US20150014220A1

US20150014220A1 - Process for producing a bitumen product

Info

Publication number: US20150014220A1
Application number: US13/939,020
Authority: US
Inventors: Richard H. Schlosberg; Richard D. Jordan; Edward L. Diefenthal
Original assignee: Epic Oil Extractors LLC
Current assignee: Epic Oil Extractors LLC
Priority date: 2013-07-10
Filing date: 2013-07-10
Publication date: 2015-01-15
Also published as: CA2855693A1; CA2855693C; WO2015006077A1; CA2917826A1

Abstract

Disclosed is a process for producing a high quality bitumen product derived from oil sand. The process for producing the high quality bitumen product involves a dual phase bitumen extraction process. In this dual phase process, a very high quality deasphalted crude oil is extracted from the oil sand in a solvent treatment first phase. The second phase of the process produces a high quality bitumen product from the solvent-treated oil sand.

Description

This invention relates to a method for producing bitumen product. In particular, this invention relates to producing a bitumen product that can be used as asphalt or asphalt binder.

BACKGROUND OF THE INVENTION

Bitumen is generally defined as an amorphous, black or dark-colored, (solid, semi-solid, or viscous) cementitious substance, comprised primarily of high molecular weight hydrocarbons, and which is soluble in trichloroethylene. A substantial amount of bitumen is commercially obtained as a heavy residue fraction from the distillation of crude petroleum. This residue can be used as a binder to produce asphalt cement. These asphalt cements have a wide variety of uses such as paving materials and roof coating materials.
Typically, asphalt basestock material obtained from the heavy residue fraction of petroleum distillation is treated, prior to being used as a binder for making asphalt cement. For example, to improve hardness characteristics, lighter components can be extracted from an asphalt basestock using hydrocarbon solvents. Hardness characteristics can also be improved by oxidizing the asphalt basestock by air blowing at an elevated temperature. However, many of the asphalt basestock treatment processes have been known to be problematic in that the produced asphalt binders can be relatively brittle at low temperature, resulting in excessive cracking in cold weather.
U.S. Pat. No. 6,258,255 discloses a method for enhancing the volatility and flash of various distillation residues to meet specifications for roofing and paving asphalts, without degrading many of the desirable properties of the product asphalt. The method includes vacuum distilling a blend of a high boiling petroleum fraction having an initial boiling point of at least 270° C., having essentially no asphaltene content, and a crude to produce a product asphalt having a flash of from 265° C. to 300° C. and a mass loss of less than 1 wt. %.
Another means of improving the characteristics of an asphalt material is to blend the material with suitable polymers. Certain polymers can be effective in reducing the tendency of an asphalt pavement to creep and rut in warm weather by increasing its high temperature viscoelastic stiffness. These polymers are typically added to softer grades of asphalt to reduce cracking in cold weather, reducing risk of excessive softening in hot weather. Unfortunately, many of the asphalt-polymer blends are not storage stable. At normal handling and storage temperatures, the blend can form two liquid phases, with most of the polymer and the lighter, less polar asphalt components being in one phase, and most of the heavier, more polar asphalt components being in the second phase.
U.S. Pat. No. 4,873,275 discloses improving stability and rheological properties of paving asphalts by the addition of certain copolymers of ethylene with vinyl acetate or lower alkyl esters of acrylic acid and methacrylic acid to an asphalt, provided the asphalt has an asphaltene content below a critical level. Effects on storage stability and creep resistance relative to conventional binders (i.e. straight-run asphalts obtained from residua from vacuum distillation of crude oil) are demonstrated when the asphalt used in the binder has an asphaltene content of about 7 wt. % or less, based on wt. % of the asphalt.
U.S. Pat. No. 5,637,141 discloses a method of making a storage-stable asphaltic composition suitable for use as a pavement binder. The method includes a step of blending an unsaturated polymer (e.g. having olefinic unsaturation) with an asphalt to form a blend of substantially uniform composition. The asphalt-polymer blend is treated with a sulfonating agent, and the treated blend is contacted with stripping gas to remove strippable moieties, including sulfur-containing strippable moieties. The sulfonate-treated blend is substantially chemically stable in that it will not liberate significant amounts of sulfur moieties (e.g., SO₂) during storage or use.
There is a continuing need for materials that can be effectively used as asphalts or asphalt binders. There is a particular need for materials that can be used as asphalt binder, with little if any treatment of the asphalt base material. There is also a continuing need for new compositions having both enhanced low and high temperature service properties that minimize the necessity to use additional, costly additive materials such as monomers and polymers, and that minimize the necessity of additional processing steps such as air blowing to produce asphalt binders having desirable binder characteristics.

SUMMARY OF THE INVENTION

This invention provides a bitumen product that needs little if any treatment to produce an asphalt binder material. The process for producing the bitumen product more readily results in an asphalt binder with improved characteristics. The bitumen product requires little if any additive materials, and requires little if any air blowing to produce desirable asphalt binder materials.
According to one aspect of the invention, there is provided a process for producing a high quality bitumen product. A solvent-treated oil sand material can be provided as a feedstock for producing the high quality bitumen product, in which the solvent treated oil sand material is obtained by removing not greater than 80 wt % of a bitumen oil composition from an oil sand material by treating with a hydrocarbon solvent comprised of at least 60 wt % aliphatic hydrocarbon to separate a high quality crude oil from the oil sand. Preferably, the solvent that is used to produce the solvent-treated oil sand is comprised of a hydrocarbon selected from the group consisting of propane, butane and mixtures thereof. The solvent-treated oil sand is treated with an aqueous solution to remove at least a portion of the remaining bitumen material from the solvent-treated oil sand, and the bitumen product is recovered.
The high quality crude oil product separated from the oil sand as a result of the initial phase solvent treatment can be defined according to multiple characteristics. For example, the crude oil product can have a Conradson Carbon Residue of not greater than 5 wt %, measured according to ASTM D4530. As another example, the crude oil product can have a H/C atomic ratio of at least 1.4. In another example, the crude oil product can contain not greater than 5 wt % pentane insolubles, measured according to ASTM D4055.
The bitumen product produced from the solvent-treated oil sand material can also be of a relatively high quality. For example, the bitumen product can have a H/C atomic ratio of less than 1.4. As another example, the bitumen product has a Conradson Carbon Residue of at least 20 wt %, measured according to ASTM D4530. In another example, the bitumen product has a flash point of greater than or equal to 100° C., measured according to ASTM D92. The bitumen product can also have a solubility in trichloroethylene of greater than or equal to 98 percent, measured according to ASTM D2042.
Asphaltene content of the bitumen product can be relatively high. For example, the bitumen product has greater than or equal to 40 wt % pentane insolubles, measured according to ASTM D4055.
Viscosity of the bitumen product can also be characterized. For example, the bitumen product can have an absolute viscosity at 60° C. of greater than or equal to 500 poise, measured according to ASTM D2171. The bitumen product can also be characterized by a kinematic viscosity at 135° C. of greater than or equal to 100 cSt.
According to another aspect of the invention, a high quality bitumen product can be produced by providing a solvent-treated oil sand material, in which the solvent treated oil sand material is obtained by supplying oil sand containing bitumen to a vessel and injecting a solvent comprised of a hydrocarbon mixture into the vessel. The solvent can be characterized by Hansen solubility parameters. For example, the solvent can be characterized according to a Hansen hydrogen bonding blend parameter of not greater than 0.5. The oil sand is treated with the solvent in the vessel to remove not greater than 80 wt % of the bitumen from the supplied oil sand, in which a portion of the hydrocarbon mixture within the vessel during contacting is in vapor phase, and the solvent-treated oil sand is removed from the vessel.
In one embodiment, the solvent-treated oil sand is treated with the aqueous solution at a pH of at least 8 to recover the bitumen product. In a particular embodiment, the aqueous solution is an aqueous sodium hydroxide solution.
The bitumen material removed from the solvent-treated oil sand can be recovered as a froth comprised of the bitumen material. In one embodiment, a hydrocarbon diluent is added to the froth prior to recovering the bitumen material.
The solvent can be further defined by one or more additional Hansen solubility parameters. For example, the solvent can have a Hansen polarity blend parameter of not greater than 1. As another example, the solvent can have a Hansen dispersion blend parameter of less than 16.
In an embodiment, the solvent can have a ketone content of less than 10 wt %. In another embodiment, the solvent can have an aromatic content of less than 10 wt %.

DETAILED DESCRIPTION OF THE INVENTION

I. Dual Phase Processing of Oil Sand

This invention provides a process for producing bitumen product of relatively high quality from oil sand, which can be used in the manufacture of various asphalt materials. The bitumen product is produced by a process that is much more environmentally friendly than known processes for producing asphalt base materials, and the bitumen product is relatively high quality to the extent that little if any additional treatment is needed to use the bitumen product as a binder material for asphalt cements or roofing materials.
The process for producing the high quality bitumen product involves what can be termed as a dual phase bitumen extraction process. In this dual phase process, a very high quality deasphalted crude oil is extracted from oil sand in a solvent treatment first phase. The second phase of the process extracts high quality bitumen product from the solvent-treated oil sand.

II. Oil Sand

Bitumen product can be extracted from any oil sand according to this invention. The oil sand can also be referred to as tar sand or bitumen sand. Additionally, the oil sand can be characterized as being comprised of a porous mineral structure, which contains an oil component. The entire oil content of the oil sand can be referred to as bitumen.
Bitumen can be comprised of numerous oil components. For example, bitumen can be comprised of a flowable oil component, various volatile hydrocarbons and various non-volatile hydrocarbons, such as asphaltenes. The portion of the bitumen that is the focus of the bitumen product of this invention is a bitumen fraction that is particularly high in asphaltene content.
One example of an oil sand from which a crude oil composition, as well the high quality bitumen product produced according to this invention, can be referred to as water wet oil sand, such as that generally found in the Athabasca deposit of Canada. Such oil sand can be comprised of mineral particles surrounded by an envelope of water, which may be referred to as connate water. The bitumen of such water wet oil sand may not be in direct physical contact with the mineral particles, but rather formed as a relatively thin film that surrounds a water envelope around the mineral particles.
Another example of oil sand from which a crude oil composition, as well the high quality bitumen product produced according to this invention, can be referred to as oil wet oil sand, such as that generally found in Utah. Such oil sand may also include water. However, these materials may not include a water envelope barrier between the bitumen and the mineral particles. Rather, the oil wet oil sand can comprise bitumen in direct physical contact with the mineral component of the oil sand.
In one aspect of the invention, a feed stream of oil sand is supplied to a contact zone, with the oil sand being comprised of at least 6 wt % of a bitumen composition, based on total weight of the supplied oil sand. Preferably, the oil sand feed is comprised of at least 8 wt % of a bitumen composition, more preferably at least 10 wt % of a bitumen composition, still more preferably at least 12 wt % of a bitumen composition, based on total weight of the oil sand feed.
Oil sand can have a tendency to clump due to some stickiness characteristics of the oil component of the oil sand. The oil sand that is fed to the contact zone should not be stuck together such that fluidization of the oil sand in the contact zone or extraction of the oil component in the contact zone is significantly impeded. In one embodiment, the oil sand that is provided or fed to the contact zone has an average particle size of not greater than 20,000 microns. Alternatively, the oil sand that is provided or fed to the contact zone has an average particle size of not greater than 10,000 microns, or not greater than 5,000 microns, or not greater than 2,500 microns.
As a practical matter, the particle size of the oil sand feed material should not be extremely small. For example, it is preferred to have an average particle size of at least 100 microns.

III. Phase I Extraction of High Quality Crude

According to this invention, a very high quality deasphalted crude oil is extracted from the oil sand in a solvent treatment first phase. The solvent can be comprised of a hydrocarbon mixture, and the mixture can be comprised of at least two, or at least three or at least four different hydrocarbons.
Hydrocarbon according to this invention refers to any chemical compound that is comprised of at least one hydrogen and at least one carbon atom covalently bonded to one another (C—H). Preferably, the solvent is comprised of at least 40 wt % hydrocarbon. Alternatively, the solvent is comprised of at least 60 wt % hydrocarbon, or at least 80 wt % hydrocarbon, or at least 90 wt % hydrocarbon.
The solvent can further comprise hydrogen or inert components. The inert components are considered compounds that are substantially unreactive with the hydrocarbon component or the oil components of the oil sand at the conditions at which the solvent is used in any of the steps of the process of the invention. Examples of such inert components include, but are not limited to, nitrogen and water, including water in the form of steam. Hydrogen, however, may or may not be reactive with the hydrocarbon or oil components of the oil sand, depending upon the conditions at which the solvent is used in any of the steps of the process of the invention.
Treatment of the oil sand with the solvent is carried out as a vapor state treatment. For example, at least a portion of the solvent in the vessel that serves as a contact zone for the solvent and oil sand is in the vapor state. In one embodiment, at least 20 wt % of the solvent in the contact zone is in the vapor state. Alternatively, at least 40 wt %, or at least 60 wt %, or at least 80 wt % of the solvent in the contact zone is in the vapor state.
The hydrocarbon of the solvent can be comprised of a mix of hydrocarbon compounds. The hydrocarbon compounds can range from 1 to 20 carbon atoms. In an alternative embodiment, the hydrocarbon of the solvent is comprised of a mixture of hydrocarbon compounds having from 1 to 15, alternatively from 1 to 10, carbon atoms. Examples of such hydrocarbons include aliphatic hydrocarbons, olefinic hydrocarbons and aromatic hydrocarbons. Particular aliphatic hydrocarbons include paraffins as well as halogen-substituted paraffins. Examples of particular paraffins include, but are not limited to propane, butane and pentane. Particularly useful paraffins are propane and butane. For example, the hydrocarbon solvent can be comprised of a majority, or at least 60 wt %, or at least 80 wt %, or at least 90 wt %, of at least one of propane and butane. Examples of halogen-substituted paraffins include, but are not limited to chlorine and fluorine substituted paraffins, such as C₁-C₆chlorine or fluorine substituted or C₁-C₃chlorine or fluorine substituted paraffins.
The hydrocarbon component of the solvent can be selected according to the degree of oil component that is desired to be extracted from the oil sand feed. The degree of extraction can be determined according to the amount of bitumen that remains with the oil sand following treatment or extraction. This can be determined according to the Dean Stark process.
In another aspect, the degree of extraction can be determined according to the asphaltene content of the extracted oil compositions. Asphaltene content can be determined according to ASTM D4055-04 (2009) Standard Test Method for Pentane Insolubles by Membrane Filtration.
In general, the solvent in the first phase extraction extracts a bitumen fraction or composition from the oil sand in which the solvent extracted bitumen fraction is low in asphaltene content. Particularly effective hydrocarbons for use as the solvent according to the first phase extraction of this invention can be classified according to Hansen solubility parameters, which is a three component set of parameters that takes into account a compound's dispersion force, polarity, and hydrogen bonding force. The Hansen solubility parameters are, therefore, each defined as a dispersion parameter (D), polarity parameter (P), and hydrogen bonding parameter (H). These parameters are listed for numerous compounds and can be found in Hansen Solubility Parameters in Practice—Complete with software, data, and examples, Steven Abbott, Charles M. Hansen and Hiroshi Yamamoto, 3rd ed., 2010, ISBN: 9780955122026, the contents of which are incorporated herein by reference. Examples of the Hansen solubility parameters are shown in Tables 1-12.

	TABLE 1

	Hansen Parameter

Alkanes	D	P	H

n-Butane	14.1	0.0	0.0
n-Pentane	14.5	0.0	0.0
n-Hexane	14.9	0.0	0.0
n-Heptane	15.3	0.0	0.0
n-Octane	15.5	0.0	0.0
Isooctane	14.3	0.0	0.0
n-Dodecane	16.0	0.0	0.0
Cyclohexane	16.8	0.0	0.2
Methylcyclohexane	16.0	0.0	0.0

	TABLE 2

	Hansen Parameter

Aromatics	D	P	H

Benzene	18.4	0.0	2.0
Toluene	18.0	1.4	2.0
Naphthalene	19.2	2.0	5.9
Styrene	18.6	1.0	4.1
o-Xylene	17.8	1.0	3.1
Ethyl benzene	17.8	0.6	1.4
p-Diethyl benzene	18.0	0.0	0.6

	TABLE 3

	Hansen Parameter

Halohydrocarbons	D	P	H

Chloromethane	15.3	6.1	3.9
Methylene chloride	18.2	6.3	6.1
1,1 Dichloroethylene	17.0	6.8	4.5
Ethylene dichloride	19.0	7.4	4.1
Chloroform	17.8	3.1	5.7
1,1 Dichloroethane	16.6	8.2	0.4
Trichloroethylene	18.0	3.1	5.3
Carbon tetrachloride	17.8	0.0	0.6
Chlorobenzene	19.0	4.3	2.0
o-Dichlorobenzene	19.2	6.3	3.3
1,1,2 Trichlorotrifluoroethane	14.7	1.6	0.0

	TABLE 4

	Hansen Parameter

Ethers	D	P	H

Tetrahydrofuran	16.8	5.7	8.0
1,4 Dioxane	19.0	1.8	7.4
Diethyl ether	14.5	2.9	5.1
Dibenzyl ether	17.4	3.7	7.4

	TABLE 5

	Hansen Parameter

	Ketones	D	P	H

Acetone	15.5	10.4	7.0
Methyl ethyl ketone	16.0	9.0	5.1
Cyclohexanone	17.8	6.3	5.1
Diethyl ketone	15.8	7.6	4.7
Acetophenone	19.6	8.6	3.7
Methyl isobutyl ketone	15.3	6.1	4.1
Methyl isoamyl ketone	16.0	5.7	4.1
Isophorone	16.6	8.2	7.4
Di-(isobutyl) ketone	16.0	3.7	4.1

	TABLE 6

	Hansen Parameter

	Esters	D	P	H

Ethylene carbonate	19.4	21.7	5.1
Methyl acetate	15.5	7.2	7.6
Ethyl formate	15.5	7.2	7.6
Propylene 1,2 carbonate	20.0	18.0	4.1
Ethyl acetate	15.8	5.3	7.2
Diethyl carbonate	16.6	3.1	6.1
Diethyl sulfate	15.8	14.7	7.2
n-Butyl acetate	15.8	3.7	6.3
Isobutyl acetate	15.1	3.7	6.3
2-Ethoxyethyl acetate	16.0	4.7	10.6
Isoamyl acetate	15.3	3.1	7.0
Isobutyl isobutyrate	15.1	2.9	5.9

	TABLE 7

	Hansen Parameter

	Nitrogen Compounds	D	P	H

Nitromethane	15.8	18.8	5.1
Nitroethane	16.0	15.5	4.5
2-Nitropropane	16.2	12.1	4.1
Nitrobenzene	20.0	8.6	4.1
Ethanolamine	17.2	15.6	21.3
Ethylene diamine	16.6	8.8	17.0
Pyridine	19.0	8.8	5.9
Morpholine	18.8	4.9	9.2
Aniline	19.4	5.1	10
N-Methyl-2-pyrrolidone	18.0	12.3	7.2
Cyclohexylamine	17.4	3.1	6.6
Quinoline	19.4	7.0	7.6
Formamide	17.2	26.2	19.0
N,N-Dimethylformamide	17.4	13.7	11.3

	TABLE 8

	Hansen Parameter

	Sulfur Compounds	D	P	H

Carbon disulfide	20.5	0.0	0.6
Dimethylsulfoxide	18.4	16.4	10.2
Ethanethiol	15.8	6.6	7.2

	TABLE 9

	Hansen Parameter

	Alcohols	D	P	H

Methanol	15.1	12.3	22.3
Ethanol	15.8	8.8	19.4
Allyl alcohol	16.2	10.8	16.8
1-Propanol	16.0	6.8	17.4
2-Propanol	15.8	6.1	16.4
1-Butanol	16.0	5.7	15.8
2-Butanol	15.8	5.7	14.5
Isobutanol	15.1	5.7	16.0
Benzyl alcohol	18.4	6.3	13.7
Cyclohexanol	17.4	4.1	13.5
Diacetone alcohol	15.8	8.2	10.8
Ethylene glycol monoethyl ether	16.2	9.2	14.3
Diethylene glycol monomethyl ether	16.2	7.8	12.7
Diethylene glycol monoethyl ether	16.2	9.2	12.3
Ethylene glycol monobutyl ether	16.0	5.1	12.3
Diethylene glycol monobutyl ether	16.0	7.0	10.6
1-Decanol	17.6	2.7	10.0

	TABLE 10

	Hansen Parameter

	Acids	D	P	H

Formic acid	14.3	11.9	16.6
Acetic acid	14.5	8.0	13.5
Benzoic acid	18.2	7.0	9.8
Oleic acid	14.3	3.1	14.3
Stearic acid	16.4	3.3	5.5

	TABLE 11

	Hansen Parameter

	Phenols	D	P	H

Phenol	18.0	5.9	14.9
Resorcinol	18.0	8.4	21.1
m-Cresol	18.0	5.1	12.9
Methyl salicylate	16.0	8.0	12.3

	TABLE 12

	Hansen Parameter

	Polyhydric alcohols	D	P	H

Ethylene glycol	17.0	11.0	26.0
Glycerol	17.4	12.1	29.3
Propylene glycol	16.8	9.4	23.3
Diethylene glycol	16.2	14.7	20.5
Triethylene glycol	16.0	12.5	18.6
Dipropylene glycol	16.0	20.3	18.4

According to the Hansen Solubility Parameter System, a mathematical mixing rule can be applied in order to derive or calculate the respective Hansen parameters for a blend of hydrocarbons from knowledge of the respective parameters of each hydrocarbon component and the volume fraction of the hydrocarbon component. Thus according to this mixing rule:
Dblend=ΣVi Di,
Pblend=ΣVi Pi,
Hblend=ΣVi Hi,
where Dblend is the Hansen dispersion parameter of the blend, Di is the Hansen dispersion parameter for component i in the blend; Pblend is the Hansen polarity parameter of the blend, Pi is Hansen polarity parameter for component i in the blend, Hblend is the Hansen hydrogen bonding parameter of the blend, Hi is the Hansen hydrogen bonding parameter for component i in the blend, Vi is the volume fraction for component i in the blend, and summation is over all i components in the blend.
The solvent of this invention is defined according to the mathematical mixing rule. The solvent is comprised of a blend of hydrocarbon compounds and can optionally include limited amounts of non-hydrocarbons being optionally present. In such cases when non-hydrocarbon compounds are included in the solvent, the Hansen solubility parameters of the non-hydrocarbon compounds should also be taken into account according to the mathematical mixing rule. Thus, reference to Hansen solubility blend parameters herein, takes into account the Hansen parameters of all the compounds present. Of course, it may not be practical to account for every compound present in the solvent. In such complex cases, the Hansen solubility blend parameters can be determined according to Hansen Solubility Parameters in Practice. See, e.g., Chapter 3, pp. 15-18, and Chapter 8, pp. 43-46, for further description.
In order to produce a high quality bitumen product from the second phase extraction, the solvent is selected to limit the amount of asphaltenes that are extracted from oil sand in the first phase extraction. The more desirable solvents have Hansen blend parameters that are relatively low. Lower values for the Hansen dispersion blend parameter and/or the Hansen polarity blend parameter are particularly preferred. Especially desirable solvents have low Hansen dispersion blend and Hansen polarity blend parameters.
The Hansen dispersion blend parameter of the solvent is desirably less than 16. In general, lower dispersion blend parameters are particularly desirable. As an example, the solvent is comprised of a hydrocarbon mixture, with the solvent having a Hansen dispersion blend parameter of not greater than 15. Additional examples include solvents comprised of a hydrocarbon mixture, with the solvent having a Hansen dispersion blend parameter of from 13 to 16 or from 13 to 15.
The Hansen polarity blend parameter of the solvent is desirably less than 2. In general, lower polarity blend parameters are particularly desirable. It is further desirable to use solvents that have both low Hansen dispersion blend parameters, as defined above, along with the low Hansen polarity blend parameters. As an example of low polarity blend parameters, the solvent is comprised of a hydrocarbon mixture, with the solvent having a Hansen polarity blend parameter of not greater than 1, alternatively not greater than 0.5, or not greater than 0.1. Additional examples include solvents comprised of a hydrocarbon mixture, with the solvent having a Hansen polarity blend parameter of from 0 to 2 or from 0 to 1.5 or from 0 to 1 or from 0 to 0.5 or from 0 to 0.1.
The Hansen hydrogen bonding blend parameter of the solvent is desirably less than 2. In general, lower hydrogen bonding blend parameters are particularly desirable. It is further desirable to use solvents that have low Hansen dispersion blend parameters and Hansen polarity blend parameters, as defined above, along with the low Hansen hydrogen bonding blend parameters. As an example of low hydrogen bonding blend parameters, the solvent is comprised of a hydrocarbon mixture, with the solvent having a Hansen hydrogen bonding blend parameter of not greater than 1, alternatively not greater than 0.5, or not greater than 0.1, or not greater than 0.05. Additional examples include solvents comprised of a hydrocarbon mixture, with the solvent having a Hansen hydrogen bonding blend parameter of from 0 to 1 or from 0 to 0.5 or from 0 to 0.1 or from 0 to 0.05.
The solvent can be a blend of relatively low boiling point compounds. Since the solvent is a blend of compounds, the boiling range of solvent compounds useful according to this invention, as well as the crude oil compositions produced according to this invention, can be determined by batch distillation according to ASTM D86-09e1, Standard Test Method for Distillation of Petroleum Products at Atmospheric Pressure.
In one embodiment, the solvent has an ASTM D86 10% distillation point of at least 45° C. Alternatively, the solvent has an ASTM D86 10% distillation point of at least 40° C., or at least 30° C. The solvent can have an ASTM D86 10% distillation point within the range of from 45° C. to 50° C., alternatively within the range of from 35° C. to 45° C., or from 20° C. to 40° C.
The solvent can have an ASTM D86 90% distillation point of not greater than 300° C. Alternatively, the solvent has an ASTM D86 90% distillation point of not greater than 200° C., or not greater than 100° C.
The solvent can have a significant difference between its ASTM D86 90% distillation point and its ASTM D86 10% distillation point. For example, the solvent can have a difference of at least 5° C. between its ASTM D86 90% distillation point and its ASTM D86 10% distillation point, alternatively a difference of at least 10° C., or at least 15° C. However, the difference between the solvent's ASTM D86 90% distillation point and ASTM D86 10% distillation point should not be so great such that efficient recovery of solvent from extracted crude is impeded. For example, the solvent can have a difference of not greater than 60° C. between its ASTM D86 90% distillation point and its ASTM D86 10% distillation point, alternatively a difference of not greater than 40° C., or not greater than 20° C.
Solvents high in aromatic content are not particularly desirable. For example, the solvent can have an aromatic content of not greater than 10 wt %, alternatively not greater than 5 wt %, or not greater than 3 wt %, or not greater than 2 wt %, based on total weight of the solvent injected into the extraction vessel. The aromatic content can be determined according to test method ASTM D6591-06 Standard Test Method for Determination of Aromatic Hydrocarbon Types in Middle Distillates-High Performance Liquid Chromatography Method with Refractive Index Detection.
Solvents high in ketone content are also not particularly desirable. For example, the solvent can have a ketone content of not greater than 10 wt %, alternatively not greater than 5 wt %, or not greater than 2 wt %, based on total weight of the solvent injected into the extraction vessel. The ketone content can be determined according to test method ASTM D4423-10 Standard Test Method for Determination of Carbonyls in C₄Hydrocarbons.
In one embodiment, the solvent can be comprised of hydrocarbon in which at least 60 wt % of the hydrocarbon is aliphatic hydrocarbon, based on total weight of the solvent. Alternatively, the solvent can be comprised of hydrocarbon in which at least 70 wt %, or at least 80 wt %, or at least 90 wt % of the hydrocarbon is aliphatic hydrocarbon, based on total weight of the solvent. Light aliphatic hydrocarbons are preferred, such as C₁-C₅aliphatic hydrocarbons. Particular examples include propane, butane and pentane. Preferred are propane and butane, with propane being more preferred.
The solvent preferably does not include substantial amounts of non-hydrocarbon compounds. Non-hydrocarbon compounds are considered chemical compounds that do not contain any C—H bonds. Examples of non-hydrocarbon compounds include, but are not limited to, hydrogen, nitrogen, water and the noble gases, such as helium, neon and argon. For example, the solvent preferably includes not greater than 20 wt %, alternatively not greater than 10 wt %, alternatively not greater than 5 wt %, non-hydrocarbon compounds, based on total weight of the solvent injected into the extraction vessel.
Solvent to oil sand feed ratios can vary according to a variety of variables. Such variables include amount of hydrocarbon mix in the solvent, temperature and pressure of the contact zone, and contact time of hydrocarbon mix and oil sand in the contact zone. Preferably, the solvent and oil sand is supplied to the contact zone of the extraction vessel at a weight ratio of total hydrocarbon in the solvent to oil sand feed of at least 0.01:1, or at least 0.1:1, or at least 0.5:1 or at least 1:1. Very large total hydrocarbon to oil sand ratios are not required. For example, the solvent and oil sand can be supplied to the contact zone of the extraction vessel at a weight ratio of total hydrocarbon in the solvent to oil sand feed of not greater than 4:1, or 3:1, or 2:1.
Extraction of oil compounds from the oil sand in the Phase I extraction of crude or deasphalted oil from the bitumen is carried out in a contact zone such as in a vessel having a zone in which the solvent contacts the oil sand. Any type of extraction vessel can be used that is capable of providing contact between the oil sand and the solvent such that a portion of the oil is removed from the oil sand. For example, horizontal or vertical type extractors can be used. The solid can be moved through the extractor by pumping, such as by auger-type movement, or by fluidized type of flow, such as free fall or free flow arrangements. An example of an auger-type system is described in U.S. Pat. No. 7,384,557.
The solvent can be injected into the vessel by way of nozzle-type devices. Nozzle manufacturers are capable of supplying any number of nozzle types based on the type of spray pattern desired.
The contacting of oil sand with solvent in the contact zone of the extraction vessel is at a pressure and temperature in which at least a portion of the hydrocarbon mixture within the contacting zone of the vessel is in vapor phase during contacting. For example, at least 20 wt % of the hydrocarbon mixture within the contacting zone of the vessel is in vapor phase during contacting. Alternatively, at least 40 wt %, or at least 60 wt % or at least 80 wt % of the hydrocarbon mixture within the contacting zone of the vessel is in the vapor phase.
Carrying out the extraction process at the desired conditions using the desired solvent enables controlling the amount of oil that is extracted from the oil sand. For example, contacting the oil sand with the solvent in a vessel's contact zone can produce a crude oil composition comprised of not greater than 80 wt %, or not greater than 70 wt %, or not greater than 60 wt %, of the bitumen from the supplied oil sand. That is, the solvent is comprised of a hydrocarbon mix or blend that has the desired characteristics such that the solvent process can remove or extract not greater than 80 wt %, or greater than 70 wt %, or greater than 60 wt %, of the bitumen from the supplied oil sand. This crude oil composition that leaves the extraction zone will also include at least a portion of the solvent. However, a substantial portion of the solvent can be separated from the crude oil composition to produce a crude oil product that can be pipelined, transported by other means such as railcar or truck, or further upgraded to make fuel products. The separated solvent can then be recycled. Since the extraction process incorporates a relatively light solvent blend relative to the crude oil composition, the solvent portion can be easily recovered, with little if any external make-up being required.
The crude oil composition that includes at least a portion of the solvent, as well the crude oil product that is later separated from the crude oil composition containing solvent, will be reduced in metals and asphaltenes compared to typical processes. Metals content can be determined according to ASTM D5708-11 Standard Test Methods for Determination of Nickel, Vanadium, and Iron in Crude Oils and Residual Fuels by Inductively Coupled Plasma (ICP) Atomic Emission Spectrometry. For example, the crude oil composition that includes at least a portion of the solvent, as well the separated crude oil product, can have a nickel plus vanadium content of not greater than 150 wppm, or not greater than 125 wppm, or not greater than 100 wppm, based on total weight of the composition.
As another example, the crude oil composition that includes at least a portion of the solvent, as well the separated crude oil product, can have an asphaltenes content (i.e., pentane insolubles measured according to ASTM D4055 of not greater than 5 wt %, alternatively not greater than 3 wt %, or not greater than 1 wt %, or not greater than 0.5 wt %.
The crude oil composition that includes at least a portion of the solvent, as well the crude oil product that is later separated from the crude oil composition containing solvent, will also have a reduced Conradson Carbon Residue (CCR), measured according to ASTM D4530. For example, the crude oil composition that includes at least a portion of the solvent, as well the crude oil product that is later separated from the crude oil composition containing solvent, can have a CCR of not greater than 5 wt %, or not greater than 4 wt %, or not greater than 3 wt %.
The Phase I extraction is carried out at temperatures and pressures that allow at least a portion of the solvent to be maintained in the vapor phase in the contact zone. Since at least a portion of the solvent is in the vapor phase in the contact zone, higher contact zone temperatures. For example, the contacting of the oil sand and the solvent in the contact zone of the extraction vessel can be carried out at a temperature of at least 35° C., or at least 50° C., or at least 70° C. Upper temperature limits depend primarily upon physical constraints, such as contact vessel materials. In addition, temperatures should be limited to below cracking conditions for the extracted crude. Generally, it is desirable to maintain temperature in the contact vessel at not greater than 500° C., alternatively not greater than 400° C. or not greater than 300° C. or not greater than 100° C.
Pressure in the contact zone can vary as long as the desired amount of hydrocarbon in the solvent remains in the vapor phase in the contact zone. Atmospheric pressure and above is preferred. For example, pressure in the contacting zone can be at least 15 psia (103 kPa), or at least 50 psia (345 kPa), or at least 100 psia (689 kPa), or at least 150 psia (1034 kPa). Extremely high pressures are not preferred to ensure that at least a portion of the solvent remains in the vapor phase. For example, the contacting of the oil sand and the solvent in the contact zone of the extraction vessel can be carried out a pressure of not greater than 600 psia (4137 kPa), alternatively not greater than 500 psia (3447 kPa), or not greater than 400 psia (2758 kPa) or not greater than 300 psia (2068 kPa).
The crude oil composition that is removed from the contact zone of the extraction vessel in the Phase I extraction comprises the deasphalted oil component extracted from the oil sand and at least a portion of the solvent. At least a portion of the solvent in the oil composition can be separated and recycled for reuse as solvent in the Phase I extraction step. This separated solvent is separated so as to match or correspond within 50%, preferably within 30% or 20% or 10%, of the Hansen solubility characteristics of any make-up solvent, i.e., the overall generic chemical components and boiling points as described above for the solvent composition. For example, an extracted crude product containing the extracted crude oil and solvent is sent to a separator and a light fraction is separated from a crude oil fraction in which the separated solvent has each of the Hansen solubility characteristics and each of the boiling point ranges within 50% of the above noted amounts, alternatively within 30% or 20% or 10% of the above noted amounts. This separation can be achieved using any appropriate chemical separation process. For example, separation can be achieved using any variety of evaporators, flash drums or distillation equipment or columns. The separated solvent can be recycled to contact oil sand, and optionally mixed with make-up solvent having the characteristics indicated above.
Following removal of the deasphalted crude oil composition from the extraction vessel, the crude oil composition is separated into fractions comprised of recycle solvent and deasphalted crude oil product. The deasphalted crude oil product can be relatively high in quality in that it can have relatively low metals and asphaltenes content as described above. The low metals and asphaltenes content enables the crude oil product to be relatively easily upgraded to liquid fuels compared to typical bitumen oils.
The crude oil product will have a relatively high API gravity compared to the bitumen product extracted in the second phase extraction step. API gravity can be determined according to ASTM D287-92 (2006) Standard Test Method for API Gravity of Crude Petroleum and Petroleum Products (Hydrometer Method). The crude oil product can, for example, have an API gravity of at least 8, or at least 10, or at least 12, or at least 14, depending on the exact solvent composition and process conditions.

IV. Phase II Extraction of High Quality Asphalt

The solvent-treated oil sand contains the fraction of bitumen remaining following the Phase I extraction of crude oil that is recovered as the high quality bitumen basestock or binder. Generally, this fraction of bitumen is high in asphaltene content and can be referred to as asphalt bitumen.
In the Phase II extraction step, the solvent-treated oil sand is provided, and the provided oil sand is mixed with water to form a slurry. An aqueous slurry of the treated oil sand can be prepared by contacting the treated oil sand with water in an amount of 10% to 500%, based on the mass of the water to total mass of the treated oil sand, preferably, 50% to 200%.
The slurry is maintained at higher temperatures such as from 25° C. to the boiling point of the water to facilitate removal of the asphalt bitumen from the sand. Preferably, the slurry is maintained within a temperature range of from 25° C. to below the boiling point of the water. For example, the temperature range can be from 25° C. to 90° C., or from 35° C. to 85° C.
Air can be added to the slurry to further facilitate separation of the asphalt bitumen. For example, air can be added and the slurry retained in a primary vessel such as a holding or settler vessel. The air can facilitate the removal of the bitumen by enhancing the ability of the asphalt bitumen to rise through the slurry and form a froth.
The froth can be recovered from an upper or overflow portion of the settler vessel. This froth can be comprised of from 50 wt % to 80 wt % of the asphalt bitumen, 20 wt % to 45 wt % water, and 5 wt % to 30 wt % solids.
A majority of the solids in the slurry can settle in the settler vessel and be discharged from a lower discharge portion of the vessel as an underflow stream. This underflow stream can also contain a portion of the asphalt bitumen and the water in the settler vessel.
A mid-section can also form in the settler vessel. This mid-section can be referred to as a middlings section, and can contain a substantial portion (i.e., a majority) of the water in the settler vessel, as well as a portion of the asphalt bitumen and solids. Generally, the solids in the mid-section have an average diameter less than that of the solids in the discharge portion.
At least a portion of the middlings section, at least a portion of the underflow, or both, can be sent to a second vessel for recovery of additional asphalt bitumen. For example, in the second vessel, a portion of the middlings section can be mixed with underflow. The mixture can then separate into fractions within the second vessel similar to the separation of the fractions in the primary vessel.
In one embodiment of the invention, a secondary froth can be recovered from an upper or overflow portion of the second vessel. This secondary froth will generally comprise a percentage of the asphalt bitumen less than that in the primary settler, such as from 20% to 80% or 30% to 60% less asphalt bitumen than in the primary froth. For example, the secondary froth can be comprised of from 20 wt % to 50 wt % of asphalt bitumen, 30 wt % to 60 wt % water, and 5 wt % to 30 wt % solids. If desired, additional or subsequent vessels can be used to enhance the asphalt bitumen recovery.
Water and solids in the froth are preferably removed from the froth to provide a high-quality asphalt bitumen that can be used as bitumen binder. The bitumen binder is particularly useful for bitumen concrete and roofing materials.
One or more of the following additives may be added to the slurry prior to facilitate separation and removal of the bitumen. Examples of such additives include, but are not limited to, polysilicate microgels, caustics such as sodium hydroxide, sodium carbonate, sodium silicate, and sodium citrate; organic acids and salts of organic acids, such as glycolic acid and sodium glycolate, surfactants, buffers such as bicarbonates, and antimicrobial agents.
In one embodiment, the treated oil sands and water, and optionally one or more additives, are mixed and contacted with air, generally in the form of air bubbles, in one or more contact vessels or in a transport line. Contacting the air bubbles with the slurry results in bitumen floating to the top of the slurry, creating a top, froth layer. The froth comprises the high-quality bitumen that has floated to the top of the slurry, and also comprises clay fines.
In one embodiment, one or more additives are added to the slurry to maintain an alkaline pH. For example, one or more additives are added to the slurry to maintain a pH of at least 7.5. As another example, one or more additives are added to the slurry to maintain a pH of from 8 to 10 or 8 to 9.
The process may further comprise removing the froth and transferring the froth to a froth treatment unit. In the froth treatment unit, the froth is contacted with a solvent to extract the bitumen from the froth and to concentrate the bitumen. The solvent can be selected from the group consisting of paraffinic alkanes, such as C₅to C₈n-alkanes, kerosene, diesel, naphthenic solvents and combinations thereof. Examples of naphthenic solvents include, but are not limited to, light naphtha, heavy naphtha, coker naphtha and hydrotreated naphtha. In one embodiment the solvent can have an end boiling point of less than 150° C. or not greater than 125° C. A by-product from froth treatment unit is froth treatment tailings, which comprise very fine solids, hydrocarbons and water.
The froth treatment tailings may be further treated in a dewatering step to remove water, from the solids which comprise clay fines and sand. The removed water can be recycled into any portion of the Phase II where water is desired.
The process may further comprise dewatering tailings. The tailings can be one or more of any of the tailings streams produced in a process to extract bitumen from the treated oil sand. The term tailings can refer to one or more of the coarse tailings, fine tailings and froth treatment tailings. The tailings may be combined into a single tailings stream for dewatering or each tailings stream may be dewatered individually. Depending upon the composition of the tailings stream, the additives may change, concentrations of additives may change, and the sequence of adding the additives may change. Such changes may be determined from experience with different tailings streams compositions.
Dewatering may be accomplished by any appropriate means. Examples of dewatering steps include the use of thickeners, hydrocyclones and/or centrifuges, or by decantation and/or filtration. Dewatered solids should be handled in compliance with governmental regulations.
Conventionally, fine tailings and froth treatment tailings have been difficult to dewater. Both comprise clay fines and unextracted bitumen. Such tailings after dewatering, have been sent to tailings ponds. According to this invention, separation of solids from the fine tailings and froth treatment tailings is improved.
The high-quality bitumen recovered from the froth can be used as asphalt binder for concrete or roofing materials with little if any additional processing. The high quality of the bitumen product is indicated by any of a variety of characteristics.
According to one characteristic, the bitumen product is considered a high quality bitumen product in that it has a H/C atomic ratio of less than 1.4. Alternatively, the bitumen product has a H/C atomic ratio of less than 1.2 or less than 1.
According to another characteristic, the bitumen product is considered a high quality bitumen product in that it has a Conradson Carbon Residue of at least 20 wt %, measured according to ASTM D4530. Alternatively, the bitumen product has a CCR of at least 30 wt % or at least 40 wt %.
According to another characteristic, the bitumen product is considered a high quality bitumen product in that it has a flash point of greater than or equal to 100° C., measured according to ASTM D92. Alternatively, the bitumen product has a flash point of greater than or equal to 140° C. or greater than or equal to 180° C. or greater than or equal to 220° C.
According to another characteristic, the bitumen product is considered a high quality bitumen product in that it has a solubility in trichloroethylene of greater than or equal to 98 percent, measured according to ASTM D2042. Alternatively, the bitumen product has a solubility in trichloroethylene of greater than or equal to 99 percent or greater than or equal to 99.9 percent.
According to another characteristic, the bitumen product is considered a high quality bitumen product in that it has greater than or equal to 40 wt % pentane insolubles, measured according to ASTM D4055. Alternatively, the bitumen product has greater than or equal to 50 wt % pentane insolubles or greater than or equal to 60 wt % pentane insolubles.
According to another characteristic, the bitumen product is considered a high quality bitumen product in that it has an absolute viscosity at 60° C. of greater than or equal to 500 poise, measured according to ASTM D2171. Alternatively, the bitumen product has an absolute viscosity at 60° C. of greater than or equal to 1000 poise or greater than or equal to 2000 poise.
According to another characteristic, the bitumen product is considered a high quality bitumen product in that it has a kinematic viscosity at 135° C. of greater than or equal to 100 cSt, measured according to ASTM D2170. Alternatively, the bitumen product has a kinematic viscosity at 135° C. of greater than or equal to 200 cSt or greater than or equal to 300 cSt.

V. Examples

Particles of Utah oil sands were screened through a standard US 12 mesh screen to obtain a relatively uniformed-sized feedstock. A portion of the oil sands was evaluated for total bitumen content by extracting the bitumen according to the Dean-Stark method (ASTM D95-05e1 Standard Test Method for Water in Petroleum Products and Bituminous Materials by Distillation). The Dean-Stark method can be used to determine the weight percent of oil in an oil sand sample as well as water content. A sample is first weighed, then solute is extracted using solvent. The sample and solvent are refluxed under a condenser using a standard Dean-Stark apparatus. Water (e.g., water extracted from sample along with solute) and organic material (e.g., solvent and extracted solute) condense to form two phases in the condenser. The two layers can be separated and weight percent of water and solute can be determined according to the standard method. The untreated oil sands were found to have a total bitumen content of 14.6%, based on total weight of the oil sands prior.
In carrying out the Phase I crude oil extraction step, screened Utah oil sands particles were fed to an extraction chamber and moved through the extraction chamber while being contacted with propane-based solvent. The extraction chamber consisted of an auger type moving device in which the auger was used to move the particles through the chamber, and solvent was injected into the extraction chamber as the particles moved through the extraction chamber. An example of the device is depicted in U.S. Pat. No. 7,384,557.
Solvent injected into the extraction chamber was comprised of 99 wt % propane. The solvent was injected under pressure 160 psia (10.9 atm) at a flow rate of 1.2 g/min. The extractor was maintained at an average pressure of 116 psia (7.9 atm), with the residence time of the solids being about 35 minutes. Ambient temperature was about 55-59° F.
Liquid was separated from the solid in the extraction chamber, as the oil sand flowed through the extraction chamber. The separated liquid was subjected to flash vaporization to remove the propane solvent, leaving a crude oil composition. The remaining oil sands were further heated to remove residual solvent. The bitumen content of the remaining tailings was determined using the Dean-Stark method, and the remaining bitumen content of the tailings was determined to be 4.3 wt. %, indicating a 68% extraction from the bitumen in the starting oil sands.
In carrying out the Phase II extraction step, the residual bitumen was separated from the rest of the tailings via a water-based extraction process. 250 grams of the propane-treated oil sands tailings and 74 milliliters (ml) of a 0.5 N sodium hydroxide solution were vigorously mixed using a blender type apparatus at 200° F. (93° C.) for 10-15 minutes. An additional 500 ml of sodium hydroxide solution was added to the mixer, and the oil sands and solution were vigorously mixed for an additional 10 minutes. Froth was collected from the mixer and water and bitumen were separated from the collected froth.
The Phase II separated bitumen was analyzed at Intertek, St. Rose, La., with the results shown in Table 13. Note that the organic C, H, N and S account for 38%, indicating in this experiment that the organics were not fully separated from the inorganics. A more complete separation is achievable via more efficient stirring/mixing than the blender provided.
Table 13 shows via the hydrogen and carbon analyses of the organics extracted from the tailings of stage 1, that the hydrogen/carbon atomic ratio is 1.31.

TABLE 13

Method	Test	Result

ASTM D5291	C, H, N and S Content
	Carbon content (wt. %)	33.0
	Hydrogen content (wt. %)	3.60
	Nitrogen content (wt. %)	0.40
	Sulfur content (wt. %)	1.7
	Hydrogen/Carbon Atomic Ratio	1.31

The H/C ratio of Table 13 is indicative of a highly aromatic, asphaltenic material and is consistent with the selective nature of the first step, the extraction with a light hydrocarbon solvent. Thus two low energy steps, Phase I and Phase II, produce a high quality crude material from the first step and a high quality asphalt material in the second step.
The principles and modes of operation of this invention have been described above with reference to various exemplary and preferred embodiments. As understood by those of skill in the art, this invention also encompasses a variety of preferred embodiments within the overall description of the invention as defined by the claims, which embodiments have not necessarily been specifically enumerated herein.

Claims

1. A process for producing a bitumen product, comprising:

removing not greater than 80 wt % of a bitumen oil composition from an oil sand material by treating with a hydrocarbon solvent comprised of at least 60 wt % aliphatic hydrocarbon selected from the group consisting of propane, butane and mixtures thereof, to produce a crude oil material and a solvent-treated oil sand;

separating the crude oil material from the solvent-treated oil sand;

treating the solvent-treated oil sand separated from the crude oil material with an aqueous solution to remove bitumen material from the solvent-treated oil sand; and

recovering the bitumen product from the bitumen material.

2. The process of claim 1, further comprising a step of separating at least a portion of the hydrocarbon solvent from the separated crude oil material to obtain a crude oil product

3. The process of claim 2, wherein the crude oil product has a Conradson Carbon Residue of not greater than 5 wt %, measured according to ASTM D4530.

4. The process of claim 2, wherein the crude oil product has a H/C atomic ratio of at least 1.4.

5. The process of claim 2, wherein the crude oil product contains not greater than 5 wt % pentane insolubles, measured according to ASTM D4055.

6. The process of claim 1, wherein the bitumen product has a H/C atomic ratio of less than 1.4.

7. The process of claim 1, wherein the bitumen product has a Conradson Carbon Residue of at least 20 wt %, measured according to ASTM D4530.

8. The process of claim 1, wherein the bitumen product has a flash point of greater than or equal to 100° C., measured according to ASTM D92.

9. The process of claim 1, wherein the bitumen product has a solubility in trichloroethylene of greater than or equal to 98 percent, measured according to ASTM D2042.

10. The process of claim 1, wherein the bitumen product has greater than or equal to 40 wt % pentane insolubles, measured according to ASTM D4055.

11. The process of claim 1, wherein the bitumen product has an absolute viscosity at 60° C. of greater than or equal to 500 poise, measured according to ASTM D2171.

12. The process of claim 1, wherein the bitumen product has a kinematic viscosity at 135° C. of greater than or equal to 100 cSt.

13. A process for producing a bitumen product, comprising:

a) providing a solvent-treated oil sand material, wherein the solvent treated oil sand material is obtained by:

i) removing not greater than 80 wt % of a bitumen oil composition from an oil sand material by treating with a hydrocarbon solvent comprised of at least 60 wt % aliphatic hydrocarbon selected from the group consisting of propane, butane and mixtures thereof, to produce a crude oil material and the solvent-treated oil sand material, and

ii) separating the crude oil material from the solvent-treated oil sand material;

b) treating the solvent-treated oil sand material with an aqueous solution to remove bitumen material from the solvent-treated oil sand; and

c) recovering the bitumen product from the bitumen material.

14. The process of claim 13, wherein the bitumen product has a H/C atomic ratio of less than 1.4.

15. The process of claim 13, wherein the bitumen product has a Conradson Carbon Residue of at least 20 wt %, measured according to ASTM D4530.

16. The process of claim 13, wherein the bitumen product has a flash point of greater than or equal to 100° C., measured according to ASTM D92.

17. The process of claim 13, wherein the bitumen product has a solubility in trichloroethylene of greater than or equal to 98 percent, measured according to ASTM D2042.

18. The process of claim 13, wherein the bitumen product has greater than or equal to 40 wt % pentane insolubles, measured according to ASTM D4055.

19. The process of claim 13, wherein the bitumen product has an absolute viscosity at 60° C. of greater than or equal to 500 poise, measured according to ASTM D2171.

20. The process of claim 13, wherein the bitumen product has a kinematic viscosity at 135° C. of greater than or equal to 100 cSt.

21. A process for producing a bitumen product, comprising:

supplying oil sand containing bitumen to a vessel;

injecting a solvent comprised of a hydrocarbon mixture into the vessel, wherein the solvent has a Hansen hydrogen bonding blend parameter of not greater than 0.5;

treating the oil sand with the solvent in the vessel to remove not greater than 80 wt % of a bitumen oil composition from the supplied oil sand, wherein at least a portion of the hydrocarbon mixture within the vessel during contacting is in vapor phase;

removing the solvent-treated oil sand from the vessel;

treating the solvent-treated oil sand removed from the vessel with an aqueous solution to remove bitumen material from the solvent-treated oil sand; and

recovering the bitumen product from the bitumen material.

22. The process of claim 21, wherein the solvent-treated oil sand is treated with the aqueous solution at a pH of at least 8.

23. The process of claim 21, wherein the aqueous solution is an aqueous sodium hydroxide solution.

24. The process of claim 21, wherein the bitumen material removed from the solvent-treated oil sand is recovered as a froth comprised of the bitumen material.

25. The process of claim 24, wherein a hydrocarbon diluent is added to the froth prior to recovering the bitumen material.

26. The process of claim 21, wherein the solvent has a Hansen polarity blend parameter of not greater than 1.

27. The process of claim 21, wherein the solvent has a Hansen dispersion blend parameter of less than 16.

28. The process of claim 21, wherein the solvent has a ketone content of less than 10 wt %.

29. The process of claim 21, wherein the solvent has an aromatic content of less than 10 wt %.

30. A process for producing a bitumen product, comprising:

i) supplying oil sand containing bitumen to a vessel,

ii) injecting a solvent comprised of a hydrocarbon mixture into the vessel, wherein the solvent has a Hansen hydrogen bonding blend parameter of not greater than 0.5,

iii) treating the oil sand with the solvent in the vessel to remove not greater than 80 wt % of the bitumen from the supplied oil sand, wherein at least a portion of the hydrocarbon mixture within the vessel during contacting is in vapor phase, and

iv) removing the solvent-treated oil sand from the vessel;

c) recovering the bitumen product from the bitumen material.

31. The process of claim 30, wherein the solvent-treated oil sand is treated with the aqueous solution at a pH of at least 8.

32. The process of claim 30, wherein the aqueous solution is an aqueous sodium hydroxide solution.

33. The process of claim 30, wherein the asphalt material removed from the solvent-treated oil sand is recovered as a froth comprised of the bitumen material.

34. The process of claim 30, wherein a hydrocarbon diluent is added to the froth prior to recovering the bitumen material.

35. The process of claim 30, wherein the solvent has a Hansen polarity blend parameter of not greater than 1.

36. The process of claim 30, wherein the solvent has a Hansen dispersion blend parameter of less than 16.

37. The process of claim 30, wherein the solvent has a ketone content of less than 10 wt %.

38. The process of claim 30, wherein the solvent has an aromatic content of less than 10 wt %.