Note: Descriptions are shown in the official language in which they were submitted.
CA 02861858 2014-06-26
METHOD OF PRODUCING OIL
[0001]
The present disclosure relates to enhanced oil recovery methods and, in
particular, injecting a combination of solvent and polymer floods to increase
hydrocarbon
production from oil bearing underground rock formations.
BACKGROUND
[0002]
Enhanced Oil Recovery (EOR) is used to increase oil recovery in
hydrocarbon-bearing rock formations worldwide. There are basically three main
types of
EOR methods: thermal, chemical/polymer, and gas injection, each of which may
be used
worldwide to increase oil recovery from a reservoir beyond what would
otherwise be possible
with conventional hydrocarbon extraction means. These methods may also extend
the life of
the reservoir or otherwise boost its overall oil recovery factor.
[0003] Briefly,
thermal EOR works by adding heat to a hydrocarbon-bearing
reservoir. The most widely practiced form of thermal EOR uses steam which
serves to
reduce the viscosity of the oil so that the oil is able to freely flow to
adjacent producing wells.
Chemical EOR, on the other hand, entails flooding the reservoir with a
chemical agent or
-
solvent designed to reduce the capillary forces that trap residual oil, and
thereby increase
20.
hydrocarbon recovery. Polymer EOR entails flooding the hydrocarbon-bearing
reservoir with
a polymer which improves the sweep efficiency of injected water. Gas
injection, also known
as miscible injection, works somewhat similar to chemical EOR. By injecting a
fluid that is
miscible with the oil, trapped residual oil can be more easily recovered.
[0004]
One of the advantages to chemical EOR is the miscibility of the solvents
used with the oil phase. Theoretically, in a 1D displacement a recovery
efficiency of 100%
can be achieved using chemical EOR. In practice, however, the
recovery/displacement
efficiency of chemical EOR using a solvent is limited by flow front
instabilities, such as
viscous fingering and gravity effects. Viscous fingering occurs when the low-
viscosity solvent
tends to "finger" through the more viscous oil in the reservoir. Once this
finger reaches the
producer well, very little of the bypassed oil is ultimately displaced.
Gravity effects on the
solvent and mobilized oil often result in a gravity over-run or a gravity
under-run reservoir.
SUMMARY OF THE INVENTION
[0005]
The present disclosure relates to enhanced oil recovery methods and, in
particular, injecting a combination of solvent and polymer floods to increase
hydrocarbon
production from oil bearing underground rock formations.
1
CA 02861858 2014-06-26
TSLWO 2013/101599
PCT/US2012/070669
[0006]
In one aspect of the present disclosure, a method for producing oil from an
underground formation is disclosed. The method may include injecting or
otherwise placing a
solvent slug into the underground formation for a first time period from a
first well. The
solvent slug may be configured to solubilize the oil and generate a mixture of
mobilized oil.
In one or more embodiments, the solvent slug has a density that is less than
90% or at least
110% of a density of the oil. The method may further include injecting or
otherwise placing
an aqueous polymer slug into the underground formation for a second time from
the first well.
The polymer slug may have a viscosity greater than the solvent slug. In some
embodiments,
the viscosity of the polymer slug may be at least 5 centipoise. The polymer
slug may be
configured to generate an interface between the polymer slug and the mixture
of mobilized
oil. The mixture of mobilized oil and the solvent slug may be forced towards a
second well by
using the injected aqueous polymer slug, and oil and/or gas may subsequently
be produced
from the second well.
[0007]
In another aspect of the present disclosure, another method for producing
oil from an underground formation is disclosed. The method may include
injecting a carbon
disulfide slug into the underground formation for a first time period from a
first well, and
solubilizing the oil with the carbon disulfide slug, thereby generating a
mixture of mobilized
oil. The method may also include injecting an aqueous polymer slug into the
underground
formation for a second time from the first well. The aqueous polymer slug may
be injected
into the formation in a pore volume that is at least 1.5 times more than a
pore volume
injection of the solvent slug. Moreover, the aqueous polymer slug may have a
viscosity that
ranges between 5 centipoise and 50 centipoise. The method may further include
creating a
hydrodynamic force between the carbon disulfide slug and the aqueous polymer
slug,
impelling the carbon disulfide slug and the mixture of mobilized oil across
the formation using
the hydrodynamic force, and producing oil from a second well in fluid
communication with the
first well.
[0008]
The features and advantages of the present invention will be readily
apparent to those skilled in the art upon a reading of the description of the
preferred
embodiments that follows.
BRIEF DESCRIPTION OF THE DRAWINGS
[0009]
The following figures are included to illustrate certain aspects of the
present invention, and should not be viewed as exclusive embodiments. The
subject matter
disclosed is capable of considerable modifications, alterations, combinations,
and equivalents
in form and function, as will occur to those skilled in the art and having the
benefit of this
disclosure.
2
CA 02861858 2014-06-26
TSLWO 2013/101599
PCT/US2012/070669
[0010]
Figure 1 illustrates a system for producing hydrocarbons from an
underground reservoir, according to one or more embodiments.
[0011]
Figure 2a illustrates a well pattern, according to one or more
embodiments.
[0012] Figure
2b illustrates the well pattern of Figure 2a during an exemplary
enhanced oil recovery process, according to one or more embodiments.
[0013]
Figure 3 illustrates another system for producing hydrocarbons from an
underground reservoir, according to one or more embodiments.
[0014]
Figure 4 illustrates an enlarged view of an underground formation during
an exemplary enhanced oil recovery process, according to one or more
embodiments.
[0015]
Figure 4a is a graph indicating viscosity reduction in oil when interacting
with various solvents and solvent/polymer mixtures.
[0016]
Figure 5 illustrates an exemplary method timeline of injection and
production using an exemplary enhanced oil recovery process, according to one
or more
embodiments.
DETAILED DESCRIPTION
[0017]
The present disclosure relates to enhanced oil recovery methods and, in
particular, injecting a combination of solvent and polymer floods to increase
hydrocarbon
production from oil bearing underground rock formations.
[0018] The present invention provides improved methods of extracting
hydrocarbons from underground reservoirs using miscible solvents and
immiscible polymer
floods. At least one of the advantages of the disclosure is the increased
displacement
stability of the miscible solvent and the mobilized oil. Viscous fingering and
gravity effects,
such as gravity over-run or a gravity under-run reservoirs, are substantially
minimized. As a
result, the miscible solvent is more efficiently or otherwise effectively used
in enhanced oil
recovery processes. This improves not only the recovery efficiency of the
reservoir, but also
the effective utilization of both the solvents and the polymers.
[0019]
Referring to Figure 1, illustrated is a system 100 used to produce
hydrocarbons (e.g., oil and/or gas) from an underground hydrocarbon-bearing
formation,
such as an oil reservoir. Specifically, the system 100 may be configured to
extract
hydrocarbons from a first underground formation 102, a second underground
formation 104,
a third underground formation 106, and/or a fourth underground formation 108.
As
illustrated, a production facility 110 is generally provided at the surface
and a well 112
extends from the surface and through the first and second formations 102, 104,
ultimately
terminating within the third formation 106. The third formation 106 may
include one or more
3
CA 02861858 2014-06-26
TSLWO 2013/101599
PCT/US2012/070669
adjacent formation portions 114 from which hydrocarbons or other fluids may be
removed
and transported to the production facility 110 via the well 112. Gases and
liquids are
separated from each other at the production facility 110, and the extracted
gas is stored in a
gas storage 116 while the extracted liquid is stored in a liquid storage 118.
[0020]
Referring to Figure 2a, illustrated is a plan view of an exemplary array 200
of wells, according to one or more embodiments. In some embodiments, each of
the wells
depicted in the array 200 and described below may be substantially similar to
the completion
well 112 described above with reference to Figure 1. As illustrated, the array
200 includes a
first well group 202 (denoted by horizontal cross-hatching) and a second well
group 204
(denoted by diagonal cross-hatching). In some embodiments, the array of wells
200 may
include a total of between about 10 wells and about 1000 wells. For example,
the array of
wells 200 may include between about 5 wells and about 500 wells from the first
well group
202, and between about 5 wells and about 500 wells from the second well group
204.
[0021]
Each well in the first well group 202 may be arranged a first lateral
distance 230 and a second lateral distance 232 from any adjacent well in the
first well group
202. The first and second lateral distances 230, 232 may be generally
orthogonal to each
other. Likewise, each well in the second well group 204 may be arranged a
first lateral
distance 236 and a second lateral distance 238 from any adjacent well in the
second well
group 204, where the first and second lateral distances 236, 238 may also be
generally
orthogonal to each other. Moreover, each well in the first well group 202 may
be a third
distance 234 from any adjacent wells in the second well group 204. As a
result, each well in
the second well group 204 is also the third distance 234 from any adjacent
wells in the first
well group 202.
[0022]
In some embodiments, each well in the first well group 202 may be
surrounded by four individual wells belonging to the second well group 204.
Likewise, each
well in the second well group 204 may be surrounded by four individual wells
belonging to the
first well group 202. In some embodiments, the first and second lateral
distances 230, 232
may range from about 5 meters to about 1000 meters, for example, from about 10
meters to
about 500 meters, from about 20 meters to about 250 meters, from about 30
meters to about
200 meters, from about 50 meters to about 150 meters, from about 90 meters to
about 120
meters, or about 100 meters. Similarly, in some embodiments, the first and
second lateral
distances 236, 238 may range from about 5 meters to about 1000 meters, for
example, from
about 10 meters to about 500 meters, from about 20 meters to about 250 meters,
from about
30 meters to about 200 meters, from about 50 meters to about 150 meters, from
about 90
meters to about 120 meters, or about 100 meters. Moreover, the third distance
234 may
4
CA 02861858 2014-06-26
TSLWO 2013/101599
PCT/US2012/070669
range from about 5 meters to about 1000 meters, for example, from about 10
meters to about
500 meters, from about 20 meters to about 250 meters, from about 30 meters to
about 200
meters, from about 50 meters to about 150 meters, from about 90 meters to
about 120
meters, or about 100 meters.
[0023] While
Figure 2a is described above as depicting a top view of the array of
wells 200, where the first and second well groups 202, 204 are vertically-
disposed wells,
Figure 2a may equally and without limitation illustrate a cross-sectional side
view of the array
200, without departing from the scope of the disclosure. For instance, Figure
2a may
alternatively illustrate a cross-sectional side view of the array 200 where
the first and second
well groups 202, 204 are horizontally-disposed wells within a formation.
Accordingly, it will
be appreciated that the systems and methods disclosed herein may equally
function whether
the first and second well groups 202, 204 are vertically or horizontally-
disposed, or
combinations thereof. As used herein, a "vertical" well may refer to a well
that is slanted. In
other embodiments, the array of wells 200 may be indicative of j-shaped wells
or any other
type of well known to those skilled in the art.
[0024]
The recovery of oil and/or gas from an underground formation using the
array of wells 200 may be accomplished by any known method. Suitable methods
include
subsea production, surface production, primary, secondary, or tertiary
production, and the
like. In some embodiments, as described above with reference to Figure 1, oil
and/or gas
may be recovered from a formation 102, 104, 106, 108 into a production well
112, and flow
through the well 112 to a production facility 110 for processing. In other
embodiments,
enhanced oil recovery (EOR) techniques may be used to increase the flow of oil
and/or gas
from the formation(s) 102, 104, 106, 108. As will be described in greater
detail below,
exemplary EOR techniques and methods may include injecting or otherwise
placing a solvent
flood into one or more of the formations 102, 104, 106, 108 to solubilize and
mobilize portions
of the viscous oil found therein. Following the injection of the solvent, an
aqueous polymer
flood may be injected into the formation to force the solubilized oil toward
an adjacent
production well and simultaneously improve the front stability of the solvent
as it traverses the
formation.
[0025] In one
or more embodiments, the solvent may be a miscible enhanced oil
recovery agent that is generally miscible with highly viscous oil and able to
solubilize and
mobilize the oil for faster and more efficient recovery. The miscible enhanced
oil recovery
agent may include, but is not limited to, a carbon disulfide formulation. The
carbon disulfide
formulation may include carbon disulfide and/or carbon disulfide derivatives,
such as
thiocarbonates, xanthates, mixtures thereof, and the like. In other
embodiments, the carbon
5
CA 02861858 2014-06-26
TSLWO 2013/101599
PCT/US2012/070669
disulfide formulation may further include one or more of the following:
hydrogen sulfide,
sulfur, carbon dioxide, hydrocarbons, and mixtures thereof.
Other suitable miscible
enhanced oil recovery agents will have a density that is less than
approximately 0.7g/m1 and
may include, but are not limited to, hydrogen sulfide, carbon dioxide, octane,
pentane, LPG,
02-06 aliphatic hydrocarbons, nitrogen, diesel, mineral spirits, naptha
solvent, asphalt
solvent, kerosene, acetone, xylene, trichloroethane, mixtures of two or more
of the preceding,
or other miscible enhanced oil recovery agents as are known in the art. In
some
embodiments, suitable solvents or miscible enhanced oil recovery agents are
first contact
miscible or multiple contact miscible with oil in the underground formation.
[0026] In one
or more embodiments, the aqueous polymer flood may be
characterized as an immiscible enhanced oil recovery agent configured to help
mobilize the
solvent flood and the solubilized oil through the formation. The immiscible
enhanced oil
recovery agent may further be configured to reduce the mobility of the water
phase in pores
of the formation which, as can be appreciated, may allow the solvent flood to
be more easily
mobilized through the formation. The immiscible enhanced oil recovery agent
includes a
polymer and may include an additional immiscible enhanced oil recovery agent
such as, but
not limited to, a monomer, a surfactant, water in gas or liquid form, carbon
dioxide, nitrogen,
air, mixtures of two or more of the preceding, or other immiscible enhanced
oil recovery
agents as are known in the art. Suitable polymers may include, but are not
limited to,
polyacrylamides, partially hydrolyzed polyacrylamide, polyacrylates, ethylenic
copolymers,
biopolymers, carboxymethylcellulose, polyvinyl alcohol, polystyrene
sulfonates,
polyvinylpyrolidone, 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 and guar gum. In some embodiments, polymers
may be
crosslinked in situ in a formation. In other embodiments, polymers may be
generated in situ
in a formation. In yet other embodiments, suitable polymers include liquid
viscosifiers, such
as Shell Vis 50. Moreover, in some embodiments, suitable immiscible enhanced
oil recovery
agents are not first contact miscible or multiple contact miscible with oil in
the formation.
[0027]
Referring now to Figure 2b, illustrated is the array of wells 200 being
treated using one or more exemplary EOR techniques, according to one or more
embodiments disclosed. In some embodiments, the solvent and/or polymer floods
are
injected into the second well group 204 and result in an injection profile
208. Injected solvent
solubilizes and mobilizes the more viscous oil trapped in the formation such
that it may be
recovered via the first well group 202, as depicted by a resulting oil
recovery profile 206. In
6
CA 02861858 2014-06-26
TSLWO 2013/101599
PCT/US2012/070669
some embodiments, the injected polymer flood may force the solvent and
solubilized/mobilized oil toward the first well group 202 for production.
In alternative
embodiments, plugs of each of the solvent and polymer floods are injected into
the first well
group 202 in alternating stages, and oil is subsequently recovered from the
second well
group 204.
[0028]
In some embodiments, the solvent flood may be continuously injected into
the first well group 202 for a first time period. Following the first time
period, oil and/or gas
may be produced from the second well group 204 for a second time period. In
other
embodiments, following the first time period, the aqueous polymer flood may be
injected into
the first well group 202 for a second time period. Oil and/or gas may be
produced from the
second well group 204 during the first time period, or during the second time
period, or during
both the first and second time periods, or for a third time period including a
period of time
after the first time period and the second time period and may include a
period of time within
the first and/or second time periods. It will be appreciated, however, that
the injection and
production processes may be carried out through either the first or second
well groups 202,
204, without departing from the scope of the disclosure.
[0029]
The first, second, and third time periods may be predetermined lengths of
time which together may be characterized as a complete cycle. In some
embodiments, an
exemplary cycle may span about 12 hours to about 1 year. In other embodiments,
however,
the exemplary cycle may span about 3 days to about 6 months, or between about
5 days to
about 3 months. In one or more embodiments, each consecutive cycle may
increase in time
from the previous cycle. For example, each consecutive cycle may be from about
5% to
about 10% longer than the previous cycle. In at least one embodiment, a
consecutive cycle
may be about 8% longer than the previous cycle.
[0030] In some
embodiments, multiple cycles may be conducted which include
alternating well groups 202, 204 between injecting or placing the solvent and
polymer floods
and producing oil and/or gas from the formation. For example, one well group
may be
injecting and the other well group may be producing for the first time period,
and then they
may be switched for the second time period.
[0031] In some
embodiments, the solvent flood may be injected at the beginning
of a cycle, and the polymer flood or a mixture including one or more
immiscible enhanced oil
recovery agents may be injected at the end of the cycle. In one or more
embodiments, the
beginning of the cycle may be the first 10% to about 80% of a cycle, the first
20% to about
60% of a cycle, or the first 25% to about 40% of a cycle. The end of the cycle
may simply
span the remainder of the cycle.
7
CA 02861858 2014-06-26
TSLWO 2013/101599
PCT/US2012/070669
[0032]
In some embodiments, the oil present in the formation prior to the injection
of any of the enhanced oil recovery agents (i.e., solvents and/or polymers)
may have a
viscosity of at least about 100 centipoise (MPa s), or at least about 500
centipoise (MPa s),
or at least about 1000 centipoise (MPa s), or at least about 2000 centipoise
(MPa s), or at
least about 5000 centipoise (MPa s), or at least about 10,000 centipoise (MPa
s). In other
embodiments, however, the oil present in the formation prior to the injection
of any of the
enhanced oil recovery agents may have a viscosity of up to about 5,000,000
centipoise (MPa
s), or up to about 2,000,000 centipoise (MPa s), or up to about 1,000,000
centipoise (MPa s),
or up to about 500,000 centipoise (MPa s).
[0033]
Injecting or placing the solvent flood into the formation 106 (Figure 1) may
be accomplished by methods known by those skilled in the art. In at least one
embodiment,
the solvent flood is injected into a single conduit in a single well, such as
the well 112 of
Figure 1. The solvent, such as a carbon disulfide formulation, is then allowed
to soak into the
adjacent hydrocarbon-bearing formations and react with the viscous oil. As the
carbon
disulfide reacts with the oil, the oil solubilizes and begins to mobilize.
After the solvent has
soaked for a predetermined amount of time, a mixture of the solvent with the
mobilized oil
may then be either pumped out of the formation 106 through well 112 or flooded
across the
formation 106 to an adjacent production well using the aqueous polymer flood.
[0034]
In one or more embodiments, the solvent may have a density that is less
than 90% of the density of the oil or at least 110% of the density of the oil.
Adding other
agents or surfactants to the solvent may help achieve lower or higher
densities, depending
on what is required for the particular application. For example, one or more
of 002, H2S, C3,
04, and/or 05 hydrocarbons may be added to the solvent to help achieve the
proper density
ratio between the solvent and the oil.
[0035]
Referring now to Figure 3, illustrated is another system 300 used to
produce hydrocarbons (i.e., oil and/or gas) from an underground hydrocarbon-
bearing
formation, such as an oil reservoir. The system 300 may be similar in some
respects to the
system 100 described above with reference to Figure 1. Accordingly, the system
300 may be
best understood with reference to Figure 1, where like numerals are used to
indicated like
components that will not be described again in detail. In one or more
embodiments, the
production facility 110 may further include a production storage tank 302 and
the system 300
may further include a second well 304. Similar to the first well 112, the
second well 304
extends through the first and second formations 102, 104 and ultimately
terminates within the
third formation 106 surrounded by one or more adjacent formation portions 306.
It will be
8
CA 02861858 2014-06-26
TSLWO 2013/101599
PCT/US2012/070669
appreciated that the adjacent formation portions 114 and 306 of each well 112,
302,
respectively, may be optionally fractured and/or perforated to enhance
production.
[0036]
The production storage tank 302 may be configured to store miscible
and/or immiscible enhanced oil recovery agents and/or formulations (i.e.,
solvents and/or
polymers) for injection into the underground formations 102, 104, 106, 108. In
one or more
embodiments, the production storage tank 302 is communicably coupled to the
second well
304 and configured to provide the solvent and/or aqueous polymer thereto for
injection. In
other embodiments, however, the production storage tank 302 may be
communicably
coupled to the first well 112 and configured to provide solvent and/or aqueous
polymer
thereto for injection. In yet other embodiments, the production storage tank
302 may be
communicably coupled to both the first and second wells 112, 302 and
configured to provide
solvent and/or aqueous polymer to both for injection, without departing from
the scope of the
disclosure.
[0037]
In some embodiments the second well 304 may be representative of a well
belonging to the first well group 202, and the first well 112 may be
representative of a well
belonging to the second well group 204, as described above with reference to
Figures 2a and
2b. In other embodiments, however, the second well 304 may be representative
of a well
belonging to the second well group 204, and the first well 112 may be
representative of a well
belonging to the first well group 202. In one or more embodiments, the solvent
formulation
may be pumped down the second well 304 and injected as a slug into the
adjacent formation
portions 306 of the third underground formation 106. Once coming into contact
with the
viscous oil present in the formation 106, the solvent flood solubilizes the
oil and forms a
mixture of the solvent and the oil which exhibits a reduced viscosity as
compared with the oil
prior to solubilization. As a result of the solubilization, the less viscous
mixture becomes
mobilized for easier extraction from the formation 106.
[0038]
In some embodiments, continual pumping of the solvent via the second
well 304 may flow the mixture across the third underground formation 106, as
indicated by
the arrows, and ultimately to the first well 112 to be produced to the
production facility 110.
In other embodiments, however, the solvent flood may be followed by an aqueous
polymer
flood also injected via the second well 304 into the adjacent formation
portions 306 of the
third underground formation 106. The polymer flood may be configured to
improve the
displacement stability of the solvent flood and the mixture of the solvent and
the oil as each
traverses the formation 106.
[0039]
Referring to Figure 4, with continued reference to Figure 3, illustrated is
an
enlarged view of one or more solvent and polymer slugs traversing the third
underground
9
CA 02861858 2014-06-26
TSLWO 2013/101599
PCT/US2012/070669
formation 106, according to one or more embodiments. As illustrated, the
underground
formation 106 may be geologically-bounded on an upper edge 402a and a lower
edge 402b,
thereby being geologically-separated or sealed by the second and fourth
underground
formations 104, 108. While not shown, it will be appreciated that the first
and second wells
112 and 304 may be arranged at either end of the underground formation 106 in
order to
either inject or produce fluids into or out of the formation 106. Flow across
the formation 106
may be in the direction indicated by the arrows. In other embodiments,
however, the flow
may be reversed, without departing from the scope of the disclosure.
[0040]
The formation 106 may consist of an oil bearing layer 404 providing oils
ranging from light oils to heavy oils. As illustrated, a solvent slug 406 may
be injected into
the formation 106 and, once coming into contact with the oil bearing layer
404, may solubilize
a portion 408 of the oil such that the solubilized portion 408 is more easily
mobilized across
the formation 106 for extraction. In some embodiments, the solvent slug 406
may be
pumped into the formation 106 below the fracture pressure of the formation
106, for example
from about 40% to about 90% of the fracture pressure.
[0041]
Following the solvent slug 406, an aqueous polymer slug 410 may be
injected into the formation 106. In one or more embodiments, the polymer used
may exhibit
a higher viscosity than the solvent and is immiscible with the solvent slug
406, and may
exhibit a viscosity on the same order of magnitude as the mixture of solvent
and oil and is
immiscible with the mixture of solvent and oil 408. For example, in one or
more
embodiments, the viscosity of the aqueous polymer slug 410 may range between
about 1
centipoise (MPa s) and about 1000 centipoise (MPa s), or between 5 centipoise
(MPa s) and
100 centipoise (MPa s). As a result, an interface 412 is generated by
interfacial tension
and/or capillary pressure between the solvent slug 406 and the polymer slug
410. The
generated interface 412 may be seen or otherwise measured using CT scan
technology,
pressure drop measurements derived from multiple pressure taps along the span
of the
formation 106, and/or from fluid sampling as the fluids are being produced. In
operation, the
interface 412 may provide a layer of uniform pressure that forces the solvent
plug 406 and
the mixture of solvent and solubilized oil 408 across the third underground
formation 106.
Consequently, a hydrodynamic force impels the solvent slug 406 and the mixture
of solvent
and solubilized oil 408 across the formation 106 with a substantially uniform
front. The
hydrodynamic force is able to actively and/or passively impel the solvent slug
406 and the
mixture of solvent and solubilized oil 408 across the formation 106 depending
on whether the
polymer slug is actively being driven (e.g., through the use of a pump or
other driving
CA 02861858 2014-06-26
TSLWO 2013/101599
PCT/US2012/070669
mechanism) or passively being driven with the built up pressures in the
wellbore and/or
formation 106.
[0042]
As can be appreciated, this may prove advantageous in improving
displacement stability of the solvent plug 406 within the oil bearing layer
404, such that the
solvent plug 406 will be less prone to viscous fingering at the front of the
mixture of solvent
and solubilized oil 408 and/or the oil bearing layer 404. For example, various
solvents, such
as carbon disulfide, are less viscous than the oils encountered in the
underground
formations. As such, these solvents naturally tend to finger at the flow
front. When followed
by a polymer slug 410, however, as described herein, a substantially uniform
pressure is
applied at the interface 412 which forces the solvent plug 406 and the mixture
of solvent and
solubilized oil 408 across the formation 106 in an increasingly uniform
progress such that the
potential for viscous fingering is dramatically reduced.
[0043]
The polymer slug 410 also helps alleviate other front flow instabilities,
such
as gravity effects where the solvent plug 406 may be prone to gravity over-run
or gravity
under-run. For example, as a more dense solvent (e.g., carbon disulfide) mixes
with the
viscous oil, the solvent/oil mixture becomes more dense than the remaining oil
in the
formation 106 and gravity naturally forces the solvent/oil mixture 408 to
lower portions of the
formation 106. Likewise, as a less dense solvent mixes with the viscous oil,
the resulting
solvent/oil mixture becomes less dense than the remaining oil in the formation
106 and
natural buoyant forces will force these solvent/oil mixtures 408 to higher
portions of the
formation 106. As a result, the solvent may be unevenly forced through the
formation 106,
thereby causing gravity over-run and gravity under-run, where an excess of
less dense
solvent may traverse at higher portions of the formation 106 and an excess of
more dense
solvent may traverse at lower portions of the formation 106, while the
intermediate portions
are not efficiently produced. The polymer slug 410, however, sharpens the
displacement of
the oil and facilitates a more uniform movement across the entire front of the
solvent/oil
mixture 408.
[0044]
In some embodiments, the solvent slug 406 may be heated prior to being
injected into the formation 106 to lower the viscosity of fluids in the
formation 106, for
example, the heavy oils, paraffins, asphaltenes, etc. In other embodiments,
the solvent slug
406 may be heated and/or boiled while within the formation 106 to heat and/or
vaporize the
solvent formulation. The solvent slug 406 may be heated either actively or
passively. For
example, the solvent slug 406 may be heated using, for example, a heated fluid
(i.e., steam)
or a heater. In other embodiments, however, the solvent slug 406 may be heated
naturally
via the naturally-occurring heat emanating from the formation 106. In one or
more
11
CA 02861858 2014-06-26
TS4.,
w 0 2013/101599
PCT/US2012/070669
embodiments, a brine flood or chase 414 may be injected into the formation 106
following the
polymer plug 410. The brine chase 414 may be configured to displace the
remaining
mobilized fluids. In at least some embodiments, the chase 414 may be
undertaken using
nitrogen.
[0045] In
other embodiments, the polymer slug 410 may be injected into the
formation 106 prior to the solvent slug 406 in order to pretreat the formation
106. Moreover,
instead of a brine chase 414 following the polymer slug 410, another solvent
slug 406 may be
injected followed by another polymer slug 410, thereby creating an alternating
sequence. In
yet other embodiments, a pore volume of the polymer slug 410 may be at least
1.5 times the
pore volume of the solvent slug 406 injected into the formation 106. "Pore
volume" is defined
as the pore volume of the formation 106, relative to total volume of the
formation. "Pore
volume" may also refer to the swept volume between an injection well and a
production well
and may be readily determined by methods known to those skilled in the art.
Such methods
include modeling studies. However, the pore volume may also be determined by
passing a
high salinity water having a tracer contained therein through the formation
form the injection
well to the production well. The swept volume is the volume swept by the
displacement fluid
averaged over all flow paths between the injection well and production well.
This may be
determined with reference to the first temporal moment of the tracer
distribution in the
produced high salinity water, as would be well known to the person skilled in
the art.
[0046]
Referring to Figure 4a, illustrated is a graph 416 indicating the reduction in
oil viscosity at a reservoir as the oil comes into contact with solvents or
solvent/polymer
combinations. Of note, the graph 416 shows the decreasing viscosity of the oil
as it contacts
carbon disulfide (CS2) by itself, as it contacts a CS2 and polystyrene (PS)
mixture, and as it
contacts a CS2 and Shell Vis 50 mixture. Table 1 below provides the properties
of the CS2/PS
solution at about 23 C, and Table 2 below provides the properties of the
C52/ShellVis 50
solution at about 23 C.
TABLE 1
ozstimr.ttraii,:qi derisIty o witemi)sity
(gleati2)
1.26 0.4 .4: OA
6.9 Ii) +. 0.1
132 4.3
16.2 1,24 7.4
22,4 1,22
TABLE 2
12
CA 02861858 2014-06-26
TS4.,
w 0 2013/101599
PCT/US2012/070669
mixtvant,tion glEmsity f) vis,anky
(glom3) (a)
:0 1:26 OS 0, I
3,4 1 5,1 10,5
5.5 1.25 14õ9 3:1,5
8,3 1.24
[0047]
Referring now to Figure 5, with continued reference to Figures 3 and 4,
illustrated is an exemplary method or pattern 500 of injection and production,
according to
one or more embodiments disclosed. The exemplary pattern 500 may provide an
illustration
of an exemplary injection and production timing for the first well group 202,
as shown by the
top timeline, and an exemplary injection and production timing for the second
well group 204,
as shown by the bottom timeline. As illustrated, injection of solvent slugs is
indicated by a
checkerboard pattern, injection of polymer slugs is indicated by a diagonal
pattern, and the
white areas are indicative of producing oil and/or gas from the formation.
[0048] In some
embodiments, at time 520, a solvent slug is injected into the first
well group 202 for time period 502, while oil and/or gas is produced from the
second well
group 204 for time period 503. A solvent slug may then be injected into the
second well
group 204 for time period 505, while oil and/or gas is produced from the first
well group 202
for time period 504. This injection/production cycling for well groups 202 and
204 may be
continued for any number of cycles, for example from about 5 cycles to about
25 cycles.
[0049]
In some embodiments, at time 530, there may be a cavity in the formation
due to oil and/or gas that has been produced during time 520. During time 530,
only the
leading edge of cavity may be filled with a solvent slug, which is then pushed
through the
formation with a polymer slug. For example, a solvent slug may be injected
into the first well
group 202 for time period 506, then a polymer slug may be injected into the
first well group
202 for time period 508, while oil and/or gas may be produced from the second
well group
204 for time period 507. In one or more embodiments, a solvent slug may then
be injected
into the second well group 204 for time period 509, and then a polymer slug
may be injected
into the second well group 204 for time period 511, while oil and/or gas may
be produced
from the first well group 202 for time period 510. This injection/production
cycling for well
groups 202 and 204 may be continued for any number of cycles, for example from
about 5
cycles to about 25 cycles.
[0050]
In some embodiments, at time 540 there may be a significant hydraulic
communication between the first well group 202 and the second well group 204.
In one or
more embodiments, a solvent slug may be injected into the first well group 202
for time
period 512, then a polymer slug may be injected into the first well group 202
for time period
13
CA 02861858 2014-06-26
TSLWO 2013/101599
PCT/US2012/070669
514 while oil and/or gas may be produced from the second well group 204 for
time period
515. The injection cycling of solvent and polymer slugs into the first well
group 202 while
producing oil and/or gas from the second well group 204 may be continued as
long as
desired, for example as long as oil and/or gas is produced from the second
well group 204.
[0051] In some
embodiments, time periods 502, 503, 504, and/or 505 may be
from about 6 hours to about 10 days, for example, from about 12 hours to about
72 hours, or
from about 24 hours to about 48 hours. In some embodiments, each of time
periods 502,
503, 504, and/or 505 may increase in length from time 520 until time 530. In
other
embodiments, however, each of time periods 502, 503, 504, and/or 505 may
continue
relatively unchanged from time 520 until time 530 for about 5 cycles to about
25 cycles, for
example from about 10 cycles to about 15 cycles.
[0052]
In some embodiments, time period 506 is from about 10% to about 50% of
the combined length of time period 506 and time period 508, for example from
about 20% to
about 40%, or from about 25% to about 33%. In some embodiments, time period
509 is from
about 10% to about 50% of the combined length of time period 509 and time
period 511, for
example from about 20% to about 40%, or from about 25% to about 33%. In some
embodiments, the combined length of time period 506 and time period 508 is
from about 2
days to about 21 days, for example from about 3 days to about 14 days, or from
about 5 days
to about 10 days. In some embodiments, the combined length of time period 509
and time
period 511 is from about 2 days to about 21 days, for example from about 3
days to about 14
days, or from about 5 days to about 10 days. In some embodiments, the combined
length of
time period 512 and time period 514 is from about 2 days to about 21 days, for
example from
about 3 days to about 14 days, or from about 5 days to about 10 days.
[0053]
Referring again to Figure 3, after separating the oil from the solvent and
the polymer, the solvent formulation may then be processed for recycling and
placed back in
the production storage vessel 302. Processing the solvent formulation for
recycling may
include boiling, condensing, filtering, and/or reacting the solvent. Moreover,
the oil and/or
gas produced may be transported to a refinery and/or a treatment facility. The
oil and/or gas
may be processed to produced to produce commercial products such as
transportation fuels
such as gasoline and diesel, heating fuel, lubricants, chemicals, and/or
polymers. Processing
may include distilling and/or fractionally distilling the oil and/or gas to
produce one or more
distillate fractions. In some embodiments, the oil and/or gas, and/or the one
or more distillate
fractions may be subjected to a process of one or more of the following:
catalytic cracking,
hydrocracking, hydrotreating, coking, thermal cracking, distilling, reforming,
polymerization,
isomerization, alkylation, blending, and dewaxing.
14
CA 02861858 2014-06-26
TSLWO 2013/101599
PCT/US2012/070669
[0054]
Therefore, 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
15 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 about a to about b," or, equivalently, "from approximately a to
b," or, equivalently,
"from approximately a-b") disclosed herein is to be understood to set forth
every number and
range encompassed within the broader range of values. Also, the terms in the
claims have
20 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. If there is any
conflict in the usages
of a word or term in this specification and one or more patent or other
documents that may be
incorporated herein by reference, the definitions that are consistent with
this specification
25 should be adopted.
