U.S. patent application number 11/206708 was filed with the patent office on 2007-02-22 for methods and compositions for improving hydrocarbon recovery by water flood intervention.
This patent application is currently assigned to BJ Services Company. Invention is credited to Gene Brock, Jeffrey C. Dawson, Leonard J. Kalfayan.
Application Number | 20070039732 11/206708 |
Document ID | / |
Family ID | 37766413 |
Filed Date | 2007-02-22 |
United States Patent
Application |
20070039732 |
Kind Code |
A1 |
Dawson; Jeffrey C. ; et
al. |
February 22, 2007 |
Methods and compositions for improving hydrocarbon recovery by
water flood intervention
Abstract
Methods useful in improving hydrocarbon recovery from
subterranean formations using relative permeability modifier (RPM)
macromolecules are described. The RPMs are typically crosslinked
RPMs having K-values from 250-300 which, when injected into an
injector well associated with a producer well, redirect the
production water so as to improve the injection profile of the well
and simultaneously improve hydrocarbon recovery from the producer
well.
Inventors: |
Dawson; Jeffrey C.; (Spring,
TX) ; Kalfayan; Leonard J.; (Houston, TX) ;
Brock; Gene; (Magnolia, TX) |
Correspondence
Address: |
JONES & SMITH, LLP
THE RIVIANA BUILDING
2777 ALLEN PARKWAY, SUITE 800
HOUSTON
TX
77019-2141
US
|
Assignee: |
BJ Services Company
|
Family ID: |
37766413 |
Appl. No.: |
11/206708 |
Filed: |
August 18, 2005 |
Current U.S.
Class: |
166/270 ;
166/294; 166/295; 166/300; 507/225; 507/226 |
Current CPC
Class: |
C09K 8/588 20130101;
E21B 43/20 20130101; C09K 8/882 20130101; C09K 8/5083 20130101 |
Class at
Publication: |
166/270 ;
166/294; 166/295; 507/225; 166/300; 507/226 |
International
Class: |
E21B 33/138 20060101
E21B033/138; E21B 43/22 20060101 E21B043/22 |
Claims
1. A method for increasing hydrocarbon production from a production
well in a hydrocarbon-bearing formation, wherein there is at least
one injector well associated with the production well, the method
comprising: introducing an aqueous treating composition comprising
a relative permeability modifier (RPM) macromolecule into one or
more injector wells.
2. The method of claim 1, wherein the relative permeability
modifier macromolecule is a microgel.
3. The method of claim 2, wherein the microgel has a weight average
molecular weight from about 10.sup.4 to about 10.sup.8 g/mol.
4. The method of claim 2, wherein the microgel is present in the
aqueous concentrate composition in a concentration of about 15,000
parts per million (ppm) to about 50,000 ppm.
5. The method of claim 2, wherein the microgel has a K value from
about 200 to about 1,000.
6. The method of claim 5, wherein the microgel has a K value from
about 250 to about 300.
7. The method of claim 1, wherein the relative permeability
modifier macromolecule has a viscosity from about 1 cP to about 5
cP.
8. The method of claim 1, wherein the relative permeability
modifier macromolecule is deformable.
9. The method of claim 1, wherein the concentration of the relative
permeability modifier in the aqueous treating composition
introduced into the one or more injector wells is from about 3 ppm
to about 6000 ppm.
10. The method of claim 1, wherein the aqueous treating composition
further comprises water, brine, or seawater.
11. The method of claim 1, wherein the relative permeability
modifier macromolecule is capable of redirecting a portion of the
water flow through the hydrocarbon-bearing formation from the
injector well(s) to the producer well.
12. The method of claim 1, further comprising the step of providing
an improved injection profile after the introducing step.
13. A method for increasing hydrocarbon production from a
production well in a hydrocarbon-bearing formation, wherein there
is at least one injector well associated with the production well,
the method comprising: introducing an aqueous treating composition
comprising a relative permeability modifier (RPM) macromolecule
into an injector well in a permeable formation, in an amount
effective to enhance oil production from the production well; and
continuing the injection of the RPM macromolecule into the injector
well for a time sufficient to increase oil flow from the formation
to the production well where it is subsequently produced to the
surface via the producer well.
14. The method of claim 13, wherein the RPM macromolecule is
capable of redirecting water flow through the hydrocarbon-bearing
formation to provide an improved injection profile.
15. The method of claim 13, further comprising the step of forming
a treating solution comprising at least one relative permeability
modifier (RPM) macromolecule in an aqueous solution prior to, or
during the introducing step.
16. The method of claim 15, wherein the solution has a RPM
macromolecule concentration from about 3 ppm to about 6000 ppm.
17. The method of claim 15, wherein the forming of a treating
solution step is carried out at the wellsite, immediately prior to,
or during, the introducing step.
18. The method of claim 13, wherein the relative permeability
modifier has a weight average molecular weight from about 10,000 to
about 50,000,000 g/mol.
19. The method of claim 18, wherein the relative permeability
modifier has a weight average molecular weight from about 50,000 to
about 5,000,000 g/mol.
20. The method of claim 19, wherein the relative permeability
modifier macromolecule has a weight average molecular weight from
about 100,000 to about 2,000,000 g/mol.
21. The method of claim 13, wherein the relative permeability
modifier macromolecule has a K value from about 200 to about
1000.
22. The method of claim 21, wherein the relative permeability
modifier macromolecule has a K value from about 200 to about
600.
23. The method of claim 1, wherein the relative permeability
modifier macromolecule comprises a homopolymer, a terpolymer, or
copolymer of acrylamide.
24. The method of claim 1, wherein the relative permeability
modifier macromolecule comprises a quaternary ammonium salt,
sulfonic acid salt, or mixture thereof.
25. The method of claim 1, wherein the aqueous treating composition
comprises a relative permeability modifier macromolecule and an
organosilicon compound capable of forming a reactive silanol.
26. The method of claim 1, wherein the relative permeability
modifier macromolecule is crosslinked.
27. The method of claim 1, wherein the hydrocarbon-bearing
formation is a permeable formation comprised of diatomaceous
materials, quartz, shale, zeolite, chert, clay, silt, carbonate, or
combinations thereof.
28. The method of claim 23, wherein the RPM is crosslinked.
29. The method of claim 13, further comprising the step of
injecting an external crosslinker into the hydrocarbon-bearing
formation.
30. The method of claim 9, wherein the relative permeability
modifier macromolecule is present in the aqueous treating
composition in an amount from about 10 ppm to about 3,000 ppm.
31. The method of claim 26, wherein the crosslinked RPM
macromolecule comprises: a terpolymer, copolymer or homopolymer
comprising an anchoring monomer and a hydrophilic monomer; wherein
the anchoring monomer is a vinyl formamide or a mixture thereof,
and the hydrophilic monomer is an acrylamido sulfonic acid or a
mixture thereof; and wherein the RPM macromolecule is capable of
redirecting water flow through the hydrocarbon-bearing formation to
provide an improved injection profile.
32. The method of claim 26, wherein the crosslinked RPM
macromolecule is deformable.
33. The method of claim 1, wherein the aqueous treating solution is
introduced at flow rates below flow rates necessary to cause
fractures in the subterranean formation.
34. The method of claim 26, wherein the RPM macromolecule is
crosslinked either during polymerization or by an external
crosslinker during the introduction step.
35. The method of claim 26, wherein the crosslinked RPM
macromolecule further comprises an acrylamide spacer monomer.
36. The method of claim 26, further comprising: preparing an
aqueous solution of an anchoring monomer, a hydrophilic monomer,
and a spacer monomer; and polymerizing the monomers in the aqueous
solution to form a RPM macromolecule; wherein the preparing and
polymerizing take place prior to the injection step; wherein the
anchoring monomer is a vinylformamide; wherein the hydrophilic
monomer is an alkali metal, alkali earth metal, or quaternary
ammonium salt of an acrylamido sulfonic acid; and wherein the
spacer monomer is an acrylamide or mixture of acrylamides.
37. The method of claim 36, wherein the preparing and polymerizing
steps are carried out at or near the wellbore.
38. The method of claim 36, wherein the polymerization step further
comprises a crosslinking step to form a crosslinked RPM
macromolecule, the crosslinking step comprising: contacting the RPM
macromolecule with a crosslinking agent selected from the group
consisting of aldehydes, amides, metal salts, epoxides,
carbodiimides, di- or poly-allyl based monomers, or mixtures
thereof.
39. A method for increasing hydrocarbon production from a
production well in a hydrocarbon-bearing formation, wherein there
is at least one injector well associated with the production well,
the method comprising: introducing an aqueous water-control fluid
composition comprising a relative permeability modifier (RPM)
macromolecule and an aqueous base fluid into an injector well in a
permeable formation; and continuing the injection of the RPM
macromolecule into the injector well for a time sufficient to
increase oil flow from the formation to the production well where
it is subsequently produced to the surface via the producer well;
wherein the RPM macromolecule is capable of redirecting water flow
through the hydrocarbon-bearing formation to provide an improved
injection profile; and wherein the water control fluid composition
is introduced into the hydrocarbon-bearing formation prior to, in
conjunction with, or after a stimulation operation into the
formation.
40. The method of claim 39, wherein the RPM macromolecule is
crosslinked.
41. A method for enhancing hydrocarbon recovery from a reservoir or
formation containing substantially immobile hydrocarbons, the
method comprising: a) drilling and completing at least one injector
well in a subterranean formation in proximity to a producer well,
or converting a producer well into an injector well in proximity to
other producer wells; b) directing an aqueous mixture comprising a
relative permeability modifier (RPM) macromolecule into the
injector well, wherein the RPM macromolecule is present in an
amount effective to redirect water flow in the subterranean
formation and thereby increase hydrocarbon flow therefrom; and c)
continuing the injection of the aqueous mixture comprising a RPM
macromolecule into the injector well for a time sufficient to
increase flow of hydrocarbons from the formation towards the
producer well, where it is subsequently produced to the surface via
the producer well.
42. The method of claim 41, further comprising, after step (c):
injecting the aqueous mixture into the at least one injector well,
aqueous mixture injection is ceased, and hydrocarbons are produced
from the producer well.
43. The method of claim 41, wherein the RPM macromolecule is
crosslinked.
Description
FIELD OF THE INVENTION
[0001] The present invention provides methods of enhanced recovery
of hydrocarbons from subterranean formations. In particular, the
present invention provides methods for improving the recovery of
hydrocarbons from subterranean formations using relative
permeability modifier macromolecules.
DESCRIPTION OF RELATED ART
[0002] Water production is always a harbinger of problems in a
subterranean well, with water cuts in oil producing wells
increasing as time passes and oil fields become more mature. The
source of the water is often either formation water or injected
water used for the purpose of reservoir maintenance. In other
instances, heterogeneities encountered in reservoir rocks can cause
water channeling through higher permeability streaks/hairline
fractures, or near wellbore water coning at early periods in the
well's productivity life span, often due to limited reservoir
thickness or excessive pressure drawdowns.
[0003] Such water production can cause a variety of problems. It
can cause scaling problems in susceptible wells, induce fines
migration or sandface failure, increase corrosion of tubulars, and
sometimes even kill wells by hydrostatic loading, among other
things. Clearly, while water production is an inevitable
consequence of oil production, it is often desirable to defer its
onset, or at least its rise, for as long as possible during
hydrocarbon production.
[0004] Numerous strategies, both mechanical and chemical, have been
employed over the years in attempts to achieve these goals, or at
the least use the water flow to aid in hydrocarbon production.
These approaches have ranged from simple shut-off techniques, such
as cements, mechanical plugs, and inorganic gel squeezes to isolate
watered out zones, to more advanced concepts, such as the use of
several types of gel systems with varying degrees of success in the
control of water and water production. Among these, three main
chemical gel types have emerged as showing promise in subterranean
water treatments: permeability blockers or gellants, which plug
pore spaces and prevent fluid movement, often by means of a
controlled, delayed chemical reaction, such as precipitation or
swelling to form a three-dimensional "gel"; Disproportionate
Permeability Reducers (DPR) and/or Selective Permeability Blockers
(SPB), which also plug the pore spaces, restricting fluid movement,
but do not precipitate, swell, or viscosify significantly in the
presence of hydrocarbons, thereby reducing water relative
permeability; and Relative Permeability Modifiers (RPMs), which,
generally speaking, are water-soluble, hydrophilic polymer systems
that, when hydrated, produce long polymer chains that loosely
occupy pore spaces in the rock. Being strongly hydrophilic, RPMs
attract water and repel oil and, as a net result, exert a "drag
force" on water flow in the pores with a minimal effect on oil
flow.
[0005] Various methods have been proposed for increasing
hydrocarbon production from subterranean formations with water
problems. For example, U.S. Pat. No. 4,485,871 suggests a method
for recovering hydrocarbons in which an alcohol is injected into
the formation, followed by an aqueous alkaline solution. However,
this type of methodology is particular to diatomaceous formations.
In particular, hydrocarbon recovery using this method is reportedly
not optimum in formations that are deeply buried and/or have not
been extensively exposed to the atmosphere or oxygen bearing
formation water, resulting in an interfacial tension and oil/rock
wettability issues in these formations.
[0006] Davis, in U.S. Pat. No. 4,828,031, offers a method for
recovering oil from subterranean formations, in which a solvent is
injected into the formation, followed by an aqueous surface-active
solution. The aqueous surface-active solution is described to
contain a diatomite/oil water wettability improving agent and an
oil/water surface tension lowering agent. It is also suggested that
the method can be supplemented by the injection of water and/or
steam into the formation, at a pressure just below that where a
long fracture may be induced.
[0007] The use of numerous relative permeability modifiers for the
control of production water have been described in the art. For
example, U.S. Pat. No. 6,228,812 describes a chemical composition
treatment that selectively reduces water production by the
employment of relative permeability modifiers (RPMs). According to
the specification, the use of RPMs entails low risk to oil
production, as the polymers reportedly reduce the water
permeability downhole without adversely affecting oil permeability.
The use of RPMs for water control is also reported to be low in
cost and low in application cost as the use of such compositions
does not require expensive equipment for their application.
[0008] In U.S. Pat. No. 6,228,812, compositions and methods for
modifying the permeability of subterranean formations is described,
for the purpose of selectively reducing the production of aqueous
fluids. The compositions are described to include relative
permeability modifiers which include copolymers with hydrophilic
and anchoring monomeric copolymer units that can be added to well
treatment fluids to form water control treatment fluids.
[0009] However, while the use of polymeric compositions are
exhibiting increased utility and promise for downhole applications,
many water control compositions, and even some relative
permeability modifiers, do not always impart extended
effectiveness, or exhibit utility in formations having
permeability's greater than 1 Darcy. Thus, there exists a need for
methods to increase hydrocarbon production from hydrocarbon-bearing
formations using compositions and methods that do not adversely
affect oil production or permeability through the formation.
SUMMARY OF THE INVENTION
[0010] The present invention is directed generally to methods for
increasing hydrocarbon production from a hydrocarbon-bearing
formation, using relative permeability modifier macromolecules or
microgels. In a first aspect, the present invention provides a
method for increasing hydrocarbon production from a production well
in a hydrocarbon-bearing formation wherein there is at least one
injector well associated with the production well, the method
comprising the step of introducing an aqueous composition
comprising a relative permeability modifier macromolecule into the
at least one injector well. In accordance with this aspect, the
relative permeability macromolecule can be a microgel, be
deformable, have a K-value from about 200 to about 1,000, and/or be
present in the aqueous composition in a concentration from about
15,000 ppm to about 50,000 ppm.
[0011] In a further aspect of the present invention, a method for
increasing hydrocarbon production from a production well in a
hydrocarbon-bearing formation having at least one injector well
associated with the production well is provided, wherein the method
comprises the steps of introducing an aqueous composition
comprising a relative permeability modifier (RPM) macromolecule
into an injector well in a permeable formation in an amount
effective to enhance oil production from the production well, and
continuing the injection of the RPM macromolecule into the at least
one injector well for a time sufficient to increase oil flow from
the formation to the production well where it is subsequently
produced to the surface. In accordance with this aspect of the
invention, the RPM macromolecule is capable of redirecting water
flow through the hydrocarbon-bearing formation to provide an
improved injection profile, and/or the method can further comprise
the step of forming a treating solution comprising at least one RPM
macromolecule prior to the introducing step.
[0012] In yet another aspect of the present invention, a method for
increasing hydrocarbon formation from a production well in a
hydrocarbon-bearing formation having at least one injector well
associated with the production well is provided, the method
comprising the steps of introducing an aqueous composition of a
water-soluble, crosslinked, RPM macromolecule comprised of a
terpolymer, copolymer, or homopolymer of a vinyl acetamide and a
sulfonated vinyl monomer into an injector well, and continuing the
injection for a period of time sufficient to increase oil flow from
the formation to the production well, where the oil can be
subsequently produced. In accordance with this aspect of the
invention, the RPM macromolecule can further be classified as a
microgel, have a weight average molecular weight from about 10,000
to about 50,000,000 g/mol, and/or a K-value from about 200 to about
1,000.
[0013] In a further aspect of the present invention, a method for
increasing hydrocarbon production from a production well in a
subterranean formation is provided, the method comprising
introducing an aqueous treating solution comprising a crosslinked
relative permeability modifier (RPM) macromolecule into the
subterranean formation through an injector well that is associated
with the production well. In accordance with this aspect of the
invention, the crosslinked RPM macromolecule comprises a
terpolymer, copolymer, or homopolymer comprising an anchoring
monomer and a hydrophilic monomer, and is capable of redirecting
water flow through the hydrocarbon-bearing formation to provide an
improved injection profile.
[0014] In another aspect of the present invention, a method for
increasing hydrocarbon production from a production well in a
hydrocarbon-bearing formation, wherein there is at least one
injector well associated with the production well, the method
comprising introducing an aqueous water-control fluid composition
comprising a crosslinked relative permeability modifier (RPM)
macromolecule and an aqueous base fluid into an injector well in a
permeable formation, and continuing the injection of the
crosslinked RPM macromolecule into the injector well for a time
sufficient to increase oil flow from the formation to the
production well where it is subsequently produced to the surface
via the producer well. In accordance with this aspect of the
present invention, the crosslinked RPM macromolecule is a
terpolymer, copolymer or homopolymer comprising a hydrophilic
monomeric unit and a vinyl amide unit, is capable of redirecting
water flow through the hydrocarbon-bearing formation to provide an
improved injection profile, and is introduced into the
hydrocarbon-bearing formation prior to, in conjunction with, or
after a stimulation operation.
[0015] In yet another aspect of the present invention, a method for
enhancing hydrocarbon recovery from a reservoir or formation
containing substantially immobile hydrocarbons is provided, wherein
the method comprises drilling and completing at least one injector
well in a subterranean formation in proximity to a producer well,
or converting a producer well into an injector well in proximity to
other producer wells; directing an aqueous mixture comprising a
crosslinked relative permeability modifier (RPM) macromolecule into
the injector well, wherein the RPM macromolecule is present in an
amount effective to redirect water flow in the subterranean
formation and thereby increase hydrocarbon flow therefrom; and
continuing the injection of the aqueous treating composition into
the injector well for a time sufficient to increase flow of
hydrocarbons from the formation towards the producer well, where it
is subsequently produced to the surface via the producer well.
DESCRIPTION OF THE FIGURES
[0016] The following figures form part of the present specification
and are included to further demonstrate certain aspects of the
present invention. The invention may be better understood by
reference to one or more of these figures in combination with the
detailed description of specific embodiments presented herein.
[0017] FIG. 1 is a schematic representation of one aspect of the
present invention, illustrating RPM microgel flow from injector
wells towards producer wells.
[0018] FIG. 2 is a graphic representation of the parallel core
flood test of compositions in accordance with the present
invention.
DETAILED DESCRIPTION OF THE INVENTION
[0019] The present invention is directed to well treatment methods
useful in redirecting water in a subterranean formation so as to
improve the injection profile of the well and increase hydrocarbon
production from the well. Illustrative embodiments of the
invention, as well as illustrative methods of operation of the
unit, are described below in detail.
Composition
[0020] The compositions of the present invention are aqueous
treatment compositions containing one or more relative permeability
modifier (RPM) macromolecules. As used herein an RPM macromolecule
refers to a deformable, polymeric composition that comprises at
least one hydrophilic monomer which aids in the RPM adhering to the
formation and adds to the water/brine solubility; and at least one
anchoring monomeric unit to cause the RPM to adhere to the
formation. Further general characteristics of the relative
permeability modifier macromolecules as used herein include those
RPM macromolecules having K-values from about 200 to about 1,000
(which can be controlled by the concentration of the starting
monomers and/or the amount of crosslinking), and those RPM
macromolecules that are crosslinked, or both. Such RPM
macromolecules also include soft "microgels", which as used herein
refers to those RPM macromolecules which are crosslinked during
their manufacture and have a weight average molecular weight of
from about 10.sup.4 to 10.sup.8 g/mol. These RPM microgels
typically have a diameter from about 0.001 micron to about 500
micron, and more typically from about 0.001 micron to about 100
micron.
[0021] The relative permeability modifiers suitable for use in the
methods of the present invention are any polymers which can either
impede the production of water and/or redirect water through
permeable formation materials. Suitable RPMs include copolymers,
homopolymers, or terpolymers comprised of hydrophilic monomers, at
least one anchoring monomeric unit, an optional secondary anchoring
unit, and one or more filler/spacer monomer units. Optionally, the
RPMs can provide grafting sites for the inclusion of organosilicon
compounds. Suitable relative permeability modifiers include those
described in U.S. Pat. Nos. 5,735,349; 6,169,058; 6,465,397; and
6,228,812, herein incorporated by reference. Optionally, and in
accordance with the present invention, the RPM can include one or
more organosilicon compounds. Preferred RPM macromolecules suitable
for use within the present invention are AquaCon.TM., AQUATROL.TM.
I , and Aquatrol V (available from BJ Services Company, Houston,
Tex.).
[0022] The RPM macromolecules suitable for use in the present
invention have weight average molecular weights ranging from about
10,000 g/mol to about 50,000,000 g/mol, preferably from about
50,000 g/mol to about 5,000,000 g/mol, and more preferably from
about 100,000 g/mol to about 2,000,000 g/mol. The RPM
macromolecules for use herein also have a viscosity from about 1 cP
(0.001 Pa-s) to about 10 cP (0.010 Pa-s), and more preferably from
about 1 cP (0.001 Pa-s) to about 5 cP (0.005 Pa-s), as measured by
standard techniques.
[0023] The RPM macromolecule compositions of the present invention
are copolymers, homopolymers, or terpolymers comprising a
hydrophillic monomeric unit; at least one first anchoring monomeric
unit; and may also include at least one optionally selected second
anchoring monomeric unit. A filler monomeric unit may also be
employed. These copolymer compositions may be advantageously used
in aqueous-based water control treatment fluids to selectively
control water production from hydrocarbon production wells. As used
herein, the term "monomer" refers to molecules or compounds capable
of conversion to polymers by combining with other like molecules or
similar molecules or compounds. A "Monomeric unit" refers to a
repeating molecular group or unit having a structure corresponding
to a particular monomer. In this regard, the source of a given
monomeric unit may or may not be the corresponding monomer
itself.
[0024] As used herein, the term "monomeric anchoring unit" refers
to components of a polymer that will preferentially bind, by either
physical or chemical processes, to subterranean formation material
and which therefore tend to retain the polymer to the formation
material. Anchoring groups are typically selected to prevent a
polymer from washing out of the formation due to fluid flow.
Primary anchoring sites for the monomeric anchoring units are
typically clay and feldspar surfaces existing in formation pores,
channels and pore throats. With benefit of this disclosure, those
of skill in the art will understand that particularly useful
anchoring monomeric units are those having functional groups
capable of hydrolyzing to form amine-based anchoring groups on the
polymer. Examples include amide-containing monomeric units.
[0025] Advantageously, the disclosed co-polymers having the first
anchoring monomeric units described herein may be utilized in well
treatment methods to selectively reduce the permeability of a
subterranean formation to water by a factor of about 10 or more,
while at the same time leaving the permeability of the formation to
oil virtually unchanged. Furthermore, the disclosed compositions,
when introduced into a formation, tend to exhibit a high resistance
to removal from water bearing areas of the formation over time.
[0026] Hydrophillic monomers may include both ionic and nonionic
monomers. The term "nonionic monomer" refers to monomers that do
not ionize in aqueous solution at neutral pH. Examples of suitable
nonionic hydrophillic monomers include, but are not limited to,
vinyl acylamide comonomers including, but not limited to,
acrylamide, N-vinyl acetamide, N-vinyl-N-methyl acetamide,
N,N-dimethyl acetamide, N-vinyl-2-pyrrolidone, N-vinyl formamide
(VF), and N-ethenyl-N-alkyl acetamide, as well as mixtures of two
or more of such comonomers. Ionic monomers may be either anionic or
cationic. Examples of anionic monomers include, but are not limited
to, alkaline salts of acrylic acid, ammonium or alkali salts of
acrylamidomethylpropane sulfonic acid ("AMPS"), maleic acid,
itaconic acid, styrene sulfonic acid, and vinyl sulfonic acid (or
its ammonium or alkali metal salts). Examples of suitable cationic
monomers include, but are not limited to, dimethyldiallyl ammonium
chloride and quaternary ammonium salt derivatives from acrylamide
or acrylic acid such as acrylamidoethyltrimethyl ammonium
chloride.
[0027] In one embodiment, one or more hydrophillic monomeric units
are typically employed and are based on AMPS (such as at least one
of ammonium or alkali metal salt of AMPS, including sodium and/or
potassium salts of AMPS), acrylic acid, an acrylic salt (such as
sodium acrylate, N-vinyl pyrolidone, ammonium or alkali metal salts
of styrene sulfonic acid, etc.), or a mixture thereof. It may be
desirable to employ ammonium or alkali metal salts of AMPS for
added stability, with or without one or more other hydrophilic
monomers, in those cases where aqueous treatment and/or formation
fluids contain high concentrations of divalent ions, such as
Ca.sup.+2, Mg.sup.+2, and the like.
[0028] Optional second anchoring monomeric units may include any
monomeric unit that will adsorb onto formation material. In one
embodiment, examples of optional second anchoring monomeric units
include at least one of dimethyldiallylammonium chloride, ammonium
or alkali metal salts of acrylic acid, (such as sodium salts), or a
mixture thereof.
[0029] Optional filler monomeric units may include any monomeric
unit suitable for copolymerization with the other monomers in the
composition. Desirable characteristics of filler monomer units are
the ability to retain water solubility and/or relative low cost
compared to other monomer units present in a copolymer. Filler
monomer units may be based on, for example, monomers such as
acrylamide, methylacrylamide, etc. In one embodiment, optional
filler monomeric units include monomers such as acrylamide,
methylacrylamide, and the like.
[0030] With benefit of the present disclosure, the disclosed
compositions may be prepared using any method suitable for
preparing co-polymers known to those of skill in the art. In one
embodiment, monomers corresponding to the desired monomeric units
in the copolymer are selected and polymerized in an aqueous monomer
solution.
[0031] In one exemplary embodiment, a first N-vinylformamide
monomer is combined with a hydrophillic monomer (such as ammonium
or alkali metal salt/s of AMPS) and a filler monomer (such as
acrylamides), in an aqueous base fluid, typically water. Other
additives may include disodium ethylenediamine tetraacetate
(Na.sub.2EDTA), pH adjusting chemicals (such as potassium or sodium
hydroxide), and a catalyst to initiate polymerization. Monomers
with other anchoring groups may also be present.
[0032] Any relative proportion of the disclosed monomers that is
suitable for polymerization and use in a water control treatment
fluid may be combined in an aqueous solution for polymerization.
However, in one embodiment, a first anchoring monomer is combined
to be present in an amount of from about 2% to about 50% by weight
of the total polymer composition, alternatively from about 5% to
about 25% by weight of the total polymer composition. In another
embodiment a first anchoring monomer is combined to be present in
an amount from about 2% to about 50%, alternatively from about 5%
to about 25%, by weight of the total polymer composition; ammonium
or alkali metal salts of AMPS is combined so that AMPS-based
monomer is present in an amount from about 0% to about 50%,
alternatively from about 20% to about 30%, by weight of the total
polymer composition; and acrylamide is combined to be present in an
amount from about 20% to about 98%, alternatively from about 40% to
about 65% by weight of the total polymer composition. In one
embodiment, N-vinylformamide is utilized as the first anchoring
monomer.
[0033] Where necessary or desirable, the pH of a monomer solution
may be adjusted or neutralized prior to polymerization by, for
example, addition of a base such as sodium hydroxide or potassium
hydroxide. For example, the pH of an aqueous solution containing
ammonium or alkali metal salts of AMPS may be adjusted to, for
example, about 10 prior to the addition of N-vinylformamide and/or
a second anchoring monomer or a filler monomer such as acrylamide.
In one embodiment, a copolymer may be prepared by mixing the
appropriate monomers into a tank of fresh water, followed by
addition of a Na.sub.2EDTA, pH adjuster and catalyst system to
initiate polymerization. In one embodiment, ultimate pH range may
be from about 6.5 to about 10.0 and alternatively from about 7.5 to
about 9.5.
[0034] Additionally, the rate permeability modifier macromolecules
of the present invention can optionally include organosilicon
compounds, in order to afford modified viscosities and allow for
further binding to substrate materials including quartz, clay,
chert, shale, silt, zeolite, or combinations thereof.
[0035] Suitable organosilicon compounds suitable for use in the
aqueous RPM macromolecule compositions described herein are those
capable of forming water-soluble silanols by hydrolysis, include
amino silanes, vinyl silanes, organosilane halides, and
organosilane alkoxides, as well as combinations thereof. Suitable
water-soluble amino silanes include, without limitation,
3-aminopropyltriethoxy silane and
N-2-aminoethyl-3-aminopropyltrimethoxy silane. Vinyl silanes
suitable for use in accordance with the present invention include
but are not limited to vinyl tris-(2-methoxyethoxy) silane,
aminopropyl triethoxy silane, aminoethyl triethoxy silane,
aminopropyl trimethoxy silane, aminoethyl trimethoxy silane,
ethylene trimethoxy silane, ethylene triethoxy silane, ethyne
trimethoxy silane, ethyne triethoxy silane,
3,3,3-trifluoropropyl(2-trimethylsilylpiperidinyl)dimethoxysilane;
3,3,3-trifluoropropyl(2-trimethylsilyl-pyrrolidinyl)dimethoxysilane;
3,3,3-trifluoropropyl(2-(3-methylphenyl)piperidinyl)-dimethoxysilane;
3,3,3-trifluoropropyl(2-(3-methylphenyl)pyrrolidinyl)dimethoxysilane;
3,3,3-trifluoropropyl(1,2,3,4-tetrahydroquinolinyl)dimethoxysilane;
3,3,3-trifluoropropyl-(1,2,3,4-tetrahydroisoquinolinyl)dimethoxysilane;
3,3,3-trifluoropropyl-(decahydroquinolinyl)dimethoxysilane;
3,3,3-trifluoropropyl(bis(2-ethylhexyl)amino)-dimethoxysilane; and
3,3,3-trifluoropropyl(cis-2,6-dimethylpiperidinyl)dimethoxy-silane
and combinations thereof.
[0036] Organosilane halides suitable for use in accordance with the
present invention include those silanes of formula (I): ##STR1##
wherein X is halogen, R.sub.1 is an organic radical, and R.sub.2
and R.sub.3 are independently hydrogen, or are the same or
different halogens, or are the same or different organic radicals.
Preferably, R.sub.1 is a C.sub.1-C.sub.50 radical selected from the
group of C.sub.1-C.sub.50 alkyl, C.sub.1-C.sub.50 alkoxy,
C.sub.1-C.sub.50 alkoxyalkyl, C.sub.2-C.sub.50 alkenyl,
C.sub.2-C.sub.50 alkynyl, an aralkyl group, or an aryl group having
from 1 to 18 carbon atoms. Similarly, in accordance with the
present invention, it is preferred that X in Formula (I) is a
halogen selected from the group consisting of bromine, chlorine,
fluorine, and iodine, with chlorine and bromine being preferred.
R.sub.2 and R.sub.3, as indicated previously, can be hydrogen, the
same or different halogens, or a C.sub.1-C.sub.50 radical selected
from the group of C.sub.1-C.sub.50 alkyl, C.sub.1-C.sub.50 alkoxy,
C.sub.1-C.sub.50 alkoxyalkyl, C.sub.2-C.sub.50 alkenyl,
C.sub.2-C.sub.50 alkynyl, an aralkyl group, or an aryl group having
from 1 to 18 carbon atoms.
[0037] Suitable organosilane halides of formula (I) suitable for
use with the present invention include but are not limited to
methyldiethylchlorosilane, dimethyldichlorosilane,
methyltrichlorosilane, dimethyldibromosilane, diethyldiiodosilane,
dipropyldichlorosilane, dipropyldibromosilane,
butyltrichlorosilane, phenyltribromosilane, diphenyldichlorosilane,
tolyltribromosilane, methylphenyldichlorosilane,
propyldimethoxychlorosilane and the like.
[0038] Organosilane alkoxides suitable for use in accordance with
the present invention include those silanes of formula (II):
##STR2## wherein R.sub.4, R.sub.5, and R.sub.6 are independently
selected from hydrogen and organic radicals having from 1 to 50
carbon atoms, with the proviso that not all of R.sub.4, R.sub.5 and
R.sub.6 are hydrogen, and R.sub.7 is an organic radical having from
1 to 50 carbon atoms and is not hydrogen. Preferably, R.sub.4,
R.sub.5, R.sub.6 and R.sub.7 are independently hydrogen,
C.sub.1-C.sub.50 radicals selected from the group of
C.sub.1-C.sub.50 alkyl, C.sub.1-C.sub.50 alkoxy, C.sub.1-C.sub.50
alkoxyalkyl, C.sub.2-C.sub.50 alkenyl, C.sub.2-C.sub.50 alkynyl, an
aralkyl group, or an aryl group having from 1 to 18 carbon
atoms.
[0039] Suitable organosilane alkoxides of Formula (II) suitable for
use within the present invention include but are not limited to
methyltriethoxysilane, dimethyldiethoxysilane,
methyltrimethoxysilane, divinyldimethoxysilane,
divinyldi-2-methoxyethoxy silane, di(3-glycidoxypropyl)
dimethoxysilane, vinyltriethoxysilane,
vinyltris-2-methoxyethoxysilane, 3-glycidoxypropyltrimethoxysilane,
3-methacryloxypropyltrimethoxysilane, 2-(3,4-epoxycyclohexyl)
ethyltrimethoxysilane,
N-2-aminoethyl-3-propylmethyldimethoxysilane,
N-2-aminoethyl-3-propyltrimethoxysilane,
N-2-aminoethyl-3-aminopropyltrimethoxysilane,
3-aminopropyltriethoxysilane, tetraethoxysilane and the like.
[0040] The weight ratio of RPM macromolecule to organosilicon
compound in the aqueous composition is generally from about 3:200
to about 20:4. The weight percentage of the RPM and organosilicon
compound composite in the aqueous composition is generally from
about 0.01 to about 25 weight percent. For instance, where the RPM
macromolecule is PVA, the concentration ratio in parts per million
of PVA RPM macromolecule to silicon in the organosilicon compound
in the aqueous composition is generally from about 20,000:80 to
about 200,000:40,000, preferably from about 50,000:800 to about
100,000:4,000. The weight percentage of the PVA RPM and silicon in
the organosilicon compound composite in the aqueous composition is
generally from about 2.0% to 24.00%, preferably from 5.0% to 10.5%,
weight percentage. The concentration ratio in parts per million of
polyacrylamide RPM macromolecule to silicon in the organosilicon
compound in the aqueous composition is generally from about 100:80
to about 6,000:40,000, preferably from about 900:800 to about
3,000:4,000. The weight percentage of the polyacrylamide RPM and
silicon in the organosilicon compound composite in the aqueous
composition is generally from about 0.02% to 4.60%, preferably from
0.17% to 0.70%, weight percent.
[0041] As used herein, the terms "alkyl", "alkylene", "alkynyl",
"alkoxy", "alkoxyalkyl", "aryl", "halogen"/"halide",
"heterocyclic", and "aralkyl", alone or in combination, have their
usual chemical meaning, as known to those of skill in the art.
Preferably, the alkyl radicals contain from about 1 to about 50
carbon atoms, and more preferably from about 1 to about 25 carbon
atoms. In a similar manner, the alkylene and/or alkynyl radicals
contain from about 2 to about 50 carbon atoms, and more preferably
from about 2 to about 18 carbon atoms.
[0042] The term "substituted", as used herein, indicates that one
or more hydrogen on the designated atom or substituent is replaced
with a selection from the indicated group, provided that the
designated atom's normal valency is not exceeded, and the that the
substitution results in a stable compound.
[0043] In one embodiment, the disclosed co-polymers may be
polymerized from monomers using gel polymerization methods. In any
case, polymerization is typically carried out in oxygen free or in
a reduced oxygen environment. In this regard, a closed reactor in
which oxygen has been removed and the reactor has been sparged and
pressured with nitrogen gas, a solution where nitrogen gas is
bubbled throughout the reacting solution, or other suitable
polymerization methods known in the art may be employed with
benefit of this disclosure. If so desired, a water control
treatment fluid may be prepared at a well site.
[0044] With benefit of this disclosure, an aqueous base fluid may
be any aqueous-base fluid suitable for well treatments known in the
art including, but not limited to, fresh water, acidified water
having pH range from 1.0 to 3.0, brine, sea water, synthetic brine
(such as 2% KCl), produced formation water, and the like.
[0045] If so desired, optional mutual solvents may also be used
with the aqueous composition of the invention. Mutual solvents,
among other things, may act to remove hydrocarbons adhering to
formation material. In this regard, any mutual solvent suitable for
solubilizing hydrocarbons may be employed including, but not
limited to, terpenes (such as limonene), C.sub.3 to C.sub.9
alcohols (such as isopropanol), glycol-ether (such as ethylene
glycol monobutyl ether, "EGMBE"), or mixtures thereof.
[0046] It will be understood with benefit of the present disclosure
that other additives known in the art for use in stimulation and
well treatments may be employed in the practice of the disclosed
method if so desired. For example, wetting agents, surfactants,
thickeners, diversion agents, pH buffers, and the like can be used.
In one embodiment, internal diverting materials may be employed if
desired. Examples of suitable diverting agents include, but are not
limited to, viscous water external emulsions, and are known to
those of skill in the art. In one embodiment, an aqueous
composition may be added to a salt solution, such as a 2% salt
solution, wherein the salt is preferably potassium chloride.
[0047] The disclosed aqueous compositions may be used as the only
component in an aqueous water control treatment fluid or may be
combined with other components of stimulation fluid or other well
treatment fluid (such as hydraulic fracturing fluids, acid fluids,
surfactant squeeze treatment fluids, etc.).
[0048] Whether utilized as part of a stand-alone water control
treatment fluid, employed in conjunction with another type of well
treatment such as a stimulation treatment, or otherwise introduced
into a well, the disclosed aqueous composition may be present in
any concentration suitable for controlling water production in a
subterranean formation. However, in one embodiment, one or more of
the disclosed RPMs and/or RPM microgel compositions are present in
the treatment fluid at a total concentration of from about 1 ppm to
about 10,000 ppm polymer, and more preferably from about 3 ppm to
about 6,000 ppm polymer, based on the total weight of the water
control treatment fluid.
[0049] To reduce injection pressures during injection of a well
treatment fluid, the potassium chloride may be added to the aqueous
solution and the pH reduced to a low value, for example to about 1,
just prior to introduction of the treatment fluid into a wellbore.
Using this optional procedure helps minimize injection pressure and
ensure the extent of penetration of the aqueous composition into
the formation. The pH of a well treatment fluid may be lowered by
the addition of any acidic material suitable for decreasing pH of
the fluid to less than about 3, and alternatively between about 1
and about 3. Suitable acidic materials for this purpose include,
but are not limited to, hydrochloric acid, formic acid and acetic
acid, etc. With benefit of this disclosure, those of skill in the
art will understand that addition of acidic material and adjustment
of pH may be varied as desired according to treatment fluid
characteristics and formation temperature conditions in order to
optimize polymer retention and water control.
[0050] The aqueous composition may be batch prepared or prepared by
continuous mix processes. For example, the water control treatment
fluid may be first prepared in total, and then injected or
otherwise introduced into a subterranean formation. This is
referred to as a "batch mixing" process. In another embodiment, a
water control treatment fluid may be prepared by continuous mix
processes, wherein the treatment fluid components are mixed
together while the fluid is simultaneously introduced into the
wellbore.
[0051] Once a treatment fluid is prepared (either by batch or
continuous mixing), the water control treatment fluid is introduced
into the subterranean formation in any amount suitable for
contacting a portion of a reservoir matrix of flow pathways. By
"introduced" it is meant that a fluid may be pumped, injected,
poured, released, displaced, spotted, circulated or otherwise
placed within a well, wellbore, and/or formation using any suitable
manner known in the art. In one embodiment, an amount of treatment
fluid sufficient to treat the entire height of the producing
interval having a radius of from about 3 to about 10 foot from the
wellbore may be employed, however greater or lesser amounts are
also possible.
[0052] The aqueous treating compositions of the present invention
have particular applicability in those instances where the
formation permeability is between from about 0.1 mD to about 10,000
mD. In high permeability (>1 to 1.5 Darcy) formations, optimum
treatment results have been obtained. Core flow test results show
effectiveness at a permeability as high as 8.0 Darcy (8,000 mD)
under high rate flow conditions. Such hydrocarbon-bearing
formations suitable for treatment with the compositions described
herein are permeable formations including those comprised of
diatomaceous materials, quartz, shale, zeolite, chert, clay, silt,
carbonate, or combinations thereof.
Crosslinkers
[0053] As indicated previously, and in accordance with the present
invention, the relative permeability modifier macromolecules of the
present invention used as water redirecting agents can be
crosslinked either internally, externally, or both. Such
crosslinking is preferably performed using one or more chemical
cross-linking techniques (vs. UV irradiation, biological
crosslinking, etc.), and can occur during the synthesis of the RPM
macromolecules, at the wellsite just prior to injection into an
injector well (in the case of external crosslinking), or both.
Crosslinkers suitable for use with the RPM macromolecules/microgels
of the present invention include aldehydes, amides, acrylamides,
isocyanates, metal salts, di- or poly-allyl based monomers,
carbodiimide cross-linkers, and polyepoxide compounds. Most
preferably, the RPM macromolecules of the present invention are
crosslinked using aldehyde-based crosslinking techniques,
acrylamide-based crosslinking techniques, or using polyepoxide
compounds.
[0054] Examples of useful multifunctional crosslinking monomers
include multifunctional acrylamides, and (meth)acrylates containing
unsaturation at preferably 2, and optionally 3 or more sites on
each copolymerizable comonomer molecule. In one embodiment, the
multifunctional crosslinking monomers are selected from the group
consisting of monomeric polyesters of acrylic or methacrylic acids
and polyhydric alcohols; and monomeric polyalkenyl polyethers of
polyhydric alcohols containing from 2 to about 6 polymerizable
alkenyl ether groups per polyether molecule. Another exemplary
crosslinking monomer is a monomeric polyester of an acrylic or
methacrylic acid and a polyhydric alcohol containing from 2 to
about 6 polymerizable .alpha.,.beta.-unsaturated acrylic groups per
polyester molecule. Other copolymerizable crosslinking monomers
include divinyl ether, ethylene glycol dimethacrylate,
(m)ethylene-bisacrylamide, allylpentaerythritol, and the like. The
preferred crosslinking comonomers are somewhat water soluble and
monomer soluble. Preferably, the acrylamide crosslinking agent used
with the RPM macromolecules suitable for use in the methods of the
present disclosure is methylene bis-acrylamide, or combinations of
crosslinkers including methylene bis-acrylamide.
[0055] Aldehyde-based cross-linking techniques includes those
techniques using a reagent containing two reactive aldehyde groups
to form covalent cross-links between neighboring amino groups of
monomer residues in the relative permeability modifier
macromolecules described herein [Khor, E., Biomaterials, Vol. 18:
pp. 95-105 (1997)]. Aldehydes suitable for use with the present
invention include but are not limited to glutaraldehyde,
formaldehyde, propionaldehyde, and butyraldehyde. Preferably, the
aldehydes are glutaraldehyde or formaldehyde.
[0056] Polyepoxy based cross-linking techniques and agents include
the use of compounds, such as short, branched polymers, terminating
in reactive epoxy functionalities. Polyepoxy compounds suitable for
use as cross-linking agents in the present invention include but
are not limited to glycerol ethers, glycol, and glycerol
polyglycidyl ethers.
[0057] Isocyanates are also suitable for use as cross-linking
agents in the present invention. Generally, the isocyanates (R-NCO)
react with primary amines to form a urea bond (R--H--CO--NH--R);
difunctional isocyanates therefore have the ability to cross-link
RPMs via lysine-like side chains. Isocyanates suitable for use as
cross-linking agents in the present invention are preferably
diisocyanates, including biphenyl diisocyanate,
dimethoxy-4,4'-biphenyl diisocyanante, dimethyl-4,4'-biphenyl
diisocyanate, 1,3-bis(isocyanatomethyl)benzene, phenyl
diisocyanate, toluene diisocyanate, tolylene diisocyanate,
diisocyanato hexane, diisocyanato octane, diisocyanato butane,
isophorone diisocyanante, xylene diisocyanate, hexamethylene
diisocyanante, octamethylene diisocyanante, phenylene diisocyanate,
and poly(hexamethylene diisocyanate). Preferably, the isocyanate
used as a cross-linking agent of the RPM macromolecules of the
present invention is hexamethylene diisocyanate.
[0058] Carbodiimide cross-linking agents and techniques can also be
used within the scope of the present invention. These agents react
with the carboxyl groups of monomers within the RPM
macromolecules/microgels to form isoacylurea
derivatives/iso-peptide bonds [Khor, E., ibid.]. Carbodiimides
suitable for use as cross-linking agents with the relative
permeability modifier macromolecules of the present invention
include but are not limited to N,N'-dicyclohexylcarbodiimide (DCC);
N,N'-diisopropylcarbodiimide (DIC); N,N'-di-tert-butylcarbodiimide;
1-ethyl-3-(3-dimethylaminopropyl)carbodiimide (EDC; EDAC);
water-soluble EDC (WSC); 1-tert-butyl-3-ethylcarbodiimide;
1-(3-dimethylaminopropyl)-3-ethylcarbodiimide;
bis(trimethylsilyl)carbodiimide;
1,3-bis(2,2-dimethyl-1,3-dioxolan-4-ylmethyl)carbodiimide (BDDC, as
described in U.S. Pat. No. 5,602,264);
N-cyclohexyl-N'-(2-morpholinoethyl) carbodiimide;
N,N'-diethylcarbodiimide (DEC);
1-cyclohexyl-3-(2-morpholinoethyl)carbodiimide
methyl-p-toluenesulfonate [e.g., Sheehan, J. C., et al., J. Org.
Chem., Vol. 21: pp. 439-441 (1956)]; oligomeric alkyl
cyclohexylcarbodiimides, such as those described by Zhang, et al.
[J. Org. Chem., Vol. 69: pp. 8340-8344 (2004)]; polymer bound DCC;
and polymer bound EDC, such as cross-linked
N-ethyl-N'-(3-dimethylaminopropyl)carbodiimide on JANDAJEL.TM..
Additionally, N-hydroxysuccinimide (NHS),
1-hydroxy-7-azabenzotriazole (HOAt), or similar reagents can be
utilized in conjunction with the carbodiimide to minimize internal
rearrangement of the activated isoacylurea derivative and provide
more efficient cross-linking.
[0059] Other chemical cross-linking agents suitable for use in the
present invention to provide cross-linked RPM macromolecules for
use in redirecting formation water to improve hydrocarbon recovery
from subterranean formations include but are not limited to
homobifunctional cross-linkers such as BMME, BSOCOES, DSP (a
thio-cleavable cross-linker), DSS, EGS, water-soluble EGS, and
SATA, as well as heterobifunctional cross-linking agents including
GMB, MBS, PMPI, SMCC, SPDP, and MPH (maleimidopropionic acid
hydrazide), MCH, EMCH (maleimidocaprionic acid hydrazide), KMUH
(N-(.kappa.-Maleimidoundecanoic acid)hydrazide), and MPBH
(4-(4-N-MaleimidoPhenyl)butyric acid hydrazide), all available from
Interchim (Cedex, France).
[0060] Specific examples of other crosslinking monomers suitable
for use herein include but are not limited to trimethylol propane
triacrylate (TMPTA), trimethylol propane trimethacrylate (TMPTMA);
diethylene glycol diacrylate (DEGDA), diethylene glycol
dimethacrylate (DEGDMA), trimethylene glycol diacrylate, butylene
glycol diacrylate, methylene-bis-acrylamide, pentamethylene glycol
diacrylate, octylene glycol diacrylate, glyceryl diacrylate,
glyceryl triacrylate, neopentyl glycol diacrylate, the
tetraacrylate ester of pentaerythritol, as well as combinations
thereof.
[0061] It is understood that certain monounsaturated monomers may
act in varying degrees to crosslink or branch the water soluble
copolymer of the invention. For example, acrylate monomers with
abstractable hydrogens, which can function as radical reactive
sites, can in some embodiments of this invention, form a more
branched or crosslinked polymer, thus affecting the preferred
levels of the polyethylenic unsaturated crosslinking comonomers. An
example of a monounsaturated monomer with an abstractable hydrogen
is 2-ethylhexyl acrylate.
[0062] Optional heat-reactive, latent carboxy- or hydroxy-reactive
internal crosslinking systems can be provided by the incorporation
of carboxylic-group containing comonomers, and N-alkylol amides,
for example, N-methylol acrylamide, N-propylol acrylamide,
N-methylol methacrylamide, N-methylol maleimide, N-methylol
maleamic acid esters, N-methylol-p-vinyl benzamide, and the
like.
[0063] Known methods for optional post-polymerization crosslinking
of carboxylic acid containing copolymers include, for example, U.S.
Pat. No. 4,666,983 (crosslinking agent without any carrier
solvent), using e.g. polyhydric alcohols, polyglycidyl ethers,
polyfunctional amines and polyfunctional isocyanates. U.S. Pat. No.
4,507,438 and 4,541,871 utilize a difunctional compound in water
with inert solvent or mixture of solvents. The difunctional
compounds include glycidyl ethers, haloepoxies, aldehydes and
isocyanates with ethylene glycol diglycidyl ether crosslinker. The
solvents include polyhydric alcohols with ethylene glycol,
propylene glycol and glycerine enumerated as preferred polyhydric
alcohols. U.S. Pat. No. 5,140,076 teaches a
water-solvent-crosslinker mixture. Crosslinkers such as polyhydric
alcohol, diglycidyl ether, polyaziridene, urea, amine and ionic
crosslinkers are suggested.
[0064] The crosslinked copolymers used herein form a stable,
microgel solution as a result of obtaining a molecular size or
weight, as characterized by the K-value test, of from about 220 to
about 1000 (i.e., a K-value of from about 200 to about 1,000), and
more typically have K-values of from about 220 to about 500. For
example, in accordance with one aspect of the present invention,
the relative permeability macromolecules of the present invention
have a K value from about 220 to about 300.
[0065] The crosslinked copolymers of the present invention have no
readily definable molecular weight due to the intermolecular
crosslinking of the polymer chains. The Fikentscher value, or
K-value measurement is a way to indirectly indicate molecular
weight and/or size of the copolymers, accordingly. A higher K-value
corresponds to a polymer of comparatively larger molecular weight
and/or size or one that exhibits greater chain entanglement
behavior.
[0066] To determine the K-value, the copolymer is typically
dissolved to a 0.5% concentration in deionized water and the
flow-out time is determined at about 25.degree. C. by means of a
capillary viscometer. This value gives the absolute viscosity
(eta-c) of the solution. The absolute viscosity of the solvent is
eta-0. The ratio of the two absolute viscosities gives the relative
viscosity, z, z = eta - c eta - 0 ##EQU1## from the relative
viscosities of the function of the concentration. The K-value can
then be determined by means of the following equation: Log .times.
.times. z = 75 * k 2 1 + 1.5 .times. kc + k * c ##EQU2## Any
suitable capillary viscomter instrument known in the art (e.g., a
Ubbelohde viscometer) can be used for the K-value measurements, in
accordance with the present invention. Methods of Use
[0067] The RPM macromolecules and/or soft RPM microgel compositions
of the present invention can be used to improve hydrocarbon
recovery in subterranean operations by water flood intervention.
More particularly, and as shown in FIG. 1, a series of drilled and
completed producing wells (12) has a series of injection wells (10)
loosely spaced apart from each other and perforated so as to be
able to direct fluid (14) in the direction of the producer wells
(12). According to one aspect of the present invention, injection
fluid (14), which is an aqueous treating fluid comprising at least
one RPM macromolecule as described herein, is directed into
injector well or wells (10) by a pressure sufficient to move the
fluid containing the RPM macromolecules into the
hydrocarbon-bearing formation. The mixture that is ultimately used
can optionally contain, in addition to the RPM macromolecules, one
or more of a combination of chemical additives including wetting
agents, surfactants, and caustic or alkaline materials, in order to
enhance the redirection of water flow within the subterranean
matrix within the formation. As fluid (14) is pumped into the
formation, the RPMs in the treating fluid cause the water to be
redirected through the formation, and in doing so displace the
hydrocarbons (e.g., oil) toward the producing well or wells (12).
Thereafter, the oil will be produced from the producer well (12) to
the surface, preferably with very little water contamination which
would necessitate separation of the oil from the water at the
surface level.
[0068] Use of the relative permeability modifier macromolecules
and/or RPM microgels in combination with the formations as
described herein will allow substantially more hydorcarbonaceous
fluids or oil to be produced from the formation than before the
treatment methods described herein. This occurs because the flow of
the RPM macromolecules in the aqueous treating fluid down and
through the injector wells allow for substantially more formation
contact by the RPM treating fluid mixture, which then redirects
water from the formation toward the producer wells, and in doing so
removes oil from the formation and alters the injection profile of
the well.
[0069] The following examples are included to demonstrate preferred
embodiments of the invention. It should be appreciated by those of
skill in the art that the techniques disclosed in the examples
which follow represent techniques discovered by the inventors to
function well in the practice of the invention, 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
similar result without departing from the scope of the
invention.
EXAMPLES
Example 1
General Procedure for Parallel Core Flow Testing
[0070] The first step is to determine the test core dimensions and
baseline properties. The test cores were placed into a suitable
core-holder of a parallel flow test apparatus. The dry cores were
then saturated with brine. Following saturation, the cores were
heated to the test temperature(s) with the required confining and
back pressures. The initial permeability to brine through both
cores was then determined independently by establishing flow in an
arbitrary injection direction (to simulate injection into the
reservoir) at constant rate until steady state. AquaCon.TM.
(available from BJ Services Company, Houston, Tex.) treatment fluid
was then injected through the parallel flow apparatus, at a
constant rate of approx. 0.3 ml/min, in the injection (treatment)
direction. AquaCon.TM. treatment flow and pressure drops through
both the high permeability and low permeability cores were measured
simultaneously. The duration of this AquaCon.TM. treatment stage
depended upon three things: i.) achievement of an 80-90%
permeability reduction (for high permeability cores only); ii.)
little or no noticeable permeability reduction at any given
treatment concentration; and/or iii.) pore volume throughput based
on previous tests.
[0071] Following the initial injection and measurements of the
treatment fluid through the parallel-flow apparatus, brine was
re-injected in the same direction at a constant rate of 0.3 ml/min
in order to determine post-treatment steady state permeability to
brine. These last two steps, treatment fluid injection and brine
re-injection, were then repeated as necessary in order to further
reduce the permeability to brine.
Example 2
Parallel Core Flow Test
[0072] The purpose of this test was to determine AquaCon.TM. (BJ
Services Co., Houston, Tex.) effectiveness in reducing water flow
through high permeability thief zones without significantly
affecting the permeability in lower permeability zones. For this
test, a high permeability sandstone core that was 10 times more
permeable than the low permeability core (air permeability contrast
of 10:1) was used. The result of the linear parallel core flood
testing with 0.05% AquaCon.TM. is shown in Table 1 below.
TABLE-US-00001 TABLE 1 Before Treatment After Treatment Ratio of
AquaCon Ratio of High Treatment Permeability High Core
K.sub.brine:Low % Pore Reduction K.sub.brine:Low Test Type
K.sub.air K.sub.brine K.sub.brine Conc. Volumes K.sub.brine from
Initial % K.sub.brine 1 Sandstone 601 134 9.6 0.05 23 19 86% 1.9
59.4 14 0.05 10 29%
[0073] A total of 23 pore volumes of AquaCon.TM. treatment were
injected through the parallel core flow apparatus. As expected, the
majority of the AquaCon.TM. treatment flowed preferentially through
the high permeability core that resulted in a significant brine
permeability reduction (86%). In the low permeability core, there
was less treatment invasion and hence a smaller brine permeability
reduction (29%). Since a much larger injectivity loss occurs in the
high permeability core, the AquaCon.TM. treatment significantly
improved the injection profile, or distribution through the cores
of contrasting permeabilities. Initially, the brine permeability
contrast between the two cores was 9.6, compared to 1.9 after
treatment. FIG. 2 illustrates the graphical representation of these
test results. The results of this core-flow testing showed that
AquaCon.TM. at very low concentrations could be applied to
effectively treat injection wells.
[0074] All of the apparatus, methods and other particular
embodiments disclosed and claimed herein can be made and executed
without undue experimentation in light of the present disclosure.
While the compositions and methods of this invention have been
described illustratively in terms of preferred embodiments, it will
be apparent to those of skill in the art that variations may be
applied to the methods and/or apparatus and in the steps or in the
sequence of steps of the methods described herein without departing
from the concept and scope of the invention. Furthermore, no
limitations are intended as relates to the details of construction
or design as described herein. For example, the dimensioning
illustrated in some of the drawing figures is exemplary in nature
only, and it is to be understood that the particular embodiments
described herein may be altered or modified by one of skill in the
art, and that all such variations are considered within the scope
and spirit of the present invention.
* * * * *