U.S. patent application number 13/729596 was filed with the patent office on 2013-07-04 for method for producing oil.
This patent application is currently assigned to SHELL OIL COMPANY. The applicant listed for this patent is SHELL OIL COMPANY. Invention is credited to Steffen BERG, Raul Valdez, Jorge VIAMONTES, Paul Richard WEIDER.
Application Number | 20130168089 13/729596 |
Document ID | / |
Family ID | 48693924 |
Filed Date | 2013-07-04 |
United States Patent
Application |
20130168089 |
Kind Code |
A1 |
BERG; Steffen ; et
al. |
July 4, 2013 |
METHOD FOR PRODUCING OIL
Abstract
The present disclosure relates to enhanced oil recovery methods
including the injection of solvent and polymer floods to increase
hydrocarbon production from oil bearing underground rock
formations. One method includes injecting a solvent slug into the
underground formation for a first time period from a first well.
The solvent slug solubilizes the oil and generates a mixture of
mobilized oil and solvent. An aqueous polymer slug may then be
injected into the underground formation for a second time from the
first well. The polymer slug may have a viscosity greater than the
solvent slug and thereby generates an interface between the solvent
slug and the polymer slug. The solvent slug and the mobilized oil
are then forced towards a second well using a buoyant hydrodynamic
force generated by the aqueous polymer slug. Oil and/or gas may
then be produced from the second well.
Inventors: |
BERG; Steffen; (Rijswijk,
NL) ; Valdez; Raul; (Rijswijk, NL) ;
VIAMONTES; Jorge; (Katy, TX) ; WEIDER; Paul
Richard; (Houston, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
SHELL OIL COMPANY; |
Houston |
TX |
US |
|
|
Assignee: |
SHELL OIL COMPANY
Houston
TX
|
Family ID: |
48693924 |
Appl. No.: |
13/729596 |
Filed: |
December 28, 2012 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61581670 |
Dec 30, 2011 |
|
|
|
Current U.S.
Class: |
166/270.1 |
Current CPC
Class: |
C09K 8/588 20130101;
E21B 43/16 20130101 |
Class at
Publication: |
166/270.1 |
International
Class: |
E21B 43/16 20060101
E21B043/16 |
Claims
1. A method for producing oil from an underground oil-bearing
formation, comprising: placing a solvent slug into the underground
oil-bearing formation for a first time period from a first well,
the solvent slug being configured to solubilize the oil upon
contacting the oil and generate a mixture of mobilized oil, wherein
the solvent slug has a density that is less than 90% or at least
110% of a density of the oil; placing an aqueous polymer slug into
the underground formation for a second time period from the first
well, the polymer slug having a viscosity greater than the mixture
of mobilized oil and at least 5 centipoise; displacing the mixture
of mobilized oil and the solvent slug towards a second well with
the aqueous polymer slug; and producing oil and/or gas from the
second well.
2. The method of claim 1 wherein an interface is generated between
the polymer slug and the mixture of mobilized oil and solvent.
3. The method of claim 1 wherein the solvent slug comprises a
carbon disulfide formulation.
4. The method of claim 1 further comprising placing a brine chase
into the formation following the aqueous polymer slug.
5. The method of claim 1 further comprising repeating the placement
of the solvent slug and the aqueous polymer slug in an alternating
sequence.
6. The method of claim 1 wherein the polymer of the aqueous polymer
slug is selected from the group of polymers consisting of
polyacrylamides, partially hydrolyzed polyacrylamide,
polyacrylates, ethylenic copolymers, biopolymers,
carboxymethylcellulose, polyvinyl alcohol, polystyrene sulfonates,
polyvinylpyrolidone, AMPS (2-acrylamide-2-methyl propane
sulfonate), copolymers of acrylic acid and acrylamide, acrylic acid
and lauryl acrylate, lauryl acrylate and acrylamide, xanthan gum,
and guar gum.
7. The method of claim 1 wherein the aqueous polymer slug is placed
in the formation in a pore volume that is at least 1.5 times more
than a pore volume of the solvent slug placed in the formation
immediately preceding placement of the aqueous polymer slug.
8. The method of claim 1 wherein the polymer slug has a viscosity
greater than the solvent slug.
9. A method for producing oil from an underground oil-bearing
formation, comprising: placing a first carbon disulfide slug into
the underground formation for a first time period from a first
well; contacting at least a portion of the oil with the first
carbon disulfide slug, thereby generating a mixture of mobilized
oil and carbon disulfide; placing an aqueous polymer slug into the
underground formation for a second time from the first well,
wherein a quantity of the aqueous polymer slug is placed in the
formation in a pore volume that is at least 1.5 times more than a
pore volume of the first carbon disulfide slug placed into the
formation, and the aqueous polymer slug has a viscosity ranging
between 5 centipoise (MPa s) and 100 centipoise (MPa s); creating a
hydrodynamic force between the first carbon disulfide slug and the
aqueous polymer slug; impelling the first carbon disulfide slug and
the mixture of mobilized oil and carbon disulfide across the
formation using the hydrodynamic force; and producing oil from a
second well in fluid communication with the first well.
10. The method of claim 9 further comprising placing a second
carbon disulfide slug into the underground formation for a third
time period from the first well.
11. The method of claim 9 further comprising placing a brine chase
into the formation following the aqueous polymer slug.
12. The method of claim 9 further comprising repeating the
placement of the first carbon disulfide slug and the aqueous
polymer slug in an alternating sequence.
13. The method of claim 9 wherein the underground formation
interposes two adjacent underground formations which seal the
underground formation on an upper edge and a lower edge.
14. The method of claim 9 wherein the first carbon disulfide slug
has a density that is at least 110% of a density of the oil.
Description
[0001] The present application claims the benefit of U.S. Patent
Application No. 61/581,670, filed Dec. 30, 2011, the entire
disclosure of which is hereby incorporated by reference.
FIELD OF THE INVENTION
[0002] 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
[0003] 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.
[0004] 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
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.
[0005] 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
[0006] 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.
[0007] 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.
[0008] 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.
[0009] 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
[0010] 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.
[0011] FIG. 1 illustrates a system for producing hydrocarbons from
an underground reservoir, according to one or more embodiments.
[0012] FIG. 2a illustrates a well pattern, according to one or more
embodiments.
[0013] FIG. 2b illustrates the well pattern of FIG. 2a during an
exemplary enhanced oil recovery process, according to one or more
embodiments.
[0014] FIG. 3 illustrates another system for producing hydrocarbons
from an underground reservoir, according to one or more
embodiments.
[0015] FIG. 4 illustrates an enlarged view of an underground
formation during an exemplary enhanced oil recovery process,
according to one or more embodiments.
[0016] FIG. 4a is a graph indicating viscosity reduction in oil
when interacting with various solvents and solvent/polymer
mixtures.
[0017] FIG. 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
[0018] 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.
[0019] 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.
[0020] Referring to FIG. 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
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.
[0021] Referring to FIG. 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 FIG. 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.
[0022] 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.
[0023] 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
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.
[0024] While FIG. 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, FIG. 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,
FIG. 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.
[0025] 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
FIG. 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.
[0026] 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 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 0.7 g/ml and may include, but are not
limited to, hydrogen sulfide, carbon dioxide, octane, pentane, LPG,
C.sub.2-C.sub.6 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.
[0027] 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 ShellVis 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.
[0028] Referring now to FIG. 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 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.
[0029] 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.
[0030] 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.
[0031] 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.
[0032] 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.
[0033] 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).
[0034] Injecting or placing the solvent flood into the formation
106 (FIG. 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 FIG. 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.
[0035] 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 CO.sub.2, H.sub.2S, C.sub.3, C.sub.4, and/or C.sub.5
hydrocarbons may be added to the solvent to help achieve the proper
density ratio between the solvent and the oil.
[0036] Referring now to FIG. 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 FIG. 1. Accordingly,
the system 300 may be best understood with reference to FIG. 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 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.
[0037] 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.
[0038] 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 FIGS.
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.
[0039] 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.
[0040] Referring to FIG. 4, with continued reference to FIG. 3,
illustrated is an enlarged view of one or more solvent and polymer
slugs traversing the third underground 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.
[0041] 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.
[0042] 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 mechanism) or
passively being driven with the built up pressures in the wellbore
and/or formation 106.
[0043] 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.
[0044] 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.
[0045] 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 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.
[0046] 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.
[0047] Referring to FIG. 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 (CS.sub.2) by itself, as it contacts a CS.sub.2
and polystyrene (PS) mixture, and as it contacts a CS.sub.2 and
ShellVis 50 mixture. Table 1 below provides the properties of the
CS.sub.2/PS solution at about 23.degree. C., and Table 2 below
provides the properties of the CS.sub.2/ShellVis 50 solution at
about 23.degree. C.
TABLE-US-00001 TABLE 1 concentration density .rho. viscosity .mu.
wt-% (g/cm.sup.3) (cP) 0 1.26 0.4 .+-. 0.1 6.9 1.26 1.0 .+-. 0.1
13.2 1.25 4.3 .+-. 0.4 16.2 1.24 7.4 .+-. 0.7 22.4 1.22 26.8 .+-.
2.7
TABLE-US-00002 TABLE 2 concentration density .rho. viscosity .mu.
wt-% (g/cm.sup.3) (cP) 0 1.26 0.4 .+-. 0.1 3.4 1.26 5.1 .+-. 0.5
5.5 1.25 14.9 .+-. 1.5 8.3 1.24 65.9 .+-. 1.6
[0048] Referring now to FIG. 5, with continued reference to FIGS. 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.
[0049] 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.
[0050] 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.
[0051] 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 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.
[0052] 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.
[0053] 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.
[0054] Referring again to FIG. 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.
[0055] 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 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. It is therefore evident that the particular
illustrative embodiments disclosed above may be altered, combined,
or modified and all such variations are considered within the scope
and spirit of the present invention. The invention illustratively
disclosed herein suitably may be practiced in the absence of any
element that is not specifically disclosed herein and/or any
optional element disclosed herein. While compositions 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. All numbers and ranges disclosed
above may vary by some amount. 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 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
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 should be adopted.
* * * * *