Note: Descriptions are shown in the official language in which they were submitted.
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METHOD TO EXTRACT BITUMEN FROM OIL SANDS USING AROMATIC
AMINES
FIELD OF THE INVENTION
The present invention relates to the recovery of bitumen from oil sands. More
particularly, the present invention is an improved method for bitumen recovery
from oil
sands through either surface mining or in situ recovery. The improvement is
the use of an
aromatic amine as an extraction aid in the water and/or steam used in the
bitumen recovery
process.
BACKGROUND OF THE INVENTION
Deposits of oil sands are found around the world, but most prominently in
Canada,
Venezuela, and the United States. These oil sands contain significant deposits
of heavy oil,
typically referred to as bitumen. The bitumen from these oil sands may be
extracted and
refined into synthetic oil or directly into petroleum products. The difficulty
with bitumen
lies in that it typically is very viscous, sometimes to the point of being
more solid than
liquid. Thus, bitumen typically does not flow as less viscous, or lighter,
crude oils do.
Because of the viscous nature of bitumen, it cannot be produced from a well
drilled
into the oil sands as is the case with lighter crude oil. This is so because
the bitumen simply
does not flow without being first heated, diluted, and/or upgraded. Since
normal oil drilling
practices are inadequate to produce bitumen, several methods have been
developed over
several decades to extract and process oil sands to remove the bitumen. For
shallow
deposits of oil sands, a typical method includes surface extraction, or
mining, followed by
subsequent treatment of the oil sands to remove the bitumen.
The development of surface extraction processes has occurred most extensively
in
the Athabasca field of Canada. In these processes, the oil sands are mined,
typically
through strip or open pit mining with draglines, bucket-wheel excavators, and,
more
recently, shovel and truck operations. The oil sands are then transported to a
facility to
process and remove the bitumen from the sands. These processes typically
involve a
solvent of some type, most often water or steam, although other solvents, such
as
hydrocarbon solvents, have been used.
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After excavation, a hot water extraction process is typically used in the
Athabasca
field in which the oil sands are mixed with water at temperatures ranging from
approximately 35 C to 75 C, with recent improvements lowering the temperature
necessary
to the lower portion of the range. An extraction agent, such as sodium
hydroxide (NaOH),
surfactants, and/or air may be mixed with the oil sands.
Water is added to the oil sands to create an oil sands slurry, to which
additives such
as NaOH may be added, which is then transported to an extraction plant,
typically via a
pipeline. Inside a separation vessel, the slurry is agitated and the water and
NaOH releases
the bitumen from the oil sands. Air bubbles entrained with the water and NaOH
attaches to
the bitumen, allowing it to float to the top of the slurry mixture and create
a froth. The
bitumen froth is further treated to remove residual water and fines, which are
typically small
sand and clay particles. The bitumen is then either stored for further
treatment or
immediately treated, either chemically or mixed with lighter petroleum
products, and
transported by pipeline for upgrading into synthetic crude oil. Unfortunately,
this method
cannot be used for deeper tar sand layers. In situ techniques are necessary to
recover deeper
oil in well production. It is estimated that around 80 percent of the Alberta
tar sands and
almost all of the Venezuelan tar sands are too far below the surface to use
open pit mining.
In well production, referred to as in situ recovery, Cyclic Steam Stimulation
(CSS)
is the conventional "huff and puff in situ method whereby steam is injected
into the well at
a temperature of 250 C to 400 C. The steam rises and heats the bitumen,
decreasing its
viscosity. The well is allowed to sit for days or weeks, and then hot oil
mixed with
condensed steam is pumped out for a period of weeks or months. The process is
then
repeated. Unfortunately, the "huff and puff method requires the site to be
shut down for
weeks to allow pumpable oil to accumulate. In addition to the high cost to
inject steam, the
CSS method typically results in 20 to 25percent recovery of the available oil.
Steam Assisted Gravity Drainage (SAGD) is another in situ method where two
horizontal wells are drilled in the tar sands, one at the bottom of the
formation and another
five meters above it. The wells are drilled in groups off of central pads.
These wells may
extend for miles in all directions. Steam is injected into the upper well,
thereby melting the
bitumen which then flows into the lower well. The resulting liquid oil mixed
with
condensed steam is subsequently pumped to the surface. Typical recovery of the
available
oil is 40 to 60 percent.
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Challenges of in situ methods include low recovery rate and high energy and
water
requirement. In addition, steam-based methods are not energy-efficient for
shallow
reservoirs with low maximum operating pressure or reservoirs with thin pay
zones.
USP 5264118 describes a pipeline conditioning process for mined oil sands. The
invention related to transport of oil sand with hot water and sodium hydroxide
in pipelines
of sufficient length. During transportation, bitumen is released from surfaces
of oil sand
grains and the entrained air helps aeration of liberated bitumen. Caustic is
an effective
extraction aid but is difficult to control and easy to overdose, which would
create stable
emulsions that are difficult to separate. High pH due to caustic can result in
generating
excessive naturally-occurring surfactants from the bitumen surface and
possible bitumen
emulsification. Moreover, the generated surfactants can absorb at the
bitumen/water
interface and prevent effective coalescence between bitumen droplets and
making it difficult
to separate from water. Additionally, the use of a large quantity of caustic
not only presents
process safety hazards but also contributes to stability of fine clay
particles in tailings, the
disposal of which is a major environmental problem. The above discussed
problems related
to the use of caustic can severely compromise the efficiency and quality of
bitumen
recovery.
Canadian Patent 2004352 discloses use of kerosene and methyl-isobutyl carbinol
to
address the above mentioned problems related to use of caustic in extracting
bitumen,
However, the need for large amounts of chemicals increases the operating cost
tremendously and makes use of kerosene and methyl-isobutyl carbinol
prohibitive.
Canadian Patent 1022098 discloses a method of breaking bitumen-water emulsion
created during caustic extraction by adjusting the pH to emulsion to around
7.0 using
inorganic salt and carbon dioxide. However, carbon dioxide is not a strong
acid and hence
not an effective pH reducer. Use of inorganic acids, on the other hand,
generates unwanted
salt in the process water and can severely limit reuse of the process water.
USP 4,357,230 discloses using an amide to extract bituminous materials from
shale
or sand at a preferred minimum ratio of 1:2 and can be carried out at ambient
temperature
and pressure. Preferred amide includes di-substituted acid amides with
straight or branched
chain aliphatic groups attached.
USP 5,169,518 discloses ex-situ recovery of bitumen from tar sands where in
floatation is improved by the use of alkanolamines. Specific examples of
useful
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alkanolamines include mono-, di-, and tri-ethanolamine, isopropanolamines,
butanolamine,
and hexanolamines and mixtures thereof.
Canadian Patent Application 2,640,448 discloses enhancements in bitumen
recovery
from oil sands by adding lipids to the ore-water slurry.
USP 7,938,183 discloses the use of ammonia and aliphatic amines as low dose
(1%
or less) for enhancing bitumen recovery in in situ production methods.
USP 8,272,442 discloses various classes of additives in combination with the
turpentine solvent. These classes include lower aliphatic alcohols, lower
alkanes, lower
aromatics, aliphatic amines, aromatic amines, carbon bisulfide, vegetable oil
and mixtures
thereof.
There remains a need for efficient, safe and cost-effective methods to improve
the
recovery of bitumen from oil sands from surface mining operations and to
improve
efficiency and productivity of bitumen from in situ production via hot water
or steam
flooding.
SUMMARY OF THE INVENTION
The present invention is an improved bitumen recovery process comprising the
step of treating oil sands with an aromatic amine wherein the treatment is to
oil sands
recovered by surface mining or in situ production of oil sands in a
subterranean reservoir.
In one embodiment of the bitumen recovery process described herein above,
aromatic amine is described by the structure:
R1R2R3N
wherein Rl and R2 are independently -H, -AL where -AL is an unsubstituted Ci
to
C20, preferably Ci to C6 alkyl group, a C6 to C12 aromatically substituted Ci
to C20,
preferably Ci to C6 alkyl group, or combination thereof, wherein -AL may
contain
one or more of a -COOR4 where R4 is -H, alkyl, aryl or alkylaryl, CN, -CHO,
-NR5R6 group where R5 and R6 are independently -H, alkyl or aryl, -OH group, -
0-
group, -S- group, -N- group, -Cl, -Br, -F, or R1 and R2 may form an
unsubstituted or
substituted imine, or R1 and R2 may form a 5 to 7 atom saturated or
unsaturated
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cyclic moiety wherein there may be one or more carbon atom, oxygen atom,
nitrogen atom, or sulfur atom
and
R3 is -H or -AR where -AR is an unsubstituted Ci to C20, preferably Ci to C6
alkyl
group, an unsubstituted C6 to C14 aromatic group, or a Ci to C20, preferably
Ci to C6
alkyl group substituted with one or more C6 to C14 aromatic group, or a C6 to
C14
aromatic group substituted with one or more Ci to C20, preferably Ci to C6
alkyl
group, or a C6 to C14 aromatic group substituted with one or more Ci to C20,
preferably Ci to C6 alkyl group and/or one or more C6 to C14 aromatic group,
wherein -AR may contain one or more of a -COOR4 where R4 is -H, alkyl, aryl or
alkylaryl, CN, -CHO, -NR5R6 group where R5 and R6 are independently -H, alkyl
or
aryl, -OH group, -0- group, -S- group, -N- group, -Cl, -Br, -F, or R1, R2 and
R3 may
form a 5 to 7 atom saturated or unsaturated cyclic moiety wherein there may be
one
or more carbon atom, oxygen atom, nitrogen atom, or sulfur atom.
Preferably the aromatic amine is 2,4,6-trimethylaniline, N-benzy1-2-
phenethylamine,
N-butylbenzylamine, dibenzylamine, 2-aminobiphenyl, aminodiphenylmethane,
aniline, 2-
phenoxyaniline, 9,10-diaminophenanthrene, 1-amino-2-methylnaphthalene, N,N-
bis(salicylidene)ethylenediamine, N-phenyl-o-phenylenediamine, 2,4,6-tri-tert-
butylaniline,
N-phenylglycine, 3,5-di-tert-butylaniline, -1,11-binaphthy1-2,2'-diamine, 4'-
aminobenzo-15-
crown 5-ether, a-methylbenzylamine, 4-(dimethylamino)phenylacetic acid, N-
benzyl-
ethylenediamine, N-methylphenethylamine, 1,2-diphenylethylenediamine,
tritylamine, N-
phenylethylenediamine, pyridine, toluidine, anisidine, methylaniline,
diphenylamine,
halogen substitution of aromatic amines, indole, indoline, quinoline, 1-amino-
4-
alkylaminobenzene, 1,4-diaminobenzene, imidazole, benzimidazole,
benzotriazole, pyrrole,
4-dimethylaminopyridine, or mixtures thereof.
In another embodiment of the present invention, the bitumen recovery process
by
surface mining described herein above comprises the steps of: i) surface
mining oil sands,
ii) preparing an aqueous slurry of the oil sands, iii) treating the aqueous
slurry with the
aromatic amine, iv) agitating the treated aqueous slurry, v) transferring the
agitated treated
aqueous slurry to a separation tank, and vi) separating the bitumen from the
aqueous
portion, preferably the aromatic amine is present in the aqueous slurry in an
amount of from
0.01 to 10 weight percent based on the weight of the oil sands.
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In another embodiment of the present invention, the bitumen recovery process
by in
situ production described herein above comprises the steps of: i) treating a
subterranean
reservoir of oil sands by injecting hot water and/or steam containing the
aromatic amine into
a well, and ii) recovering the bitumen from the well, preferably the
concentration of the
aromatic amine in the steam is in an amount of from 100 ppm to 10 weight
percent.
DETAILED DESCRIPTION OF THE EMBODIMENTS
The separation of bitumen and/or heavy oil from oil sands is accomplished by,
but
not limited to, two methods; surface mining or in situ recovery sometimes
referred to as
well production. The oil sands may be recovered by surface or strip mining and
transported
to a treatment area. A good summary can be found in the article "Understanding
Water-
Based Bitumen Extraction from Athabasca Oil Sands", J. Masliyah, et al.,
Canadian
Journal of Chemical Engineering, Volume 82, August 2004. The basic steps in
bitumen
recovery via surface mining include: extraction, froth treatment, tailings
treatment, and
upgrading. The steps are interrelated; the mining operation affects the
extraction and in turn
the extraction affects the upgrading operation.
Typically, in commercial bitumen recovery operations, the oil sand is mined in
an
open-pit mine using trucks and shovels. The mined oil sands are transported to
a treatment
area. The extraction step includes crushing the oil sand lumps and mixing them
with
(recycle process) water in mixing boxes, stirred tanks, cyclo-feeders or
rotary breakers to
form a conditioned oil sands slurry. The conditioned oil sands slurry is
introduced to
hydrotransport pipelines or to tumblers, where the oil sand lumps are sheared
and size
reduction takes place. Within the tumblers and/or the hydrotransport
pipelines, bitumen is
recovered or "released', or "liberated", from the sand grains. Chemical
additives can be
added during the slurry preparation stage; for examples of chemicals known in
the art see
US2008/0139418, incorporated by reference herein in its entirety. In typical
operations, the
operating slurry temperature ranges from 35 C to 75 C, preferably 40 C to 55
C.
Entrained or introduced air bubbles attaches to bitumen in the tumblers and
hydrotransport pipelines creating froth. In the froth treatment step, the
aerated bitumen
floats and is subsequently skimmed off from the slurry. This is accomplished
in large
gravity separation vessels, normally referred to as primary separation vessels
(PSV),
separation cells (Sep Cell) or primary separation cells (PSC). Small amounts
of bitumen
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droplets (usually un-aerated bitumen) remaining in the slurry are further
recovered using
either induced air flotation in mechanical flotation cells and tailings oil
recovery vessels, or
cyclo-separators and hydrocyclones. Generally, overall bitumen recovery in
commercial
operations is about 88 to 95 percent of the original oil in place. The
recovered bitumen in
the form of froth normally contains 60 percent bitumen, 30 percent water and
10 percent
solids.
The bitumen froth recovered as such is then de-aerated, and diluted (mixed)
with
solvents to provide sufficient density difference between water and bitumen
and to reduce
the bitumen viscosity. The dilution by a solvent (e.g., naphtha or hexane)
facilitates the
removal of the solids and water from the bitumen froth using inclined plate
settlers,
cyclones and/or centrifuges. When a paraffinic diluent (solvent) is used at a
sufficiently
high diluent to bitumen ratio, partial precipitation of asphaltenes occurs.
This leads to the
formation of composite aggregates that trap the water and solids in the
diluted bitumen
froth. In this way gravity separation is greatly enhanced, potentially
eliminating the need
for cyclones or centrifuges.
In the tailings treatment step, the tailings stream from the extraction plant
goes to the
tailings pond for solid-liquid separation. The clarified water is recycled
from the pond back
to the extraction plant. To accelerate tailings handling, gypsum may be added
to mature
fine tailings to consolidate the fines together with the coarse sand into a
non-segregating
mixture. This method is referred to as the consolidated (composite) tailing
(CT) process.
CT is disposed of in a geotechnical manner that enhances its further
dewatering and
eventual reclamation. Optionally, tailings from the extraction plant are
cycloned, with the
overflow (fine tailings) being pumped to thickeners and the cyclone underflow
(coarse
tailings) to the tailings pond. Fine tailings are treated with flocculants,
then thickened and
pumped to a tailings pond. Further, the use of paste technology (addition of
flocculants/polyelectrolytes) or a combination of CT and paste technology may
be used for
fast water release and recycle of the water in CT to the extraction plant for
bitumen
recovery from oil sands.
In the final step, the recovered bitumen is upgraded. Upgrading either adds
hydrogen or removes carbon in order to achieve a balanced, lighter hydrocarbon
that is
more valuable and easier to refine. The upgrading process also removes
contaminants such
as heavy metals, salts, oxygen, nitrogen and sulfur. The upgrading process
includes one or
more steps such as: distillation wherein various compounds are separated by
physical
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properties, coking, hydro-conversion, solvent deasphalting to improve the
hydrogen to
carbon ratio, and hydrotreating which removes contaminants such as sulfur.
In one embodiment of the present invention, the improvement to the process of
recovering bitumen from oil sands is the addition of an aromatic amine during
the slurry
preparation stage. The sized material is added to a slurry tank with agitation
and combined
with an aromatic amine. The aromatic amine may be added to the oil sands
slurry neat or as
an aqueous solution having a concentration of from 100 ppm to 10 weight
percent aromatic
amine based on the total weight of the aromatic amine solution. Preferably,
the aromatic
amine is present in the aqueous oil sands slurry in an amount of from 0.01 to
10 weight
percent based on the weight of the oil sands.
In one embodiment of the process of the present invention, the aromatic amine
is not
added with an organic solvent, for example aromatic organic solvent such as
toluene,
xylene, benzene, and the like or non-aromatic organic solvent such as alkane
hydrocarbons
such as Ci to C12 alkane hydrocarbon, and alkene hydrocarbons such as Ci to
C12 alkylene
hydrocarbon. Suitable organic solvents include, but are not limited to,
ethanol, propanol,
isopropanol, butanol, pentane, heptane, hexane, benzene, xylene, tetraline,
carbon bisulfide,
soybean oil, palm oil, rapeseed oil, corn oil, sunflower oil, canola oil, and
mixtures thereof.
Preferred aromatic amines of the present invention are represented by the
following
formula:
R1R2R3N
wherein R1 and R2 are independently -H, -AL where -AL is an unsubstituted Ci
to
C20, preferably Ci to C6 alkyl group, a C6 to C12 aromatically substituted Ci
to C20,
preferably Ci to C6 alkyl group, or combination thereof, wherein -AL may
contain
one or more of a -COOR4 where R4 is -H, alkyl, aryl or alkylaryl, CN, -CHO,
-NR5R6 group where R5 and R6 are independently -H, alkyl or aryl, -OH group, -
0-
group,
-S- group, -N- group, -Cl, -Br, -F, or R1 and R2 may form an unsubstituted or
substituted imine, or R1 and R2 may form a 5 to 7 atom saturated or
unsaturated
cyclic moiety wherein there may be one or more carbon atom, oxygen atom,
nitrogen atom, or sulfur atom
and
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R3 is -H or -AR where -AR is an unsubstituted Ci to C20, preferably Ci to C6
alkyl
group, an unsubstituted C6 to C14 aromatic group, or a Ci to C20, preferably
Ci to C6
alkyl group substituted with one or more C6 to C14 aromatic group, or a C6 to
C14
aromatic group substituted with one or more Ci to C20, preferably Ci to C6
alkyl
group, or a C6 to C14 aromatic group substituted with one or more Ci to C20,
preferably Ci to C6 alkyl group and/or one or more C6 to C14 aromatic group,
wherein -AR may contain one or more of a -COOR4 where R4 is -H, alkyl, aryl or
alkylaryl, CN, -CHO, -NR5R6 group where R5 and R6 are independently -H, alkyl
or
aryl, -OH group, -0- group, -S- group, -N- group, -Cl, -Br, -F, or Ri, R2 and
R3 may
form a 5 to 7 atom saturated or unsaturated cyclic moiety wherein there may be
one
or more carbon atom, oxygen atom, nitrogen atom, or sulfur atom.
Preferred aromatic amines are 2,4,6-trimethylaniline, N-benzy1-2-
phenethylamine,
N-butylbenzylamine, dibenzylamine, 2-aminobiphenyl, aminodiphenylmethane,
aniline, 2-
phenoxyaniline, 9,10-diaminophenanthrene, 1-amino-2-methylnaphthalene, N,N-
bis(salicylidene)ethylenediamine, N-phenyl-o-phenylenediamine, 2,4,6-tri-tert-
butylaniline,
N-phenylglycine, 3,5-di-tert-butylaniline, -1,11-binaphthy1-2,2'-diamine, 4'-
aminobenzo-15-
crown 5-ether, a-methylbenzylamine, 4-(dimethylamino)phenylacetic acid, N-
benzyl-
ethylenediamine, N-methylphenethylamine, 1,2-diphenylethylenediamine,
tritylamine, N-
phenylethylenediamine, pyridine, toluidine, anisidine, methylaniline,
diphenylamine,
halogen substitution of aromatic amines, indole, indoline, quinoline, 1-amino-
4-
alkylaminobenzene, 1,4-diaminobenzene, imidazole, benzimidazole,
benzotriazole, pyrrole,
4-dimethylaminopyridine, or mixtures thereof.
The aromatic amine solution/oil sand slurry is typically agitated from 5
minutes to 4
hours, preferably for an hour or less. Preferably, the aromatic amine solution
oil sands
slurry is heated to equal to or greater than 35 C, more preferably equal to or
greater than
40 C, more preferably equal to or greater than 55 C, more preferably equal to
or greater
than 60 C. Preferably, the aromatic amine solution oil sands slurry is heated
to equal to or
less than 100 C, more preferably equal to or less than 80 C, and more
preferably equal to or
less than 75 C.
As outlined herein above, the aromatic amine treated slurry may be transferred
to a
separation tank, typically comprising a diluted detergent solution, wherein
the bitumen and
heavy oils are separated from the aqueous portion. The solids and the aqueous
portion may
be further treated to remove any additional free organic matter.
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In another embodiment of the present invention, bitumen is recovered from oil
sands
through well production wherein the aromatic amine as described herein above
can be
added to oil sands by means of in situ treatment of the oil sand deposits that
are located too
deep for strip mining. The most common methods of in situ production recovery
are hot
water flood, cyclic steam stimulation (CSS), and steam-assisted gravity
drainage (SAGD).
CSS can utilize both vertical and horizontal wells that alternately inject
steam and pump
heated bitumen to the surface, forming a cycle of injection, heating, flow and
extraction.
SAGD utilizes pairs of horizontal wells placed one over the other within the
bitumen pay
zone. The upper well is used to inject steam, creating a permanent heated
chamber within
which the heated bitumen flows by gravity to the lower well, which extracts
the bitumen.
However, new technologies, such as vapor recovery extraction (VAPEX) and cold
heavy oil
production with sand (CHOPS) are being developed.
The basic steps in the in situ treatment to recover bitumen from oil sands
includes:
hot water and/or steam injection into a well, recovery of bitumen from the
well, and dilution
of the recovered bitumen, for example with condensate, for shipping by
pipelines.
In accordance with this method, the aromatic amine is used as a hot water
and/or
steam additive in a bitumen recovery process from a subterranean oil sand
reservoir. The
mode of hot water and/or steam injection may include one or more of steam
drive, steam
soak, or cyclic steam injection in a single or multi-well program. Water
flooding may be
used in addition to one or more of the steam injection methods listed herein
above.
Typically, the hot water and/or steam is injected into an oil sands reservoir
through
an injection well, and wherein formation fluids, comprising reservoir and
injection fluids,
are produced either through an adjacent production well or by back flowing
into the
injection well.
In most oil sand reservoirs, a water temperature of at least 150 C to 180 C is
needed
to mobilize the bitumen.
In most oil sand reservoirs, a steam temperature of at least 180 C, which
corresponds to a pressure of 150 psi (1.0 MPa), or greater is needed to
mobilize the
bitumen. Preferably, the aromatic amine-steam injection stream is introduced
to the
reservoir at a temperature in the range of from 150 C to 300 C, preferably 180
C to 260 C.
The particular steam temperature and pressure used in the process of the
present invention
will depend on such specific reservoir characteristics as depth, overburden
pressure, pay
zone thickness, and bitumen viscosity, and thus will be worked out for each
reservoir.
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It is preferable to inject the aromatic amine simultaneously with the hot
water and/or
steam in order to ensure or maximize the amount of aromatic amine actually
moving with
the steam. In some instances, it may be desirable to precede or follow a steam-
aromatic
amine injection stream with a steam-only injection stream. In this case, the
steam
temperature can be raised above 260 C during the steam-only injection. The
term "steam"
used herein is meant to include superheated steam, saturated steam, and less
than 100
percent quality steam.
For purposes of clarity, the term "less than 100 percent quality steam" refers
to
steam having a liquid water phase present. Steam quality is defined as the
weight percent of
dry steam contained in a unit weight of a steam-liquid mixture. "Saturated
steam" is used
synonymously with "100 percent quality steam". "Superheated steam" is steam
which has
been heated above the vapor-liquid equilibrium point. If super heated steam is
used, the
steam is preferably super heated to between 5 to 50 C above the vapor-liquid
equilibrium
temperature, prior to adding the aromatic amine.
The aromatic amine may be added to the hot water and/or steam neat or as a
concentrate. If added as a concentrate, it may be added as a 1 to 99 weight
percent solution
in water.
The aromatic amine is preferably injected intermittently or continuously with
the hot
water and/or steam, so that the hot water/steam-aromatic amine injection
stream reaches the
downhole formation through common tubing. The rate of aromatic amine addition
is
adjusted so as to maintain the preferred aromatic amine concentration of 100
ppm to 10
weight percent in steam. The rate of hot water and/or steam injection for a
typical oil sands
reservoir might be on the order of enough hot water and/or steam to provide an
advance
through the formation of from 1 to 3 feet/day.
In one embodiment of the process of the present invention, the bitumen
recovery
rate over time can be improved by injection of additives in more than one
stage, for
example: (a) using different additives (or formulations) injected with the hot
water and/or
steam at different stages, and/or (b) using the same additive (or formulation)
injected with
hot water and/or steam at different concentrations at different stages.
Additives (or
formulations) in addition to the aromatic amines of the present invention may
be selected
based on their performance for enhancing oil drainage in porous media under
the range of
oil saturation expected in the reservoir in a given stage (e.g., very high oil-
saturation at
initial well start-up phase and low oil-saturation at declining phase). If a
single additive (or
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formulation) is being used, the oil recovery agent can be injected at lower
concentration
with hot water and/or steam to help recover oil at high oil saturation,
followed by the
injection of the same enhanced oil recovery agent at higher concentration as
the oil
saturation in the formation decreases with time.
In one embodiment of the process of the present invention, the bitumen
recovery
rate over time can be improved by dividing the total hot water and/or steam
composition
injection phase into two or more stages, with a different concentration of
aromatic amine
being selected for each stage.
EXAMPLES
Parallel Pressure Reactor (PPR) Testing.
For Examples 1 to 19, approximately, 0.05 g of an aromatic amine, 0.5 g of oil
sand,
and 5 mL of water is placed into a 12 mL glass vial. The vial is then loosely
capped and is
then heated for 45 minutes at 120 C in a convection oven. The oven is then
turned off and
the sample is allowed to cool down to room temperature. Once cooled, the
sample is placed
on a white background and a picture is taken. Example 20 is conducted
similarly but in the
absence of an aromatic amine.
For Examples 21 to 28, the mixtures are prepared as described above but tested
at
200 C and 150 psi. These reactions conditions are representative of the
minimum steam
conditions necessary to mobilize bitumen in oil-field reservoir using steam-
assisted gravity
drainage (SAGD) applications. 0.05 g of an aromatic amine along with 0.5 g of
oil sand
and 5 mL of deionized (DI) water are added into a 15 mL glass insert, which is
then
transferred and placed in a PPR well and heated for 1 hour. At the end of 1
hour, the
sample is cooled and a picture is taken. Example 29 is conducted similarly but
in the
absence of an aromatic amine.
An additive is deemed to have a positive impact on bitumen liberation from the
oil
sand if the free oil attached along the glass wall of the vial, above the
liquid level, is higher
compared to the baseline. The oil liberated is estimated based on color
intensity (i.e., higher
color intensity would mean higher amount of bitumen liberated) both via visual
observation
and ImageJ analysis. In ImageJ, the images of the vials are initially
converted to 32 bit gray
scale and color intensity above the water level is measured and is compared
against the
baseline (water only). A color intensity of "0" represents complete black and
"255"
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represents complete white. Therefore, the higher the amount of bitumen
liberated by an
additive compared to the baseline the lower would be the mean intensity ratio.
The mean intensity ratios for Examples 1 to 29 are shown in Table 1:
Table 1
Mean
Example Aromatic Amine Wt % Structure
Intensity
Ratio
:::=:,
2,4,6-
tr. --,e
1 1 lt .. 0.45
lt ..
Trimethylaniline
wAs-"Nzw,
N-Benzy1-2- kl
2 1 1
phenethylamine
1.1
N-Butyl- 4
3 1 h ,1 0.58
benzylamine
4 Dibenzylamine 1 It j Losj 0.59
..
i.4...1;i.
i
.,
..--,......=t
5 2-Aminobiphenyl 1 ..¨ns.
i \I¨ \ 0.62
is.
6
Aminodiphenyl-
1
1 11 0.62
methane
N H,
7 Aniline 1 1 0.63
-.-C.--..
N--
-14
AO' \ ,.." .."\
8 2-Phenoxyaniline 1 r: W I \. 0.67
=,...k..._.-> --... 41
...
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. ,
9,10-Diamino- .............................. / \ .. ,
9 0.5 ¨ 0.73
phenanthrene I \\
1- 1 Amino-2-methyl- ..s.õ.., ,... .....--
....
0.78
naphthalene 11
'-"--,.?"=-' -
,
N,N-Bis(salicylidene)-
11 1 µ.\,....,"
\.00.N3,\,./\\3,ve\k,,,õ,õ,.--µ,õ 0.82
ethylenediamine i., 1
.1.= .....'
N-Phenyl-o-
12 1 0.83
phenylenediamine
Lks.õ,.õ... 1
.................................................... 31
õ
..
, At
2,4,6-Tri-tert- ...., .....õ:õ....--
13 1 0.84
butylaniline
,
mo....
..... ..,.:
14 N-Phenylglycine 1 0.85
1 'I
3,5-Di-tert-butylaniline 1 1 J 0.86
-....f.,
.-.a:
1,1'-Binaphthy1-2,2'- 1 1
16 0.92
diamine .:Ø=""---- ....,.:0\=-= õ.--j"
,............õ, ..õ..........,õ.,
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,¨,
4'-Aminobenzo-15- b 1
17 1 / 0.96
172
.......---.k.kõ......"-\Nõ.õ
18 a-Methylbenzylamine 1 )
L 0.98 I
, ..T..............,.r.,
\ mi
4-(Dimethylamino)- 1 /\ 4 .
19 ,1 0.99
phenylacetic acid .?
4
20* Water 1.00
r,
,,,.......,.-NN
21 2,4,6-Trimethylaniline 1 0.79
11 i
N-Benzyl-
22 1 ,..A. 0.80
ethylenediamine r ==1
23 N-Butylbenzylamine 1 ------k,..------11----"',--------N--,
1 i 0.81
=-z:::::N\ -.1
N-Methylphenethyl-
24 1 ...,,õõ...\\N ....,õ 0.90
amine
H
1,2-Diphenyl- , .....,,
25 1 "# -,,"-- -1-- -., 0.92
ethylenediamine
===',:. .:\,,,,õ.$4.=
11
,.....-,;,'7=-..
26 Tritylamine 1 . õ = 0.96
"ev C NH21:r1 '
"',..... ' ==,,,..1.-
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N-Phenylethylene-
27 1 0 .1 0.97
diamine
NH
2
28 2-Phenoxyaniline 1 0.99
29* Water 1.00
*Not an example of the invention
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