line 1835 from the one or more ADUs 1830. In one or more embodiments the operating pressure of the one or more ADUs 1830 can range from a low of about 100 kPa, about 150 kPa, about 200 kPa, or about 250 kPa, to a high of about 300 kPa, about 350 kPa, about 400 kPa, or about 450 kPa.
  • In one or more embodiments the temperature of the residual hydrocarbons in line 1835 can be increased using the one or more heat exchangers 1850 to provide heated residual hydrocarbons via line 1855. In one or more embodiments, the temperature of the heated residual hydrocarbons in line 1855 can be about 100° C. or more, about 150° C. or more, about 200° C. or more, about 300° C. or more, or about 400° C. or more.
  • In one or more embodiments, the heated residual hydrocarbons via line 1855 can be introduced to one or more VDUs 1870 where at least a portion of the hydrocarbons can vaporize to provide a vaporized hydrocarbon mixture via line 1880. In one or more embodiments, non-vaporized, residual hydrocarbons (“resid”) can be recovered via line 105 from the one or more VDUs 1870. In one or more embodiments the operating pressure of the one or more VDU 1870 can range from a low of about 0 kPa, about 10 kPa, about 20 kPa, or about 25 kPa, to a high of about 80 kPa, about 85 kPa, about 90 kPa, or about 95 kPa.
  • In one or more embodiments, the hydrocarbon in line 105 can be selectively separated within the two-stage separator/solvent extraction system 100 to provide the asphaltene product via line 133 and the DAO product via line 163, as discussed and described above with reference to FIG. 1. In one or more embodiments, the hydrocarbon in line 105 can be selectively separated within the three-stage separator/solvent extraction system 200 to provide the asphaltene product via line 233, the H-DAO product via line 205 and the L-DAO product via line 288, as discussed and described above with reference to FIG. 2.
  • FIG. 19 depicts an illustrative asphaltene blending system integrated with one or more separator/solvent extraction systems 100, 200, according to one or more embodiments. The hydrocarbon treatment system 1900 can include one or more mixers 1910 and one or more separator/solvent extraction systems 100, 200. In one or more embodiments, the hydrocarbon treatment system 1900 can include an asphaltene blending system as disclosed in U.S. Publication No.: 2006/0000749.
  • In one or more embodiments, a hydrocarbon in line 305, which can be as discussed and described above with reference to FIG. 3 can be introduced to the one or more mixers 1910. In one or more embodiments, the hydrocarbon in line 305 can contain one or more hydrophilic asphaltenic hydrocarbons. To reduce the wetting tendency of the hydrophilic asphaltenes in the hydrocarbon in line 305, a solution containing one or more hydrophobic asphaltenic hydrocarbons in line 1905 can be mixed or otherwise combined with the hydrocarbon in line 305 to provide an asphaltenic hydrocarbon mixture having reduced wetting tendencies via line 105.
  • In one or more embodiments, the hydrocarbon feed in line 305 can contain one or more hydrophobic asphaltenic hydrocarbons. To reduce the wetting tendency of the hydrophobic asphaltenes in the hydrocarbon in line 305, a solution containing one or more hydrophilic asphaltenic hydrocarbons in line 1905 can be mixed or otherwise combined with the hydrocarbon in line 305 to provide an asphaltenic hydrocarbon mixture having reduced wetting tendencies via line 105.
  • In one or more embodiments, the hydrocarbon in line 105 can be selectively separated within the two-stage separator/solvent extraction system 100 to provide the asphaltene product via line 133 and the DAO product via line 163, as discussed and described above with reference to FIG. 1. In one or more embodiments, the hydrocarbon in line 105 can be selectively separated within the three-stage separator/solvent extraction system 200 to provide the asphaltene product via line 233, the H-DAO product via line 205 and the L-DAO product via line 288, as discussed and described above with reference to FIG. 2.
  • FIG. 20 depicts an illustrative fractionating and hydrorefining system integrated with one or more separator/solvent extraction systems 100, 200, according to one or more embodiments. The hydrocarbon treatment system 2000 can include one or more heat exchangers (two are shown 2010 and 2050), one or more fractionators 2030, one or more hydrorefiners 2070, and one or more separator/solvent extraction systems 100, 200. In one or more embodiments, the hydrocarbon treatment system 2000 can include one or more fractionation and hydrorefining systems as disclosed in U.S. Publication No.: 2004/0069685.
  • In one or more embodiments, a hydrocarbon in line 305, which can be as discussed and described above with reference to FIG. 3, can be heated using the one or more heat exchangers 2010 to provide a heated hydrocarbon via line 2015. In one or more embodiments, the temperature of the heated hydrocarbon in line 2015 can be about 100° C. or more, about 150° C. or more, about 200° C. or more, about 300° C. or more, or about 400° C. or more. The heated hydrocarbon in line 2015 can be introduced to one or more fractionators 2030 where at least a portion of the hydrocarbons present can be vaporized to provide a vaporized hydrocarbon mixture via line 2035. One or more non-vaporized residual hydrocarbons can be recovered via line 105 from the fractionator 2030.
  • In one or more embodiments, all or a portion of the vaporized hydrocarbons in line 2035 can be heated using the one or more heat exchangers 2050 to provide a heated vaporized hydrocarbon in line 2055. In one or more embodiments, the temperature of the vaporized hydrocarbons in line 2055 can be about 100° C. or more, about 150° C. or more, about 200° C. or more, about 300° C. or more, or about 400° C. or more.
  • In one or more embodiments, all or a portion of the heated hydrocarbon in line 2055 and hydrogen via line 2065 can be introduced to the one or more hydrorefiners 2070. The hydrogen introduced via line 2065 to the one or more hydrorefiners 2070 can have a hydrogen concentration of about 40% wt or more, about 50% wt or more, about 60% wt or more, about 70% wt or more, about 80% wt or more, about 90% wt or more, about 95% wt or more, about 99% wt or more.
  • In one or more embodiments, the hydrogen in line 2065 can contain a mixture of hydrogen, carbon monoxide, carbon dioxide, or any combination thereof, for example a syngas provided from one or more gasifiers. In one or more embodiments, the hydrogen in line 2065 can have a hydrogen concentration of about 5% mol or more, about 10% mol or more, about 25% mol or more, about 50% mol or more, about 75% mol or more, about 90% mol or more, about 95% mol or more. In one or more embodiments, the hydrogen in line 2065 can have a carbon monoxide concentration of about 5% mol or more, about 10% mol or more, about 25% mol or more, about 50% mol or more, about 75% mol or more, about 90% mol or more, about 95% mol or more. In one or more embodiments, the hydrogen in line 605 can have a carbon dioxide concentration of about 5% mol or more, about 10% mol or more, about 25% mol or more, about 50% mol or more, about 75% mol or more, about 90% mol or more, about 95% mol or more. In one or more embodiments, the hydrogen in line 2065 can contain purified hydrogen, having a hydrogen concentration of about 90% mol or more, about 95% mol or more, about 99% mol or more, or about 99.9% mol or more.
  • The one or more hydrorefiners 2070 can include one or more catalysts suitable for hydrogenating unsaturated hydrocarbons. In one or more embodiments, the one or more hydrorefiners 2070 can use one or more fixed catalyst beds, one or more moving catalyst beds, or any combination thereof. In one or more embodiments, a hydrotreated hydrocarbon via line 2075 can be recovered from the one or more hydrorefiners 2070.
  • In one or more embodiments, the hydrocarbon in line 105 can be selectively separated within the two-stage separator/solvent extraction system 100 to provide the asphaltene product via line 133 and the DAO product via line 163, as discussed and described above with reference to FIG. 1. In one or more embodiments, the hydrocarbon in line 105 can be selectively separated within the three-stage separator/solvent extraction system 200 to provide the asphaltene product via line 233, the H-DAO product via line 205 and the L-DAO product via line 288, as discussed and described above with reference to FIG. 2.
  • Referring to FIGS. 1-20, in one or more embodiments at least a portion of at least one of the DAO product via line 163 and the asphaltene product via line 133 from the two-stage separator/solvent extraction system, the H-DAO product via line 205, the L-DAO product via line 288, and the asphaltene product via line 233 from the three-stage separator/solvent extraction system 200, or any combination thereof can be introduced to one or more delayed cokers. The hydrocarbon introduced to the delayed coker can be heated and subjected to destructive thermal cracking to provide lower-boiling point petroleum distillate products and solid carbonaceous residue, also referred to as coke.
  • In one or more embodiments, the coke provided from the one or more cokers can be fuel grade coke and/or anode grade coke. As used herein, the term “anode grade coke” is petroleum coke which has a sulfur content of less than 3% wt, a total metals content of less than 500 ppm, a nickel content of less than 200 ppm, a vanadium content less than 350 ppm, a bulk density of at least 800.9 kg/m3, a Hardgrove grindability index (“HGI”) greater than 70, and a volatile carbonaceous matter (“VCM”) content of less than 10-12% wt. Fuel grade coke is coke which does not meet one or more of the specifications required for anode grade coke.
  • In one or more embodiments, a portion of the hydrocarbon in line 105, the H-DAO product in line 205, and/or the DAO product in line 163 can be hydrotreated in a hydrotreater to provide a hydrotreated hydrocarbon and lighter hydrocarbon products. In one or more embodiments, at least a portion of the hydrotreated hydrocarbon can be introduced to the coker. In one or more embodiments, at least a portion of the hydrocarbon in line 105 can be hydrotreated in a hydrotreater before introducing the hydrocarbon to the two-state separator/solvent extraction system 100 and/or the three-stage separator/solvent extraction system 200. In one or more embodiments, at least a portion of the hydrocarbon in line 105 can be hydrotreated in a hydrotreater to provide a hydrotreated hydrocarbon which can then be introduced directly to the one or more delayed cokers.
  • In one or more embodiments, the one or more delayed cokers can include one or more systems, devices, or combination of systems and/or devices suitable for providing anode coke, fuel coke, or both. The one or more delayed cokers can be heated to a temperature ranging from about 425° C. to about 485° C. and can operate at a pressure ranging from about 100 kPa to about 225 kPa. In one or more embodiments, the hydrotreater can be operated at a temperature ranging from about 310° C. to about 375° C. and a pressure ranging from about 4,000 kPa to about 5,600 kPa. Typical, non-limiting, processes integrating solvent deasphalting, hydrotreating, and coking are disclosed in U.S. Pat. Nos. 4,940,529; 5,013,427; 5,124,027; 5,228,978; 5,242,578; 5,258,117; 5,312,543; and 6,332,975.
  • Certain embodiments and features have been described using a set of numerical upper limits and a set of numerical lower limits. It should be appreciated that ranges from any lower limit to any upper limit are contemplated unless otherwise indicated. Certain lower limits, upper limits and ranges appear in one or more claims below. All numerical values are “about” or “approximately” the indicated value, and take into account experimental error and variations that would be expected by a person having ordinary skill in the art.
  • Various terms have been defined above. To the extent a term used in a claim is not defined above, it should be given the broadest definition persons in the pertinent art have given that term as reflected in at least one printed publication or issued patent. Furthermore, all patents, test procedures, and other documents cited in this application are fully incorporated by reference to the extent such disclosure is not inconsistent with this application and for all jurisdictions in which such incorporation is permitted.
  • While the foregoing is directed to embodiments of the present invention, other and further embodiments of the invention may be devised without departing from the basic scope thereof, and the scope thereof is determined by the claims that follow.

Claims (20)

1) A method for processing one or more hydrocarbons comprising,
selectively separating a hydrocarbon to provide one or more finished products and an asphaltenic hydrocarbon using a pretreatment process,
selectively separating the asphaltenic hydrocarbons to provide a deasphalted oil and one or more asphaltenes,
converting at least a portion of the deasphalted oil to one or more first products using a first post-treatment process, and
converting at least a portion of the one or more asphaltenes to one or more second products using a second post-treatment process.
2) The method of claim 1 wherein the pretreatment process is selected from the group consisting of petroleum residue desulfurization units, vacuum distillation units, residuum conversion units, hydrocarbon sludge removal units, atmospheric distillation units, gravimetric hydrocarbon/water separation units, thermal cracking units, tar sand treatment units, hydrocarbon/solids separation units, hydrocarbon demetallizing units, bitumen froth separation units, hydrocarbon emissions reduction treatment units, vacuum distillation units, fractional distillation units, asphaltenic dispersion units, gas plant dilution units, visbreaking units, hydrocracking units, vaporizer units, solvent dewatering units, and flash separation units.
3) The method of claim 1 wherein the first post-treatment process is selected from the group consisting of steam generation units, gasification units, fractionation units, hydrotreatment units, thermal cracking units, visbreaking units, desulfurization units, hydrodesulfurization units, catalytic cracking units, and fluidized catalytic cracking units.
4) The method of claim 1 wherein the second post-treatment process is selected from the group consisting of steam generation units, pelletization units, hydrocarbon-based catalyst production units, asphalt building product production units, gasification units, olefinic hydrocarbon production units, catalytic cracking units, and fluidized catalytic cracking units.
5) The method of claim 1 wherein the first post-treatment process comprises a steam generation unit providing steam, and wherein at least a portion of the steam is used to stimulate extraction of additional hydrocarbons via steam assisted gravity drainage.
6) The method of claim 1 wherein the second post-treatment process comprises a steam generation unit providing steam, and wherein at least a portion of the steam is used to stimulate extraction of additional hydrocarbons via steam assisted gravity drainage.
7) The method of claim 1 wherein the pretreatment process comprises a solvent dewatering unit and wherein the addition of solvent in the solvent dewatering unit satisfies at least a portion of the solvent requirements within the solvent deasphalting process.
8) The method of claim 1 wherein the selective separation of the asphaltenic hydrocarbons to provide the deasphalted oil and the one or more asphaltenes comprises a solvent deasphalting system operated at or above supercritical temperature or pressure conditions based upon the solvent.
9) The method of claim 1 wherein the selective separation of the asphaltenic hydrocarbons to provide the deasphalted oil and the one or more asphaltenes comprises a solvent deasphalting system operated below supercritical temperature and pressure conditions based upon the solvent.
10) A method for processing one or more hydrocarbons comprising:
selectively separating a hydrocarbon to provide one or more finished products and an asphaltenic hydrocarbon using a pretreatment process,
selectively separating the asphaltenic hydrocarbons to provide a light deasphalted oil, a heavy deasphalted oil and one or more asphaltenes,
converting at least a portion of the light deasphalted oil to one or more products using a first post-treatment process,
converting at least a portion of the heavy deasphalted oil to one or more products using a second post-treatment process, and
converting at least a portion of the one or more asphaltenes to one or more products using a third post-treatment process.
11) The method of claim 10 wherein the pretreatment process is selected from the group consisting of petroleum residue desulfurization units, vacuum distillation units, residuum conversion units, hydrocarbon sludge removal units, atmospheric distillation units, gravimetric hydrocarbon/water separation units, thermal cracking units, tar sand treatment units, hydrocarbon/solids separation units, hydrocarbon demetallizing units, bitumen froth separation units, hydrocarbon emissions reduction treatment units, vacuum distillation units, fractional distillation units, asphaltenic dispersion units, gas plant dilution units, visbreaking units, hydrocracking units, vaporizer units, solvent dewatering units, and flash separation units.
12) The method of claim 10 wherein the first post-treatment process is selected from the group consisting of steam generation units, gasification units, fractionation units, hydrotreatment units, thermal cracking units, visbreaking units, desulfurization units, hydrodesulfurization units, catalytic cracking units, and fluidized catalytic cracking units.
13) The method of claim 10 wherein the second post-treatment process is selected from the group consisting of steam generation units, pelletization units, hydrocarbon-based catalyst production units, asphalt building product production units, gasification units, olefinic hydrocarbon production units, catalytic cracking units, and fluidized catalytic cracking units.
14) The method of claim 10 wherein the first post-treatment process comprises a steam generation unit providing steam, and wherein at least a portion of the steam is used to stimulate extraction of additional hydrocarbons via steam assisted gravity drainage.
15) The method of claim 10 wherein the second post-treatment process comprises a steam generation unit providing steam, and wherein at least a portion of the steam is used to stimulate extraction of additional hydrocarbons via steam assisted gravity drainage.
16) The method of claim 10 wherein the pretreatment process comprises a solvent dewatering unit and wherein the addition of solvent in the solvent dewatering unit satisfies at least a portion of the solvent requirements within the solvent deasphalting process.
17) The method of claim 10 wherein the pretreatment process comprises a solvent dewatering unit and wherein the addition of solvent in the solvent dewatering unit satisfies at least a portion of the solvent requirements within the solvent deasphalting process.
18) The method of claim 10 wherein the selective separation of the asphaltenic hydrocarbons to provide the deasphalted oil and the one or more asphaltenes comprises a solvent deasphalting system operated at or above supercritical temperature or pressure conditions based upon the solvent.
19) The method of claim 10 wherein the selective separation of the asphaltenic hydrocarbons to provide the deasphalted oil and the one or more asphaltenes comprises a solvent deasphalting system operated below supercritical temperature and pressure conditions based upon the solvent.
20) A system for processing one or more hydrocarbons comprising:
means for selectively separating a hydrocarbon to provide one or more finished products and an asphaltenic hydrocarbon using a pretreatment process,
means for selectively separating the asphaltenic hydrocarbons to provide a deasphalted oil and one or more asphaltenes,
means for converting at least a portion of the deasphalted oil to one or more first products using a first post-treatment process, and
means for converting at least a portion of the one or more asphaltenes to one or more second products using a second post-treatment process.
US12/606,896 2009-10-27 2009-10-27 Residuum Oil Supercritical Extraction Process Abandoned US20110094937A1 (en)

Priority Applications (1)

Application Number Priority Date Filing Date Title
US12/606,896 US20110094937A1 (en) 2009-10-27 2009-10-27 Residuum Oil Supercritical Extraction Process

Applications Claiming Priority (1)

Application Number Priority Date Filing Date Title
US12/606,896 US20110094937A1 (en) 2009-10-27 2009-10-27 Residuum Oil Supercritical Extraction Process

Publications (1)

Publication Number Publication Date
US20110094937A1 true US20110094937A1 (en) 2011-04-28

Family

ID=43897487

Family Applications (1)

Application Number Title Priority Date Filing Date
US12/606,896 Abandoned US20110094937A1 (en) 2009-10-27 2009-10-27 Residuum Oil Supercritical Extraction Process

Country Status (1)

Country Link
US (1) US20110094937A1 (en)

Cited By (11)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20120091032A1 (en) * 2010-10-15 2012-04-19 Kellogg Brown & Root Llc Flash Processing A Solvent Deasphalting Feed
US20130225838A1 (en) * 2012-02-26 2013-08-29 Cpc Corporation, Taiwan Regeneration of Selective Solvents for Extractive Processes
WO2014006165A2 (en) * 2012-07-06 2014-01-09 Statoil Canada Limited Method
US20140275676A1 (en) * 2013-03-14 2014-09-18 Lummus Technology Inc. Process for producing distillate fuels and anode grade coke from vacuum resid
CN104212473A (en) * 2013-06-03 2014-12-17 中国石油化工股份有限公司 Device for producing road asphalt raw material
US20140366539A1 (en) * 2012-01-03 2014-12-18 Douglas W. Hissong Power Generation Using Non-Aqueous Solvent
US20150008156A1 (en) * 2013-07-04 2015-01-08 S.A. Imperbel N.V. Bitumen
WO2017182187A1 (en) * 2016-04-22 2017-10-26 Siemens Aktiengesellschaft Method for purifying an asphaltene-containing fuel
US10125318B2 (en) 2016-04-26 2018-11-13 Saudi Arabian Oil Company Process for producing high quality coke in delayed coker utilizing mixed solvent deasphalting
US10233394B2 (en) 2016-04-26 2019-03-19 Saudi Arabian Oil Company Integrated multi-stage solvent deasphalting and delayed coking process to produce high quality coke
US10351778B2 (en) 2016-05-23 2019-07-16 Kellogg Brown & Root Llc Systems for producing anode grade coke from high sulfur crude oils

Citations (98)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US3159571A (en) * 1960-11-28 1964-12-01 Shell Oil Co Residual oil refining process
US3175966A (en) * 1962-09-24 1965-03-30 Cities Service Res & Dev Co Treatment of a crude hydrocarbon oil in several stages to produce refined lower boiling products
US3957628A (en) * 1974-12-30 1976-05-18 Exxon Research And Engineering Company Removal of organic sulfur compounds from hydrocarbon feedstocks
US4115246A (en) * 1977-01-31 1978-09-19 Continental Oil Company Oil conversion process
US4572781A (en) * 1984-02-29 1986-02-25 Intevep S.A. Solvent deasphalting in solid phase
US4686028A (en) * 1985-04-05 1987-08-11 Driesen Roger P Van Upgrading of high boiling hydrocarbons
US4781819A (en) * 1983-07-06 1988-11-01 The British Petroleum Company P.L.C. Treatment of viscous crude oils
US4931231A (en) * 1985-04-22 1990-06-05 American Colloid Company Method for manufacturing discrete pellets of asphaltic material
US4940529A (en) * 1989-07-18 1990-07-10 Amoco Corporation Catalytic cracking with deasphalted oil
US5013427A (en) * 1989-07-18 1991-05-07 Amoco Corportion Resid hydrotreating with resins
US5024750A (en) * 1989-12-26 1991-06-18 Phillips Petroleum Company Process for converting heavy hydrocarbon oil
US5026472A (en) * 1989-12-29 1991-06-25 Uop Hydrocracking process with integrated distillate product hydrogenation reactor
US5098994A (en) * 1990-12-24 1992-03-24 Uop Process for separating a resin phase from a solvent solution containing a solvent, demetallized oil and a resin
US5114562A (en) * 1990-08-03 1992-05-19 Uop Two-stage hydrodesulfurization and hydrogenation process for distillate hydrocarbons
US5120427A (en) * 1988-05-23 1992-06-09 Uop High conversion high vaporization hydrocracking process
US5124027A (en) * 1989-07-18 1992-06-23 Amoco Corporation Multi-stage process for deasphalting resid, removing catalyst fines from decanted oil and apparatus therefor
US5135640A (en) * 1990-11-05 1992-08-04 Texaco Inc. High efficiency process for preparation of gasoline by catalytic cracking
US5192421A (en) * 1991-04-16 1993-03-09 Mobil Oil Corporation Integrated process for whole crude deasphalting and asphaltene upgrading
US5228978A (en) * 1989-07-18 1993-07-20 Amoco Corporation Means for and methods of low sulfur and hydrotreated resids as input feedstreams
US5286371A (en) * 1992-07-14 1994-02-15 Amoco Corporation Process for producing needle coke
US5288681A (en) * 1991-08-26 1994-02-22 Uop Catalyst for the hydroconversion of asphaltene-containing hydrocarbonaceous charge stocks
US5318124A (en) * 1991-11-14 1994-06-07 Pecten International Company Recovering hydrocarbons from tar sand or heavy oil reservoirs
US5328591A (en) * 1992-10-13 1994-07-12 Mobil Oil Corporation Mechanical shattering of asphaltenes in FCC riser
US5385663A (en) * 1992-06-18 1995-01-31 Uop Integrated hydrocracking-catalytic dewaxing process for the production of middle distillates
US5393409A (en) * 1993-03-08 1995-02-28 Uop Hydrocracking process using a controlled porosity catalyst
US5601697A (en) * 1994-08-04 1997-02-11 Ashland Inc. Demetallation-High carbon conversion process, apparatus and asphalt products
US5607575A (en) * 1993-09-03 1997-03-04 Nippon Oil Co., Ltd. Process for removing iron impurities from petroleum oil distillation residues
US5626193A (en) * 1995-04-11 1997-05-06 Elan Energy Inc. Single horizontal wellbore gravity drainage assisted steam flooding process
US5785860A (en) * 1996-09-13 1998-07-28 University Of British Columbia Upgrading heavy oil by ultrafiltration using ceramic membrane
US5885440A (en) * 1996-10-01 1999-03-23 Uop Llc Hydrocracking process with integrated effluent hydrotreating zone
US5888377A (en) * 1997-12-19 1999-03-30 Uop Llc Hydrocracking process startup method
US5904835A (en) * 1996-12-23 1999-05-18 Uop Llc Dual feed reactor hydrocracking process
US5911875A (en) * 1997-04-07 1999-06-15 Siemens Westinghouse Power Corporation Method and system for generating power from residual fuel oil
US6171473B1 (en) * 1999-04-08 2001-01-09 Abb Lummus Global Inc. Integrated residue thermal cracking and partial oxidation process
US6180683B1 (en) * 1997-03-10 2001-01-30 Clariant Gmbh Synergistic mixtures of alkylphenol-formaldehyde resins with oxalkylated amines as asphaltene dispersants
US6183627B1 (en) * 1998-09-03 2001-02-06 Ormat Industries Ltd. Process and apparatus for upgrading hydrocarbon feeds containing sulfur, metals, and asphaltenes
US6187174B1 (en) * 1998-01-16 2001-02-13 Institut Francais Du Petrole Process for converting heavy petroleum fractions in an ebullated bed, with addition of a pre-conditioned catalyst
US6190537B1 (en) * 1998-05-22 2001-02-20 Zakrytoe Aktsionernoye Obschestove “Panjsher- Holding” Method for producing fuel distillates
US6194472B1 (en) * 1998-04-02 2001-02-27 Akzo Nobel N.V. Petroleum hydrocarbon in water colloidal dispersion
US6217746B1 (en) * 1999-08-16 2001-04-17 Uop Llc Two stage hydrocracking process
US6235190B1 (en) * 1998-08-06 2001-05-22 Uop Llc Distillate product hydrocracking process
US6241874B1 (en) * 1998-07-29 2001-06-05 Texaco Inc. Integration of solvent deasphalting and gasification
US20010002654A1 (en) * 1997-08-13 2001-06-07 Richard L. Hood Method of and means for upgrading hydrocarbons containing metals and asphaltenes
US6245222B1 (en) * 1998-10-23 2001-06-12 Exxon Research And Engineering Company Additive enhanced solvent deasphalting process (law759)
US6257334B1 (en) * 1999-07-22 2001-07-10 Alberta Oil Sands Technology And Research Authority Steam-assisted gravity drainage heavy oil recovery process
US6274030B1 (en) * 1998-12-23 2001-08-14 Texaco Inc. Filtration of feed to integration of solvent deasphalting and gasification
US6277270B1 (en) * 1998-03-23 2001-08-21 Institut Francais Du Petrole Process for converting heavy petroleum fractions that comprise a fixed-bed hydrotreatment stage, an ebullated-bed conversion stage, and a catalytic cracking stage
US20020003103A1 (en) * 1998-12-30 2002-01-10 B. Erik Henry Fluid cat cracking with high olefins prouduction
US6361682B1 (en) * 2000-03-16 2002-03-26 Kellogg Brown & Root, Inc. Pelletization of petroleum resids
US20020038778A1 (en) * 2000-05-01 2002-04-04 Maa Peter S. Process for upgrading residua
US20020100711A1 (en) * 2000-09-18 2002-08-01 Barry Freel Products produced form rapid thermal processing of heavy hydrocarbon feedstocks
US20030019790A1 (en) * 2000-05-16 2003-01-30 Trans Ionics Corporation Heavy oil upgrading processes
US6514403B1 (en) * 2000-04-20 2003-02-04 Abb Lummus Global Inc. Hydrocracking of vacuum gas and other oils using a cocurrent/countercurrent reaction system and a post-treatment reactive distillation system
US20030029775A1 (en) * 2001-06-11 2003-02-13 George Cymerman Staged settling process for removing water and solids from oils and extraction froth
US6524469B1 (en) * 2000-05-16 2003-02-25 Trans Ionics Corporation Heavy oil upgrading process
US6533925B1 (en) * 2000-08-22 2003-03-18 Texaco Development Corporation Asphalt and resin production to integration of solvent deasphalting and gasification
US6540904B1 (en) * 2000-03-03 2003-04-01 Suhas Ranjan Gun Process for the upgradation of petroleum residue
US6547956B1 (en) * 2000-04-20 2003-04-15 Abb Lummus Global Inc. Hydrocracking of vacuum gas and other oils using a post-treatment reactive distillation system
US20030075480A1 (en) * 2001-10-24 2003-04-24 Barco Processes Joint Venture Process for controlling oxidation of nitrogen and metals in circulating fluidized solids contacting process
US6558531B2 (en) * 2000-04-04 2003-05-06 Exxonmobil Chemical Patents Inc. Method for maintaining heat balance in a fluidized bed catalytic cracking unit
US20030085385A1 (en) * 2001-11-02 2003-05-08 Stellaccio Robert J Process for the gasification of heavy oil
US20030094400A1 (en) * 2001-08-10 2003-05-22 Levy Robert Edward Hydrodesulfurization of oxidized sulfur compounds in liquid hydrocarbons
US20030116470A1 (en) * 2001-12-26 2003-06-26 Philip Rettger Method of and apparatus for upgrading and gasifying heavy hydrocarbon feeds
US20030121828A1 (en) * 1999-04-16 2003-07-03 Mitchell Jacobson Process for deasphalting residua by reactive recycle of high boiling material
US20030122273A1 (en) * 2000-02-21 2003-07-03 Fifield John Alfred Building products
US20030129109A1 (en) * 1999-11-01 2003-07-10 Yoram Bronicki Method of and apparatus for processing heavy hydrocarbon feeds description
US6673231B2 (en) * 2001-02-20 2004-01-06 Sk Corporation Method for removing sludge in crude oil tank and recovering oil therefrom
US6689273B1 (en) * 1999-09-27 2004-02-10 Uop Llc Multireactor parallel flow hydrocracking process
US6690453B2 (en) * 2001-02-07 2004-02-10 Institut Francais Du Petrole Method and device for predicting the flocculation threshold of asphaltenes contained in hydrocarbon mixtures
US20040031725A1 (en) * 2000-10-24 2004-02-19 Shigeki Nagamatsu Refined oil and process for producing the same
US20040040892A1 (en) * 1999-09-24 2004-03-04 Institut Francais Du Petrole Gas/liquid separation system used in a hydrocarbonconversion process
US20040055972A1 (en) * 2002-09-19 2004-03-25 Garner William Nicholas Bituminous froth inclined plate separator and hydrocarbon cyclone treatment process
US20040055208A1 (en) * 2002-09-23 2004-03-25 Exxonmobil Upstream Research Company Integrated process for bitumen recovery, separation and emulsification for steam generation
US20040055706A1 (en) * 2001-02-08 2004-03-25 Hovenkamp Robert Christian Process for joining solid-state compositions
US20040072361A1 (en) * 2002-10-11 2004-04-15 Exxonmobil Research And Engineering Company Branched alkyl-aromatic sulfonic acid dispersants for dispersing asphaltenes in petroleum oils
US20040069685A1 (en) * 2000-11-30 2004-04-15 Makoto Inomata Method of refining petroleum
US20040118745A1 (en) * 2001-12-26 2004-06-24 Philip Rettger Method of and apparatus for upgrading and gasifying heavy hydrocarbon feeds
US20040163996A1 (en) * 2003-02-21 2004-08-26 Colyar James J. Effective integration of solvent deasphalting and ebullated-bed processing
US20050045558A1 (en) * 2003-09-02 2005-03-03 Northrup Aldrich Holt Liquid-liquid extraction apparatus and method
US20050167334A1 (en) * 2001-11-22 2005-08-04 Renaud Galeazzi Two-step method for middle distillate hydrotreatment comprising two hydrogen recycling loops
US20050167333A1 (en) * 2004-01-30 2005-08-04 Mccall Thomas F. Supercritical Hydrocarbon Conversion Process
US20060000749A1 (en) * 2004-07-02 2006-01-05 Ramesh Varadaraj Upgrading asphaltene containing oils
US20060021907A1 (en) * 2004-05-14 2006-02-02 Ramesh Varadaraj Inhibitor enhanced thermal upgrading of heavy oils
US20060042999A1 (en) * 2004-08-30 2006-03-02 Kellogg Brown And Root, Inc. Heavy Oil and Bitumen Upgrading
US7033486B2 (en) * 2002-04-01 2006-04-25 Exxonmobil Research And Engineering Company Residuum conversion process
US7048845B2 (en) * 2001-11-07 2006-05-23 Uop Llc Middle distillate selective hydrocracking process
US20060113076A1 (en) * 2003-06-13 2006-06-01 Nicolae Slemcu Substances to stimulate the extraction of crudeoil and a method of processing them
US20060116450A1 (en) * 2004-12-01 2006-06-01 Fina Technology, Inc. Reduction of sulfur emissions from crude fractions
US20060118466A1 (en) * 2001-11-22 2006-06-08 Renaud Galeazzi Two-step method for hydrotreating of a hydrocarbon feedstock comprising intermediate fractionation by rectification stripping
US20060144754A1 (en) * 2003-07-01 2006-07-06 Petrus Johannes Van Den Bosch Process to produce pipeline-transportable crude oil from feed stocks containing heavy hydrocarbons
US20060163115A1 (en) * 2002-12-20 2006-07-27 Eni S.P.A. Process for the conversion of heavy feedstocks such as heavy crude oils and distillation residues
US7169291B1 (en) * 2003-12-31 2007-01-30 Uop Llc Selective hydrocracking process using beta zeolite
US20070034550A1 (en) * 2005-08-09 2007-02-15 Hedrick Brian W Process and apparatus for improving flow properties of crude petroleum
US20070045156A1 (en) * 2005-08-16 2007-03-01 Khadzhiev Salambek N Process for hydroconverting of a heavy hydrocarbonaceous feedstock
US20070056881A1 (en) * 2005-09-14 2007-03-15 Stephen Dunn Method for extracting and upgrading of heavy and semi-heavy oils and bitumens
US20070108100A1 (en) * 2005-11-14 2007-05-17 Satchell Donald Prentice Jr Hydrogen donor solvent production and use in resid hydrocracking processes
US20070256736A1 (en) * 2006-04-20 2007-11-08 Anna Lee Tonkovich Process for treating and/or forming a non-newtonian fluid using microchannel process technology
US20080000644A1 (en) * 2006-04-21 2008-01-03 Tsilevich Maoz B System and method for steam-assisted gravity drainage (SAGD)-based heavy oil well production

Patent Citations (108)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US3159571A (en) * 1960-11-28 1964-12-01 Shell Oil Co Residual oil refining process
US3175966A (en) * 1962-09-24 1965-03-30 Cities Service Res & Dev Co Treatment of a crude hydrocarbon oil in several stages to produce refined lower boiling products
US3957628A (en) * 1974-12-30 1976-05-18 Exxon Research And Engineering Company Removal of organic sulfur compounds from hydrocarbon feedstocks
US4115246A (en) * 1977-01-31 1978-09-19 Continental Oil Company Oil conversion process
US4781819A (en) * 1983-07-06 1988-11-01 The British Petroleum Company P.L.C. Treatment of viscous crude oils
US4572781A (en) * 1984-02-29 1986-02-25 Intevep S.A. Solvent deasphalting in solid phase
US4686028A (en) * 1985-04-05 1987-08-11 Driesen Roger P Van Upgrading of high boiling hydrocarbons
US4931231A (en) * 1985-04-22 1990-06-05 American Colloid Company Method for manufacturing discrete pellets of asphaltic material
US5120427A (en) * 1988-05-23 1992-06-09 Uop High conversion high vaporization hydrocracking process
US5013427A (en) * 1989-07-18 1991-05-07 Amoco Corportion Resid hydrotreating with resins
US5228978A (en) * 1989-07-18 1993-07-20 Amoco Corporation Means for and methods of low sulfur and hydrotreated resids as input feedstreams
US4940529A (en) * 1989-07-18 1990-07-10 Amoco Corporation Catalytic cracking with deasphalted oil
US5124027A (en) * 1989-07-18 1992-06-23 Amoco Corporation Multi-stage process for deasphalting resid, removing catalyst fines from decanted oil and apparatus therefor
US5024750A (en) * 1989-12-26 1991-06-18 Phillips Petroleum Company Process for converting heavy hydrocarbon oil
US5026472A (en) * 1989-12-29 1991-06-25 Uop Hydrocracking process with integrated distillate product hydrogenation reactor
US5114562A (en) * 1990-08-03 1992-05-19 Uop Two-stage hydrodesulfurization and hydrogenation process for distillate hydrocarbons
US5135640A (en) * 1990-11-05 1992-08-04 Texaco Inc. High efficiency process for preparation of gasoline by catalytic cracking
US5098994A (en) * 1990-12-24 1992-03-24 Uop Process for separating a resin phase from a solvent solution containing a solvent, demetallized oil and a resin
US5192421A (en) * 1991-04-16 1993-03-09 Mobil Oil Corporation Integrated process for whole crude deasphalting and asphaltene upgrading
US5288681A (en) * 1991-08-26 1994-02-22 Uop Catalyst for the hydroconversion of asphaltene-containing hydrocarbonaceous charge stocks
US5318124A (en) * 1991-11-14 1994-06-07 Pecten International Company Recovering hydrocarbons from tar sand or heavy oil reservoirs
US5385663A (en) * 1992-06-18 1995-01-31 Uop Integrated hydrocracking-catalytic dewaxing process for the production of middle distillates
US5286371A (en) * 1992-07-14 1994-02-15 Amoco Corporation Process for producing needle coke
US5328591A (en) * 1992-10-13 1994-07-12 Mobil Oil Corporation Mechanical shattering of asphaltenes in FCC riser
US5393409A (en) * 1993-03-08 1995-02-28 Uop Hydrocracking process using a controlled porosity catalyst
US5607575A (en) * 1993-09-03 1997-03-04 Nippon Oil Co., Ltd. Process for removing iron impurities from petroleum oil distillation residues
US5601697A (en) * 1994-08-04 1997-02-11 Ashland Inc. Demetallation-High carbon conversion process, apparatus and asphalt products
US5626193A (en) * 1995-04-11 1997-05-06 Elan Energy Inc. Single horizontal wellbore gravity drainage assisted steam flooding process
US5785860A (en) * 1996-09-13 1998-07-28 University Of British Columbia Upgrading heavy oil by ultrafiltration using ceramic membrane
US5885440A (en) * 1996-10-01 1999-03-23 Uop Llc Hydrocracking process with integrated effluent hydrotreating zone
US5904835A (en) * 1996-12-23 1999-05-18 Uop Llc Dual feed reactor hydrocracking process
US6180683B1 (en) * 1997-03-10 2001-01-30 Clariant Gmbh Synergistic mixtures of alkylphenol-formaldehyde resins with oxalkylated amines as asphaltene dispersants
US5911875A (en) * 1997-04-07 1999-06-15 Siemens Westinghouse Power Corporation Method and system for generating power from residual fuel oil
US6274032B2 (en) * 1997-08-13 2001-08-14 Ormat Industries Ltd. Method of and means for upgrading hydrocarbons containing metals and asphaltenes
US20010002654A1 (en) * 1997-08-13 2001-06-07 Richard L. Hood Method of and means for upgrading hydrocarbons containing metals and asphaltenes
US5888377A (en) * 1997-12-19 1999-03-30 Uop Llc Hydrocracking process startup method
US6187174B1 (en) * 1998-01-16 2001-02-13 Institut Francais Du Petrole Process for converting heavy petroleum fractions in an ebullated bed, with addition of a pre-conditioned catalyst
US6277270B1 (en) * 1998-03-23 2001-08-21 Institut Francais Du Petrole Process for converting heavy petroleum fractions that comprise a fixed-bed hydrotreatment stage, an ebullated-bed conversion stage, and a catalytic cracking stage
US6194472B1 (en) * 1998-04-02 2001-02-27 Akzo Nobel N.V. Petroleum hydrocarbon in water colloidal dispersion
US6190537B1 (en) * 1998-05-22 2001-02-20 Zakrytoe Aktsionernoye Obschestove “Panjsher- Holding” Method for producing fuel distillates
US6241874B1 (en) * 1998-07-29 2001-06-05 Texaco Inc. Integration of solvent deasphalting and gasification
US6235190B1 (en) * 1998-08-06 2001-05-22 Uop Llc Distillate product hydrocracking process
US6183627B1 (en) * 1998-09-03 2001-02-06 Ormat Industries Ltd. Process and apparatus for upgrading hydrocarbon feeds containing sulfur, metals, and asphaltenes
US6274003B1 (en) * 1998-09-03 2001-08-14 Ormat Industries Ltd. Apparatus for upgrading hydrocarbon feeds containing sulfur, metals, and asphaltenes
US6245222B1 (en) * 1998-10-23 2001-06-12 Exxon Research And Engineering Company Additive enhanced solvent deasphalting process (law759)
US6274030B1 (en) * 1998-12-23 2001-08-14 Texaco Inc. Filtration of feed to integration of solvent deasphalting and gasification
US20020003103A1 (en) * 1998-12-30 2002-01-10 B. Erik Henry Fluid cat cracking with high olefins prouduction
US6171473B1 (en) * 1999-04-08 2001-01-09 Abb Lummus Global Inc. Integrated residue thermal cracking and partial oxidation process
US20030121828A1 (en) * 1999-04-16 2003-07-03 Mitchell Jacobson Process for deasphalting residua by reactive recycle of high boiling material
US6257334B1 (en) * 1999-07-22 2001-07-10 Alberta Oil Sands Technology And Research Authority Steam-assisted gravity drainage heavy oil recovery process
US6217746B1 (en) * 1999-08-16 2001-04-17 Uop Llc Two stage hydrocracking process
US20040040892A1 (en) * 1999-09-24 2004-03-04 Institut Francais Du Petrole Gas/liquid separation system used in a hydrocarbonconversion process
US6689273B1 (en) * 1999-09-27 2004-02-10 Uop Llc Multireactor parallel flow hydrocracking process
US20060032789A1 (en) * 1999-11-01 2006-02-16 Ormat Industries Ltd. Method of and apparatus for processing heavy hydrocarbon feeds
US20030129109A1 (en) * 1999-11-01 2003-07-10 Yoram Bronicki Method of and apparatus for processing heavy hydrocarbon feeds description
US6899839B2 (en) * 2000-02-21 2005-05-31 Shell Oil Company Building products
US20030122273A1 (en) * 2000-02-21 2003-07-03 Fifield John Alfred Building products
US6540904B1 (en) * 2000-03-03 2003-04-01 Suhas Ranjan Gun Process for the upgradation of petroleum residue
US6361682B1 (en) * 2000-03-16 2002-03-26 Kellogg Brown & Root, Inc. Pelletization of petroleum resids
US6558531B2 (en) * 2000-04-04 2003-05-06 Exxonmobil Chemical Patents Inc. Method for maintaining heat balance in a fluidized bed catalytic cracking unit
US6547956B1 (en) * 2000-04-20 2003-04-15 Abb Lummus Global Inc. Hydrocracking of vacuum gas and other oils using a post-treatment reactive distillation system
US6514403B1 (en) * 2000-04-20 2003-02-04 Abb Lummus Global Inc. Hydrocracking of vacuum gas and other oils using a cocurrent/countercurrent reaction system and a post-treatment reactive distillation system
US20030159973A1 (en) * 2000-05-01 2003-08-28 Maa Peter S. Process for upgrading residua
US20020038778A1 (en) * 2000-05-01 2002-04-04 Maa Peter S. Process for upgrading residua
US20030019790A1 (en) * 2000-05-16 2003-01-30 Trans Ionics Corporation Heavy oil upgrading processes
US6524469B1 (en) * 2000-05-16 2003-02-25 Trans Ionics Corporation Heavy oil upgrading process
US6533925B1 (en) * 2000-08-22 2003-03-18 Texaco Development Corporation Asphalt and resin production to integration of solvent deasphalting and gasification
US20020100711A1 (en) * 2000-09-18 2002-08-01 Barry Freel Products produced form rapid thermal processing of heavy hydrocarbon feedstocks
US20040031725A1 (en) * 2000-10-24 2004-02-19 Shigeki Nagamatsu Refined oil and process for producing the same
US20040069685A1 (en) * 2000-11-30 2004-04-15 Makoto Inomata Method of refining petroleum
US6690453B2 (en) * 2001-02-07 2004-02-10 Institut Francais Du Petrole Method and device for predicting the flocculation threshold of asphaltenes contained in hydrocarbon mixtures
US20040055706A1 (en) * 2001-02-08 2004-03-25 Hovenkamp Robert Christian Process for joining solid-state compositions
US6673231B2 (en) * 2001-02-20 2004-01-06 Sk Corporation Method for removing sludge in crude oil tank and recovering oil therefrom
US20030029775A1 (en) * 2001-06-11 2003-02-13 George Cymerman Staged settling process for removing water and solids from oils and extraction froth
US6746599B2 (en) * 2001-06-11 2004-06-08 Aec Oil Sands Limited Partnership Staged settling process for removing water and solids from oils and extraction froth
US20030094400A1 (en) * 2001-08-10 2003-05-22 Levy Robert Edward Hydrodesulfurization of oxidized sulfur compounds in liquid hydrocarbons
US20030075480A1 (en) * 2001-10-24 2003-04-24 Barco Processes Joint Venture Process for controlling oxidation of nitrogen and metals in circulating fluidized solids contacting process
US6773630B2 (en) * 2001-11-02 2004-08-10 Texaco Inc. Process for the gasification of heavy oil
US20030085385A1 (en) * 2001-11-02 2003-05-08 Stellaccio Robert J Process for the gasification of heavy oil
US7048845B2 (en) * 2001-11-07 2006-05-23 Uop Llc Middle distillate selective hydrocracking process
US20060118466A1 (en) * 2001-11-22 2006-06-08 Renaud Galeazzi Two-step method for hydrotreating of a hydrocarbon feedstock comprising intermediate fractionation by rectification stripping
US20050167334A1 (en) * 2001-11-22 2005-08-04 Renaud Galeazzi Two-step method for middle distillate hydrotreatment comprising two hydrogen recycling loops
US20030116470A1 (en) * 2001-12-26 2003-06-26 Philip Rettger Method of and apparatus for upgrading and gasifying heavy hydrocarbon feeds
US20040118745A1 (en) * 2001-12-26 2004-06-24 Philip Rettger Method of and apparatus for upgrading and gasifying heavy hydrocarbon feeds
US6702936B2 (en) * 2001-12-26 2004-03-09 Ormat Industries Ltd. Method of and apparatus for upgrading and gasifying heavy hydrocarbon feeds
US7033486B2 (en) * 2002-04-01 2006-04-25 Exxonmobil Research And Engineering Company Residuum conversion process
US20060138036A1 (en) * 2002-09-19 2006-06-29 Garner William N Bituminous froth inclined plate separator and hydrocarbon cyclone treatment process
US20060138055A1 (en) * 2002-09-19 2006-06-29 Garner William N Bituminous froth hydrocarbon cyclone
US20040055972A1 (en) * 2002-09-19 2004-03-25 Garner William Nicholas Bituminous froth inclined plate separator and hydrocarbon cyclone treatment process
US20040055208A1 (en) * 2002-09-23 2004-03-25 Exxonmobil Upstream Research Company Integrated process for bitumen recovery, separation and emulsification for steam generation
US20040072361A1 (en) * 2002-10-11 2004-04-15 Exxonmobil Research And Engineering Company Branched alkyl-aromatic sulfonic acid dispersants for dispersing asphaltenes in petroleum oils
US20060163115A1 (en) * 2002-12-20 2006-07-27 Eni S.P.A. Process for the conversion of heavy feedstocks such as heavy crude oils and distillation residues
US20040163996A1 (en) * 2003-02-21 2004-08-26 Colyar James J. Effective integration of solvent deasphalting and ebullated-bed processing
US20060113076A1 (en) * 2003-06-13 2006-06-01 Nicolae Slemcu Substances to stimulate the extraction of crudeoil and a method of processing them
US20060144754A1 (en) * 2003-07-01 2006-07-06 Petrus Johannes Van Den Bosch Process to produce pipeline-transportable crude oil from feed stocks containing heavy hydrocarbons
US20050045558A1 (en) * 2003-09-02 2005-03-03 Northrup Aldrich Holt Liquid-liquid extraction apparatus and method
US7169291B1 (en) * 2003-12-31 2007-01-30 Uop Llc Selective hydrocracking process using beta zeolite
US20050167333A1 (en) * 2004-01-30 2005-08-04 Mccall Thomas F. Supercritical Hydrocarbon Conversion Process
US20060021907A1 (en) * 2004-05-14 2006-02-02 Ramesh Varadaraj Inhibitor enhanced thermal upgrading of heavy oils
US20060000749A1 (en) * 2004-07-02 2006-01-05 Ramesh Varadaraj Upgrading asphaltene containing oils
US20060042999A1 (en) * 2004-08-30 2006-03-02 Kellogg Brown And Root, Inc. Heavy Oil and Bitumen Upgrading
US20060116450A1 (en) * 2004-12-01 2006-06-01 Fina Technology, Inc. Reduction of sulfur emissions from crude fractions
US20070034550A1 (en) * 2005-08-09 2007-02-15 Hedrick Brian W Process and apparatus for improving flow properties of crude petroleum
US20070045156A1 (en) * 2005-08-16 2007-03-01 Khadzhiev Salambek N Process for hydroconverting of a heavy hydrocarbonaceous feedstock
US20070056881A1 (en) * 2005-09-14 2007-03-15 Stephen Dunn Method for extracting and upgrading of heavy and semi-heavy oils and bitumens
US20070108100A1 (en) * 2005-11-14 2007-05-17 Satchell Donald Prentice Jr Hydrogen donor solvent production and use in resid hydrocracking processes
US20070256736A1 (en) * 2006-04-20 2007-11-08 Anna Lee Tonkovich Process for treating and/or forming a non-newtonian fluid using microchannel process technology
US20080000644A1 (en) * 2006-04-21 2008-01-03 Tsilevich Maoz B System and method for steam-assisted gravity drainage (SAGD)-based heavy oil well production

Cited By (20)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20120091032A1 (en) * 2010-10-15 2012-04-19 Kellogg Brown & Root Llc Flash Processing A Solvent Deasphalting Feed
US8728300B2 (en) * 2010-10-15 2014-05-20 Kellogg Brown & Root Llc Flash processing a solvent deasphalting feed
US20140366539A1 (en) * 2012-01-03 2014-12-18 Douglas W. Hissong Power Generation Using Non-Aqueous Solvent
US9719380B2 (en) * 2012-01-03 2017-08-01 Exxonmobil Upstream Research Company Power generation using non-aqueous solvent
US20130225838A1 (en) * 2012-02-26 2013-08-29 Cpc Corporation, Taiwan Regeneration of Selective Solvents for Extractive Processes
US9440947B2 (en) * 2012-02-26 2016-09-13 Amt International, Inc. Regeneration of selective solvents for extractive processes
WO2014006165A2 (en) * 2012-07-06 2014-01-09 Statoil Canada Limited Method
WO2014006165A3 (en) * 2012-07-06 2014-10-02 Statoil Canada Limited A method of recovering a hydrocarbon mixture from a subterranean formation
US9670766B2 (en) 2012-07-06 2017-06-06 Statoil Canada Limited Method and system for recovering and processing hydrocarbon mixture
US20140275676A1 (en) * 2013-03-14 2014-09-18 Lummus Technology Inc. Process for producing distillate fuels and anode grade coke from vacuum resid
US9452955B2 (en) * 2013-03-14 2016-09-27 Lummus Technology Inc. Process for producing distillate fuels and anode grade coke from vacuum resid
CN104212473B (en) * 2013-06-03 2016-12-28 中国石油化工股份有限公司 A kind of device producing road asphalt raw material
CN104212473A (en) * 2013-06-03 2014-12-17 中国石油化工股份有限公司 Device for producing road asphalt raw material
US20150008156A1 (en) * 2013-07-04 2015-01-08 S.A. Imperbel N.V. Bitumen
US9796852B2 (en) * 2013-07-04 2017-10-24 S.A. Imperbel N.V. Bitumen
WO2017182187A1 (en) * 2016-04-22 2017-10-26 Siemens Aktiengesellschaft Method for purifying an asphaltene-containing fuel
CN109072092A (en) * 2016-04-22 2018-12-21 西门子股份公司 Method for purifying bitumeniferous fuel
US10125318B2 (en) 2016-04-26 2018-11-13 Saudi Arabian Oil Company Process for producing high quality coke in delayed coker utilizing mixed solvent deasphalting
US10233394B2 (en) 2016-04-26 2019-03-19 Saudi Arabian Oil Company Integrated multi-stage solvent deasphalting and delayed coking process to produce high quality coke
US10351778B2 (en) 2016-05-23 2019-07-16 Kellogg Brown & Root Llc Systems for producing anode grade coke from high sulfur crude oils

Similar Documents

Publication Publication Date Title
US9187701B2 (en) Reactions with undesirable components in a coking process
RU2628067C2 (en) Method for producing distillate fuel and anode grade coke from vacuum resid
US9434888B2 (en) Methods and systems for producing reduced resid and bottomless products from heavy hydrocarbon feedstocks
US10233400B2 (en) Integrated hydrotreating, solvent deasphalting and steam pyrolysis system for direct processing of a crude oil
Speight Heavy and extra-heavy oil upgrading technologies
EP0121376B1 (en) Process for upgrading a heavy viscous hydrocarbon
US10246651B2 (en) Integrated solvent deasphalting, hydrotreating and steam pyrolysis system for direct processing of a crude oil
US9637694B2 (en) Upgrading hydrocarbon pyrolysis products
US7572362B2 (en) Modified thermal processing of heavy hydrocarbon feedstocks
AU2003293938B2 (en) Process for the conversion of heavy feedstocks such as heavy crude oils and distillation residues
US8017000B2 (en) Process for the conversion of heavy feedstocks such as heavy crude oils and distillation residues
CA2617806C (en) Process and apparatus for improving flow properties of crude petroleum
RU2394067C2 (en) Improvement of heavy crude and bitumen processing
US20190136139A1 (en) Integrated process to produce asphalt and desulfurized oil
US9574144B2 (en) Process for oxidative desulfurization and denitrogenation using a fluid catalytic cracking (FCC) unit
US6524469B1 (en) Heavy oil upgrading process
KR101886858B1 (en) Process for stabilization of heavy hydrocarbons
ES2395116T3 (en) Products produced from rapid thermal processing of heavy hydrocarbon raw materials
US5258117A (en) Means for and methods of removing heavy bottoms from an effluent of a high temperature flash drum
JP2018087355A (en) High-rate reactor system
KR101592856B1 (en) Systems and Methods for Producing a Crude Product
CN100467575C (en) Converting process of heavy material, such as heavy raw oil and distilled residue
US7572365B2 (en) Modified thermal processing of heavy hydrocarbon feedstocks
US5124027A (en) Multi-stage process for deasphalting resid, removing catalyst fines from decanted oil and apparatus therefor
US8709233B2 (en) Disposition of steam cracked tar

Legal Events

Date Code Title Description
AS Assignment

Owner name: KELLOGG BROWN & ROOT LLC, TEXAS

Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNORS:SUBRAMANIAN, ANAND, MR.;FLOYD, RAYMOND, MR.;REEL/FRAME:023431/0651

Effective date: 20090205

AS Assignment

Owner name: BANK OF AMERICA, N.A., AS ADMINISTRATIVE AGENT, NORTH CAROLINA

Free format text: SECURITY INTEREST;ASSIGNOR:KELLOGG BROWN & ROOT LLC;REEL/FRAME:046022/0413

Effective date: 20180425

Owner name: BANK OF AMERICA, N.A., AS ADMINISTRATIVE AGENT, NO

Free format text: SECURITY INTEREST;ASSIGNOR:KELLOGG BROWN & ROOT LLC;REEL/FRAME:046022/0413

Effective date: 20180425

STPP Information on status: patent application and granting procedure in general

Free format text: NON FINAL ACTION MAILED

STCB Information on status: application discontinuation

Free format text: ABANDONED -- FAILURE TO RESPOND TO AN OFFICE ACTION