U.S. patent application number 16/312308 was filed with the patent office on 2019-07-25 for method to extract bitumen from oil sands using aromatic amines.
The applicant listed for this patent is Dow Global Technologies LLC. Invention is credited to Naoko AKIYA, Biplab MUKHERJEE, Michael L. TULCHINSKY, Cole A. WITHAM.
Application Number | 20190225889 16/312308 |
Document ID | / |
Family ID | 59285333 |
Filed Date | 2019-07-25 |
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United States Patent
Application |
20190225889 |
Kind Code |
A1 |
TULCHINSKY; Michael L. ; et
al. |
July 25, 2019 |
METHOD TO EXTRACT BITUMEN FROM OIL SANDS USING AROMATIC AMINES
Abstract
The present invention relates to an improved bitumen recovery
process from oil sands. The oil sands may be surface mined and
transported to a treatment area or may be treated directly by means
of an in situ process of oil sand deposits that are located too
deep for strip mining. Specifically, the present invention involves
the step of treating oil sands with an aromatic amine.
Inventors: |
TULCHINSKY; Michael L.;
(Midland, MI) ; AKIYA; Naoko; (Missouri city,
TX) ; MUKHERJEE; Biplab; (Pearland, TX) ;
WITHAM; Cole A.; (Pearland, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Dow Global Technologies LLC |
Midland |
MI |
US |
|
|
Family ID: |
59285333 |
Appl. No.: |
16/312308 |
Filed: |
June 16, 2017 |
PCT Filed: |
June 16, 2017 |
PCT NO: |
PCT/US2017/037899 |
371 Date: |
December 21, 2018 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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62363461 |
Jul 18, 2016 |
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Current U.S.
Class: |
1/1 |
Current CPC
Class: |
C10G 2300/4037 20130101;
C10G 1/047 20130101; C10G 2300/802 20130101; E21B 43/2408 20130101;
C10G 1/045 20130101; C10G 1/04 20130101 |
International
Class: |
C10G 1/04 20060101
C10G001/04; E21B 43/24 20060101 E21B043/24 |
Claims
1. A 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.
2. The process of claim 1 wherein the aromatic amine is described
by the following structure: R.sup.1R.sup.2R.sup.3N wherein R.sup.1
and R.sup.2 are independently --H, -AL where -AL is an
unsubstituted C.sub.1 to C.sub.20 alkyl group, a C.sub.6 to
C.sub.12 aromatically substituted C.sub.1 to C.sub.20 alkyl group,
or combination thereof, wherein -AL may contain one or more of a
--COOR.sup.4 where R.sup.4 is --H, alkyl, aryl or alkylaryl, CN,
--CHO, --NR.sup.5R.sup.6 group where R.sup.5 and R.sup.6 are
independently H, alkyl or aryl, --OH group, --O-- group, --S--
group, --N-- group, --Cl, --Br, --F, or R.sup.1 and R.sup.2 may
form an unsubstituted or substituted imine, or R.sup.1 and R.sup.2
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 R.sup.3 is --H or -AR where -AR is an
unsubstituted C.sub.1 to C.sub.20 alkyl group, an unsubstituted
C.sub.6 to C.sub.14 aromatic group, or a C.sub.1 to C.sub.20 alkyl
group substituted with one or more C.sub.6 to C.sub.14 aromatic
group, or a C.sub.6 to C.sub.14 aromatic group substituted with one
or more C.sub.1 to C.sub.20 alkyl group, or a C.sub.6 to C.sub.14
aromatic group substituted with one or more C.sub.1 to C.sub.20
alkyl group and/or one or more C.sub.6 to C.sub.14 aromatic group,
wherein -AR may contain one or more of a --COOR.sup.4 where R.sup.4
is --H, alkyl, aryl or alkylaryl, CN, --CHO, --NR.sup.5R.sup.6
group where R.sup.5 and R.sup.6 are independently --H, alkyl or
aryl, --OH group, --O-- group, --S-- group, --N-- group, --Cl,
--Br, --F, or R.sup.1, R.sup.2 and R.sup.3 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.
3. The bitumen recovery process of claim 1 by surface mining
comprising 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.
4. The bitumen recovery process of claim 3 wherein 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.
5. The bitumen recovery process of claim 1 by in situ production
comprising 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.
6. The bitumen recovery process of claim 5 wherein the
concentration of the aromatic amine in the steam is in an amount of
from 100 ppm to 10 weight percent.
7. The process of claim 1 wherein amine is selected from
2,4,6-trimethylaniline, N-benzyl-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, -1,1'-binaphthyl-2,2'-diamine,
4'-aminobenzo-15-crown 5-ether, .alpha.-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, or 4-dimethylaminopyridine.
Description
FIELD OF THE INVENTION
[0001] 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
[0002] 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.
[0003] 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.
[0004] 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.
[0005] 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.degree. C. to 75.degree. 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.
[0006] 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.
[0007] 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.degree. C. to 400.degree. 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 25 percent recovery of the available
oil.
[0008] 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.
[0009] 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.
[0010] U.S. Pat. No. 5,264,118 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.
[0011] 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.
[0012] 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.
[0013] U.S. Pat. No. 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.
[0014] U.S. Pat. No. 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 alkanolamines include
mono-, di-, and tri-ethanolamine, isopropanolamines, butanolamine,
and hexanolamines and mixtures thereof.
[0015] Canadian Patent Application 2,640,448 discloses enhancements
in bitumen recovery from oil sands by adding lipids to the
ore-water slurry.
[0016] U.S. Pat. No. 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.
[0017] U.S. Pat. No. 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.
[0018] 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
[0019] 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.
[0020] In one embodiment of the bitumen recovery process described
herein above, aromatic amine is described by the structure:
R.sup.1R.sup.2R.sup.3N [0021] wherein R.sup.1 and R.sup.2 are
independently --H, -AL where -AL is an unsubstituted C.sub.1 to
C.sub.20, preferably C.sub.1 to C.sub.6 alkyl group, a C.sub.6 to
C.sub.12 aromatically substituted C.sub.1 to C.sub.20, preferably
C.sub.1 to C.sub.6 alkyl group, or combination thereof, wherein -AL
may contain one or more of a --COOR.sup.4 where R.sup.4 is --H,
alkyl, aryl or alkylaryl, CN, --CHO, --NR.sup.5R.sup.6 group where
R.sup.5 and R.sup.6 are independently --H, alkyl or aryl, --OH
group, --O-- group, --S-- group, --N-- group, --Cl, --Br, --F, or
R.sup.1 and R.sup.2 may form an unsubstituted or substituted imine,
or R.sup.1 and R.sup.2 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 [0022] R.sup.3
is --H or -AR where -AR is an unsubstituted C.sub.1 to C.sub.20,
preferably C.sub.1 to C.sub.6 alkyl group, an unsubstituted C.sub.6
to C.sub.14 aromatic group, or a C.sub.1 to C.sub.20, preferably
C.sub.1 to C.sub.6 alkyl group substituted with one or more C.sub.6
to C.sub.14 aromatic group, or a C.sub.6 to C.sub.14 aromatic group
substituted with one or more C.sub.1 to C.sub.20, preferably
C.sub.1 to C.sub.6 alkyl group, or a C.sub.6 to C.sub.14 aromatic
group substituted with one or more C.sub.1 to C.sub.20, preferably
C.sub.1 to C.sub.6 alkyl group and/or one or more C.sub.6 to
C.sub.14 aromatic group, wherein -AR may contain one or more of a
--COOR.sup.4 where R.sup.4 is --H, alkyl, aryl or alkylaryl, CN,
--CHO, --NR.sup.5R.sup.6 group where R.sup.5 and R.sup.6 are
independently --H, alkyl or aryl, --OH group, --O-- group, --S--
group, --N-- group, --Cl, --Br, --F, or R.sup.1, R.sup.2 and
R.sup.3 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.
[0023] Preferably the aromatic amine is 2,4,6-trimethylaniline,
N-benzyl-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, -1,1'-binaphthyl-2,2'-diamine,
4'-aminobenzo-15-crown 5-ether, .alpha.-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.
[0024] 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.
[0025] 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
[0026] 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.
[0027] 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.degree.
C. to 75.degree. C., preferably 40.degree. C. to 55.degree. C.
[0028] 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 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.
[0029] 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.
[0030] 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.
[0031] 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 properties,
coking, hydro-conversion, solvent deasphalting to improve the
hydrogen to carbon ratio, and hydrotreating which removes
contaminants such as sulfur.
[0032] 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.
[0033] 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 C.sub.1 to C.sub.12 alkane hydrocarbon, and
alkene hydrocarbons such as C.sub.1 to C.sub.12 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.
[0034] Preferred aromatic amines of the present invention are
represented by the following formula:
R.sup.1R.sup.2R.sup.3N [0035] wherein R.sup.1 and R.sup.2 are
independently --H, -AL where -AL is an unsubstituted C.sub.1 to
C.sub.20, preferably C.sub.1 to C.sub.6 alkyl group, a C.sub.6 to
C.sub.12 aromatically substituted C.sub.1 to C.sub.20, preferably
C.sub.1 to C.sub.6 alkyl group, or combination thereof, wherein -AL
may contain one or more of a --COOR.sup.4 where R.sup.4 is --H,
alkyl, aryl or alkylaryl, CN, --CHO, --NR.sup.5R.sup.6 group where
R.sup.5 and R.sup.6 are independently --H, alkyl or aryl, --OH
group, --O-- group, [0036] --S-- group, --N-- group, --Cl, --Br,
--F, or R.sup.1 and R.sup.2 may form an unsubstituted or
substituted imine, or R.sup.1 and R.sup.2 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 [0037]
and [0038] R.sup.3 is --H or -AR where -AR is an unsubstituted
C.sub.1 to C.sub.20, preferably C.sub.1 to C.sub.6 alkyl group, an
unsubstituted C.sub.6 to C.sub.14 aromatic group, or a C.sub.1 to
C.sub.20, preferably C.sub.1 to C.sub.6 alkyl group substituted
with one or more C.sub.6 to C.sub.14 aromatic group, or a C.sub.6
to C.sub.14 aromatic group substituted with one or more C.sub.1 to
C.sub.20, preferably C.sub.1 to C.sub.6 alkyl group, or a C.sub.6
to C.sub.14 aromatic group substituted with one or more C.sub.1 to
C.sub.20, preferably C.sub.1 to C.sub.6 alkyl group and/or one or
more C.sub.6 to C.sub.14 aromatic group, wherein -AR may contain
one or more of a --COOR.sup.4 where R.sup.4 is --H, alkyl, aryl or
alkylaryl, CN, --CHO, --NR.sup.5R.sup.6 group where R.sup.5 and
R.sup.6 are independently --H, alkyl or aryl, --OH group, --O--
group, --S-- group, --N-- group, --Cl, --Br, --F, or IV, R.sup.2
and R.sup.3 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.
[0039] Preferred aromatic amines are 2,4,6-trimethylaniline,
N-benzyl-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, -1,1'-binaphthyl-2,2'-diamine,
4'-aminobenzo-15-crown 5-ether, .alpha.-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.
[0040] 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.degree. C., more preferably equal to
or greater than 40.degree. C., more preferably equal to or greater
than 55.degree. C., more preferably equal to or greater than
60.degree. C. Preferably, the aromatic amine solution oil sands
slurry is heated to equal to or less than 100.degree. C., more
preferably equal to or less than 80.degree. C., and more preferably
equal to or less than 75.degree. C.
[0041] 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.
[0042] 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.
[0043] 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.
[0044] 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.
[0045] 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.
[0046] In most oil sand reservoirs, a water temperature of at least
150.degree. C. to 180.degree. C. is needed to mobilize the
bitumen.
[0047] In most oil sand reservoirs, a steam temperature of at least
180.degree. 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.degree. C. to
300.degree. C., preferably 180.degree. C. to 260.degree. 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.
[0048] 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.degree. 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.
[0049] 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.degree. C.
above the vapor-liquid equilibrium temperature, prior to adding the
aromatic amine.
[0050] 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.
[0051] 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.
[0052] 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 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.
[0053] 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.
[0054] 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.degree. 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.
[0055] For Examples 21 to 28, the mixtures are prepared as
described above but tested at 200.degree. 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.
[0056] 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" 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.
[0057] The mean intensity ratios for Examples 1 to 29 are shown in
Table 1:
TABLE-US-00001 TABLE 1 Mean Wt Intensity Example Aromatic Amine %
Structure Ratio 1 2,4,6- Trimethylaniline 1 ##STR00001## 0.45 2
N-Benzyl-2- phenethylamine 1 ##STR00002## 0.51 3 N-Butyl-
benzylamine 1 ##STR00003## 0.58 4 Dibenzylamine 1 ##STR00004## 0.59
5 2-Aminobiphenyl 1 ##STR00005## 0.62 6 Aminodiphenyl- methane 1
##STR00006## 0.62 7 Aniline 1 ##STR00007## 0.63 8 2-Phenoxyaniline
1 ##STR00008## 0.67 9 9,10-Diamino- phenanthrene 0.5 ##STR00009##
0.73 10 1-Amino-2-methyl- naphthalene 1 ##STR00010## 0.78 11
N,N-Bis(salicylidene)- ethylenediamine 1 ##STR00011## 0.82 12
N-Phenyl-o- phenylenediamine 1 ##STR00012## 0.83 13 2,4,6-Tri-tert-
butylaniline 1 ##STR00013## 0.84 14 N-Phenylglycine 1 ##STR00014##
0.85 15 3,5-Di-tert-butylaniline 1 ##STR00015## 0.86 16
1,1'-Binaphthyl-2,2'- diamine 1 ##STR00016## 0.92 17
4'-Aminobenzo-15- crown 5-ether 1 ##STR00017## 0.96 18
.alpha.-Methylbenzylamine 1 ##STR00018## 0.98 19 4-(Dimethylamino)-
phenylacetic acid 1 ##STR00019## 0.99 20* Water 1.00 21
2,4,6-Trimethylaniline 1 ##STR00020## 0.79 22 N-Benzyl-
ethylenediamine 1 ##STR00021## 0.80 23 N-Butylbenzylamine 1
##STR00022## 0.81 24 N-Methylphenethyl- amine 1 ##STR00023## 0.90
25 1,2-Diphenyl- ethylenediamine 1 ##STR00024## 0.92 26 Tritylamine
1 ##STR00025## 0.96 27 N-Phenylethylene- diamine 1 ##STR00026##
0.97 28 2-Phenoxyaniline 1 ##STR00027## 0.99 29* Water 1.00 *Not an
example of the invention
* * * * *