U.S. patent application number 14/297120 was filed with the patent office on 2014-12-11 for remediation of asphaltene-induced plugging of an oil-bearing formation.
The applicant listed for this patent is SHELL OIL COMPANY. Invention is credited to John Justin FREEMAN, Stanley Nemec MILAM, Erik Willem TEGELAAR.
Application Number | 20140360727 14/297120 |
Document ID | / |
Family ID | 52004481 |
Filed Date | 2014-12-11 |
United States Patent
Application |
20140360727 |
Kind Code |
A1 |
MILAM; Stanley Nemec ; et
al. |
December 11, 2014 |
REMEDIATION OF ASPHALTENE-INDUCED PLUGGING OF AN OIL-BEARING
FORMATION
Abstract
A system and method for remediation of asphaltene-induced
fouling of an oil-bearing formation is provided wherein an
asphaltene solvent comprising at least 75 mol % dimethyl sulfide is
introduced into an oil-bearing formation containing asphaltene
deposits and the dimethyl sulfide is contacted with the asphaltene
deposits.
Inventors: |
MILAM; Stanley Nemec;
(Houston, TX) ; TEGELAAR; Erik Willem; (Rijswijk,
NL) ; FREEMAN; John Justin; (Pattison, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
SHELL OIL COMPANY |
Houston |
TX |
US |
|
|
Family ID: |
52004481 |
Appl. No.: |
14/297120 |
Filed: |
June 5, 2014 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61832272 |
Jun 7, 2013 |
|
|
|
Current U.S.
Class: |
166/304 ;
166/52 |
Current CPC
Class: |
C09K 8/58 20130101; C09K
8/524 20130101; E21B 43/162 20130101 |
Class at
Publication: |
166/304 ;
166/52 |
International
Class: |
E21B 43/16 20060101
E21B043/16; E21B 43/14 20060101 E21B043/14 |
Claims
1. A method for remediating asphaltene deposition in an oil-bearing
formation, comprising: providing an asphaltene solvent comprising
at least 75 mol % dimethyl sulfide (DMS); introducing the
asphaltene solvent into an oil-bearing formation containing one or
more asphaltene deposits; and contacting the asphaltene solvent
with one or more of the asphaltene deposits in the formation.
2. The method of claim 1 further comprising producing the
asphaltene solvent from the formation after introducing the
asphaltene solvent into the formation.
3. The method of claim 1 further comprising producing oil from the
formation after introducing the asphaltene solvent into the
formation.
4. The method of claim 1 wherein the asphaltene solvent is
introduced into the formation through a first well.
5. The method of claim 4 further comprising producing oil from the
formation through the first well after introducing the asphaltene
solvent into the formation through the first well.
6. The method of claim 4 wherein the asphaltene deposits are
located in the formation within 5 meters of the first well.
7. The method of claim 6 wherein a volume of solvent sufficient to
penetrate up to 5 meters radially from the first well is introduced
into the formation through the first well.
8. The method of claim 4 further comprising producing oil from the
formation through a second well after introducing the asphaltene
solvent into the formation through the first well.
9. The method of claim 8 where from 0.1 to 2 pore volumes of the
asphaltene solvent are introduced into the formation through the
first well.
10. The method of claim 1 wherein one or more of the asphaltene
deposits form a tar mat in the formation.
11. The method of claim 10 wherein the first well is located in the
formation within 10 meters of the tar mat.
12. The method of claim 1 wherein the asphaltene solvent is first
contact miscible with oil in or from the formation.
13. The method of claim 1 wherein the asphaltene solvent consists
essentially of DMS.
14. The method of claim 1 wherein the asphaltene solvent further
comprises up to 25 mol % decant oil.
15. The method of claim 1 wherein the asphaltene deposit is an
asphaltene accretion on a portion of the formation or is a
sludge.
16. A system for remediating asphaltene deposition in an
oil-bearing formation containing asphaltene deposits, comprising:
an asphaltene solvent comprising at least 75 mol % dimethyl sulfide
(DMS); an asphaltene solvent storage facility containing at least a
portion of the asphaltene solvent; a well extending into the
oil-bearing formation positioned to introduce the asphaltene
solvent into the formation to contact an asphaltene deposit
therein, the well being structured and arranged to introduce the
asphaltene solvent into the oil-bearing formation to contact the
asphaltene deposit therein, wherein the asphaltene solvent storage
facility is operatively fluidly coupled to the first well to
provide the asphaltene solvent to the first well.
17. The system of claim 16 wherein the well is further structured
and arranged to produce oil from the formation.
18. The system of claim 17 wherein the well is further structured
and arranged to produce the asphaltene solvent from the
formation.
19. The system of claim 16 wherein the well is a first well and
further comprising a second well extending into the formation
positioned to produce oil from the formation, wherein the second
well is structured and arranged to produce oil from the
formation.
20. The system of claim 16 wherein the asphaltene solvent further
comprises up to 25 mol % decant oil.
21. The system of claim 16 wherein the asphaltene solvent consists
essentially of DMS.
22. The system of claim 16 wherein the asphaltene solvent is first
contact miscible with oil in or from the formation.
Description
RELATED CASES
[0001] This application claims benefit of U.S. Provisional
Application No. 61/832,272, filed on Jun. 7, 2013, which is
incorporated herein by reference.
FIELD OF THE INVENTION
[0002] The present invention is directed to improving oil recovery
from an oil-bearing formation fouled by asphaltene deposits. In
particular, the present invention is directed to improving oil
recovery from an oil-bearing formation fouled by asphaltene
deposits using an asphaltene solvent to dissolve the asphaltene
deposits.
BACKGROUND OF THE INVENTION
[0003] Production of oil from an oil-bearing formation may be
impeded by hydrocarbonaceous deposits within the formation.
Asphaltene deposits are one type of hydrocarbonaceous deposit that
may impede the flow of oil through a formation by reducing the
permeability of the formation. Asphaltenes are a fraction of crude
oil formed predominately of aromatic hydrocarbons and
heteroatom-containing hydrocarbons that are high in molecular
weight relative to other components of the crude oil.
[0004] Production of oil from an oil-bearing formation may induce
asphaltene flocculation in the formation, where the flocculated
asphaltenes may aggregate and deposit in the formation to impede or
block the flow of oil through the formation and thereby reduce the
amount of oil that may be produced from the formation. Asphaltene
flocculation may be induced, in particular, in the formation near a
production well, where changes in pressure, temperature,
composition, and shear rate caused by production of oil from the
well may destabilize the asphaltenes in the oil near the production
well and cause the asphaltenes to flocculate, aggregate, and
deposit, plugging the formation near the production well.
[0005] In other formations, naturally occurring tar mats formed of
asphaltenes may inhibit the flow of oil through the formation,
blocking mobilization of the oil through the formation for
production. These tar mats may form by destabilization of the
asphaltenes in the oil within the formation in high permeability
portions of the oil-bearing formation. The destabilized asphaltenes
in the high permeability portion of the formation may flocculate,
and the flocculated asphaltenes may aggregate and deposit in the
formation and thereby form the tar mat.
[0006] Asphaltenes may deposit in the formation in the form of a
solid deposit or a sludge. Solid deposits of asphaltenes may be a
result of growth of asphaltene aggregates on formation surfaces,
while sludges may form as large aggregates in solution that settle
out.
[0007] Various solvents have been utilized to solubilize
asphaltenes that have deposited in an oil-bearing formation to
improve recovery of oil from the formation by increasing the
permeability of the formation to mobilized oil. U.S. Pat. No.
5,425,422 discloses injecting deasphalted oil into an oil-bearing
formation to solvate asphaltene deposits near a wellbore in the
formation and thereby improve production of oil from the formation,
where the injected oil is produced from the formation and
deasphalted prior to being injected into the formation. The use of
aromatic solvents such as o-xylene and toluene to dissolve
asphaltene-based deposits in a formation near a wellbore is also
known.
[0008] Disulfide solvents have also been used to dissolve
asphaltene-based deposits in a formation for near-wellbore
formation remediation. U.S. Pat. No. 4,379,490 discloses the use of
an amine activated disulfide oil for treating and removing unwanted
asphaltene deposits from the pore spaces of oil-bearing formations.
U.S. Pat. No. 4,379,490 further discloses that carbon disulfide is
one of the most effective asphaltene solvents known, and that it
has been utilized for the removal of asphaltene-based deposits from
oil-bearing formations.
[0009] Such solvents, however, have certain disadvantages attached
to them. Injection of deasphalted oil to remediate asphaltene
deposition in a formation is inefficient since it requires
injecting oil produced from the formation and subsequently
processed back into the formation, where some of the injected oil
may not be recovered again from the formation. Injection of
aromatics such as toluene and o-xylene may be subject to regulatory
limitation, and is economically inefficient since such aromatics
are even more highly processed and valuable than deasphalted oil.
Disulfide solvents may be subject to hydrolysis within the
formation, and, in the case of carbon disulfide, may result in
souring the formation. Carbon disulfide is also highly toxic.
[0010] Improvements to existing methods of remediating asphaltene
deposits and tar mats in oil-bearing formations are desirable.
SUMMARY OF THE INVENTION
[0011] In one aspect, the present invention is directed to a method
of remediating asphaltene deposition in an oil-bearing formation,
comprising:
[0012] providing an asphaltene solvent comprising at least 75 mol %
dimethyl sulfide (DMS);
[0013] introducing the asphaltene solvent into an oil-bearing
formation containing one or more asphaltene deposits; and
[0014] contacting the asphaltene solvent with one or more of the
asphaltene deposits in the formation.
[0015] In another aspect, the present invention is directed to a
system for remediating asphaltene deposition in an oil-bearing
formation containing asphaltene deposits, comprising:
[0016] an asphaltene solvent comprising at least 75 mol % dimethyl
sulfide (DMS);
[0017] an asphaltene solvent storage facility containing at least a
portion of the asphaltene solvent; and
[0018] a well extending into the oil-bearing formation positioned
to introduce the asphaltene solvent into the formation to contact
an asphaltene deposit therein, the well being structured and
arranged to introduce the asphaltene solvent into the oil-bearing
formation to contact an asphaltene deposit therein, wherein the
asphaltene solvent storage facility is operatively fluidly coupled
to the first well to provide the asphaltene solvent to the first
well.
BRIEF DESCRIPTION OF THE DRAWINGS
[0019] The drawing figures depict one or more implementations in
accord with the present teachings, by way of example only, not by
way of limitation. In the figures, like reference numerals refer to
the same or similar elements.
[0020] FIG. 1 is a schematic diagram illustrating a system of the
present invention that may be utilized to practice a method of the
present invention.
[0021] FIG. 2 is a schematic diagram illustrating a system of the
present invention that may be utilized to practice a method of the
present invention.
[0022] FIG. 3 is a schematic diagram illustrating a system of the
present invention that may be utilized to practice a method of the
present invention.
[0023] FIG. 4 is a graph showing petroleum recovery from oil sands
at 30.degree. C. using various solvents.
[0024] FIG. 5 is a graph showing petroleum recovery from oil sands
at 10.degree. C. using various solvents.
DETAILED DESCRIPTION OF THE INVENTION
[0025] The present invention resides in the discovery that dimethyl
sulfide (hereafter often referred to as "DMS") is miscible with all
fractions of crude oil except solid paraffin waxes, and in
particular, that DMS is a highly effective asphaltene solvent. An
asphaltene solvent comprising at least 75 mol % DMS is provided,
and is introduced into an oil-bearing formation containing one or
more asphaltene deposits. The solvent is contacted with the
asphaltenes of the asphaltene deposits to solvate the deposited
asphaltenes. The solvent may solvate a substantial portion of the
asphaltenes in the asphaltene deposits to remove, or reduce the
size of, the asphaltene deposits, which may increase the
permeability of the formation. Mobilized oil then may be produced
from the formation through the formation portion from which
asphaltene deposits have been removed or reduced by contact with
the solvent.
[0026] DMS exhibits solubility with asphaltenes similar to carbon
disulfide. DMS, however, is relatively non-toxic, is not subject to
hydrolysis at typical temperatures within oil-bearing formations,
and may be produced from relatively low value components. DMS also
has a low boiling point relative to most components of a crude oil,
and may be easily separated from oil produced from the formation by
flashing or distillation.
[0027] Certain terms used herein are defined as follows:
"Asphaltenes", as used herein, are defined as hydrocarbons and
heteroatom-containing hydrocarbonaceous materials that are
insoluble in n-heptane and soluble in toluene at standard
temperature and pressure. "Miscible", as used herein, is defined as
the capacity of two or more substances, compositions, or liquids to
be mixed in any ratio without separation into two or more phases at
equilibrium. "Near-wellbore", as used herein, is defined as within
5 meters of a wellbore in an oil-bearing formation. "Operatively
fluidly coupled" or "operatively fluidly connected", as used
herein, defines a connection between two or more elements in which
the elements are directly or indirectly connected to allow direct
or indirect fluid flow between the elements. The term "fluid flow",
as used herein, refers to the flow of a gas or a liquid; the term
"direct fluid flow" as used in this definition means that the flow
of a liquid or a gas between two defined elements flows directly
between the two defined elements; and the term "indirect fluid
flow" as used in this definition means that the flow of a liquid or
a gas between two defined elements may be directed through one or
more additional elements to change one or more aspects of the
liquid or gas as the liquid or gas flows between the two defined
elements. Aspects of a liquid or a gas that may be changed in
indirect fluid flow include physical characteristics, such as the
temperature or the pressure of a gas or a liquid; the state of the
fluid between a liquid and a gas; and/or the composition of the gas
or liquid. "Indirect fluid flow", as defined herein, excludes
changing the composition of the gas or liquid between the two
defined elements by chemical reaction, for example, oxidation or
reduction of one or more elements of the liquid or gas.
[0028] The asphaltene solvent provided for use in the method or
system of the present invention is comprised of at least 75 mol %
DMS. The asphaltene solvent may be comprised of at least 80 mol %,
or at least 85 mol %, or at least 90 mol %, or at least 95 mol %,
or at least 99 mol % DMS. The asphaltene solvent may consist
essentially of DMS, or may consist of DMS.
[0029] The asphaltene solvent provided for use in the method or
system of the present invention may be comprised of one or more
compounds that form a mixture with the DMS in the solvent. The one
or more compounds may be compounds that form an azeotropic mixture
with DMS. Compounds that may form an azeotropic mixture with DMS
that may be included in the asphaltene solvent are pentane,
isopentane, 2-methyl-2-butene, and isoprene. The asphaltene
solvent, therefore, may be comprised of at least 75 mol % DMS and
one or more compounds selected from the group consisting of
pentane, isopentane, 2-methyl-2-butene, and isoprene.
[0030] The asphaltene solvent may also include one or more other
compounds that do not form azeotropic mixtures with DMS in which
asphaltenes are soluble at temperatures within the range of
temperatures in the formation, or from 5.degree. C. to 300.degree.
C. The one or more other compounds may be selected from the group
consisting of o-xylene, toluene, carbon disulfide, dichloromethane,
trichloromethane, natural gas condensates, hydrogen sulfide,
diesel, naphtha solvent, asphalt solvent, kerosene, and dimethyl
ether.
[0031] The asphaltene solvent may include a fluid that has a
density greater than DMS, and preferably greater than oil in the
formation. The fluid having a density greater than DMS may be
included in the asphaltene solvent to increase the density of the
solvent relative to the density of DMS to enhance plug flow of the
solvent through the formation. The fluid having a density greater
than DMS may have a density of at least 0.9 g/cm.sup.3 or at least
1.0 g/cm.sup.3. The fluid having a density greater than DMS may be
decant oil. In an embodiment, the asphaltene solvent provided for
use in the method or system of the present invention may be
comprised of up to 25 mol % decant oil.
[0032] The asphaltene solvent provided for use in the method or
system of the present invention may be first contact miscible with
liquid petroleum compositions, preferably any liquid petroleum
composition. In liquid phase or in gas phase the solvent may be
first contact miscible with substantially all crude oils including
light crude oils, heavy crude oils, extra-heavy crude oils, and
bitumen, and may be first contact miscible in liquid phase or in
gas phase with the oil in the oil-bearing formation.
[0033] The asphaltene solvent may be first contact miscible with
liquid phase residue--hydrocarbons having a boiling point of at
least 540.degree. C. at 0.101 MPa--and liquid phase asphaltenes in
a hydrocarbonaceous composition. The asphaltene solvent may
dissolve at least a portion of asphaltene deposits in an
oil-bearing formation including asphaltene sludges and solid
asphaltene deposits within a formation, where the asphaltene
deposits may be near-wellbore deposits induced, at least in part,
by production of oil from the formation, or the asphaltene deposits
may be naturally occurring tar mats. The asphaltene solvent may
also be first contact miscible with C.sub.3 to C.sub.8 aliphatic
and aromatic hydrocarbons containing less than 5 wt. % oxygen, less
than 10 wt. % sulfur, and less than 5 wt. % nitrogen.
[0034] The asphaltene solvent may be first contact miscible with
oil having a moderately high or a high viscosity. The asphaltene
solvent may be first contact miscible with oil having a dynamic
viscosity of at least 1000 mPa s (1000 cP), or at least 5000 mPa s
(5000 cP), or at least 10000 mPa s (10000 cP), or at least 50000
mPa s (50000 cP), or at least 100000 mPa s (100000 cP), or at least
500000 mPa s (500000 cP) at 25.degree. C. The asphaltene solvent
may be first contact miscible with oil having a dynamic viscosity
of from 1000 mPa s (1 cP) to 5000000 mPa s (5000000 cP), or from
5000 mPa s (100 cP) to 1000000 mPa s (1000000 cP), or from 10000
mPa s (500 cP) to 500000 mPa s (500000 cP), or from 50000 mPa s
(1000 cP) to 100000 mPa s (100000 cP) at 25.degree. C.
[0035] The asphaltene solvent provided for use in the method or
system of the present invention may have a low viscosity. The
asphaltene solvent may be a fluid having a dynamic viscosity of at
most 0.35 mPa s (0.35 cP), or at most 0.3 mPa s (0.3 cP), or at
most 0.285 mPa s (0.285 cP) at a temperature of 25.degree. C.
[0036] The asphaltene solvent provided for use in the method or
system of the present invention may have a relatively high cohesive
energy density. The asphaltene solvent provided for use in the
method or system of the present invention may have a cohesive
energy density of at least 300 Pa to 410 Pa, or from 320 Pa to 400
Pa.
[0037] The asphaltene solvent provided for use in the method or
system of the present invention preferably is relatively non-toxic
or is non-toxic. The asphaltene solvent may have an aquatic
toxicity of LC.sub.50 (rainbow trout) greater than 200 mg/l at 96
hours. The asphaltene solvent may have an acute oral toxicity of
LD.sub.50 (mouse and rat) of from 535 mg/kg to 3700 mg/kg, an acute
dermal toxicity of LD.sub.50 (rabbit) of greater 5000 mg/kg, and an
acute inhalation toxicity of LC.sub.50 (rat) of 40250 ppm at 4
hours.
[0038] Referring now to FIG. 1, a system of the invention useful
for practicing a process of the present invention is shown. An
asphaltene solvent comprising at least 75 mol. % DMS as described
above is provided and stored in an asphaltene solvent storage
facility 101. The asphaltene solvent storage facility 101 is
operatively fluidly coupled to a well 103. The well 103 extends
into an oil-bearing formation 105 containing one or more asphaltene
deposits 107, and is positioned to introduce the asphaltene solvent
into the formation to contact an asphaltene deposit therein.
[0039] The oil-bearing formation 105 may be a subterranean
formation. The subterranean formation may be comprised of one or
more porous matrix materials selected from the group consisting of
a porous mineral matrix, a porous rock matrix, and a combination of
a porous mineral matrix and a porous rock matrix, where the porous
matrix material may be located beneath an overburden at a depth
ranging from 50 meters to 6000 meters, or from 100 meters to 4000
meters, or from 200 meters to 2000 meters under the earth's
surface. The formation may have a permeability of from 0.000001 to
15 Darcies, or from 0.001 to 1 Darcy. The rock and/or mineral
porous matrix material of the formation may be comprised of
sandstone, shale, and/or a carbonate selected from dolomite,
limestone, and mixtures thereof--where the limestone may be
microcrystalline or crystalline limestone and/or chalk. The
subterranean formation may be a subsea subterranean formation.
[0040] One or more asphaltene deposits 107 are located in the
formation 105. An asphaltene deposit may be comprised of a solid
accumulation of asphaltenes that have deposited on mineral or rock
surfaces within the formation. An asphaltene deposit may be
comprised of a sludge of asphaltenes that has settled out of the
oil in the formation. An asphaltene deposit 107 may impede fluid
flow through the portion of the formation 105 in which the deposit
is located, wherein the asphaltene deposit may have accumulated in
pores of the porous rock or mineral matrix of the formation,
thereby reducing the permeability of the formation to the flow of
fluids. An asphaltene deposit 107 may be a near-wellbore deposit
that has accumulated near the wellbore 109 within the formation
105, for example, within 5 meters of the wellbore. A near-wellbore
asphaltene deposit may have resulted from producing oil from the
formation 105 through the well 103, for example, by changing
pressure, temperature, composition, and/or shear rate. An
asphaltene deposit 107 may be a naturally occurring tar mat or a
tar mat formed as a result of producing oil from the formation.
[0041] The well 103 is structured and arranged to introduce the
asphaltene solvent into the oil-bearing formation in position to
contact an asphaltene deposit 107 therein. The well 103 may be
operatively fluidly coupled to the asphaltene solvent storage
facility 101 through an injection/production facility 111. The
asphaltene solvent storage facility 101 may be operatively fluidly
coupled to the injection/production facility 111 via conduit 113 to
provide asphaltene solvent to the injection/production facility.
The injection/production facility 111 may be operatively fluidly
coupled to the well 103 to provide the asphaltene solvent to the
well. As shown by the down arrow in the well 103, the asphaltene
solvent may flow from the injection/production facility 111 through
the well to be introduced into the formation 105 in position to
contact the asphaltene deposit 107. The well 103 may be a
conventional well for introducing or injecting a fluid into an
oil-bearing formation wherein the well may contain conduits, tubes,
or strings therein to conduct the asphaltene solvent from the
injection/production facility 111 into the formation to a position
from which the solvent may be introduced into the formation to
contact an asphaltene deposit 107. The well 103 may have
perforations in the wellbore at a location through which the
solvent may be introduced into the formation to contact an
asphaltene deposit.
[0042] The injection/production facility 111 and the well 103, or
the well itself, may include a mechanism for introducing the
asphaltene solvent into the formation 105. The mechanism for
introducing the asphaltene solvent into the formation 105 may be
comprised of a pump 115 for delivering the asphaltene solvent to
perforations or openings in the well through which the asphaltene
solvent may be injected into the formation in position to contact
an asphaltene deposit 107. In one embodiment, the well 103 may
comprise a pump and the asphaltene solvent may be provided directly
from the asphaltene solvent storage facility 101 to the pump of the
well for introduction into the formation in the absence of an
injection/production facility 111.
[0043] The asphaltene solvent is introduced into the oil-bearing
formation 105, for example by being injected into the formation by
pumping the asphaltene solvent into the formation. The asphaltene
solvent may be introduced into the formation at a pressure above
the instantaneous pressure in the formation to force the asphaltene
solvent to flow into the formation. The pressure at which the
asphaltene solvent is introduced into the formation may range from
the instantaneous pressure in the formation up to, but not
including, the fracture pressure of the formation. The pressure at
which the asphaltene solvent may be injected into the formation may
range from 20% to 95%, or from 40% to 90%, of the fracture pressure
of the formation. The pressure at which the asphaltene solvent is
injected into the formation may range from a pressure from 0 to 37
MPa above the initial formation pressure as measured prior to the
start of injection.
[0044] An amount of the asphaltene solvent may be introduced into
the formation to contact and dissolve at least a portion of an
asphaltene deposit 107. If the asphaltene deposit 107 is a
near-wellbore deposit wherein the deposit is located in the
formation within 5 meters of the well, a volume of asphaltene
solvent sufficient to penetrate up to 5 meters radially from the
well within the portion of the formation in which the deposit is
located may be introduced into the formation. If the asphaltene
deposit is located at a known distance greater than 5 meters from
the well 103, a volume of asphaltene solvent sufficient to
penetrate to the known distance radially from the well within the
portion of the formation in which the asphaltene deposit is located
may be introduced into the formation.
[0045] As the asphaltene solvent is introduced into the formation
105, the asphaltene solvent may spread into the formation as shown
by arrows 117. Upon introduction to the formation 105, the
asphaltene solvent may contact the asphaltene deposit 107. The
asphaltenes of the asphaltene deposit 107 are very soluble in the
asphaltene solvent, where the asphaltenes may be first contact
miscible with the asphaltene solvent. The asphaltene solvent may
solvate and mobilize at least a portion, and preferably
substantially all, of the asphaltenes in the asphaltene deposit
upon contact with the asphaltene deposit.
[0046] The asphaltene solvent may be left to soak in the formation
105 after introduction into the formation to contact, solvate, and
mobilize the asphaltenes in the asphaltene deposit 107. The
asphaltene solvent should be contacted with asphaltene deposit for
a sufficient period of time to solvate at least a portion, and
preferably substantially all, of the asphaltenes of the asphaltene
deposit, for example, at least 50 wt. %, or at least 75 wt. %, or
at least 90 wt. % of the asphaltenes in the asphaltene deposit that
are contacted by the asphlatene solvent. The asphaltene solvent may
be left to soak in the formation for a time period of from 1 hour
to 15 days, or from 5 hours to 50 hours.
[0047] Subsequent to the introduction of the asphaltene solvent
into the formation 105 and contact of the asphaltene solvent with
the asphaltene deposit, a mixture of the asphaltene solvent and
mobilized asphaltenes solvated by the solvent may be removed from
the site of the (former) asphlatene deposit in the formation. The
mixture of asphaltene solvent and mobilized asphaltenes may be
removed from the site of the (former) asphaltene deposit in the
formation by injecting additional asphaltene solvent into the
formation, or by injecting another fluid, for example water, into
the formation, or by producing the mixture of asphaltene solvent
and mobilized asphaltenes from the formation.
[0048] Mobilization and removal of asphaltenes from the asphaltene
deposit with the asphaltene solvent may increase the fluid
permeability of the formation at the location of the former
asphaltene deposit. The fluid permeability of the formation at the
location of the former asphaltene deposit may be increased by at
least 0.001 Darcy, or at least 0.01 Darcy, or at least 0.1 Darcy,
or at least 0.5 Darcy by mobilization and removal of asphaltenes
from the asphaltene deposit with the asphaltene solvent.
[0049] The mixture of asphaltene solvent and mobilized asphaltenes
may be recovered and produced from the formation 105, as shown in
FIG. 2. The system may include a mechanism for producing the
mixture of asphaltene solvent and mobilized asphaltenes from the
formation 105 subsequent to introduction of the asphaltene solvent
into the formation and contact of the asphaltene solvent with the
asphaltene deposit, for example, after completion of introduction
of the asphaltene solvent into the formation and following the soak
period. The mechanism for recovering and producing the mixture of
asphaltene solvent and asphaltenes may be comprised of a pump 112,
which may be located in the injection/production facility 111
and/or within the well 103, and which draws the asphaltene solvent
and the mixture of asphaltene solvent and mobilized asphaltenes
from the formation to deliver the asphaltene solvent and the
mixture of asphaltene solvent and mobilized asphaltenes to the
facility 111.
[0050] Alternatively, the mechanism for recovering and producing
the mixture of asphaltene solvent and mobilized asphaltenes from
the formation 105 may be comprised of a compressor 114. The
compressor 114 may be operatively fluidly coupled to a gas storage
tank 119 by conduit 121, and may compress gas from the gas storage
tank for injection into the formation 105 through the well 103. The
compressor may compress the gas to a pressure sufficient to drive
production of the mixture of asphaltene solvent and mobilized
asphaltenes from the formation 105 via the well 103, where the
appropriate pressure can be determined by conventional methods
known to those skilled in the art. The compressed gas may be
injected into the formation from a different position on the well
103 than the well position at which the mixture of asphaltene
solvent and mobilized asphaltenes are produced from the
formation.
[0051] Oil, and optionally gas and water, also may be mobilized and
recovered from the formation 105 while recovering and producing the
mixture of asphaltene solvent and mobilized asphaltenes from the
formation. Oil may be recovered and produced from the formation
105, in part, through the portion of the formation from which at
least a part of the asphaltene deposit has been removed due to the
increased fluid permeability of the formation.
[0052] The mixture of asphaltene solvent and mobilized asphaltenes,
and optionally oil, water, and gas may be drawn from the formation
105 as shown by arrows 123 and produced back up the well 103 to the
injection/production facility 103. The produced mobilized
asphaltenes, optionally together with produced oil, may be
separated from the produced asphaltene solvent, and optionally
produced water and gas, in a separation unit 125. The separation
unit 125 may be comprised of a conventional flash or distillation
column for separating the produced asphaltene solvent from the
produced mobilized asphaltenes, and optionally produced oil and
produced water. The separation unit may also be comprised of a
conventional liquid-gas separator for separating produced gas from
the produced mobilized asphaltenes and produced asphaltene
solvent--and optionally produced oil and produced water, and a
conventional water knockout vessel for separating the produced
mobilized asphaltenes--and optionally produced oil--from produced
water.
[0053] The separated produced asphaltenes, and optionally produced
oil, may be provided from the separation unit 125 of the
injection/production facility 111 to a liquid storage tank 127,
which may be operatively fluidly coupled to the separation unit of
the injection/production facility by conduit 129. The separated
produced gas, if any, may be provided from the separation unit 125
of the injection/production facility 111 to the gas storage tank
119, which may be operatively fluidly coupled to the separation
unit of the injection/production facility by conduit 131. The
separated produced asphaltene solvent may be provided from the
separation unit 125 of the injection/production facility 111 to the
asphaltene solvent storage facility 101 via conduit 133.
[0054] After dissolving at least a portion of the asphaltene
deposit 107 in the formation 105 by introducing the asphaltene
solvent into the formation and contacting the asphaltene solvent
with the asphaltene deposit to mobilize at least a portion of the
asphaltenes therein, oil may be produced from the formation 105
through the portion of the formation previously occupied by the
asphaltene deposit. As noted above, removal of at least a portion
of the asphaltene deposit 107 by contact with the asphaltene
solvent may increase the fluid permeability of the formation 105 at
the location of the former asphaltene deposit. Oil which could not
be produced from the formation 105, or which could be produced only
in limited quantities, due to the asphaltene deposit 107 may be
produced from the formation. Oil recovery and production from the
formation 105 may be effected in accordance with conventional oil
recovery processes and techniques after removal of at least a
portion of the asphaltene deposit with the asphaltene solvent. For
example, after removal of at least a portion of an asphaltene
deposit, oil recovery may be effected by cyclic steam stimulation
or by cyclic injection and recovery of an oil miscible oil recovery
formulation. In one embodiment, the oil miscible oil recovery
formulation may be the asphaltene solvent.
[0055] Referring now to FIG. 3, a system 300 of the present
invention for practicing a method of the present invention is
shown. The system includes a first well 301 and a second well 303
extending into an oil-bearing formation 305, where the first well
is structured and arranged to introduce an asphaltene solvent into
the formation and a second well is structured and arranged to
produce oil from the formation, and, optionally to produce a
mixture of the asphaltene solvent and asphaltenes from the
formation. The oil-bearing formation 305 contains one or more
asphaltene deposits 311 therein. The first well 301 extends into
the formation in position to introduce an asphaltene solvent into
the formation to contact an asphaltene deposit 311 therein, where
the asphaltene deposit may be on a fluid flow path from the first
well.
[0056] An asphaltene solvent comprising at least 75 mol % DMS as
described above is provided and may be stored in an asphaltene
solvent storage facility 315. The asphaltene solvent may be
provided from the asphaltene solvent storage facility 315 to an
injection facility 317 via conduit 319, where the asphaltene
solvent storage facility may be operatively fluidly coupled to the
injection facility.
[0057] The injection facility 317 may be operatively fluidly
coupled to the first well 301. The asphaltene solvent may flow from
the injection facility 317 through the first well 301 to be
introduced into the formation 305. The injection facility 317 may
include a mechanism such as a pump 321 for introducing the
asphaltene solvent into the formation through the first well 301.
Alternatively, the asphaltene solvent may flow from the asphaltene
solvent storage facility 315 directly to the first well 301 for
injection into the formation 305, where the first well comprises a
mechanism such as a pump for introducing the asphaltene solvent
into the formation.
[0058] As shown by the down arrow in the first well 301, the
asphaltene solvent may flow through the first well to be introduced
into the formation 305 in position to contact the asphaltene
deposit 311. The first well 301 may be a conventional well for
introducing or injecting a fluid into an oil-bearing formation
wherein the first well may contain conduits, tubes, or strings
therein to conduct the asphaltene solvent to a position from which
the solvent may be introduced into the formation to contact an
asphaltene deposit 311. The first well 301 may have perforations in
the wellbore at a location through which the solvent may be
introduced into the formation to contact an asphaltene deposit. The
asphaltene solvent may be introduced into the formation 305 by
injecting the asphaltene solvent into the formation through the
first well 301 at pressures as described above.
[0059] The asphaltene deposit 311 may lie along a fluid flow path
from the first well 301, wherein the asphaltene solvent may proceed
along the fluid flow path in the formation as shown by arrows 323
to contact the asphaltene deposit upon being introduced into the
formation. The asphaltene deposit 311 may be a near-wellbore
deposit or the asphaltene deposit may lie a substantial distance
from the first well 301, for example greater than 5 meters, or
greater than 10 meters, or greater than 25 meters, or greater than
50 meters. If the asphaltene deposit 311 lies a substantial
distance from the first well 301, the asphaltene deposit may be a
naturally occurring tar mat. The asphaltene deposit 311 may lie
along a fluid flow path between the first well 301 and the second
well 303. The asphaltene deposit 311 may impede or block fluid flow
along the flow path between the first well 301 and the second well
303.
[0060] The volume of asphaltene solvent introduced into the
formation 305 via the first well 301 may range from 0.001 to 5 pore
volumes, or from 0.01 to 2 pore volumes, or from 0.1 to 1 pore
volumes, or from 0.2 to 0.6 pore volumes, where the term "pore
volume" refers to the volume of the formation that may be swept by
the asphaltene solvent between the first well 301 and the second
well 303. This pore volume may be readily be determined by methods
known to a person skilled in the art, for example by modelling
studies or by injecting water having a tracer contained therein
through the formation 305 from the first well 301 to the second
well 303.
[0061] As the asphaltene solvent is introduced into the formation
305, the solvent spreads into the formation as shown by arrows 323.
Upon introduction to the formation 305 and subsequently reaching an
asphaltene deposit 311, the asphaltene solvent may contact the
asphaltene deposit 311. The asphaltenes of the asphaltene deposit
are very soluble in the asphaltene solvent, where the asphaltenes
may be first contact miscible with the asphaltene solvent. The
asphaltene solvent may solvate and mobilize at least a portion of
the asphaltenes in the asphaltene deposit 311 upon contact with the
asphaltene deposit, forming a mixture of the asphaltene solvent and
mobilized asphaltenes.
[0062] Additional asphaltene solvent or another fluid such as water
or brine or an oil recovery formulation may be introduced into the
formation through the first well to remove the mixture of the
asphaltene solvent and mobilized asphaltenes from the site of the
asphaltene deposit. The mixture of asphaltene solvent and mobilized
asphaltenes may be pushed through the formation from the former
asphaltene deposit to the second well 303 along the fluid flow path
between the first and second wells 301 and 303 as shown by arrows
329. The mixture of asphaltene solvent and mobilized asphaltenes
may then be produced from the formation through the second
well.
[0063] Mobilization and removal of asphaltenes from the site of the
asphaltene deposit 311 may increase the permeability of the
formation for fluid flow at the location of the former asphaltene
deposit. The fluid permeability of the formation at the location of
the former asphaltene deposit may be increased by at least 0.001
Darcy, or at least 0.01 Darcy, or at least 0.1 Darcy, or at least
0.5 Darcy by mobilization and removal of asphaltenes from the
asphaltene deposit with the asphaltene solvent. Fluid flow along
the fluid flow path between the first well 301 and the second well
303 may be improved by increasing the fluid permeability of the
formation 305 at the location of the former asphaltene deposit.
[0064] The mixture of the asphaltene solvent and mobilized
asphaltenes may be pushed across the formation 305 from the first
well 301 to the second well 303 by introduction of an oil
immiscible formulation into the formation subsequent to
introduction of the asphaltene solvent into the formation. The oil
immiscible formulation may be introduced into the formation 305
through the first well 301 after completion of introduction of the
asphaltene solvent into the formation to force or otherwise
displace the mixture of the asphaltene solvent and mobilized
asphaltenes from the asphaltene deposit, preferably toward the
second well 303.
[0065] The oil immiscible formulation may be configured to displace
the mixture of asphaltene solvent and mobilized asphaltenes through
the formation 305. Suitable oil immiscible formulations are not
first contact miscible or multiple contact miscible with the
asphaltene solvent or a mixture of the asphaltene solvent and
asphaltenes or oil in the formation. The oil immiscible formulation
may be water, brine, or an aqueous polymer fluid. Suitable polymers
for use in an aqueous polymer fluid may include, but are not
limited to, polyacrylamides, partially hydrolyzed polyacrylamides,
polyacrylates, ethylenic copolymers, biopolymers,
carboxymethylcellulose, polyvinyl alcohols, polystyrene sulfonates,
polyvinylpyrolidones, AMPS (2-acrylamide-2-methyl propane
sulfonate), combinations thereof, or the like. Examples of
ethylenic copolymers include copolymers of acrylic acid and
acrylamide, acrylic acid and lauryl acrylate, lauryl acrylate and
acrylamide. Examples of biopolymers include xanthan gum, guar gum,
alginic acids, and alginate salts.
[0066] The oil immiscible formulation may be stored in, and
provided for introduction into the formation 305 from, an oil
immiscible formulation storage facility 325 that may be operatively
fluidly coupled to the injection facility 317 via conduit 327. The
injection facility 317 may be operatively fluidly coupled to the
first well 301 to provide the oil immiscible formulation to the
first well for introduction into the formation 305. Alternatively,
the oil immiscible formulation storage facility 325 may be
operatively fluidly coupled to the first well 301 directly to
provide the oil immiscible formulation to the first well for
introduction into the formation 305. The injection facility 317 and
the first well 301, or the first well itself, may comprise a
mechanism for introducing the oil immiscible formulation into the
formation 305 via the first well 301. The mechanism for introducing
the oil immiscible formulation into the formation 305 via the first
well 301 may be comprised of a pump or a compressor for delivering
the oil immiscible formulation to perforations or openings in the
first well through which the oil immiscible formulation may be
injected into the formation. The mechanism for introducing the oil
immiscible formulation into the formation 305 via the first well
301 may be the pump 321 utilized to inject the asphaltene solvent
into the formation via the first well 301, where the oil immiscible
formulation may be introduced into the formation by injecting the
oil immiscible formulation into the formation at pressures of from
the instantaneous pressure of the formation up to, but not
including, the fracture pressure of the formation.
[0067] An oil recovery formulation may be introduced into the
formation through the first well 301 at pressures of from the
instantaneous pressure of the formation up to, but not including,
the fracture pressure of the formation 305 following introduction
of the asphaltene solvent into the formation, or simultaneously
with the introduction of the asphaltene solvent into the formation,
or after injection of the oil immiscible formulation into the
formation to enhance recovery of oil from the formation through the
second well 303. The oil recovery formulation may proceed through
the formation along the fluid flow path as shown by arrows 323 and
329 mobilizing oil in the formation for production from the
formation through the second well 303. The oil recovery formulation
and the mobilized oil may flow through the site of the former
asphaltene deposit 311 in the formation due to the improved
permeability of the formation resulting from dissolution of the
asphaltene deposit into the asphaltene solvent. The oil recovery
formulation and mobilized oil may be produced from the formation
through the second well 303. The oil recovery formulation may be a
formulation utilized to improve or enhance recovery of oil from an
oil-bearing formation including water, brine, low salinity water
having a total dissolved solids content of from 500 parts per
million ("ppm") to 10000 ppm and a total ionic strength of at most
0.15M, conventional alkali-surfactant-polymer enhanced oil recovery
formulations, dimethyl ether, carbon disulfide, or dimethyl
sulfide.
[0068] The oil recovery formulation may be stored in, and provided
for introduction into the formation 305 from, an oil recovery
formulation storage facility 326 that may be operatively fluidly
coupled to the injection facility 317 via conduit 328. The
injection facility 317 may be operatively fluidly coupled to the
first well 301 to provide the oil recovery formulation to the first
well for introduction into the formation 305. Alternatively, the
oil recovery formulation storage facility 326 may be operatively
fluidly coupled to the first well 301 directly to provide the oil
recovery formulation to the first well for introduction into the
formation 305. The injection facility 317 and the first well 301,
or the first well itself, may comprise a mechanism for introducing
the oil recovery formulation into the formation 305 via the first
well 301. The mechanism for introducing the oil recovery
formulation into the formation 305 via the first well 301 may be
comprised of a pump or a compressor for delivering the oil recovery
formulation to perforations or openings in the first well through
which the oil recovery formulation may be injected into the
formation. The mechanism for introducing the oil recovery
formulation into the formation 305 via the first well 301 may be
the pump 321 utilized to inject the asphaltene solvent into the
formation via the first well 301.
[0069] The mixture of asphaltene solvent and mobilized asphaltenes
and optionally oil, water, and gas may be recovered and produced
from the formation 305 through the second well 303. The system may
include a mechanism for producing the mixture of asphaltene solvent
and mobilized asphaltenes from the formation 305 subsequent to
introduction of the asphaltene solvent into the formation, for
example, after completion of introduction of the asphaltene solvent
into the formation and arrival of the mixture of asphaltene solvent
and mobilized asphaltenes at the second well 303, after the
introduction of the oil immiscible formulation into the formation,
or after the introduction of the oil recovery formulation into the
formation and arrival of mobilized oil and the oil recovery
formulation at the second well. The mechanism for recovering and
producing the mixture of asphaltene solvent and mobilized
asphaltenes, and optionally oil, water, and/or gas may be comprised
of a pump 333, which may be located in a production facility 331
and/or within the second well 303, and which draws the mixture of
asphaltene solvent and mobilized asphaltenes from the formation,
and optionally oil, water, and/or gas, to deliver the mixture of
asphaltene solvent and mobilized asphaltenes, and optionally oil,
water, and/or gas to the production facility 331.
[0070] Alternatively, the mechanism for recovering and producing
the mixture of asphaltene solvent and mobilized asphaltenes from
the formation 305 through the second well 303 may be comprised of a
compressor 334. The compressor 334 may be operatively fluidly
coupled to a gas storage tank 341 by conduit 353, and may compress
gas from the gas storage tank for injection into the formation 305
through the second well 303. The compressor 334 may compress gas
from a gas storage tank for injection into the formation 305
through the second well 303. The compressor may compress the gas to
a pressure sufficient to drive production of the mixture of
asphaltene solvent and mobilized asphaltenes from the formation via
the second well 303, where the appropriate pressure can be
determined by conventional methods known to those skilled in the
art. The compressed gas may be injected into the formation from a
different position on the second well 303 than the position in the
second well at which the mixture of asphaltene solvent and
mobilized asphaltenes are produced from the formation.
[0071] Oil, and optionally water, the oil recovery formulation,
and/or gas, also may be mobilized and recovered from the formation
305 while recovering and producing the mixture of asphaltene
solvent and mobilized asphaltenes from the formation. Oil may be
recovered and produced from the formation 305, in part, through the
portion of the formation from which at least a part of the
asphaltene deposit 311 has been removed due to the increased fluid
permeability of the formation. The oil, in part, may be oil
mobilized by the oil recovery formulation. Oil, and optionally
water, the oil recovery formulation, and/or gas may be continue to
be recovered from the formation 305 after recovery of the mixture
of the asphaltene solvent and asphaltenes is complete as a result
of ongoing oil recovery from the formation once the blockage caused
by asphaltene deposit 311 has been remediated by contact with the
asphaltene solvent.
[0072] The mixture of asphaltene solvent and mobilized asphaltenes,
oil, and optionally oil recovery formulation, water, and/or gas may
be produced up the second well 303 to the production facility 331.
The produced mobilized asphaltenes, together with produced oil, may
be separated from the produced asphaltene solvent, and optionally
produced oil recovery formulation, produced water, and/or produced
gas, in a separation unit 335 in the production facility 331. The
separation unit may be comprised of a conventional flash or
distillation column for separating the produced asphaltene solvent
and, optionally the produced oil recovery formulation, from the
produced mobilized asphaltenes and produced oil, and optionally
from the produced water and/or produced gas. The separation unit
335 may also be comprised of a conventional liquid-gas separator
for separating produced gas from the produced mobilized
asphaltenes, produced oil, and produced asphaltene solvent, and
optionally produced water and/or produced oil recovery formulation,
and a conventional water knockout vessel for separating the
produced mobilized asphaltenes and produced oil from produced
water.
[0073] The separated produced asphaltenes and produced oil may be
provided from the separation unit 335 of the production facility
331 to an oil storage tank 337, which may be operatively fluidly
coupled to the separation unit of the production facility by
conduit 339. The separated produced gas, if any, may be provided
from the separation unit 335 of the production facility 331 to the
gas storage tank 341, which may be operatively fluidly coupled to
the separation unit of the injection/production facility by conduit
343. The separated produced oil recovery formulation, if any, may
be provided from the separation unit 335 of the production facility
331 to the oil recovery formulation storage facility 326, which may
be operatively fluidly coupled to the separation unit of the
production facility 331 by conduit 366. The separated produced
asphaltene solvent may be provided from the separation unit 335 of
the production facility 331 to the asphaltene solvent storage
facility 315 via conduit 349.
To facilitate a better understanding of the present invention, the
following examples of certain aspects of some embodiments are
given. In no way should the following examples be read to limit, or
define, the scope of the invention.
Example 1
[0074] The quality of dimethyl sulfide as an asphaltene solvent
based on the miscibility of dimethyl sulfide with a crude oil
relative to other compounds was evaluated. The miscibility of
dimethyl sulfide, ethyl acetate, o-xylene, carbon disulfide,
chloroform, dichloromethane, tetrahydrofuran, and pentane solvents
with mined oil sands was measured by extracting the oil sands with
the solvents at 10.degree. C. and at 30.degree. C. to determine the
fraction of hydrocarbons extracted from the oil sands by the
solvents. The bitumen content of the mined oil sands was measured
at 11 wt. % as an average of bitumen extraction yield values for
solvents known to effectively extract substantially all of bitumen
from oil sands--in particular chloroform, dichloromethane,
o-xylene, tetrahydrofuran, and carbon disulfide. One oil sands
sample per solvent per extraction temperature was prepared for
extraction, where the solvents used for extraction of the oil sands
samples were dimethyl sulfide, ethyl acetate, o-xylene, carbon
disulfide, chloroform, dichloromethane, tetrahydrofuran, and
pentane. Each oil sands sample was weighed and placed in a
cellulose extraction thimble that was placed on a porous
polyethylene support disk in a jacketed glass cylinder with a drip
rate control valve. Each oil sands sample was then extracted with a
selected solvent at a selected temperature (10.degree. C. or
30.degree. C.) in a cyclic contact and drain experiment, where the
contact time ranged from 15 to 60 minutes. Fresh contacting solvent
was applied and the cyclic extraction repeated until the fluid
drained from the apparatus became pale brown in color.
[0075] The extracted fluids were stripped of solvent using a rotary
evaporator and thereafter vacuum dried to remove residual solvent.
The recovered bitumen samples all had residual solvent present in
the range of from 3 wt. % to 7 wt. %. The residual solids and
extraction thimble were air dried, weighed, and then vacuum dried.
Essentially no weight loss was observed upon vacuum drying the
residual solids, indicating that the solids did not retain either
extraction solvent or easily mobilized water. Collectively, the
weight of the solid sample and thimble recovered after extraction
plus the quantity of bitumen recovered after extraction divided by
the weight of the initial oil sands sample plus the thimble provide
the mass closure for the extractions. The calculated percent mass
closure of the samples was slightly high because the recovered
bitumen values were not corrected for the 3 wt. % to 7 wt. %
residual solvent. The extraction experiment results are summarized
in Table 1.
TABLE-US-00001 TABLE 1 Summary of Extraction Experiments of
Bituminous Oil Sands with Various Fluids Input Output Experimental
Solids Solids Weight Recovered Weight Extraction Fluid Temperature,
C. weight, g weight, g Change, g Bitumen, g Closure, % Carbon
Disulfide 30 151.1 134.74 16.4 16.43 100.0 Carbon Disulfide 10
151.4 134.62 16.8 16.62 99.9 Chloroform 30 153.7 134.3 19.4 18.62
99.5 Chloroform 10 156.2 137.5 18.7 17.85 99.5 Dichloromethane 30
155.8 138.18 17.7 16.30 99.1 Dichloromethane 10 155.2 136.33 18.9
17.66 99.2 o-Xylene 30 156.1 136.58 19.5 17.37 98.6 o-Xylene 10
154.0 136.66 17.3 17.36 100.0 Tetrahydrofuran 30 154.7 136.73 18.0
17.67 99.8 Tetrahydrofuran 10 154.7 136.98 17.7 16.72 99.4 Ethyl
Acetate 30 153.5 135.81 17.7 11.46 96.0 Ethyl Acetate 10 155.7
144.51 11.2 10.32 99.4 Pentane 30 154.0 139.11 14.9 13.49 99.1
Pentane 10 152.7 138.65 14.1 13.03 99.3 Dimethyl Sulfide 30 154.2
137.52 16.7 16.29 99.7 Dimethyl Sulfide 10 151.7 134.77 16.9 16.55
99.7
[0076] FIG. 4 provides a graph plotting the weight percent yield of
extracted bitumen as a function of the extraction fluid at
30.degree. C. applied with a correction factor for residual
extraction fluid in the recovered bitumen, and FIG. 5 provides a
similar graph for extraction at 10.degree. C. without a correction
factor. FIGS. 4 and 5 and Table 1 show that dimethyl sulfide is
comparable for recovering bitumen from an oil sand material with
the best known fluids for recovering bitumen from an oil sand
material--o-xylene, chloroform, carbon disulfide, dichloromethane,
and tetrahydrofuran--and is significantly better than pentane and
ethyl acetate.
[0077] The bitumen samples extracted at 30.degree. C. from each oil
sands sample were evaluated by SARA analysis to determine the
saturates, aromatics, resins, and asphaltenes composition of the
bitumen samples extracted by each solvent. The results are shown in
Table 2.
TABLE-US-00002 TABLE 2 SARA Analysis of Extracted Bitumen Samples
as a Function of Extraction Fluid Oil Composition Normalized Weight
Percent Extraction Fluid Saturates Aromatics Resins Asphaltenes
Ethyl Acetate 21.30 53.72 22.92 2.05 Pentane 22.74 54.16 22.74 0.36
Dichloromethane 15.79 44.77 24.98 14.45 Dimethyl Sulfide 15.49
47.07 24.25 13.19 Carbon Bisulfide 18.77 41.89 25.49 13.85 o-Xylene
17.37 46.39 22.28 13.96 Tetrahydrofuran 16.11 45.24 24.38 14.27
Chloroform 15.64 43.56 25.94 14.86
[0078] The SARA analysis showed that pentane and ethyl acetate were
much less effective for extraction of asphaltenes from oil sands
than are the known highly effective asphaltene extraction fluids
dichloromethane, carbon disulfide, o-xylene, tetrahydrofuran, and
chloroform. The SARA analysis also showed that dimethyl sulfide has
excellent miscibility properties for even the most difficult
hydrocarbons-asphaltenes.
[0079] The data showed that dimethyl sulfide is generally as good
as the recognized very good asphaltene extraction fluids for
removal of asphaltenes from oil sands. The data also show that DMS
is highly compatible with all classes of crude oil
hydrocarbons--saturates, aromatics, resins, and asphaltenes, and,
therefore, is unlikely to induce phase instability in crude oil
upon introduction into an oil-bearing formation.
Example 2
[0080] Two experiments were conducted on a naturally occurring tar
mat material recovered from an oil-bearing formation to compare the
rate of dissolution of the tar mat material using dimethyl sulfide
and A150, a commercially available solvent comprised of a mixture
of aromatic hydrocarbons that is commonly used to dissolve tar
mats. A naturally occurring tar mat material recovered from an
oil-bearing formation at a depth of 4690 meters and at a formation
temperature of 50.degree. C. was utilized as the tar mat material
for the comparison.
[0081] In the first experiment, two samples of DMS solvent and two
samples of A150 solvent were individually mixed with the tar mat
material at ambient temperature and pressure, where the volume (ml)
to weight (g) ratio of each solvent sample to the tar mat material
was approximately 100:1. The length of time required to entirely
dissolve the tar mat material was measured and recorded. Table 3
below shows the results.
TABLE-US-00003 TABLE 3 Time Required for Dissolution of Tar Mat
Material Weight of Tar Mat Volume of Time Until Sample Material
Solvent Dissolution # Solvent (g) (ml) (h) 1 A150 1.07 100 Between
8.00 and 22.00 (overnight) 2 A150 1.07 100 Between 8:00 and 22:00
(overnight) 1 DMS 1.07 100 4:00 2 DMS 1.07 100 4:00
[0082] In the second experiment, four samples of DMS solvent and
four samples of A150 solvent were individually mixed with the tar
mat material at ambient temperature and pressure, where the volume
(ml) to weight (g) ratio of each solvent sample to the tar mat
material was approximately 10:1. The length of time required to
entirely dissolve the tar mat material was measured and recorded.
Table 4 below shows the results.
TABLE-US-00004 TABLE 4 Time Required for Dissolution of Tar Mat
Material Weight of Tar Mat Volume of Time Until Sample Material
Solvent Dissolution # Solvent (g) (ml) (h) 1 A150 1.02 10 Between
8.00 and 22.00 (overnight) 2 A150 1.00 10 Between 8:00 and 22:00
(overnight) 3 A150 1.02 10 Between 8:00 and 22:00 (overnight) 4
A150 1.02 10 Between 8:00 and 22:00 (overnight) 1 DMS 1.00 10 5:48
2 DMS 1.01 10 5:01 3 DMS 1.00 10 5:03 4 DMS 0.99 10 7:28
[0083] As shown by the results of each of the experiments, DMS
dissolved the naturally occurring tar mat material at a higher rate
than A150. In particular, DMS dissolved the naturally occurring tar
mat material at a rate that was not less than 1.4 times faster than
the A150 solvent. This data shows that DMS is an effective solvent
for dissolving tar mat materials, and that DMS dissolves tar mat
materials faster than A150, a commercially utilized solvent for
dissolving tar mat materials.
[0084] The present invention is well adapted to attain the ends and
advantages mentioned as well as those that are inherent therein.
The particular embodiments disclosed above are illustrative only,
as the present invention may be modified and practiced in different
but equivalent manners apparent to those skilled in the art having
the benefit of the teachings herein. Furthermore, no limitations
are intended to the details of construction or design herein shown,
other than as described in the claims below. While systems and
methods are described in terms of "comprising," "containing," or
"including" various components or steps, the compositions and
methods can also "consist essentially of" or "consist of" the
various components and steps. Whenever a numerical range with a
lower limit and an upper limit is disclosed, any number and any
included range falling within the range is specifically disclosed.
In particular, every range of values (of the form, "from a to b,"
or, equivalently, "from a-b") disclosed herein is to be understood
to set forth every number and range encompassed within the broader
range of values. Whenever a numerical range having a specific lower
limit only, a specific upper limit only, or a specific upper limit
and a specific lower limit is disclosed, the range also includes
any numerical value "about" the specified lower limit and/or the
specified upper limit. Also, the terms in the claims have their
plain, ordinary meaning unless otherwise explicitly and clearly
defined by the patentee. Moreover, the indefinite articles "a" or
"an", as used in the claims, are defined herein to mean one or more
than one of the element that it introduces.
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