[go: up one dir, main page]

WO2012121804A4 - Hydrocarbon viscosity reduction method - Google Patents

Hydrocarbon viscosity reduction method Download PDF

Info

Publication number
WO2012121804A4
WO2012121804A4 PCT/US2012/021317 US2012021317W WO2012121804A4 WO 2012121804 A4 WO2012121804 A4 WO 2012121804A4 US 2012021317 W US2012021317 W US 2012021317W WO 2012121804 A4 WO2012121804 A4 WO 2012121804A4
Authority
WO
WIPO (PCT)
Prior art keywords
hydrocarbon
sorbent
heating
solvent
viscosity reduction
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.)
Ceased
Application number
PCT/US2012/021317
Other languages
French (fr)
Other versions
WO2012121804A1 (en
Inventor
John F. Schabron
Joseph F. Rovani, Jr.
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.)
University of Wyoming Research Corp (dba Western Research Institute)
University of Wyoming
Original Assignee
University of Wyoming Research Corp (dba Western Research Institute)
University of Wyoming
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 University of Wyoming Research Corp (dba Western Research Institute), University of Wyoming filed Critical University of Wyoming Research Corp (dba Western Research Institute)
Priority to EP12754614.1A priority Critical patent/EP2683795A4/en
Priority to US14/004,023 priority patent/US20140021101A1/en
Priority to CA2829291A priority patent/CA2829291A1/en
Publication of WO2012121804A1 publication Critical patent/WO2012121804A1/en
Publication of WO2012121804A4 publication Critical patent/WO2012121804A4/en
Priority to US13/723,058 priority patent/US20130104772A1/en
Anticipated expiration legal-status Critical
Priority to US15/358,991 priority patent/US20190299180A9/en
Priority to US16/183,584 priority patent/US10449502B2/en
Priority to US16/358,337 priority patent/US10994252B2/en
Ceased legal-status Critical Current

Links

Classifications

    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING 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
    • C10G25/00—Refining of hydrocarbon oils in the absence of hydrogen, with solid sorbents
    • C10G25/003—Specific sorbent material, not covered by C10G25/02 or C10G25/03
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING 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
    • C10G21/00—Refining of hydrocarbon oils, in the absence of hydrogen, by extraction with selective solvents
    • C10G21/30—Controlling or regulating
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING 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
    • C10G25/00—Refining of hydrocarbon oils in the absence of hydrogen, with solid sorbents
    • C10G25/12—Recovery of used adsorbent
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING 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
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/20—Characteristics of the feedstock or the products
    • C10G2300/201—Impurities
    • C10G2300/205—Metal content
    • C10G2300/206—Asphaltenes
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING 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
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/20—Characteristics of the feedstock or the products
    • C10G2300/30—Physical properties of feedstocks or products
    • C10G2300/302—Viscosity
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING 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
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/40—Characteristics of the process deviating from typical ways of processing
    • C10G2300/4043—Limiting CO2 emissions
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING 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
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/40—Characteristics of the process deviating from typical ways of processing
    • C10G2300/44—Solvents
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING 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
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/80—Additives
    • C10G2300/802—Diluents

Landscapes

  • Chemical & Material Sciences (AREA)
  • Oil, Petroleum & Natural Gas (AREA)
  • Engineering & Computer Science (AREA)
  • Chemical Kinetics & Catalysis (AREA)
  • General Chemical & Material Sciences (AREA)
  • Organic Chemistry (AREA)
  • Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)

Abstract

In accordance with particular descriptions provided herein, certain embodiments of the inventive technology may be described as a hydrocarbon viscosity reduction method that comprises the steps of: treating a hydrocarbon having asphaltenes therein to generate a treated hydrocarbon, wherein said hydrocarbon has a first viscosity; contacting said treated hydrocarbon with a sorbent (whether as a result of pouring or other means); and adsorbing at least a portion of said asphaltenes onto said sorbent, thereby removing said at least a portion of said asphaltenes from said hydrocarbon so as to generate a viscosity reduced hydrocarbon having a second viscosity that is lower than said first viscosity.

Claims

AMENDED CLAIMS received by the International Bureau on 27 August 2012 (27.08.2012) What is claimed is:
1. A hydrocarbon viscosity reduction method comprising the steps of:
- treating a hydrocarbon having asphaltenes therein to generate a treated hydrocarbon, wherein said hydrocarbon has a first viscosity;
- adsorbing at least a portion of said asphaltenes onto said sorbent, thereby removing said at least a portion of said asphaltenes from said treated hydrocarbon so as to generate a viscosity reduced hydrocarbon having a second viscosity that is lower than said first viscosity.
2. A hydrocarbon viscosity reduction method as described in claim 1 wherein said sorbent is a stationary phase sorbent.
3. A hydrocarbon viscosity reduction method as described in claim 1 wherein said sorbent is a solid sorbent.
4. A hydrocarbon viscosity reduction method as described in claim 3 wherein said sorbent is a fixed bed.
5. A hydrocarbon viscosity reduction method as described in claim 3 wherein said sorbent is a fluidized bed.
6. A hydrocarbon viscosity reduction method as described in claim 3 wherein said sorbent is surfaced.
7. A hydrocarbon viscosity reduction method as described in claim 3 wherein said sorbent is a porous membrane.
8. A hydrocarbon viscosity reduction method as described in claim 3 wherein said sorbent is high surface energy.
9. A hydrocarbon viscosity reduction method as described in claim 3 wherein said sorbent is highly aromatic.
10. A hydrocarbon viscosity reduction method as described in claim 3 wherein said sorbent is selective to adsorption of said asphaltenes.
11. A hydrocarbon viscosity reduction method as described in claim 3 wherein said sorbent is a sorbent selected from the group consisting of: metals, steel, steel wire, steel wire coils,
1
AI^®M©hffiffi^¾i#mLCe-fe19) metal wire, metal wire coils, ceramics, zeolites, clays, silica, limestone, glass, mesh glass, glass beads, mesh glass beads, quartz, sand, alumina, and high surface energy carbonaceous materials.
12. A hydrocarbon viscosity reduction method as described in claim 3 wherein said sorbent is a salt, acid or base.
13. A hydrocarbon viscosity reduction method as described in claim 3 wherein said sorbent comprises a carbon based sorbent.
14. A hydrocarbon viscosity reduction method as described in claim 13 further comprising the step of burning said carbon based sorbent as fuel.
15. A hydrocarbon viscosity reduction method as described in claim 1 wherein said hydrocarbon comprises a hydrocarbon selected from the group consisting of bitumen, shale oil, coal oil, coal tar, biological oil, heavy oil or residuum.
16. A hydrocarbon viscosity reduction method as described in claim 1 wherein said hydrocarbon comprises an atmospheric bitumen.
17. A hydrocarbon viscosity reduction method as described in claim 1 wherein said hydrocarbon comprises a vacuum bitumen.
18. A hydrocarbon viscosity reduction method as described in claim 1 wherein said step of treating a hydrocarbon comprises the step of heating said hydrocarbon.
19. A hydrocarbon viscosity reduction method as described in claim 18 wherein said step of heating said hydrocarbon comprises the step of heating said hydrocarbon to a temperature that is below a cracking temperature.
20. A hydrocarbon viscosity reduction method as described in claim 18 wherein said step of heating said hydrocarbon comprises the step of heating said hydrocarbon from a heat source that is upstream of said sorbent.
21. A hydrocarbon viscosity reduction method as described in claim 18 further comprising the step of heating said sorbent to generate a heated sorbent.
22. A hydrocarbon viscosity reduction method as described in claim 21 wherein said step of heating said sorbent to generate a heated sorbent comprises the step of heating said sorbent to a temperature below a cracking temperature.
23. A hydrocarbon viscosity reduction method as described in claim 21 wherein said step of heating said hydrocarbon comprises the step of contacting said hydrocarbon with said heated sorbent.
24. A hydrocarbon viscosity reduction method as described in claim 23 wherein said step of heating said hydrocarbon further comprises the step of heating said hydrocarbon with heat from a source other than said heated sorbent.
25. A hydrocarbon viscosity reduction method as described in claim 23 further comprising the step of cooling said hydrocarbon upon contact of said hydrocarbon with said heated sorbent.
26. A hydrocarbon viscosity reduction method as described in claim 19 wherein said step of heating said hydrocarbon comprises the step of separating the most aromatic and refractory molecules from peptizing molecules associated therewith.
27. A hydrocarbon viscosity reduction method as described in claim 19 wherein said step of heating said hydrocarbon comprises the step of depeptizing said hydrocarbon.
28. A hydrocarbon viscosity reduction method as described in claim 19 wherein said step of heating said hydrocarbon comprises the step of heating said hydrocarbon to below 340C.
29. A hydrocarbon viscosity reduction method as described in claim 28 wherein said step of heating said hydrocarbon comprises the step of heating said hydrocarbon from 200-250C.
30. A hydrocarbon viscosity reduction method as described in claim 28 wherein said step of heating said hydrocarbon comprises the step of heating said hydrocarbon from 150-300C.
31. A hydrocarbon viscosity reduction method as described in claim 28 wherein said step of heating said hydrocarbon comprises the step of heating said hydrocarbon from 100-340C.
32. A hydrocarbon viscosity reduction method as described in claim 19 further comprises the step of rinsing said sorbent with an aromatic solvent.
33. A hydrocarbon viscosity reduction method as described in claim 32 wherein said step of rinsing said sorbent comprises the step of rinsing said sorbent with strong chromatographic extraction solvent.
34. A hydrocarbon viscosity reduction method as described in claim 33 wherein said step of rinsing said sorbent comprises the step of rinsing with a halogenated solvent, an aromatic solvent, an alcohol, or a mixture thereof.
35. A hydrocarbon viscosity reduction method as described in claim 19 wherein said step of heating said hydrocarbon comprises the step of reversibly heating said hydrocarbon.
36. A hydrocarbon viscosity reduction method as described in claim 19 wherein said step of treating said hydrocarbon further comprises the step of adding a solvent thereto.
37. A hydrocarbon viscosity reduction method as described in claim 19 wherein said step of heating said hydrocarbon occurs for a heating time.
38. A hydrocarbon viscosity reduction method as described in claim 37 further comprising the step of optimizing said heating time.
39. A hydrocarbon viscosity reduction method as described in claim 18 wherein said step of heating said hydrocarbon comprises the step of heating said hydrocarbon to a cracking temperature.
40. A hydrocarbon viscosity reduction method as described in claim 39 wherein said step of heating said hydrocarbon comprises the step of heating said hydrocarbon from a heat source that is upstream of said sorbent.
41. A hydrocarbon viscosity reduction method as described in claim 39 further comprising the step of heating said sorbent to generate a heated sorbent.
42. A hydrocarbon viscosity reduction method as described in claim 41 wherein said step of heating said sorbent to generate a heated sorbent comprises the step of heating said sorbent to a cracking temperature.
43. A hydrocarbon viscosity reduction method as described in claim 41 wherein said step of heating said sorbent to generate a heated sorbent comprises the step of heating said sorbent to a temperature below a cracking temperature.
44. A hydrocarbon viscosity reduction method as described in claim 41 wherein said step of heating said hydrocarbon comprises the step of contacting said hydrocarbon with said heated sorbent.
45. A hydrocarbon viscosity reduction method as described in claim 44 wherein said step of heating said hydrocarbon further comprises the step of heating said hydrocarbon with heat from a source other than said heated sorbent.
46. A hydrocarbon viscosity reduction method as described in claim 44 further comprising the step of cooling said treated hydrocarbon by contacting it with said heated sorbent
47. A hydrocarbon viscosity reduction method as described in claim 39 wherein said step of treating said hydrocarbon further comprises the step of cooling said hydrocarbon to a temperature below a minimum cracking temperature before contacting said hydrocarbon with said sorbent.
48. A hydrocarbon viscosity reduction method as described in claim 47 further comprising the step of heating said sorbent to a temperature less that said minimum cracking temperature.
49. A hydrocarbon viscosity reduction method as described in claim 39 wherein said step of heating said hydrocarbon comprises the step of irreversibly heating said hydrocarbon.
50. A hydrocarbon viscosity reduction method as described in claim 39 wherein said step of heating said hydrocarbon comprises the step of heating said hydrocarbon to or above 340C.
51. A hydrocarbon viscosity reduction method as described in claim 39 further comprising the step of minimizing the need for subsequent hydrogen addition.
52. A hydrocarbon viscosity reduction method as described in claim 39 wherein said step of treating said hydrocarbon further comprises the step of adding a solvent thereto.
53. A hydrocarbon viscosity reduction method as described in claim 18 wherein said step of treating is solventless.
54. A hydrocarbon viscosity reduction method as described in claim 18 wherein said step of heating said hydrocarbon is performed in an inert gas atmosphere.
55. A hydrocarbon viscosity reduction method as described in claim 1 wherein said step of treating said hydrocarbon comprises the step of adding a substance to said hydrocarbon, wherein said substance is selected from the group consisting of solvent and chemical additive.
56. A hydrocarbon viscosity reduction method as described in claim 55 wherein said solvent comprises a low polarity solvent.
57. A hydrocarbon viscosity reduction method as described in claim 55 wherein performance of said step of adding a substance does not effect asphaltene precipitation.
58. A hydrocarbon viscosity reduction method as described in claim 55 wherein said step of adding a substance to said hydrocarbon comprises the step of adding a substance selected from the group consisting of a polar material, an aromatic material, and an acid or base.
59. A hydrocarbon viscosity reduction method as described in claim 55 wherein said step of treating said hydrocarbon further comprises the step of heating said hydrocarbon.
60. A hydrocarbon viscosity reduction method as described in claim 1 wherein said step of adsorbing at least a portion of said asphaltenes onto said sorbent comprises the step of adsorbing at least a portion of the most pericondensed aromatic structures of said hydrocarbon.
61. A hydrocarbon viscosity reduction method as described in claim 1 wherein said step of adsorbing at least a portion of said asphaltenes onto said sorbent comprises the step of adsorbing at least a portion of the most pericondensed, aromatic and refractory structures of said hydrocarbon.
62. A hydrocarbon viscosity reduction method as described in claim 1 wherein said step of adsorbing at least a portion of said asphaltenes onto said sorbent comprises the step of adsorbing at least a portion of the most pericondensed and highest surface energy pre- coke asphaltene materials.
63. A hydrocarbon viscosity reduction method as described in claim 1 wherein said step of adsosrbing at least a portion of said asphaltenes occurs during a sorbent contact time.
64. A hydrocarbon viscosity reduction method as described in claim 63 further comprising the step of optimizing said sorbent contact time.
65. A hydrocarbon viscosity reduction method as described in claim 1 further comprising the step of heating said sorbent to generate a heated sorbent.
66. A hydrocarbon viscosity reduction method as described in claim 65 wherein said step of treating said hydrocarbon comprises the step of contacting said hydrocarbon with said heated sorbent.
67. A hydrocarbon viscosity reduction method as described in claim 1 further comprising the step of adding a diluent amount to said viscosity reduced hydrocarbon so as to generate a diluted hydrocarbon having a diluted hydrocarbon viscosity that is no greater than a certain viscosity.
68. A hydrocarbon viscosity reduction method as described in claim 67 wherein said certain viscosity is governed by pipeline specifications.
69. A hydrocarbon viscosity reduction method as described in claim 67 wherein said diluent amount is less than that untreated hydrocarbon diluent amount required to reduce viscosity of an untreated hydrocarbon to said diluted hydrocarbon viscosity.
70. A hydrocarbon viscosity reduction method as described in claim 1 further comprising the step of contacting a material with a sorbent by pouring said material over said sorbent, wherein said material comprises a material selected from the group consisting of said treated hydrocarbon and said hydrocarbon.
71. A hydrocarbon viscosity reduction method as described in claim 1 further comprising the step of contacting a material with a sorbent by mixing said material with said sorbent, wherein said material comprises a material selected from the group consisting of said treated hydrocarbon and said hydrocarbon.
72. A new method for transporting a hydrocarbon, comprising the steps of:
- treating an untreated hydrocarbon to generate a treated hydrocarbon, and thereby lowering viscosity of said untreated hydrocarbon to a treated hydrocarbon viscosity;
- adding an amount of diluent to said treated hydrocarbon to generate a diluted hydrocarbon, thereby further lowering said treated hydrocarbon viscosity to a pipeline specification viscosity, wherein said amount of diluent is less than a conventional amount of diluent required to reduce said viscosity of said untreated hydrocarbon to said pipeline specification viscosity; and
- pumping said diluted hydrocarbon.
73. A new method for transporting a hydrocarbon as described in claim 72 wherein said step of treating an untreated hydrocarbon comprises the step of removing at least a portion of asphaltenes from said untreated hydrocarbon.
74. A new method for transporting a hydrocarbon as described in claim 73 wherein said step of removing at least a portion of said asphaltenes from said untreated hydrocarbon comprises the step of heating said hydrocarbon and contacting said hydrocarbon with a solid sorbent.
75. A new method for transporting a hydrocarbon as described in claim 74 wherein said steps of heating said hydrocarbon is performed upstream of said step of contacting said hydrocarbon with a solid sorbent occur.
76. A new method for transporting a hydrocarbon as described in claim 74 further comprising the step of heating said solid sorbent to generate a heated sorbent.
77. A new method for transporting a hydrocarbon as described in claim 76 further comprising the step of heating said hydrocarbon with heat from said heated sorbent.
78. A new method for transporting a hydrocarbon as described in claim 73 wherein said step of treating said hydrocarbon comprises the step of adding a substance to said hydrocarbon, wherein said substance is selected from the group consisting of solvent and chemical additive.
79. A new method for transporting a hydrocarbon as described in claim 72 wherein said amount of diluent is a weight percentage of diluent for a given weight of treated hydrocarbon.
80. A new method for transporting a hydrocarbon as described in claim 72 wherein said conventional amount of diluent is a weight percentage of diluent for a given weight of untreated hydrocarbon.
81. A new method for transporting a hydrocarbon as described in claim 72 further comprising the step of removing said diluent from said diluted hydrocarbon.
82. A new method for transporting a hydrocarbon as described in claim 72 further comprising the step of reducing greenhouse gas emissions.
83. A new method for transporting a hydrocarbon as described in claim 72 further comprising the step of reducing hydrocarbon piping costs.
84. A new method for transporting a hydrocarbon as described in claim 72 further
comprising the step of increasing transportation operation efficiency.
85. A new method for transporting a hydrocarbon as described in claim 72 wherein said
diluted hydrocarbon is subsequently processed.
86. A new method for transporting a hydrocarbon as described in claim 72 wherein said
diluted hydrocarbon has a reduced fouling tendency.
87. A new method for transporting a hydrocarbon as described in claim 86 wherein said
fouling tendency is a tendency to foul an element selected from the group consisting of heat exchangers, pipes and refinery components.
88. An new method for transporting a hydrocarbon as described in claim 86 wherein said fouling tendency is a tendency to foul due to asphaltene deposition.
89. A new method for transporting a hydrocarbon as described in claim 86 wherein said fouling tendency is a tendency to foul during distillation.
90. The diluted hydrocarbon of claim 72.
91. The viscosity reduced hydrocarbon generated upon performance of the hydrocarbon
viscosity reduction method of claim 1.
92. A refinery or apparatus in which the method of claim 1 is performed.
93. A refinery that processes hydrocarbons based on analysis results generated, at least in part, upon performance of the method of claim 1.
94. A hydrocarbon viscosity reduction method as described in claim 1 wherein said viscosity reduced hydrocarbon is subsequently processed.
95. A hydrocarbon viscosity reduction method as described in claim 1 wherein said viscosity reduced hydrocarbon has a reduced fouling tendency.
96. A hydrocarbon viscosity reduction method as described in claim 35 wherein said fouling tendency is a tendency to foul an element selected from the group consisting of heat exchangers, pipes and refinery components.
97. A hydrocarbon viscosity reduction method as described in claim 95 wherein said fouling tendency is a tendency to foul due to asphaltene deposition.
98. A hydrocarbon viscosity reduction method as described in claim 95 wherein said fouling tendency is a tendency to foul during distillation.
99. A method of monitoring the efficiency of sorbent based asphaltene removal, said method comprising the steps of:
- providing a vessel having a substantially chemically inert stationary phase established therein and having at least one vessel inlet, said substantially chemically inert stationary phase forming a fixed bed in said vessel;
- inputting a precipitant solvent into said vessel through at least one vessel inlet;
- inputting a hydrocarbonaceous material generated by said sorbent based asphaltene removal into said vessel through at least one vessel inlet;
- intentionally precipitating asphaltenes within said vessel and in the presence of said substantially chemically inert stationary phase, wherein said substantially chemically inert stationary phase is substantially chemically inert relative to said asphaltenes such that substantially all said precipitated asphaltenes do not adsorb onto said substantially chemically inert stationary phase;
- generating a remnant liquid upon performing said step of intentionally precipitating said asphaltenes;
- inputting a material dissolving solvent into said vessel through at least one vessel inlet; and
- dissolving at least a portion of said asphaltenes with said material dissolving solvent to generate a dissolved material solution,
- monitoring and controlling said sorbent based asphaltene removal.
100. A method as described in claim 99 wherein said step of inputting a hydrocarbonaceous material into said vessel through at least one vessel inlet comprises the step of inputting a hydrocarbon sample into said vessel.
101. A method as described in claim 100 wherein said step of inputting a hydrocarbon sample into said vessel through at least one vessel inlet comprises the step of inputting oil into said vessel.
102. A method as described in claim 100 wherein said step of inputting a hydrocarbon sample into said vessel through at least one vessel inlet comprises the step of inputting a wax component of oil into said vessel.
103. A method as described in claim 100 wherein said step of inputting a hydrocarbon sample into said vessel through at least one vessel inlet comprises the step of inputting an asphaltene into said vessel.
104. A method as described in claim 100 wherein said step of inputting a hydrocarbonaceous material into said vessel through at least one vessel inlet further comprises the step of inputting a sample in solution into said vessel.
105. A method as described in claim 100 wherein said substantially chemically inert stationary phase is also substantially chemically inert relative to said sample.
106. A method as described in claim 99 wherein said step of inputting a hydrocarbonaceous material into said vessel through at least one vessel inlet comprises the step of inputting oil into said vessel.
107. A method as described in claim 99 wherein said step of inputting a precipitant solvent into said vessel through at least one vessel inlet comprises the step of inputting into said vessel a precipitant solvent selected from the group consisting of low polarity solvents, low polarity solvent mixtures, aliphatic solvents, heptane, pentane and isooctane.
108. A method as described in claim 99 wherein said step of generating a remnant liquid
comprises the step of generating a remnant solution.
109. A method as described in claim 100 further comprising the step of determining at least one characteristic of said hydrocarbon sample.
110. A method as described in claim 109 wherein said step of determining at least one
characteristic of said sample comprises the step of using a technique selected from the group consisting of evaporative light scattering, mass spectrometry, optical absorbance, x-ray, conductivity, oxidation/reduction, refractive index, polarimetry, atomic spectroscopy, and fluorescence.
111. A method as described in claim 109 wherein said step of determining at least one
characteristic of said sample comprises the step of analyzing said remnant liquid.
112. A method as described in claim 109 wherein said step of determining at least one
characteristic of said sample comprises the step of determining a weight percentage of asphaltenes.
113. A method as described in claim 109 wherein said step of determining at least one
characteristic of said sample comprises the step of analyzing said dissolved material solution.
114. A method as described in claim 109 wherein said step of determining at least one
characteristic of said sample comprises the step of determining a mass fraction of heptane asphaltenes soluble in cyclohexane.
115. A method as described in claim 109 wherein said step of determining at least one
characteristic of said sample comprises the step of determining at least two characteristics of said sample.
116. A method as described in claim 114 wherein said step of determining at least two
characteristics of said sample comprises the step of determining a cyclohexane soluble peak value and a methylene chloride soluble peak value.
117. A method as described in claim 99 wherein said step of inputting a material dissolving solvent comprises the step of inputting a material dissolving solvent selected from the group consisting of solvents having a higher polarity than that of said precipitant solvent, solvent mixtures having a higher polarity than that of said precipitant solvent, naphthenic oils, aromatic oils, ketones, halogenated solvents, cyclohexane, toluene, cyclohexanone, and methylene chloride.
118. A method as described in claim 99 further comprising the step of separating said remnant liquid from said asphaltenes.
119. A method as described in claim 99 further comprising the step of removing said remnant liquid from said vessel.
120. A method as described in claim 119 further comprising the step of replacing said remnant liquid with said material dissolving solvent.
121. A method as described in claim 99 further comprising the step of eluting said dissolved material solution from said vessel.
122. A method as described in claim 99 wherein said step of inputting a material dissolving solvent into said vessel comprises the step of inputting cyclohexane, or a different solvent or solvent mixture with substantially the same polarity as cyclohexane.
123. A method as described in claim 99 wherein said step of dissolving at least a portion of said asphaltenes with said material dissolving solvent comprises the step of dissolving only a first portion of said asphaltenes with said material dissolving solvent.
124. A method as described in claim 123 further comprising the step of inputting a second material dissolving solvent into said vessel through at least one vessel inlet to dissolve at least a second portion of said asphaltenes.
125. A method as described in claim 124 wherein said step of inputting a second material dissolving solvent into said vessel comprises the step of inputting a stronger material dissolving solvent.
126. A method as described in claim 125 wherein said step of inputting a stronger material dissolving solvent into said vessel comprises the step of inputting into said vessel solvent that gradually increases in strength.
127. A method as described in claim 126 wherein said step of inputting into said vessel
solvent that gradually increases in strength is performed during continuous solvent flow.
128. A method as described in claim 125 wherein said strengths of said material dissolving solvents do not change in a step gradient fashion.
129. A method as described in claim 125 wherein said strengths of said material dissolving solvents change in a step gradient fashion.
130. A method as described in claim 123 further comprising the step of inputting increasingly stronger material dissolving solvent into said vessel to dissolve at least a second portion of said asphaltenes and generate a second dissolved material solution.
131. A method as described in claim 130 wherein said step of inputting increasingly stronger material dissolving solvent comprises the step of inputting material dissolving solvent that gradually increases in strength.
132. A method as described in claim 131 wherein said step of step of inputting material
dissolving solvent that gradually increases in strength is performed during continuous solvent flow.
133. A method as described in claim 130 where input solvent strengths do not change in a step gradient fashion.
134. A method as described in claim 124 further comprising the step of replacing said
dissolved material solution with said second material dissolving solvent.
135. A method as described in claim 124 wherein said step of inputting a second material dissolving solvent into said vessel comprises the step of inputting toluene, or a different solvent or solvent mixture with substantially the same polarity as toluene.
136. A method as described in claim 130 further comprising the steps of analyzing said second dissolved material solution.
137. A method as described in claim 130 wherein said step of inputting increasingly stronger material dissolving solvent into said vessel to dissolve at least a second portion of said asphaltenes comprises the step of inputting increasingly stronger material dissolving solvent into said vessel to dissolve said second and at least a third portion of said asphaltenes.
138. A method as described in claim 137 further comprising the step of generating a third dissolved material solution.
139. A method as described in claim 137 wherein said step of inputting increasingly stronger material dissolving solvent into said vessel comprises the step of inputting methylene chloride or a solvent or solvent mixture with substantially the same polarity as methylene chloride.
140. A method as described in claim 138 further comprising the step of analyzing said third dissolved material solution.
141. A method as described in claim 99 further comprising the step of fractionating said
solution into at least two parts.
142. A method as described in claim 99 wherein each of said steps is started in the order in which it appears.
143. A method as described in claim 99 wherein said step of providing a vessel having a substantially chemically inert stationary phase established therein comprises the step of providing a vessel having established therein a stationary phase selected from the group of: oligomers of PTFE, polymers of PTFE, polyphenylene sulfide, fluorinated polymers, silicon polymer and PEEK.
144. A method as described in claim 99 wherein said step of providing a vessel having a substantially chemically inert stationary phase established therein comprises the step of providing a column having a substantially chemically inert stationary phase established therein.
145. A method as described in claim 144 wherein said step of providing a column comprises the step of providing a column that is part of a chromatograph.
146. A method as described in claim 99 wherein said step of providing a vessel having a substantially chemically inert stationary phase established therein comprises the step of providing a batch type vessel having a substantially chemically inert stationary phase established therein.
147. A method as described in claim 99 wherein said step of intentionally precipitating
asphaltenes within said vessel comprises the step of intentionally precipitating solid material.
148. A method as described in claim 99 wherein said step of intentionally precipitating
asphaltenes within said vessel comprises the step of intentionally precipitating gel or viscous liquid.
149. A method as described in claim 99 wherein said method is accomplished, at least in part, with a flow system.
150. A method as described in claim 149 wherein said flow system is a continuous flow
system.
151. A method as described in claim 99 wherein said step of inputting a precipitant solvent into said vessel through at least one vessel inlet comprises the step of inputting a liquid into said vessel through at least one vessel inlet.
152. A method as described in claim 99 wherein said step of inputting a precipitant solvent into said vessel through at least one vessel inlet comprises the step of inputting gel or viscous liquid.
153. A method as described in claim 99 wherein said method is a method selected from the group consisting of coking onset estimation method, oil processing method; oil fractionating method, oil production method, pipeline fouling related method, hydrotreating, distillation method, vacuum distillation method, atmospheric distillation method, visbreaking method, blending method, asphalt formation method, asphalt extraction method, and asphaltene content of oil measurement method.
154. A method as described in claim 99 wherein said method is an automated method.
155. A refinery or apparatus in which the method of claim 99 is performed.
156. A refinery that processes hydrocarbons based on analysis results generated, at least in part, upon performance of the method of claim 99.
157. A product produced by a process that is based on analysis results generated, at least in part, upon performance of the method of claim 99.
158. A method as described in claim 99 wherein said hydrocarbonaceous material comprises a material selected from the group consisting of: treated feed material and untreated feed material
159. A method as described in claim 99 further comprising the step of analyzing said
dissolved material solution.
160. A method as described in claim 99 wherein said step of monitoring said sorbent based asphaltene removal comprises the step of evaluating the type and amount of asphaltenes removed by obtaining and evaluating a solubility profile of asphaltenes before and after said sorbent based asphaltene removal.
161. A method as described in claim 99 wherein said sorbent based asphaltene removal effects an improved quality product oil.
162. A method as described in claim 161 wherein said improved quality oil is subsequently processed.
163. A method as described in claim 99 wherein said sorbent based asphaltene removal effects a product oil having a reduced fouling tendency.
164. A method as described in claim 163 wherein said fouling tendency is a tendency to foul an element selected from the group consisting of heat exchangers, pipes and refinery components.
165. A method as described in claim 163 wherein said fouling tendency is a tendency to foul due to asphaltene deposition.
166. A method as described in claim 163 wherein said fouling tendency is a tendency to foul during distillation.
167. A hydrocarbon upgrading method comprising the steps of:
- treating a hydrocarbon having asphaltenes therein to generate a treated hydrocarbon; - adsorbing at least a portion of said asphaltenes onto said sorbent, thereby removing said at least a portion of said asphaltenes from said treated hydrocarbon so as to generate an improved hydrocarbon, said improved hydrocarbon being upgraded relative to said hydrocarbon that is treated.
168. A hydrocarbon upgrading method as described in claim 167 wherein said improved
hydrocarbon is subsequently processed.
169. A hydrocarbon upgrading method as described in claim 167 wherein said hydrocarbon upgrading method effects a product oil having a reduced fouling tendency.
170. A hydrocarbon upgrading method as described in claim 169 wherein said fouling
tendency is a tendency to foul an element selected from the group consisting of heat exchangers, pipes and refinery components.
171. A hydrocarbon upgrading method as described in claim 169 wherein said fouling
tendency is a tendency to foul due to asphaltene deposition.
172. A hydrocarbon upgrading method as described in claim 169 wherein said fouling
tendency is a tendency to foul during distillation.
173. A hydrocarbon upgrading method as described in claim 167 wherein said sorbent is a stationary phase sorbent.
174. A hydrocarbon upgrading method as described in claim 167 wherein said sorbent is a solid sorbent.
175. A hydrocarbon upgrading method as described in claim 174 wherein said sorbent is a fixed bed.
176. A hydrocarbon upgrading method as described in claim 174 wherein said sorbent is a fluidized bed.
177. A hydrocarbon upgrading method as described in claim 174 wherein said sorbent is surfaced.
178. A hydrocarbon upgrading method as described in claim 174 wherein said sorbent is a porous membrane.
179. A hydrocarbon upgrading method as described in claim 174 wherein said sorbent is high surface energy.
180. A hydrocarbon upgrading method as described in claim 174 wherein said sorbent is highly aromatic.
181. A hydrocarbon upgrading method as described in claim 174 wherein said sorbent is selective to adsorption of said asphaltenes.
182. A hydrocarbon upgrading method as described in claim 174 wherein said sorbent is a sorbent selected from the group consisting of: metals, steel, steel wire, steel wire coils, metal wire, metal wire coils, ceramics, zeolites, clays, silica, limestone, glass, mesh glass, glass beads, mesh glass beads, quartz, sand, alumina, and high surface energy carbonaceous materials.
183. A hydrocarbon upgrading method as described in claim 174 wherein said sorbent is a salt, acid or base.
184. A hydrocarbon upgrading method as described in claim 174 wherein said sorbent comprises a carbon based sorbent.
185. A hydrocarbon upgrading method as described in claim 184 further comprising the step of burning said carbon based sorbent as fuel.
186. A hydrocarbon upgrading method as described in claim 167 wherein said hydrocarbon comprises a hydrocarbon selected from the group consisting of bitumen, shale oil, coal oil, coal tar, biological oil, heavy oil or residuum.
187. A hydrocarbon upgrading method as described in claim 167 wherein said hydrocarbon comprises an atmospheric bitumen.
188. A hydrocarbon upgrading method as described in claim 167 wherein said hydrocarbon comprises a vacuum bitumen.
189. A hydrocarbon upgrading method as described in claim 167 wherein said step of treating a hydrocarbon comprises the step of heating said hydrocarbon.
190. A hydrocarbon upgrading method as described in claim 189 wherein said step of heating said hydrocarbon comprises the step of heating said hydrocarbon to a temperature that is below a cracking temperature.
191. A hydrocarbon upgrading method as described in claim 189 wherein said step of heating said hydrocarbon comprises the step of heating said hydrocarbon from a heat source that is upstream of said sorbent.
192. A hydrocarbon upgrading method as described in claim 189 further comprising the step of heating said sorbent to generate a heated sorbent.
193. A hydrocarbon upgrading method as described in claim 192 wherein said step of heating said sorbent to generate a heated sorbent comprises the step of heating said sorbent to a temperature below a cracking temperature.
194. A hydrocarbon upgrading method as described in claim 192 wherein said step of heating said hydrocarbon comprises the step of contacting said hydrocarbon with said heated sorbent.
195. A hydrocarbon upgrading method as described in claim 194 wherein said step of heating said hydrocarbon further comprises the step of heating said hydrocarbon with heat from a source other than said heated sorbent.
196. A hydrocarbon upgrading method as described in claim 194 further comprising the step of cooling said hydrocarbon upon contact of said hydrocarbon with said heated sorbent.
197. A hydrocarbon upgrading method as described in claim 190 wherein said step of heating said hydrocarbon comprises the step of separating the most aromatic and refractory molecules from peptizing molecules associated therewith.
198. A hydrocarbon upgrading method as described in claim 190 wherein said step of heating said hydrocarbon comprises the step of depeptizing said hydrocarbon.
199. A hydrocarbon upgrading method as described in claim 190 wherein said step of heating said hydrocarbon comprises the step of heating said hydrocarbon to below 340C.
200. A hydrocarbon upgrading method as described in claim 199 wherein said step of heating said hydrocarbon comprises the step of heating said hydrocarbon from 200-250C.
201. A hydrocarbon upgrading method as described in claim 199 wherein said step of heating said hydrocarbon comprises the step of heating said hydrocarbon from 150-300C.
202. A hydrocarbon upgrading method as described in claim 199 wherein said step of heating said hydrocarbon comprises the step of heating said hydrocarbon from 100-340C.
203. A hydrocarbon upgrading method as described in claim 190 further comprises the step of rinsing said sorbent with an aromatic solvent.
204. A hydrocarbon upgrading method as described in claim 203 wherein said step of rinsing said sorbent comprises the step of rinsing said sorbent with strong chromatographic extraction solvent.
205. A hydrocarbon upgrading method as described in claim 204 wherein said step of rinsing said sorbent comprises the step of rinsing with a halogenated solvent, an aromatic solvent, an alcohol, or a mixture thereof.
206. A hydrocarbon upgrading method as described in claim 190 wherein said step of heating said hydrocarbon comprises the step of reversibly heating said hydrocarbon.
207. A hydrocarbon upgrading method as described in claim 190 wherein said step of treating said hydrocarbon further comprises the step of adding a solvent thereto.
208. A hydrocarbon upgrading method as described in claim 190 wherein said step of heating said hydrocarbon occurs for a heating time.
209. A hydrocarbon upgrading method as described in claim 208 further comprising the step of optimizing said heating time.
210. A hydrocarbon upgrading method as described in claim 189 wherein said step of heating said hydrocarbon comprises the step of heating said hydrocarbon to a cracking temperature.
211. A hydrocarbon upgrading method as described in claim 210 wherein said step of heating said hydrocarbon comprises the step of heating said hydrocarbon from a heat source that is upstream of said sorbent.
212. A hydrocarbon upgrading method as described in claim 210 further comprising the step of heating said sorbent to generate a heated sorbent.
213. A hydrocarbon upgrading method as described in claim 212 wherein said step of heating said sorbent to generate a heated sorbent comprises the step of heating said sorbent to a cracking temperature.
214. A hydrocarbon upgrading method as described in claim 212 wherein said step of heating said sorbent to generate a heated sorbent comprises the step of heating said sorbent to a temperature below a cracking temperature.
215. A hydrocarbon upgrading method as described in claim 212 wherein said step of heating said hydrocarbon comprises the step of contacting said hydrocarbon with said heated sorbent.
216. A hydrocarbon upgrading method as described in claim 215 wherein said step of heating said hydrocarbon further comprises the step of heating said hydrocarbon with heat from a source other than said heated sorbent.
217. A hydrocarbon upgrading method as described in claim 212 further comprising the step of cooling said treated hydrocarbon by contacting it with said heated sorbent.
218. A hydrocarbon upgrading method as described in claim 210 wherein said step of treating said hydrocarbon further comprises the step of cooling said hydrocarbon to a temperature below a minimum cracking temperature before contacting said hydrocarbon with said sorbent.
219. A hydrocarbon upgrading method as described in claim 218 further comprising the step of heating said sorbent to a temperature less that said minimum cracking temperature.
220. A hydrocarbon upgrading method as described in claim 210 wherein said step of heating said hydrocarbon comprises the step of irreversibly heating said hydrocarbon.
221. A hydrocarbon upgrading method as described in claim 210 wherein said step of heating said hydrocarbon comprises the step of heating said hydrocarbon to or above 340C.
222. A hydrocarbon upgrading method as described in claim 210 further comprising the step of minimizing the need for subsequent hydrogen addition.
223. A hydrocarbon upgrading method as described in claim 210 wherein said step of treating said hydrocarbon further comprises the step of adding a solvent thereto.
224. A hydrocarbon upgrading method as described in claim 189 wherein said step of treating is solventless.
225. A hydrocarbon upgrading method as described in claim 189 wherein said step of heating said hydrocarbon is performed in an inert gas atmosphere.
226. A hydrocarbon upgrading method as described in claim 167 wherein said step of treating said hydrocarbon comprises the step of adding a substance to said hydrocarbon, wherein said substance is selected from the group consisting of solvent and chemical additive.
227. A hydrocarbon upgrading method as described in claim 226 wherein said solvent comprises a low polarity solvent.
228. A hydrocarbon upgrading method as described in claim 226 wherein performance of said step of adding a substance does not effect asphaltene precipitation.
229. A hydrocarbon upgrading method as described in claim 226 wherein said step of adding a substance to said hydrocarbon comprises the step of adding a substance selected from the group consisting of a polar material, an aromatic material, and an acid or base.
230. A hydrocarbon upgrading method as described in claim 226 wherein said step of treating said hydrocarbon further comprises the step of heating said hydrocarbon.
231. A hydrocarbon upgrading method as described in claim 167 wherein said step of adsorbing at least a portion of said asphaltenes onto said sorbent comprises the step of adsorbing at least a portion of the most pericondensed aromatic structures of said hydrocarbon.
232. A hydrocarbon upgrading method as described in claim 167 wherein said step of adsorbing at least a portion of said asphaltenes onto said sorbent comprises the step of adsorbing at least a portion of the most pericondensed, aromatic and refractory structures of said hydrocarbon.
233. A hydrocarbon upgrading method as described in claim 167 wherein said step of adsorbing at least a portion of said asphaltenes onto said sorbent comprises the step of adsorbing at least a portion of the most pericondensed and highest surface energy pre- coke asphaltene materials.
234. A hydrocarbon upgrading method as described in claim 167 wherein said step of adsosrbing at least a portion of said asphaltenes occurs during a sorbent contact time.
235. A hydrocarbon upgrading method as described in claim 234 further comprising the step of optimizing said sorbent contact time.
236. A hydrocarbon upgrading method as described in claim 167 further comprising the step of heating said sorbent to generate a heated sorbent.
237. A hydrocarbon upgrading method as described in claim 236 wherein said step of treating said hydrocarbon comprises the step of contacting said hydrocarbon with said heated sorbent.
238. A hydrocarbon upgrading method as described in claim 167 further comprising the step of adding a diluent amount to said improved hydrocarbon so as to generate a diluted hydrocarbon having a diluted hydrocarbon viscosity that is no greater than a certain viscosity.
239. A hydrocarbon upgrading method as described in claim 238 wherein said certain viscosity is governed by pipeline specifications.
240. A hydrocarbon upgrading method as described in claim 238 wherein said diluent amount is less than that untreated hydrocarbon diluent amount required to reduce viscosity of an untreated hydrocarbon to said diluted hydrocarbon viscosity.
241. A hydrocarbon upgrading method as described in claim 167 further comprising the step of contacting said treated hydrocarbon with a sorbent by pouring said treated hydrocarbon over said sorbent.
242. A hydrocarbon upgrading method as described in claim 167 further comprising the step of contacting said treated hydrocarbon with a sorbent by mixing said treated hydrocarbon with said sorbent.
243. A hydrocarbon upgrading method as described in claim 167 further comprising the step of contacting said hydrocarbon with a sorbent by pouring said hydrocarbon over said sorbent.
244. A hydrocarbon upgrading method as described in claim 167 further comprising the step of contacting said hydrocarbon with a sorbent by mixing said hydrocarbon with said sorbent.
245. The viscosity reduced hydrocarbon generated upon performance of the hydrocarbon
upgrading method of claim 167.
246. A refinery or apparatus in which the method of claim 167 is performed.
247. A refinery that processes hydrocarbons based on analysis results generated, at least in part, upon performance of the method of claim 167.
248. A method comprising the steps of:
(a) precipitating an amount of asphaltenes from a liquid sample of a first hydrocarbon- containing feedstock having solvated asphaltenes therein with one or more first solvents in a column;
(b) determining one or more solubility characteristics of the precipitated asphaltenes;
(c) analyzing the one or more solubility characteristics of the precipitated asphaltenes; and
(d) monitoring sorbent based asphaltene removal.
249. A method as described in claim 248 wherein said sorbent based asphaltene removal
effects an improved quality product oil.
250. A method as described in claim 249 wherein said improved quality product oil is
subsequently processed.
251. A method as described in claim 248 wherein said sorbent based asphaltene removal
effects a product oil having a reduced fouling tendency.
252. A method as described in claim 251 wherein said fouling tendency is a tendency to foul an element selected from the group consisting of heat exchangers, pipes and refinery components.
253. A method as described in claim 251 wherein said fouling tendency is a tendency to foul due to asphaltene deposition.
254. A method as described in claim 251 wherein said fouling tendency is a tendency to foul during distillation.
255. A method as described in claim 248 further comprising the step of analyzing a asphaltene solubility characteristic profile.
256. A method as described in claim 248 wherein said step of monitoring sorbent based
asphaltene removal comprises the step of using said asphaltene solubility characteristic profile.
257. The method of claim 248, wherein the first hydrocarbon-containing feedstock comprises a material selected from the group consisting of oil, crude oil, asphalt, and a coal-derived product.
258. The method of claim 248, wherein the one or more first solvents is selected from the group consisting of iso-octane, pentane, heptane, hexane, and mixtures thereof.
259. The method of claim 248, wherein step (b) comprises:
(i) dissolving at least part of the amount of the precipitated asphaltenes in one or more second solvents having a solubility parameter at least 1 MPa0 5 higher than the one or more first solvents;
(ii) dissolving a second amount of the precipitated asphaltenes in one or more third solvents having a solubility parameter higher than the one or more second solvents, wherein the solubility parameter of the one or more third solvents is at least about 21 MPa0 5 but no greater than about 30 MPa0 5.
260. The method of claim 259, wherein step (c) comprises monitoring the amount of eluted fractions from the column with a liquid chromatography detector that generates a signal proportional to the amount of each eluted fraction.
261. The method of claim 260, further comprising calculating a percentage of each peak area for the first amount and the second amount of dissolved asphaltenes relative to the total peak areas, wherein the peak areas are derived from the signals.
262. The method of claim 259, further comprising prior to step (ii): dissolving at least part of the amount of the precipitated asphaltenes in one or more fourth solvents having a solubility parameter between the solubility parameter of the second solvent and the solubility parameter of the third solvent; and dissolving at least part of the amount of the precipitated asphaltenes in one or more fifth solvents having a solubility parameter between the solubility parameter of the fourth solvent and the solubility parameter of the third solvent.
263. The method of claim 262, wherein step (c) comprises monitoring the concentration of eluted fractions from the column with a liquid chromatography detector that generates a signal proportional to the amount of each eluted fraction.
264. The method of claim 263, further comprising calculating a percentage of each peak area for the first amount and the second amount of dissolved asphaltenes relative to the total peak areas, wherein the peak areas are derived from the signals.
265. The method of claim 248, wherein step (b) comprises dissolving a first amount and a second amount of the precipitated asphaltenes by gradually and continuously changing the one or more first solvents to a final mobile phase solvent having a solubility parameter at least about 1 MPa0'5 higher than the one or more first solvents.
266. The method of claim 248, wherein step (b) comprises:
(i) gradually and continuously changing the one or more first solvents to a first final mobile phase solvent having a solubility parameter at least about 1 MPa0 5 higher than the one or more first solvents to dissolve a first amount of the precipitated asphaltenes; and
(ii) gradually and continuously changing the first final mobile phase solvent to a second final mobile phase solvent having a solubility parameter at least about 1 MPa0'5 higher than the first final mobile phase solvent to dissolve a second amount of the precipitated asphaltenes.
267. The method of claim 248 further comprising the step of correlating a measurement of feedstock fouling tendency for the first hydrocarbon-containing feedstock sample with a mathematical parameter derived from the results of analyzing the one or more solubility characteristics of the precipitated asphaltenes.
268. The method of claim 267, further comprising creating a solubility profile of the dissolved asphaltenes in the first hydrocarbon-containing feedstock sample; and correlating the fouling tendency against characteristics of the solubility profile.
269. The method of claim 267 wherein the fouling tendency is derived from a determination of the amount of foulant deposited.
270. The method of claim 267 wherein fouling tendencies are determined by heating at least two feedstocks at a plurality of temperatures for an extended period of time then cooled and samples of the feedstocks are analyzed for high polar asphaltene concentration to determine the effect heating the feedstock has on producing high polar asphaltenes.
271. The method of claim 248, further comprising the steps of:
(e) selecting one or more of the same or different hydrocarbon-containing feedstock samples; repeating steps (a)-(d); and
(f) comparing the results of the one or more of the same or different hydrocarbon- containing feedstock samples with the results of the first hydrocarbon-containing feedstock sample to predict one or more leading candidate hydrocarbon-containing feedstocks relative to fouling tendency during hydroprocessing.
272. The method of claim 271 further comprising the steps of generating a cost value for the leading candidate hydrocarbon-containing feedstock samples, and comparing the cost value generated for the leading candidate hydrocarbon-containing feedstock samples with a market price of the same or different hydrocarbon containing feedstocks.
273. The method of claim 271, further comprising the step of blending the leading candidate hydrocarbon-containing feedstock with one or more different hydrocarbon-containing feedstocks.
274. The method of claim 248, further comprising the step of comparing a different sample of the same first hydrocarbon-containing feedstock sample with the first hydrocarbon- containing feedstock sample for quality control of the first hydrocarbon-containing feedstock sample.
275. The method of claim 248 further comprising the steps of generating a cost value for a hydrocarbon-containing feedstock sample, and comparing said cost value generated for said hydrocarbon-containing feedstock sample with a market price of the same or different hydrocarbon-containing feedstock.
276. The method of claim 248 further comprising the step of (e) generating a price of the first hydrocarbon-containing feedstock, wherein said method transforms a product development process to reduce time in bringing a product to market.
277. A refinery or apparatus in which the method of claim 248 is performed.
278. A refinery that processes hydrocarbons based on analysis results generated, at least in part, upon performance of the method of claim 248.
279. A product produced by a process that is based on analysis results generated, at least in part, upon performance of the method of claim 248.
280. A method for controlling sorbent based removal of asphaltenes from a hydrocarbon- containing material having solvated asphaltenes therein comprising the steps of:
(a) precipitating an amount of the asphaltenes from a liquid sample of the hydrocarbon- containing material with an alkane mobile phase solvent in a column;
(b) dissolving a first amount and a second amount of the precipitated asphaltenes by changing the alkane mobile phase solvent to a final mobile phase solvent having a solubility parameter that is higher than the alkane mobile phase solvent;
(c) monitoring the amounts of eluted fractions from the column;
(d) creating a solubility profile of the dissolved asphaltenes in the hydrocarbon- containing material; (e) determining one or more asphaltene stability parameters of the hydrocarbon- containing material; and
(f) monitoring sorbent based asphaltene removal.
281. The method of claim 280 wherein said step of monitoring the amounts comprises the step of monitoring concentrations.
282. The method of claim 280 wherein said sorbent based asphaltene removal effects an
improved quality product oil.
283. The method of claim 282 wherein said improved quality product oil is subsequently
processed.
284. The method of claim 280 wherein said sorbent based asphaltene removal effects a
product oil having a reduced fouling tendency.
285. The method of claim 284 wherein said fouling tendency is a tendency to foul an element selected from the group consisting of heat exchangers, pipes, pipelines and refinery components.
286. The method of claim 284 wherein said fouling tendency is a tendency to foul due to
asphaltene deposition.
287. The method of claim 284 wherein said fouling tendency is a tendency to foul during
distillation.
288. The method of claim 280 wherein said step of dissolving comprises the step of dissolving by gradually changing the alkane mobile phase solvent to a final mobile phase solvent having a solubility parameter that is higher than the alkane mobile phase solvent.
289. The method of claim 280 wherein said step of dissolving comprises the step of dissolving by continuously changing the alkane mobile phase solvent to a final mobile phase solvent having a solubility parameter that is higher than the alkane mobile phase solvent.
290. The method of claim 280 wherein said step of dissolving comprises the step of dissolving by changing the alkane mobile phase solvent to a final mobile phase solvent having a solubility parameter that is at least 1 MPa° 5 higher than the alkane mobile phase solvent.
291. The method of claim 280 wherein said step of dissolving comprises the step of dissolving by gradually and continuously changing the alkane mobile phase solvent to a final mobile phase solvent having a solubility parameter that is at least 1 MPa° 5 higher than the alkane mobile phase solvent.
292. The method of claim 291 wherein said method is a method for optimizing a process utilizing a catalyst for reaction of one or more hydrocarbon-containing feedstocks, the method comprising the steps of:
(i) selecting one or more hydrocarbon-containing feedstocks having a stable plurality of asphaltene components therein, wherein the selection of the one or more hydrocarbon- containing feedstocks comprises the steps of claim 1 ; and
(ii) contacting the selected one or more hydrocarbon-containing feedstocks with a supported or unsupported catalyst at a reaction temperature in a reaction zone.
293. The method of claim 280 wherein the hydrocarbon-containing material comprises a
substance selected from the group consisting of oil, crude oil, asphalt and a coal-derived product.
294. The method of claim 280 further comprising, prior to step (a), the steps of: providing a liquid sample of the hydrocarbon-containing material solution in a first solvent; and passing at least a portion of the liquid sample into the column.
295. The method of claim 280 further comprising an inert packing material located within the column.
296. The method of claim 295 wherein the inert packing material comprises at least one of polyphenylene sulfide, silicon polymer, fluorinated polymers, fluorinated elastomers, PEEK, oligomers of polytetrafluoroethylene and polymers of polytetrafluoroethylene.
297. The method of claim 280 wherein the alkane mobile phase solvent is selected from the group consisting of iso-octane, pentane, heptane and mixtures thereof.
298. The method of claim 280 wherein step (b) comprises:
(i) gradually and continuously changing the alkane mobile phase solvent to a first final mobile phase solvent having a solubility parameter that is at least 1 MPa0 5 higher than the alkane mobile phase solvent to dissolve a first amount of the precipitated asphaltenes; and
(ii) gradually and continuously changing the first final mobile phase solvent to a second final mobile phase solvent having a solubility parameter that is at least at least 1 MPa0'5 higher than the first final mobile phase solvent to dissolve a second amount of the precipitated asphaltenes.
299. The method of claim 298 wherein the first final mobile phase solvent is selected from the group consisting of an alkane solvent, a cycloalkane solvent, a chlorinated hydrocarbon solvent, an ether solvent, an aromatic hydrocarbon solvent, a blend of a solvent with alcohol, a blend of chlorinated hydrocarbon solvent and a Ci to C6 alcohol, a ketone solvent, and mixtures thereof.
300. The method of claim 298 wherein step (i) comprises adding the first final mobile phase solvent into the column at a flow rate selected from the group consisting of up to and including about 4 mL/minute and up to and including about 6 mL/minute.
301. The method of claim 298 wherein the second final mobile phase solvent comprises a solvent selected from the group consisting of an alcohol and a Ci to C6 alcohol.
302. The method of claim 298 wherein step (ii) comprises adding the second final mobile phase solvent into the column at a flow rate selected from the group consisting of up to and including about 4 mL/minute, and up to and including about 6 mL/minute.
303. The method of claim 298 wherein the alkane mobile phase solvent is n-heptane, the first final mobile phase solvent comprises methanol and the second final mobile phase solvent comprises methanol.
304. The method of claim 280 wherein the step of monitoring the concentration of eluted fractions from the column comprises monitoring the concentration of eluted fractions from the column with a liquid chromatography detector.
305. The method of claim 304 wherein the liquid chromatography detector is an evaporative light scattering detector coupled to the column.
306. The method of claim 280 wherein the step of determining one or more asphaltene
stability parameters comprises calculating an average elution solubility parameter of the second amount of dissolved asphaltenes.
307. The method of claim 306 wherein the average elution solubility parameter of the second amount of dissolved asphaltenes is calculated from at least one peak value of the second amount of dissolved asphaltenes derived from the solubility profile.
308. The method of claim 280 wherein the step of determining one or more asphaltene
stability parameters comprises calculating a value selected from the group consisting of a ratio of peak areas of the second amount of dissolved asphaltenes to the first amount of dissolved asphaltenes, wherein each of the peak areas are derived from the solubility profile, a relative peak value of the second amount of dissolved asphaltenes and the first amount of dissolved asphaltenes, wherein each of the peak areas are derived from the solubility profile; and a difference in the separation profile areas at different times during the separation.
309. The method of claim 280 further comprising selecting a second hydrocarbon-containing material; repeating steps (a)-(e); and comparing the results with the first hydrocarbon- containing material.
310. A refinery or apparatus in which the method of claim 280 is performed.
311. A refinery that processes hydrocarbons based on analysis results generated, at least in part, upon performance of the method of claim 280.
312. A product produced by a process that is based on analysis results generated, at least in part, upon performance of the method of claim 280.
PCT/US2012/021317 2005-08-25 2012-01-13 Hydrocarbon viscosity reduction method Ceased WO2012121804A1 (en)

Priority Applications (7)

Application Number Priority Date Filing Date Title
EP12754614.1A EP2683795A4 (en) 2011-03-08 2012-01-13 PROCESS FOR REDUCING THE VISCOSITY OF HYDROCARBONS
US14/004,023 US20140021101A1 (en) 2011-03-08 2012-01-13 Hydrocarbon Viscosity Reduction Method
CA2829291A CA2829291A1 (en) 2011-03-08 2012-01-13 Hydrocarbon viscosity reduction method
US13/723,058 US20130104772A1 (en) 2005-08-25 2012-12-20 Methods for Changing Stability of Water and Oil Emulsions
US15/358,991 US20190299180A9 (en) 2005-08-25 2016-11-22 Methods for Changing Stability of Water and Oil Emulsions
US16/183,584 US10449502B2 (en) 2005-08-25 2018-11-07 Methods for analyzing hydrocarbons and hydrocarbon blends for chemical compositions
US16/358,337 US10994252B2 (en) 2005-08-25 2019-03-19 Methods for estimating a property of a hydrocarbon

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
US201161450515P 2011-03-08 2011-03-08
US61/450,515 2011-03-08

Related Parent Applications (1)

Application Number Title Priority Date Filing Date
US13/237,568 Continuation-In-Part US9353317B2 (en) 2005-08-25 2011-09-20 Hydrocarbon separation and analysis apparatus and methods

Related Child Applications (2)

Application Number Title Priority Date Filing Date
US11/510,491 Continuation-In-Part US7875464B2 (en) 2005-08-25 2006-08-25 Processing and analysis techniques involving in-vessel material generation
US13/723,058 Continuation-In-Part US20130104772A1 (en) 2005-08-25 2012-12-20 Methods for Changing Stability of Water and Oil Emulsions

Publications (2)

Publication Number Publication Date
WO2012121804A1 WO2012121804A1 (en) 2012-09-13
WO2012121804A4 true WO2012121804A4 (en) 2012-11-22

Family

ID=46798509

Family Applications (1)

Application Number Title Priority Date Filing Date
PCT/US2012/021317 Ceased WO2012121804A1 (en) 2005-08-25 2012-01-13 Hydrocarbon viscosity reduction method

Country Status (4)

Country Link
US (1) US20140021101A1 (en)
EP (1) EP2683795A4 (en)
CA (1) CA2829291A1 (en)
WO (1) WO2012121804A1 (en)

Cited By (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US10808183B2 (en) 2012-09-12 2020-10-20 The University Of Wyoming Research Corporation Continuous destabilization of emulsions

Families Citing this family (11)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US9127213B2 (en) * 2011-11-11 2015-09-08 Chevron U.S.A. Inc. Method for predicting catalyst performance
US8911512B2 (en) * 2012-09-20 2014-12-16 Kior, Inc. Use of NIR spectra for property prediction of bio-oils and fractions thereof
US9212330B2 (en) 2012-10-31 2015-12-15 Baker Hughes Incorporated Process for reducing the viscosity of heavy residual crude oil during refining
US9921205B2 (en) 2012-11-13 2018-03-20 Chevron U.S.A. Inc. Method for determining the effectiveness of asphaltene dispersant additives for inhibiting or preventing asphaltene precipitation in a hydrocarbon-containing material subjected to elevated temperature and presssure conditions
US20140259883A1 (en) * 2013-03-15 2014-09-18 Petrosonic Energy Inc. Emulsion fuel from sonication-generated asphaltenes
US9671384B2 (en) * 2014-12-11 2017-06-06 Chevron U.S.A. Inc. Low volume in-line filtration method for evaluation of asphaltenes for hydrocarbon-containing feedstock
BR112018013031B1 (en) * 2016-06-17 2022-09-20 Uop Llc PROCESS FOR PRODUCING A PARTIALLY DEOXYGENATED FUEL FROM A BIOMASS-DERIVED PYROLYSIS OIL
CA2963436C (en) 2017-04-06 2022-09-20 Iftikhar Huq Partial upgrading of bitumen
US10907473B2 (en) 2017-11-14 2021-02-02 Chevron U.S.A., Inc. Low volume in-line filtration methods for analyzing hydrocarbon-containing fluid to evaluate asphaltene content and behavior during production operations
US11280779B2 (en) 2017-12-18 2022-03-22 Championx Usa Inc. Solvency for asphaltene deposit remediation or inhibition
US11384299B2 (en) 2019-12-19 2022-07-12 Saudi Arabian Oil Company Systems and processes for upgrading and converting crude oil to petrochemicals through steam cracking

Family Cites Families (6)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US4419219A (en) * 1981-09-24 1983-12-06 Exxon Research And Engineering Co. Adsorption of basic asphaltenes on solid acid catalysts
US5785860A (en) * 1996-09-13 1998-07-28 University Of British Columbia Upgrading heavy oil by ultrafiltration using ceramic membrane
US7736900B2 (en) * 2001-02-05 2010-06-15 University Of Wyoming Research Corporation Automated flocculation titration method for accurate determination of Heithaus parameters
US20060272983A1 (en) * 2005-06-07 2006-12-07 Droughton Charlotte R Processing unconventional and opportunity crude oils using zeolites
US7875464B2 (en) * 2005-08-25 2011-01-25 The University Of Wyoming Research Corporation Processing and analysis techniques involving in-vessel material generation
US7566394B2 (en) * 2006-10-20 2009-07-28 Saudi Arabian Oil Company Enhanced solvent deasphalting process for heavy hydrocarbon feedstocks utilizing solid adsorbent

Cited By (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US10808183B2 (en) 2012-09-12 2020-10-20 The University Of Wyoming Research Corporation Continuous destabilization of emulsions

Also Published As

Publication number Publication date
CA2829291A1 (en) 2012-09-13
EP2683795A1 (en) 2014-01-15
EP2683795A4 (en) 2014-09-03
WO2012121804A1 (en) 2012-09-13
US20140021101A1 (en) 2014-01-23

Similar Documents

Publication Publication Date Title
WO2012121804A4 (en) Hydrocarbon viscosity reduction method
US20190169512A1 (en) Method for determining asphaltene stability of a hydrocarbon-containing material
Zachariah et al. Partial upgrading of bitumen: impact of solvent deasphalting and visbreaking sequence
US20190211272A1 (en) Hydrocarbon Analysis Methods
Shi et al. Development of heavy oil upgrading technologies in China
US20130124106A1 (en) Method for estimating sediment content of a hydroprocessed hydrocarbon-containing feedstock
CA2983140C (en) Hydrocarbon separation and analysis apparatus and methods
US9671384B2 (en) Low volume in-line filtration method for evaluation of asphaltenes for hydrocarbon-containing feedstock
US9921203B2 (en) Method for predicting sediment content of a hydroprocessed hydrocarbon product
US10449502B2 (en) Methods for analyzing hydrocarbons and hydrocarbon blends for chemical compositions
US20120160015A1 (en) Methods for predicting fouling tendencies of hydrocarbon containing feedstocks
WO2011113017A2 (en) Methods for predicting fouling tendencies of hydrocarbon containing feedstocks
Bambinek et al. Compatibility of crude oil Blends─ Processing issues related to asphaltene precipitation, methods of instability Prediction─ A review
Merdrignac et al. Evolution of asphaltene structure during hydroconversion conditions
Adams et al. Quantitative vacuum distillation of crude oils to give residues amenable to the asphaltene determinator coupled with saturates, aromatics, and resins separation characterization
RU2522447C1 (en) Deposit reduction in gasoline fractionation, water cooling system and product recovery section
Zhao et al. Feedstock characteristic index and critical properties of heavy crudes and petroleum residua
Miranda et al. SimDis-HT analysis of crude oils as a tool to define operating conditions for primary treatment processes
Zhang et al. Viscosity mixing rule and viscosity–temperature relationship estimation for oil sand bitumen vacuum residue and fractions
Arboleda et al. Hydrocarbon group type separation of gas oil resins by high performance liquid chromatography on hyper-cross-linked polystyrene stationary phase
CA2957249A1 (en) Methode de determination de la stabilite d'un produit petrolier contenant des asphaltenes
Gerasimova et al. Composition of resin-asphaltene and oil components of heavy oils
Balaghi Partial Upgrading of Oilsands Bitumen and Heavy Oil: Kinetic Modeling and Reactor Design
Baltus Catalytic Processing Catalytic Processing of Heavy Crude Oils and Residuals I. Characterization and Kinetic Studies
Britten et al. Heavy petroleum upgrading by microwave irradiation

Legal Events

Date Code Title Description
121 Ep: the epo has been informed by wipo that ep was designated in this application

Ref document number: 12754614

Country of ref document: EP

Kind code of ref document: A1

DPE1 Request for preliminary examination filed after expiration of 19th month from priority date (pct application filed from 20040101)
ENP Entry into the national phase

Ref document number: 2829291

Country of ref document: CA

NENP Non-entry into the national phase

Ref country code: DE

WWE Wipo information: entry into national phase

Ref document number: 14004023

Country of ref document: US

WWE Wipo information: entry into national phase

Ref document number: 2012754614

Country of ref document: EP