Note: Descriptions are shown in the official language in which they were submitted.
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ATTORNEY DOCKET NO.: 0004159.751010 (SA51010 PCT)
PCT PATENT APPLICATION
OIL RECOVERY PROCESS USING AN OIL RECOVERY COMPOSITION OF
AQUEOUS SALT SOLUTION AND DILUTE POLYMER FOR CARBONATE
RESERVOIRS
INVENTORS: Subhash Chandrabose Ayirala
Ali Abdallah Al-Yousef
Abdulkareem M. Al-Sofi
CROSS-REFERENCE TO RELATED PATENT APPLICATIONS
[0001] This
application is a continuation-in-part of and claims priority from U.S. Non-
Provisional Application No. 15/903,952, filed February 23, 2018, and titled
"OIL RECOVERY
PROCESS USING AN OIL RECOVERY COMPOSITION OF AQUEOUS SALT
SOLUTION AND DILUTE POLYMER FOR CARBONATE RESERVOIRS," which is a
divisional of and claims priority from U.S. Non-Provisional Application No.
15/358,435, filed
November 22, 2016, and titled "OIL RECOVERY PROCESS USING AN OIL RECOVERY
COMPOSITION OF AQUEOUS SALT SOLUTION AND DILUTE POLYMER FOR
CARBONATE RESERVOIRS," which claims priority from U.S. Provisional Application
No.
62/280,446, filed January 19, 2016, and titled "OIL RECOVERY PROCESS USING AN
OIL
RECOVERY COMPOSITION OF SMART WATER AND DILUTE POLYMER FOR
CARBONATE RESERVOIRS," each of which are incorporated by reference in their
entirety
for purposes of United States patent practice.
BACKGROUND
Field of the Disclosure
[0002]
Embodiments of the disclosure generally relate to formation treatment fluids
and,
more specifically, to enhanced oil recovery fluids.
Description of the Related Art
[0003] The use
of enhanced oil recovery (EOR) processes has greatly benefited the oil and
gas industry by increasing the production of problematic and underperforming
hydrocarbon
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bearing wells and fields. The EOR processes used in modern oil and gas
operations may
include chemical, hydrochemical, thermal, fluid/superfluid and microbial based
processes as
well as the relatively recent plasma-pulse technology (PPT). Water injection
(alternatively
referred to as water flooding) has been widely used to increase the
conductivity or flow of
liquid hydrocarbons in subterranean reservoir treated using EOR techniques.
The water source
may be derived from freshwater, (for example, aquifers or surface water) as
well as
saltwater/brackish sources (for example, river/sea water mixtures).
SUMMARY
[0004] The use
of water flooding processes known as "smart water flooding" or simply
"smart flooding" may be used for EOR operations in carbonate reservoirs. Such
water flooding
processes involve an ion-based (that is, salt-based) modification to an
injectable water fraction.
In addition, such water flooding processes may be generally regarded as
environmentally safe.
Further such water flooding may improve microscopic sweep efficiency and
release more oil
from reservoir pores. However, such water flooding may be mobility constrained
due to
insufficient injection water viscosities, resulting in poor sweep efficiencies
at the reservoir
scale.
[0005]
Embodiments of the disclosure generally relate to an oil recovery composition
of an
aqueous solution of one or more salts with a salinity of about 4,000 parts-per-
million (ppm) to
about 8,000 ppm, a dilute polymer, metal oxide nanoparticles, and dissolved
carbon dioxide
(CO2) for improved oil recovery from a hydrocarbon containing carbonate
reservoir formation.
In one embodiment, an oil recovery composition is provided having an aqueous
solution of one
or more salts and having a salinity of 4,000 ppm to 8,000 ppm, a polymer
having a
concentration in the range of 250 ppm to less than 500 ppm, a plurality of
metal oxide
nanoparticles having a concentration in the range of 0.5 weight (wt) % to 0.1
wt %, and
dissolved carbon dioxide (CO2) in the aqueous solution. The one or more salts
may include at
least one of sodium chloride (NaCl), calcium chloride (CaCl2), magnesium
chloride (MgCl2),
sodium sulfate (Na2SO4) and magnesium sulfate (MgSO4). The aqueous solution
may include
at least 400 ppm sulfate ions and 300 ppm or less divalent cations including
calcium,
magnesium, or a combination thereof In some embodiments, the oil recovery
composition
consists of the aqueous solution of one or more salts having a salinity of
about 4,000 ppm to
about 8,000 ppm, the polymer having a concentration of in the range of 250 ppm
to less than
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500 ppm, a plurality of metal oxide nanoparticles having a concentration in
the range of 0.5
weight (wt) % to 0.1 wt %, and dissolved carbon dioxide in the aqueous
solution.
[0006] In some
embodiments, the aqueous solution of the oil recovery composition includes
one or more ions of at least one of sodium, calcium, magnesium, sulfate, and
chloride. In some
embodiments, the polymer of the oil recovery composition is a copolymer of
acrylamide and
acrylamido tertiary butyl sulfonate (ATBS).
[0007] In
another embodiment, a method for enhancing oil recovery in a hydrocarbon
containing carbonate reservoir formation is provided. The method includes
injecting a slug of
an oil recovery composition into the reservoir formation. The oil recovery
composition includes
an aqueous solution of one or more salts and having a salinity of about 4,000
ppm to about
8,000 ppm, a polymer having a concentration in the range of 250 ppm to less
than 500 ppm, a
plurality of metal oxide nanoparticles having a concentration in the range of
0.5 weight (wt) %
to 0.1 wt %, and dissolved carbon dioxide (CO2) in the aqueous solution. The
one or more salts
of the aqueous solution include at least one of sodium chloride (NaCl),
calcium chloride
(CaCl2), magnesium chloride (MgCl2), sodium sulfate (Na2SO4) and magnesium
sulfate
(MgSO4). The aqueous solution may include at least 400 ppm sulfate ions and
300 ppm or less
divalent cations including calcium, magnesium, or a combination thereof The
method further
includes injecting a second solution into the carbonate reservoir formation
after injecting the
slug of the oil recovery composition. In some embodiments, the oil recovery
composition
consists of the aqueous solution of one or more salts having a salinity of
about 4,000 ppm to
about 8,000 ppm, the polymer having a concentration of in the range of 250 ppm
to less than
500 ppm, a plurality of metal oxide nanoparticles having a concentration in
the range of 0.5
weight (wt) % to 0.1 wt %, and dissolved carbon dioxide in the aqueous
solution. In some
embodiments, the metal oxide nanoparticles include silicon dioxide, aluminum
oxide, or a
combination thereof
[0008] In some
embodiments, the method includes recovering displaced hydrocarbon from
the carbonate reservoir formation. In some embodiments, the aqueous solution
includes one or
more ions, the one or more ions including at least one of sodium, calcium,
magnesium, sulfate,
and chloride. In some embodiments, the slug of the oil recovery composition
has a pore volume
(PV) of at least 0.3 of the carbonate reservoir to be treated. In some
embodiments, the second
solution includes seawater. In some embodiments, the second solution includes
the aqueous
solution. In some embodiments, the aqueous solution is a first aqueous
solution, the one or
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more salts are first one or more salts, and the second solution includes a
second aqueous
solution of one or more second salts suitable for enhancing oil recovery. In
some embodiments,
the polymer of the oil recovery composition includes a copolymer of acrylamide
and
acrylamido tertiary butyl sulfonate (ATBS). In some embodiments, injecting a
second solution
into the carbonate reservoir formation includes continuously injecting the
second solution at
an injection rate. In some embodiments, the carbonate reservoir formation has
an in situ oil
viscosity of less than 3 centipoise.
BRIEF DESCRIPTION OF THE DRAWINGS
[0009] These
and other features, aspects, and advantages of the present disclosure will
become better understood with regard to the following descriptions, claims,
and accompanying
drawings. It is to be noted, however, that the drawings illustrate only
several embodiments of
the disclosure and are therefore not to be considered limiting of the
disclosure's scope as it can
admit to other equally effective embodiments.
[0010] FIG. 1
is a schematic illustrating improved oil recovery from carbonate reservoirs
using an oil recovery composition in accordance with an embodiment of the
disclosure;
[0011] FIG. 2
is a plot of a ratio of aqueous salt solution viscosity over seawater
viscosity
vs polymer concentration in ppm for a first example aqueous salt solution in
accordance with
an embodiment of the disclosure;
[0012] FIG. 3
is a plot of a ratio of aqueous salt solution viscosity over seawater
viscosity
vs polymer concentration in ppm for a second example aqueous salt solution in
accordance
with an embodiment of the disclosure;
[0013] FIGS. 4-
6 are flowcharts of processes for enhancing oil recovery from carbonate
reservoirs using an oil recovery composition of an aqueous salt solution of
one or more salts
and dilute polymer in accordance with embodiments of the disclosure; and
[0014] FIGS. 7-
9 are flowcharts of processes for enhancing oil recovery from carbonate
reservoirs using an oil recovery composition of an aqueous salt solution of
one or more salts,
dilute polymer, metal oxide nanoparticles, and dissolved CO2 in accordance
with embodiments
of the disclosure.
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DETAILED DESCRIPTION
[0015] The
present disclosure will now be described more fully with reference to the
accompanying drawings, which illustrate embodiments of the disclosure. This
disclosure may,
however, be embodied in many different forms and should not be construed as
limited to the
illustrated embodiments set forth in the disclosure. Rather, these embodiments
are provided so
that this disclosure will be thorough and complete, and will fully convey the
scope of the
disclosure to those skilled in the art.
[0016] As used
in the disclosure, the term "smart water" refers to an aqueous solution of
one or more salts suitable for enhancing oil recovery in carbonate reservoirs
having a salinity
in the range of about 4,000 parts-per-million (ppm) total dissolved solids
(TDS) to about 8,000
ppm TDS (for example, about 5,000 ppm TDS to about 6,000 ppm TDS), such that
the aqueous
solution includes a concentration of one or more of the following ions
suitable for enhancing
oil recovery: sodium, calcium, magnesium, sulfate, and chloride ions. For
example, a an
aqueous solution may include one or more of the following salts suitable for
enhancing oil
recovery: sodium chloride (NaCl), calcium chloride (CaCl2), magnesium chloride
(MgCl2),
sodium sulfate (Na2SO4) and magnesium sulfate (MgSO4).
[0017] As used
in the disclosure, "in situ" refers to an event or occurrence within a
hydrocarbon reservoir including but not limited to methodologies, techniques
and chemical
reactions for enhancing hydrocarbon recovery from carbonate reservoirs. As
used in the
disclosure, the term "ppm" refers to parts-per-million by mass unless
otherwise indicated.
[0018] As shown
in FIG. 1, embodiments of the disclosure include an oil recovery
composition formed from an aqueous solution of one or more salts with a
salinity of about
4,000 ppm to about 8,000 ppm (for example, about 5,000 ppm to about 6,000 ppm)
and dilute
polymer that has improved oil recovery performance (Recovery > X) over the oil
recovery
obtained using only the an aqueous solution of one or more salts (Recovery =
X). The polymer
concentrations in the oil recovery composition provide an increase in
viscosity of the aqueous
solution and thus provide mobility control and improve the macroscopic sweep
efficiency at
reservoir scale. These improvements add to the microscopic sweep efficiency
obtained from
the aqueous solution alone to significantly boost the oil recovery performance
in carbonate
reservoirs. Additionally, the lower salinities and specific ions (for example,
sulfates) in the
aqueous solution also increase the viscosifying characteristics of enhanced
oil recovery
polymers used. Accordingly, relatively greater viscosities can be achieved
with such oil
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recovery compositions using the aqueous solutions described in the disclosure
when compared
to seawater used in typical water floods. Consequently, a greater oil recovery
may be obtained
as compared to conventional flooding compositions, resulting in improved
economics (that is,
lower cost) for oil recovery in carbonate reservoirs.
[0019] For example, in some embodiments an oil recovery composition may
include an
aqueous solution of one or more salts having a salinity of about 4,000 ppm TDS
to about 8,000
ppm TDS (for example, about 5,000 ppm TDS to about 6,000 ppm TDS) and an
anionic oil
recovery polymer having a polymer concentration of about 250 ppm to about 500
ppm. In some
embodiments, the oil recovery composition also includes metal oxide
nanoparticles in an
amount up to 0.1 weight (wt) %. In some embodiments, the oil recovery
composition also
includes dissolved carbon dioxide (CO2). In some embodiments, the one or more
salts may
include at least one of: sodium chloride (NaCl), calcium chloride (CaCl2),
magnesium chloride
(MgCl2), sodium sulfate (Na2SO4) and magnesium sulfate (MgSO4). In some
embodiments,
the aqueous solution of one or more salts may include at least one or more of
the following
ions: sodium, calcium, magnesium, or sulfates. In some embodiments, the
polymer may be a
copolymer of acrylamide and acrylamido tertiary butyl sulfonate (ATBS).
[0020]
Embodiments of the disclosure also include processes for enhancing oil
recovery in
carbonate reservoirs using an oil recovery composition of an aqueous solution
of one or more
salts with a salinity of about 4,000 ppm TDS to about 8,000 ppm TDS (for
example, about
5,000 ppm TDS to about 6,000 ppm TDS) and dilute polymer. In some embodiments,
the oil
recovery composition also includes metal oxide nanoparticles in an amount up
to 0.1 weight
(wt) %. In some embodiments, the oil recovery composition also includes
dissolved carbon
dioxide (CO2). In some embodiments, a process for enhancing oil recovery may
include
injecting a small slug of an oil recovery composition of an aqueous solution
of one or more
salts with a salinity of about 4,000 ppm TDS to about 8,000 ppm TDS (for
example, about
5,000 ppm TDS to about 6,000 ppm TDS), dilute polymer, metal oxide
nanoparticles, and
dissolved CO2 having a pore volume (PV) of at least about 0.3 into a reservoir
formation,
followed by continuously injecting an aqueous solution of one or more salts
having a salinity
of about 4,000 ppm TDS to about 8,000 ppm TDS (for example, about 5,000 ppm
TDS to about
6,000 ppm TDS) into the reservoir formation. In some embodiments, a process
for enhancing
oil recovery may include injecting a slug of an aqueous solution of one or
more salts with a
salinity of about 4,000 ppm TDS to about 8,000 ppm TDS (for example, about
5,000 ppm TDS
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to about 6,000 ppm TDS) and having a PV in the range of about 0.3 to about 0.5
of the reservoir
formation, followed by injecting a slug of an oil recovery composition of the
aqueous solution,
a dilute polymer, metal oxide nanoparticles, and dissolved carbon dioxide
(CO2) having a PV
of at least about 0.3 of the reservoir formation. After injecting the slug of
the oil recovery
composition, the process may include continuously injecting another aqueous
solution of one
or more salts or seawater into the reservoir formation or alternating from the
former to the
latter, and vice-versa.
[0021] The
following examples are included to demonstrate embodiments of the disclosure.
It should be appreciated by those of skill in the art that the techniques and
compositions
disclosed in the example which follows represents techniques and compositions
discovered by
the inventors to function well in the practice of the disclosure, and thus can
be considered to
constitute preferred modes for its practice. However, those of skill in the
art should, in light of
the present disclosure, appreciate that many changes can be made in the
specific embodiments
which are disclosed and still obtain a like or a similar result without
departing from the spirit
and scope of the disclosure.
[0022] In one
non-limiting example, an oil recovery composition was formed using a first
aqueous solution ("Aqueous Salt Solution 1") having a salinity of about 5761
ppm total
dissolved solids (TDS) and having ion concentrations of 1,824 ppm sodium, 65
ppm calcium,
211 ppm magnesium, 429 ppm sulfates and 3,220 ppm chloride ions. In a second
non-limiting
example, an oil recovery composition was formed using a second aqueous
solution ("Aqueous
Salt Solution 2") having a salinity of about 5761 ppm TDS with an ion
concentration of 1,865
ppm sodium and 3,896 ppm sulfates. Thus, Aqueous Salt Solution 1 includes
calcium,
magnesium, and sulfate ions and Aqueous Salt Solution 2 only includes
sulfates. As explained
further in the disclosure, the presence of ions such as calcium, magnesium,
and sulfates may
initiate interactions at the pore scale to further enhance oil recovery in a
carbonate reservoir.
[0023] In one
non-limiting example, a commercially available copolymer of acrylamide
(AM) and acrylamido tertiary butyl sulfonate (ATBS, Flopaam AN-125
manufactured by SNF
Floerger of Andrezieux, France(referred to as "AN-125" polymer), was added to
each example
aqueous solution in concentrations of 250 ppm, 500 ppm, and 750 ppm, and the
viscosities of
the modified aqueous solutions were measured at three different temperatures
of 25 C, 40 C,
and 60 C and at a shear rate of 6.81 5ec-1. The measured viscosities of the
modified aqueous
solutions were compared to seawater (seawater having a salinity of about
57,610 ppm)
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viscosities at the same polymer concentration and temperature. The viscosities
of Aqueous Salt
Solution 1 and Aqueous Salt Solution 2 and their comparison with seawater
viscosities at
polymer concentrations of 0 ppm, 250 ppm, 500 ppm, and 750 ppm, and at the
three different
temperatures are shown in Tables 1-3. The percentage change summarized in
these Tables
indicate a percentage increase in the viscosities of the tested aqueous
solutions when compared
to seawater viscosity at the same polymer concentration:
Composition 0 ppm 250 % 500 % 750 % Average
ppm Change ppm Change ppm Change
Seawater 1.04 1.4 0.0 2.6 0.0 3.6 0.0 0.0
Aqueous 0.96 1.9 35.7 3.4 30.8 4.2 16.7 27.7
Salt
Solution 1
Aqueous 0.96 2.5 78.6 4.3 65.4 4.7 30.6 58.2
Salt
Solution 2
Table 1: Seawater and Aqueous Solution Viscosities with Dilute Polymer at 25 C
Composition 0 ppm 250 % 500 % 750 % Average
ppm Change ppm Change ppm Change
Seawater 0.88 1.1 0.0 2.1 0.0 2.9 0.0 0.0
Aqueous 0.81 1.2 9.1 2.7 28.6 3.2 10.3 16.0
Salt
Solution 1
Aqueous 0.81 1.9 72.7 3.3 57.1 3.7 27.6 52.5
Salt
Solution 2
Table 2: Seawater and Aqueous Solution Viscosities with Dilute Polymer at 40 C
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Composition 0 ppm 250 500 750 Average
ppm Change ppm Change ppm Change
Seawater 0.67 0.8 0.0 1.4 0.0 2.0 0.0 0.0
Aqueous 0.62 0.9 12.5 20.0 42.9 2.4 20.0 25.1
Salt
Solution 1
Aqueous 0.62 1.8 125.0 2.6 85.7 2.8 40.0 83.6
Salt
Solution 2
Table 3: Seawater and Aqueous Solution Viscosities with Dilute Polymer at 60 C
[0024] FIG. 2
depicts a plot 200 illustrating the viscosity improvements of Aqueous Salt
Solution 1 as compared to seawater at the various polymer concentrations of
250 ppm, 500
ppm, 750 ppm. As shown in FIG. 2, the Y-axis 202 corresponds to the ratio of
tested aqueous
solution viscosity over seawater viscosity, and the X-axis 204 corresponds to
the polymer
concentration in ppm. FIG. 2 depicts data points corresponding to a polymer
concentration of
250 ppm, data points corresponding to a polymer concentration of 500 ppm, and
data points
corresponding to polymer concentrations of 750 ppm at the three different
temperatures of
25 C, 40 C and 60 C (as indicated by the legend 206).
[0025]
Similarly, FIG. 3 depicts a plot 300 illustrating the viscosity improvements
of
Aqueous Salt Solution 2 as compared to seawater at the various polymer
concentrations of 250
ppm, 500 ppm, 750 ppm. As shown in FIG. 3, the Y-axis 302 corresponds to the
ratio of tested
aqueous solution viscosity over seawater viscosity, and the X-axis 304
corresponds to the
polymer concentration in ppm. As shown in the legend 306, FIG. 3 depicts data
points
corresponding to a polymer concentration of 250 ppm, data points corresponding
to a polymer
concentration of 500 ppm, and data points corresponding to polymer
concentrations of 750
ppm at the three different temperatures of 25 C, 40 C and 60 C.
[0026] As shown
in Tables 1-3 and as illustrated in FIGS. 2 and 3, both tested aqueous
solutions developed about 1.5 to 2.0 times greater viscosities with a 250 ppm
polymer
concentration and 3 to 4 times greater viscosities with 500 ppm polymer
concentrations when
compared to seawater alone. Moreover, the incremental viscosities observed in
both tested
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aqueous solutions at the various polymer concentrations were about 25 to 50%
greater than
seawater having the various polymer concentrations.
[0027]
Additionally, as shown in Tables 1-3, the incremental viscosities of Aqueous
Salt
Solution 2 were about 2 to 3 times greater than Aqueous Salt Solution 1 likely
due to the
reduced interaction of sodium ion with the AN-125 polymer due to the increased
concentration
of sulfates in Aqueous Salt Solution 2. Thus, as shown supra, the addition of
polymer to tested
aqueous solutions in dilute concentrations results in viscosities suitable for
enhanced oil
recovery and provides improved polymer viscosifying characteristics due to
favorable
interactions of both low salinity and specific ions such as sulfates present
in the tested aqueous
solutions.
[0028] In some
embodiments, the oil recovery composition of an aqueous solution of one
or more salts with a salinity of about 4,000 ppm to about 8,000 ppm (for
example, 5,000 ppm
to about 6,000 ppm) and dilute polymer may be suitable for light oil recovery
with in situ
reservoir oil viscosities of less than 10 cP. In some embodiments, the oil
recovery composition
of an aqueous solution of one or more salts with a salinity of about 4,000 ppm
to about 8,000
ppm (for example, 5,000 ppm to about 6,000 ppm) and dilute polymer may be
suitable for light
oil recovery with in situ reservoir oil viscosities of less than 3 cP.
[0029]
Embodiments of the disclosure may include oil recovery compositions that
include
an aqueous solution of one or more salts with a salinity of about 4,000 ppm to
about 8,000 ppm
(for example, 5,000 ppm to about 6,000 ppm). In some embodiments, an aqueous
solution may
include one or more salts that include but are not limited to sodium chloride
(NaCl), calcium
chloride (CaCl2), magnesium chloride (MgCl2), sodium sulfate (Na2SO4) and
magnesium
sulfate (MgSO4). Embodiments of the disclosure may include aqueous solutions
having a
concentration of one or more ions that include but are not limited to sulfate
ions, calcium ions,
magnesium ions, and chloride ions. In some embodiments, an aqueous solution in
the oil
recovery composition may include dilute seawater (that is, seawater diluted to
achieve a salinity
of about 4,000 ppm to about 8,000 ppm). In some embodiments, the dilute
seawater may
include the addition of one or more salts (for example, at least one of sodium
chloride (NaCl),
calcium chloride (CaCl2), magnesium chloride (MgCl2), sodium sulfate (Na2SO4)
and
magnesium sulfate (MgSO4)). In some embodiments, an aqueous solution of one or
more salts
in the improved oil recovery composition with dilute polymer may have a
salinity of about
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4,000 ppm to about 8,000 ppm and may include about 400 ppm or greater sulfates
and about
300 ppm or less of calcium and magnesium together.
[0030]
Embodiments of the disclosure may include oil recovery compositions that
include
suitable anionic enhanced oil recovery polymers diluted to polymer
concentrations of less than
or equal to 500 ppm when combined with an aqueous solution of one or more
salts to form the
oil recovery compositions. These polymers may include but are not limited to
polyacrylamides
and copolymers of acrylamide. Such polymers may include but are not limited to
partially
hydrolyzed polyacrylamides (HPAM), copolymers of ATBS and acrylamide. In some
embodiments, such polymers may be selected from the Flopaam AN series of
polymers
manufactured by SNF Floerger of Andrezieux, France.
[0031]
Embodiments of the disclosure may include an oil recovery composition that
includes an aqueous solution of one or more salts according to the criteria
described in the
disclosure and a polymer diluted to a concentration of less than or equal to
500 ppm. For
example, embodiments of the disclosure may include an oil recovery composition
that includes
an aqueous solution of one or more salts according to the criteria described
in the disclosure
and a polymer diluted to a concentration of about 250 ppm to about 500 ppm,
about 250 ppm
to about 400 ppm, about 250 ppm to about 300 ppm. In some embodiments, as
described infra,
an oil recovery composition of an aqueous solution of one or more salts having
a salinity of
about 4,000 ppm to about 8,000 ppm (for example, 5,000 ppm to about 6,000 ppm)
and dilute
polymer may be used in combination with another aqueous solution of one or
more salts,
seawater, and other oil recovery compositions of an aqueous solution of one or
more salts and
dilute polymer.
[0032] In some
embodiments, the oil recovery composition described in the disclosure may
include metal oxide nanoparticles (that is particles having at least one
dimension (for example
diameter or length) in the range of 1 nanometer to 100 nanometers). In some
embodiments, the
metal oxide nanoparticles may include silicon dioxide (5i02), aluminum oxide
(A1203) or both.
In some embodiments, the oil recovery composition may include metal oxide
nanoparticles
having a concentration of up to 0.1 wt %. For example, the oil recovery
composition may
include metal oxide nanoparticles having a concentration of about 0.02 wt %,
0.05 wt % or
less, 0.06 wt % or less, 0.07 wt % or less, 0.08 wt % or less, 0.09 wt % or
less, or 0.1 wt % or
less. According, in some embodiments, an oil recovery composition may include
an aqueous
solution of one or more salts having a salinity of about 4,000 ppm TDS to
about 8,000 ppm
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TDS (for example, about 5,000 ppm TDS to about 6,000 ppm TDS) according to the
criteria
described in the disclosure, a polymer diluted to a concentration of about 250
ppm to about 500
ppm, about 250 ppm to about 400 ppm, or about 250 ppm to about 300 ppm, and
metal oxide
nanoparticles having a concentration of about 0.02 wt %, 0.05 wt % or less,
0.06 wt % or less,
0.07 wt % or less, 0.08 wt % or less, 0.09 wt % or less, or 0.1 wt % or less.
[0033] In some
embodiments, the oil recovery composition described in the disclosure may
include dissolved carbon dioxide (CO2) that compliments the dilute polymer. In
such
embodiments, the dissolved CO2 may be embedded in the oil recovery composition
using
known techniques before injecting or otherwise introducing the oil recovery
composition into
the carbonate reservoir formation. In such embodiments, an oil recovery
composition may
include an aqueous solution of one or more salts having a salinity of about
4,000 ppm to about
8,000 ppm (for example, 5,000 ppm to about 6,000 ppm) according to the
criteria described in
the disclosure, a polymer diluted to a concentration of about 250 ppm to about
500 ppm, about
250 ppm to about 400 ppm, or about 250 ppm to about 300 ppm, and dissolved
CO2. As will
be appreciated, the solubility of the CO2 in the oil recovery composition is
dependent on the
salinity of the aqueous solution of the oil recovery composition. In some
embodiments, the
CO2 may be dissolved in the aqueous solution of the oil recovery composition
until saturation.
[0034] With the
foregoing in mind, the oil recovery composition of an aqueous solution of
one or more salts having a salinity of about 4,000 ppm to about 8,000 ppm (for
example, 5,000
ppm to about 6,000 ppm) and dilute polymer may be used to enhance oil recovery
from
carbonate reservoirs using the example injection sequences illustrated in
FIGS. 4-6 and
described infra. In such embodiments, the injection of the oil recovery
composition of an
aqueous solution of one or more salts having a salinity of about 4,000 ppm to
about 8,000 ppm
(for example, 5,000 ppm to about 6,000 ppm) and dilute polymer into a
hydrocarbon containing
carbonate reservoir formation according to the processes described infra
results in increased
hydrocarbon production from the reservoir formation.
[0035] FIG. 4
depicts a process 400 for enhancing oil recovery using an oil recovery
composition of an aqueous solution of one or more salts having a salinity of
about 4,000 ppm
to about 8,000 ppm (for example, 5,000 ppm to about 6,000 ppm) and dilute
polymer in
accordance with an embodiment of the disclosure. As shown in FIG. 4, in some
embodiments,
a slug of an oil recovery composition of an aqueous solution of one or more
salts having a
salinity of about 4,000 ppm to about 8,000 ppm (for example, 5,000 ppm to
about 6,000 ppm)
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and dilute polymer may be injected or otherwise introduced into the carbonate
reservoir
formation (block 402). As described supra, the oil recovery composition may
include an
aqueous solution of one or more salts having a salinity of about 4,000 ppm to
about 8,000 ppm
(for example, 5,000 ppm to about 6,000 ppm) and a polymer having a
concentration of less
than or equal to 500 ppm. In some embodiments, the slug of an aqueous solution
of one or
more salts having a salinity of about 4,000 ppm to about 8,000 ppm (for
example, 5,000 ppm
to about 6,000 ppm) and dilute polymer may have a PV of at least 0.3 of the
reservoir to be
treated. Following the injection of the slug of the oil recovery composition,
an aqueous solution
of one or more salts having a salinity of about 4,000 ppm to about 8,000 ppm
(for example,
5,000 ppm to about 6,000 ppm) may be continuously injected into the carbonate
reservoir
formation (block 404). The aqueous solution of one or more salts having a
salinity of about
4,000 ppm to about 8,000 ppm (for example, 5,000 ppm to about 6,000
ppm)continuously
injected into the reservoir may be the same aqueous solution in the oil
recovery composition
or may be a different aqueous solution. Finally, displaced oil may be
recovered from the
carbonate reservoir formation (block 406).
[0036] FIG. 5
depicts a process 500 for enhancing oil recovery from a carbonate reservoir
formation using an oil recovery composition of an aqueous solution of one or
more salts having
a salinity of about 4,000 ppm to about 8,000 ppm (for example, 5,000 ppm to
about 6,000 ppm)
and dilute polymer in accordance with another embodiment of the disclosure. As
shown in FIG.
5, in some embodiments, a slug of an aqueous solution of one or more salts
having a salinity
of about 4,000 ppm to about 8,000 ppm (for example, 5,000 ppm to about 6,000
ppm) may be
injected into the carbonate reservoir (block 502). Next, a slug of an oil
recovery composition
of an aqueous solution of one or more salts and dilute polymer may be injected
into the
carbonate reservoir (block 504). As described supra, the oil recovery
composition may include
an aqueous solution of one or more salts having a salinity of about 4,000 ppm
to about 8,000
ppm (for example, 5,000 ppm to about 6,000 ppm) and a polymer having a
concentration of
less than or equal to 500 ppm. In some embodiments, the slug of oil recovery
composition may
have a PV in the range of about 0.3 to about 0.5 of the reservoir to be
treated. Following the
injection of the slug of aqueous solution of one or more salts and the slug of
oil recovery
composition, an aqueous solution of one or more salts having a salinity of
about 4,000 ppm to
about 8,000 ppm (for example, 5,000 ppm to about 6,000 ppm) may be
continuously injected
into the carbonate reservoir (block 506). Finally, displaced oil may be
recovered from the
carbonate reservoir formation (block 508).
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100371 FIG. 6
depicts a process 600 for enhancing oil recovery from a carbonate reservoir
formation using an oil recovery composition of an aqueous solution of one or
more salts having
a salinity of about 4,000 ppm to about 8,000 ppm (for example, 5,000 ppm to
about 6,000 ppm)
and dilute polymer in accordance with another embodiment of the disclosure. As
shown in FIG.
6, in some embodiments, a slug of an aqueous solution of one or more salts
having a salinity
of about 4,000 ppm to about 8,000 ppm (for example, 5,000 ppm to about 6,000
ppm) may be
injected into the carbonate reservoir (block 602). Next, a slug of an oil
recovery composition
of an aqueous solution of one or more salts having a salinity of about 4,000
ppm to about 8,000
ppm (for example, 5,000 ppm to about 6,000 ppm) and dilute polymer may be
injected into the
carbonate reservoir (block 604). As described supra, the oil recovery
composition may include
an aqueous solution of one or more salts having a salinity of about 4,000 ppm
to about 8,000
ppm (for example, 5,000 ppm to about 6,000 ppm) and a polymer having a
concentration of
less than or equal to 500 ppm. In some embodiments, the slug of the aqueous
solution and
dilute polymer may have a PV in the range of about 0.3 to about 0.5 of the
reservoir to be
treated. Following the injection of the slug of aqueous solution and the slug
of oil recovery
composition, seawater may be continuously injected into the carbonate
reservoir formation
(block 606). Finally, displaced oil may be recovered from the carbonate
reservoir formation
(block 608).
[0038] In some embodiments, an oil recovery composition of an aqueous solution
of one or
more salts having a salinity of about 4,000 ppm to about 8,000 ppm (for
example, 5,000 ppm
to about 6,000 ppm), dilute polymer, metal oxide nanoparticles, and dissolved
CO2 may be
used to enhance oil recovery from carbonate reservoirs using the example
injection sequences
illustrated in FIGS. 7-9 and described infra. In such embodiments, the
injection of the oil
recovery composition of an aqueous solution of one or more salts having a
salinity of about
4,000 ppm to about 8,000 ppm (for example, 5,000 ppm to about 6,000 ppm),
dilute polymer,
metal oxide nanoparticles, and dissolved CO2 into a hydrocarbon containing
carbonate
reservoir formation according to the processes described infra results in
increased hydrocarbon
production from the reservoir formation.
[0039] FIG. 7
depicts a process 700 for enhancing oil recovery using an oil recovery
composition of an aqueous solution of one or more salts having a salinity of
about 4,000 ppm
to about 8,000 ppm (for example, 5,000 ppm to about 6,000 ppm), dilute
polymer, metal oxide
nanoparticles, and dissolved CO2 in accordance with an embodiment of the
disclosure. As
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shown in FIG. 7, in some embodiments, a slug of an oil recovery composition of
an aqueous
solution of one or more salts having a salinity of about 4,000 ppm to about
8,000 ppm (for
example, 5,000 ppm to about 6,000 ppm), dilute polymer, metal oxide
nanoparticles, and
dissolved CO2 may be injected or otherwise introduced into the carbonate
reservoir formation
(block 702). As described supra, the oil recovery composition may include an
aqueous solution
of one or more salts having a salinity of about 4,000 ppm to about 8,000 ppm
(for example,
5,000 ppm to about 6,000 ppm), a polymer having a concentration of greater
than 0 and less
than or equal to 500 ppm, metal oxide nanoparticles in a concentration of
greater than 0 and
less than or equal to 0.1 wt %, and dissolved CO2. In some embodiments, the
process 700 may
include dissolving CO2 in the aqueous solution to form the oil recovery
composition. The CO2
may be at saturation in the oil recovery composition. In some embodiments, the
slug of an
aqueous solution of one or more salts having a salinity of about 4,000 ppm to
about 8,000 ppm
(for example, 5,000 ppm to about 6,000 ppm) and dilute polymer may have a PV
of at least 0.3
of the reservoir to be treated.
[0040]
Following the injection of the slug of the oil recovery composition, an
aqueous
solution of one or more salts having a salinity of about 4,000 ppm to about
8,000 ppm (for
example, 5,000 ppm to about 6,000 ppm) may be continuously injected into the
carbonate
reservoir formation (block 704). The aqueous solution of one or more salts
having a salinity of
about 4,000 ppm to about 8,000 ppm (for example, 5,000 ppm to about 6,000 ppm)
continuously injected into the reservoir may be the same aqueous solution in
the oil recovery
composition or may be a different aqueous solution. Finally, displaced oil may
be recovered
from the carbonate reservoir formation (block 706).
[0041] FIG. 8
depicts a process 800 for enhancing oil recovery from a carbonate reservoir
formation using an oil recovery composition of an aqueous solution of one or
more salts having
a salinity of about 4,000 ppm to about 8,000 ppm (for example, 5,000 ppm to
about 6,000
ppm), dilute polymer, metal oxide nanoparticles, and dissolved CO2 in
accordance with another
embodiment of the disclosure. As shown in FIG. 8, in some embodiments, a slug
of an aqueous
solution of one or more salts having a salinity of about 4,000 ppm to about
8,000 ppm (for
example, 5,000 ppm to about 6,000 ppm) may be injected into the carbonate
reservoir (block
802). Next, a slug of an oil recovery composition of an aqueous solution of
one or more salts,
dilute polymer, metal oxide nanoparticles, and dissolved CO2 may be injected
into the
carbonate reservoir (block 804). As described supra, the oil recovery
composition may include
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an aqueous solution of one or more salts having a salinity of about 4,000 ppm
to about 8,000
ppm (for example, 5,000 ppm to about 6,000 ppm), a polymer having a
concentration of greater
than 0 and less than or equal to 500 ppm, metal oxide nanoparticles in a
concentration of greater
than 0 and less than or equal to 0.1 wt %, and dissolved CO2. In some
embodiments, the process
700 may include dissolving CO2 in the aqueous solution to form the oil
recovery composition.
The CO2 may be at saturation in the oil recovery composition. In some
embodiments, the slug
of oil recovery composition may have a PV in the range of about 0.3 to about
0.5 of the reservoir
to be treated.
[0042]
Following the injection of the slug of aqueous solution of one or more salts
and the
slug of oil recovery composition, an aqueous solution of one or more salts
having a salinity of
about 4,000 ppm to about 8,000 ppm (for example, 5,000 ppm to about 6,000 ppm)
may be
continuously injected into the carbonate reservoir (block 806). Finally,
displaced oil may be
recovered from the carbonate reservoir formation (block 808).
[0043] FIG. 9
depicts a process 900 for enhancing oil recovery from a carbonate reservoir
formation using an oil recovery composition of an aqueous solution of one or
more salts having
a salinity of about 4,000 ppm to about 8,000 ppm (for example, 5,000 ppm to
about 6,000 ppm)
dilute polymer, metal oxide nanoparticles, and dissolved CO2 in accordance
with another
embodiment of the disclosure. As shown in FIG. 9, in some embodiments, a slug
of an aqueous
solution of one or more salts having a salinity of about 4,000 ppm to about
8,000 ppm (for
example, 5,000 ppm to about 6,000 ppm) may be injected into the carbonate
reservoir (block
902). Next, a slug of an oil recovery composition of an aqueous solution of
one or more salts
having a salinity of about 4,000 ppm to about 8,000 ppm (for example, 5,000
ppm to about
6,000 ppm), dilute polymer, metal oxide nanoparticles, and dissolved CO2 may
be injected into
the carbonate reservoir (block 904). As described supra, the oil recovery
composition may
include an aqueous solution of one or more salts having a salinity of about
4,000 ppm to about
8,000 ppm (for example, 5,000 ppm to about 6,000 ppm) a polymer having a
concentration of
greater than 0 and less than or equal to 500 ppm, metal oxide nanoparticles in
a concentration
of greater than 0 and less than or equal to 0.1 wt %, and dissolved CO2.. In
some embodiments,
the slug of the aqueous solution and dilute polymer may have a PV in the range
of about 0.3 to
about 0.5 of the reservoir to be treated. Following the injection of the slug
of aqueous solution
and the slug of oil recovery composition, seawater may be continuously
injected into the
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carbonate reservoir formation (block 906). Finally, displaced oil may be
recovered from the
carbonate reservoir formation (block 908).
[0044] Further
modifications and alternative embodiments of various aspects of the
disclosure will be apparent to those skilled in the art in view of this
description. Accordingly,
this description is to be construed as illustrative only and is for the
purpose of teaching those
skilled in the art the general manner of carrying out the embodiments
described in the
disclosure. It is to be understood that the forms shown and described in the
disclosure are to
be taken as examples of embodiments. Changes may be made in the elements
described in the
disclosure without departing from the spirit and scope of the disclosure as
described in the
following claims. Headings used in the disclosure are for organizational
purposes only and are
not meant to be used to limit the scope of the description.
[0045] Ranges
may be expressed in the disclosure as from about one particular value, to
about another particular value or both. When such a range is expressed, it is
to be understood
that another embodiment is from the one particular value, to the other
particular value, or both,
along with all combinations within said range.
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