Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
HYDROCARBON EXTRACTION OF OIL FROM OIL SAND
FIELD OF THE INVENTION
[0001] Deleted.
[0002] This invention relates to a process for removing oil from oil sand.
In particular, this
invention relates to a process for removing a portion of the bitumen oil from
oil sand using a
hydrocarbon solvent comprised of a mixture of hydrocarbons in which oil that
is removed from the
oil sand is relatively low in metals and asphaltenes content.
BACKGROUND OF THE INVENTION
[0003] Today, most of the heavy hydrocarbon oil produced from Canadian oil
sands (known
as bitumen), in particular, Athabasca oil sands, is obtained via surface
mining followed by extraction
with a water-based system built on a discovery made in the 1920s and known as
the Clark process.
Upon extraction of the bitumen, a frothy water-hydrocarbon mixture must be
separated. Thereafter,
the hydrocarbon product obtained is too viscous to pump and is frequently
diluted with an organic
material to render a bitumen-solvent blend (also known as dilbit or synbit)
pumpable. This bitumen-
solvent is pumped, i.e., pipelined, directly to a facility for upgrading to
the desired product mix, e.g.,
liquid fuel such as jet fuel, diesel and gasoline. The Clark process, despite
many decades of process
improvement work, remains energy intensive and is environmentally detrimental
in that it requires
significant quantities of water that must be cleaned for re-use, and generates
significant bottoms
components that contain high levels of fines (also referred to as tailings or
tailings fluid fines).
[0004] Tailings fluid fines from the water-based Clark extraction of
bitumen from Canadian
oil sands require long-term storage before they can become trafficable and
suitable for reclamation.
The Energy Resources Conservation Board (ERCB) of the Canadian province of
Alberta has noted in
Directive 074 (February, 2009) that "in past applications, mineable oil sands
operators proposed the
conversion of fluid tailings into deposits that would become trafficable and
ready for reclamation.
While operators have applied fluid tailings reduction technologies, they have
not met the targets set
out in their applications; as a
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result, the inventories of fluid tailings that require long-term containment
have grown. With
each successive application and approval, public concerns have grown." In one
region of
interest, in Alberta, Canada, there are already several huge operations using
this technology
wherein the water requirements are supplied by the Athabasca River.
[0005] In spite of the environmental concerns of using the water-based
Clark extraction
process, there is additional consideration of importing into the U.S. greater
quantities of the
bitumen-solvent blend product produced from the process. Currently under
consideration is a
proposed pipeline that would connect oil resources in Alberta, Canada, to
refineries on the
Texas coast. As reported in http://www dapnorg/2011/09/01/140117187/for-
protesters-
keystone-pipeline-is4ine-in-tar- sand, "The 1,700-mile long Keystone XL, as
it's called,
would help our friendly northern neighbor expand development in one of the
largest, but
dirtiest, sources of oil on the planet. It's bound up in hardened formations
called tar sands,
and it's not easy to extract."
[0006] Due to the many environmental concerns in extracting and
transporting bitumen
from oil sands, replacement of the water-based Clark extraction process with
hydrocarbon-
based solvents has been investigated. The attractive nature of using a
hydrocarbon-based
solvent is that little if any water would be needed in such a process.
[0007] U.S. Patent Pub. No. 2009/0294332 discloses, for example, an oil
extraction
process that uses an extraction chamber and a hydrocarbon solvent rather than
water to
extract the oil from oil sand. The solvent is sprayed or otherwise injected
onto the oil-bearing
product, to leach oil out of the solid product resulting in a composition
comprising a mixture
of oil and solvent, which is conveyed to an oil-solvent separation chamber.
[0008] U.S. Patent No. 4,347,118 discloses a solvent extraction process for
tar sands
wherein a low boiling solvent having a normal boiling point of from 200 to 70
C is used to
extract tar sands. The solvent is mixed with tar sands in a dissolution zone,
the
solvent:bitumen weight ratio is maintained from about 0.5:1 to 2:1. This
mixture is passed to
a separation zone in which bitumen and inorganic fines are separated from
extracted sand, the
separation zone containing a classifier and countercurrent extraction column.
The extracted
sand is introduced into a first fluid-bed drying zone fluidized by heated
solvent vapors, so as
to remove unbound solvent from extracted sand while at the same time lowering
the water
content of the sand to less than about 2 wt %. The treated sand is then passed
into a second
fluid-bed drying zone fluidized by a heated inert gas to remove bound solvent.
Recovered
solvent is recycled to the dissolution zone.
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[0009] U.S. Patent Pub. No. 2010/0130386 discloses the use of a solvent for
bitumen
extraction. The solvent includes (a) a polar component, the polar component
being a
compound comprising a non-terminal carbonyl group; and (b) a non-polar
component, the
non-polar component being a substantially aliphatic substantially non-
halogenated alkane.
The solvent has a Hansen hydrogen bonding parameter of 0.3 to 1.7 and/or a
volume ratio of
(a):(b) in the range of 10:90 to 50:50.
[0010] U.S. Patent Pub. No. 2011/0094961 discloses a process for separating
a solute
from a solute-bearing material. The solute can be bitumen and the solute-
bearing material
can be oil sand. A substantial amount of the bitumen can be extracted from the
oil sand by
contacting particles of the oil sand with globules of a hydrocarbon extraction
solvent. The
hydrocarbon extraction solvent is a C1-05 hydrocarbon. The particle size of
the oil sand and
the globule size of the extraction solvent are balanced such that little if
any bitumen or
extraction solvent remains in the oil sand.
[0011] Although hydrocarbon extraction processes provide an advantage in
that water is
not used in the extraction of the oil from the oil sand, thereby reducing a
portion of the
environmental impact, problems in using hydrocarbon-based extractions persist.
For
example, disclosed processes have typically relied on solvents that are
substantially pure
hydrocarbons. Since there is at least some solvent loss during extraction,
additional
quantities of the solvent have to be obtained externally, which substantially
adds to the
overall cost of obtaining the desired crude oil product. In addition,
disclosed processes have
generally been demonstrated to extract all or substantially all of the bitumen
from the oil
sand. This results in a crude oil product that is extremely viscous, high in
undesirable metals
and asphaltenes content and is rather difficult to pipeline and upgrade to
fuel grade products.
Although use of hydrocarbon solvents can recover substantial amounts of the
bitumen, the
resulting crude composition, which also comprises the hydrocarbon solvent, is
substantially
similar to the current dilbit or synbit. Such a product will not necessarily
allay the concerns
of pipelining the product through the proposed Keystone XL.
SUMMARY OF THE INVENTION
[0012] This invention provides a process for producing an oil composition
from oil sand
that requires little to no water to produce the oil composition. The process
is particularly
environmentally attractive in that the ultimate crude oil that is pipelined is
substantially
higher in quality than existing crude oils from oil sand. In addition, the
process does not
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produce substantial quantities of undesirable tailings. Therefore, the
invention provides a
process for producing a higher quality oil composition, with substantially
lower
environmental impact, than has been previously achieved. A further advantage
of the
invention is that the particular solvent that is used to remove or extract the
oil composition
from the oil sand can be easily recovered from the process itself. Thus, no
external solvent
make-up is required.
[0013] According to one aspect of the invention, there is provided a
process for
producing a crude oil composition from oil sand that uses a solvent comprised
of a
hydrocarbon mixture. The solvent is injected into a vessel and the oil sand is
supplied to the
vessel such that the solvent and oil sand contact one another in the vessel,
i.e., contact zone of
the vessel. The process is carried out such that not greater than 80 wt % of
the bitumen is
removed from the supplied oil sand, with the removal being controlled by the
Hansen
solubility blend parameters of the solvent and the vapor or supercritical
condition of the
solvent in the contact zone. The extracted oil and at least a portion of the
solvent are
removed from the vessel for further processing as may be desired.
[0014] The solvent can have a Hansen dispersion blend parameter of not
greater than 16
and/or a Hansen polarity blend parameter of not greater than 2.5, preferably
not greater than
2. Especially desired solvents that comprise blends of hydrocarbons would have
a Hansen
dispersion blend parameter of not greater than 16 and a Hansen polarity blend
parameter of
not greater than 2.5, preferably not greater than 2. In addition, solvents
further including a
Hansen hydrogen bonding blend parameter of not greater than 2 are particularly
preferred.
[0015] The contacting of the oil sand and the solvent in the vessel can be
at a temperature
of at least 35 C. Correspondingly, the contacting of the oil sand and the
solvent in the vessel
can be at a pressure of not greater than 50 psig (345 kPa-g).
[0016] The solvent can also be defined according to boiling point in which
the solvent
has an ASTM D86 10% distillation point of at least 30 C and an ASTM D86 90%
distillation
point of not greater than 160 C. Alternatively, the solvent can have an ASTM
D86 10%
distillation point within the range of from 30 C to 70 C and an ASTM D86 90%
distillation
point within the range of from 80 C to 160 C. The solvent can also have a
difference of at
least 30 C between its ASTM D86 90% distillation point and its ASTM D86 10%
distillation
point.
[0017] The solvent can further have an aromatic content of not greater than
15 wt %.
Additionally, the solvent can have a ketone content of not greater than 20 wt
%. It is desired
that the solvent be comprised of not greater than 20 wt % non-hydrocarbon
compounds.
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[0018] 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 at least 0.01:1,
preferably not greater than 4:1.
[0019] A fraction of the crude oil composition is separated and recycled to
the vessel as
make-up solvent.
DETAILED DESCRIPTION OF THE INVENTION
I. INTRODUCTION
[0020] This invention provides a process for producing a crude oil
composition from oil
sand using a solvent comprised of a hydrocarbon mixture oil sand. The oil
sand, which
contains bitumen, is supplied to an appropriate extraction vessel, with the
solvent being
injected into the vessel. In the vessel, i.e., contact zone of the vessel, the
oil sand is contacted
with the solvent to produce a crude oil composition. The crude oil composition
is comprised
of an extracted portion of the bitumen and at least a portion of the solvent.
The extracted
portion of the bitumen is less than the complete quantity of bitumen on the
oil sand. The
advantage in extracting only a portion of the bitumen is that a relatively
high quality crude oil
can be obtained that has fewer undesirable components. Significant quantities
of these
undesirable components, such as metals and asphaltenes, can remain with the
unextracted
bitumen component.
[0021] The solvent type and the manner by which the extraction process is
carried out has
substantial impact on the quality of the extracted oil component. The solvent
is designed so
that it has the desired Hansen solubility parameters that enable the partial
extraction of the
desired oil composition. The solvent is further designed so that it can be
comprised of
multiple hydrocarbons having the appropriate boiling point ranges that enable
the solvent to
be easily recovered and recycle, without the need to externally provide for
solvent make-up.
The ultimate crude product that can be recovered is a high quality crude
having low metals
and asphaltenes. This high quality product can be relatively easily pipelined
and/or upgraded
to liquid fuels compared to typical crude products. Since the process does not
require the use
of water, the process does not produce substantial quantities of undesirable
tailings, and the
environmental impact of the oil recovery is substantially reduced.
OIL SAND
[0022] Oil 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
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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. Oil sand can be relatively soft and free
flowing, or it can
be very hard or rock-like, while the bitumen content may vary over a wide
range.
[0023] One example of an oil sand from which an oil composition, including
bitumen,
can be extracted 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.
[0024] Another example of oil sand from which an oil composition, including
bitumen,
can be extracted 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.
[0025] The process of this invention includes a step of supplying a feed
stream of oil sand
to a contact zone, with the oil sand being comprised of at least 2 wt % of a
total oil
composition, based on total weight of the supplied oil sand. Preferably, the
oil sand feed is
comprised of at least 4 wt % of a total oil composition, more preferably at
least 6 wt % of a
total oil composition, still more preferably at least 8 wt % of a total oil
composition, based on
total weight of the oil sand feed.
[0026] The total oil or bitumen content of the solute-bearing material is
preferably
measured 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
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separated and weight percent of water and solute can be determined according
to the standard
method.
[0027] 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 the oil sand can freely flow through the contact zone
or such that
extraction of the oil component in the contact zone is not 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.
[0028] 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. However, the process of this invention is also particularly suited to
treatment of oil
sand that is of relatively small diameter. The separated solid material can
also be referred to
as fine tailings. Fine tailings can be effectively separated from the product.
These fine
tailings will also be of low environmental impact, since they can be separated
in a relatively
dry state and deposited as a substantially non-hazardous solid waste material.
111. SOLVENT CHARACTERISTICS
[0029] The solvent used according to this invention is comprised of a
hydrocarbon
mixture. 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.
[0030] 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.
[0031] At least a majority, i.e., at least 20 wt %. of the solvent in the
vessel that serves as
a contact zone for the solvent and oil sand is in a vapor or supercritical
state. Alternatively, at
7
at least 40 wt %, or at least 60 wt %, or at least 80 wt % of the solvent in
the contact zone is in a
vapor or supercritical state.
[0032] The hydrocarbon of the solvent can be comprised of a mix of
hydrocarbon
compounds. The hydrocarbon compounds can range from 1 to 30 carbon atoms. In
an alternative
embodiment, the hydrocarbon of the solvent is comprised of a mixture of
hydrocarbon compounds
having from 1 to 20, alternatively from 1 to 15, 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. Examples of halogen-
substituted paraffins include, but are not limited to chlorine and fluorine
substituted paraffins, such as
C1-C6 chlorine or fluorine substituted or C1-C3 chlorine or fluorine
substituted paraffins.
[0033] 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 asphaltenes content of the
extracted oil
compositions. Asphaltenes content can be determined according to ASTM D6560 -
00(2005)
Standard Test Method for Determination of Asphaltenes (Heptane Insolubles) in
Crude Petroleum
and Petroleum Products. In general, the lower the amount of asphaltenes in the
crude oil composition
that is produced in the extraction process, the higher the quality of ultimate
crude oil composition
that is pipelined and/or upgraded to fuel products.
[0034] Particularly effective hydrocarbons for use as the solvent
according to 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. Examples of the Hansen solubility parameters are
shown in Tables 1-
12.
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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
Napthalene 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
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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
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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 i sobutyl 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
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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 is obutyrate 15.1 2.9 5.9
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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 di amine 16.6 8.8 17.0
Pyridine 19.0 8.8 5.9
Morpholine 18.8 4.9 9.2
Analine 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
Dimethylsulphoxide 18.4 16.4 10.2
Ethanethiol 15.8 6.6 7.2
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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-Butan ol 16.0 5.7 15.8
2-Butanol 15.8 5.7 14.5
Is obutanol 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
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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
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[0035] 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:
[0036] Dblend = EVi Di,
[0037] Pblend = EVi
[0038] Hblend = EVi Hi,
[0039] 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.
[0040] 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.
[0041] In order to produce a high quality crude oil composition, the
solvent is selected to
limit the amount of asphaltenes that are extracted from the oil sand. 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.
[0042] The Hansen dispersion blend parameter of the solvent is desirably
less than 18. In
general, lower dispersion blend parameters are particularly desirable. As an
example, the
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solvent is comprised of a hydrocarbon mixture, with the solvent having a
Hansen dispersion
blend parameter of not greater than 16, alternatively not greater than 15, or
greater than 14.
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 14 to 16
or from 13 to
15.
[0043] The Hansen polarity blend parameter of the solvent is desirably less
than 4. 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 2, alternatively not
greater than 1, or not
greater than 0.5. 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.
[0044] The Hansen hydrogen bonding blend parameter of the solvent is
desirably less
than 3. 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 2, alternatively not greater than
1, or not greater
than 0.5. Additional examples include solvents comprised of a hydrocarbon
mixture, with the
solvent having a Hansen hydrogen bonding blend parameter of from 0 to 2 or
from 0 to 1.5 or
from 0 to 1.
[0045] 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.
[0046] In one embodiment, the solvent has an ASTM D86 10% distillation
point of at
least 30 C. Alternatively, the solvent has an ASTM D86 10% distillation point
of at least
40 C, or at least 50 C. The solvent can have an ASTM D86 10% distillation
point within the
range of from 30 C to 70 C, alternatively within the range of from 30 C to 60
C, or from
30 C to 50 C.
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[0047] The solvent can have an ASTM D86 90% distillation point of not
greater than
160 C. Alternatively, the solvent has an ASTM D86 90% distillation point of
alternatively
not greater than 120 C, or not greater than 80 C. The solvent can have an ASTM
D86 90%
distillation point within the range of from 80 C to 160 C, alternatively
within the range of
from 80 C to 140 C, or from 80 C to 120 C. Alternatively, the solvent can have
an ASTM
D86 90% distillation point within the range of from 90 C to 160 C,
alternatively within the
range of from 100 C to 160 C, or from 110 C to 160 C.
[0048] 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 30 C between its ASTM D86 90% distillation point
and its
ASTM D86 10% distillation point, alternatively a difference of at least 40 C,
or at least 50 C.
Alternatively, the solvent can have a difference of at least 40 C between its
ASTM D86 90%
distillation point and its ASTM D86 10% distillation point, alternatively a
difference of at
least 50 C, or at least 60 C.
[0049] Solvents high in aromatic content are not particularly desirable.
For example, the
solvent can have an aromatic content of not greater than 15 wt %,
alternatively not greater
than 12 wt %, or not greater than 10 wt %. 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.
[0050] Solvents high in ketone content are also not particularly desirable.
For example,
the solvent can have a ketone content of not greater than 20 wt %,
alternatively not greater
than 15 wt %, or not greater than 10 wt %. The ketone content can be
determined according
to test method ASTM D4423 - 10 Standard Test Method for Determination of
Carbonyls In
C4 Hydrocarbons.
[0051] 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.
[0052] 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
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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.
[0053] The hydrocarbon to oil sand feed ratio can vary according to a
variety of
variables. Such variables include, but are not limited to, solubility of the
hydrocarbon in the
oil composition, temperature and pressure of the contact zone, and contact
time of
hydrocarbon and oil sand in the contact zone.
IV. VESSEL AND PROCESS CONDITIONS
[0054] Extraction of oil compounds from the oil sand 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. Patent No.
7,384,557.
[0055] 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.
[0056] 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 20 wt % of the hydrocarbon
mixture within
the contacting zone of the vessel is in vapor or supercritical phase during
contacting.
Preferably, 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 vapor or supercritical
phase.
[0057] 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 greater than 70 wt %, or
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
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can remove or extract not greater than 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 or further upgraded to make fuel
products. The
separated solvent can then be recycled. Since the extraction process
incorporates a relatively
light solvent blend, the solvent portion can be easily recovered, with little
if any external
make-up being required.
[0058] 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 vvppm, 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 of not greater than 15 wt %,
alternatively not greater
than 12 wt %, or not greater than 10 wt %, or not greater than 5 wt %.
[0059] Since the solvent is a relatively low boiling composition, the
process can be
carried out at temperatures and pressures that are not exceedingly high, as
long as the desired
amount of hydrocarbon in the solvent remains in the vapor or supercritical
phase in the
contact zone. For example, at lower pressures, e.g., not greater than 50 psig
(345 kPa-g),
alternatively not greater than 30 psig (207 kPa-2), or greater than 20 psig
(138 kPa-g), 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
100 C, or at least
150 C, or at least 200 C.
[0060] Pressure in the contact zone can vary as long as the desired amount
of
hydrocarbon in the solvent remains in the vapor or supercritical phase in the
contact zone.
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 50 psig
(345 kPa-g),
alternatively not greater than 30 psig (207 kPa-g), or greater than 20 psig
(138 kPa-g).
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V. SEPARATION AND RECYCLE OF SOLVENT
[0061] The crude oil composition that is removed from the contact zone of
the extraction
vessel comprises the 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. This separated solvent is separated so as to match or
correspond to the
Hansen solubility characteristics, overall generic chemical components and
boiling points as
described above for the solvent composition. 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.
[0062] Following removal of the crude oil composition from the extraction
vessel, the
crude oil composition is separated into fractions comprised of recycle solvent
and crude oil
product. The 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.
[0063] The crude oil product can also have a relatively high API gravity
compared to
bitumen oils extracted according to typical processes. 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,
depending on the
exact solvent composition and process conditions. This relatively high API
gravity enables
the crude product to be relatively easily pipelined.
VI. EXAMPLES
[0064] Table 13 shows the results of performed experiments and obtained
data. For
experiments 2125 and 2127, the following procedure was carried out: 200 grams
of an
Athabasca tar sands ore sized between 12 and 16 mesh was stirred with 100
grams of solvent
for two minutes at 69-70F. The mixture was filtered and the solids treated
with a second
amount of 100 grams of solvent. The mixture was again filtered and the liquids
from the two
steps were combined. The solvent was allowed to weather off. Samples were sent
for
analysis (Intertek, New Orleans). API gravity measured by ASTM D-5002. % MCRT
measured by ASTM D-4530. Ni and V in ppm by ASTM D-5708_MOD. Wt. % Sulfur by
ASTM D4294.
[0065] Sample 2043 was obtained as the liquid product from a propane
extraction of the
same Athabasca ore as for 2125 and 2127. Experiment 2043 was run in a
continuous manner
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using an auger system to provide constant agitation of solid particles.
Temperature within the
auger was about 80-90F and the total pressure in the system was approximately
150 psi. The
liquid product was collected and propane was weathered off prior to analysis.
[0066] The comparative example of the water solvent (Clark process) was
taken from the
literature. (www,etde.org/etdewebiserviets/pur1/21239492-3CCEvD/). The
asphaltene
analysis is believed to be a measurement of pentane insolubles by ASTM D-664.
Table 13
Solvent Type API'
Gravity % MCRT wppm Ni + V Wt. % Sulfur
Pentane (2125) 12.9 6.2 92 2.9
30/70 Acetone/Pentane (2127) 11.6 8.6 167 3.0
Propane (2043) 17.0 2.4 8.3 3.2
Water (Clark Process) ¨8 14.1% 431 5.7
(Asphaltenes)
[0067] Table 14 shows the Hansen shows the Hansen solubility blend
parameters of the
solvents of Table 13.
Table 14
Hansen Parameter
Solvent
Propane 13.1 0.0 0.0
Pentane 14.5 0.0 0.0
30 Acetone/70 Pentane 14.8 3.1 2.1
Water 15.5 16 42.3
[0068] Solvents that are comprised of blends of hydrocarbons would be
particularly
advantageous in that such solvents can be more readily obtained. Blends that
can produce
higher quality crude oils are preferred, e.g., blends that produce crude oils
having low metals
and asphaltenes contents. Thus, particularly desired solvents that comprise
blends of
hydrocarbons would have a Hansen dispersion blend parameter of not greater
than 16 and/or
a Hansen polarity blend parameter of not greater than 2.5, preferably not
greater than 2.
Especially desired solvents that comprise blends of hydrocarbons would have a
Hansen
dispersion blend parameter of not greater than 16 and a Hansen polarity blend
parameter of
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not greater than 2.5, preferably not greater than 2. In addition, solvents
further including a
Hansen hydrogen bonding blend parameter of not greater than 2 are particularly
preferred.
[0069] The principles and modes of operation of this present techniques
have been
described above with reference to various exemplary and preferred embodiments.
As
understood by those of skill in the art, the overall present techniques , as
defined by the
claims, encompasses other preferred embodiments not specifically enumerated
herein.
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