U.S. patent application number 10/386160 was filed with the patent office on 2004-09-16 for organosilicon containing compositions for enhancing hydrocarbon production and method of using the same.
Invention is credited to Dawson, Jeffrey C., Kalfayan, Leonard J..
Application Number | 20040177957 10/386160 |
Document ID | / |
Family ID | 32093720 |
Filed Date | 2004-09-16 |
United States Patent
Application |
20040177957 |
Kind Code |
A1 |
Kalfayan, Leonard J. ; et
al. |
September 16, 2004 |
Organosilicon containing compositions for enhancing hydrocarbon
production and method of using the same
Abstract
Compositions useful in the reduction of excessive water in oil
and gas wells and other subterranean formations comprises an
organosilicon compound and a relative permeability modifier (RPM)
macromolecule. The RPM is capable of impeding the production of
water. The organosilicon compound is capable of forming a
water-soluble silanol by hydrolysis and is preferably either an
organosilane halide or organosilane alkoxide. The composition is
introduced into the subterranean formation for the purpose of
selectively reducing excessive production of aqueous fluids. The
composition may be employed in well treatment fluids introduced
into production wells or injection wells. The compositions may also
be utilized in conjunction with stimulation treatments and with
introduction of other well treatment fluids. By introducing the
composition into fluid passages of the formation, the water
producing zones can be selectively blocked off. Thus, the ability
of fluids to flow through the aqueous fluid containing fluid
passages is selectively reduced resulting in the reduced production
of aqueous fluids while maintaining production of hydrocarbons.
Core flow test results show effectiveness at permeability as high
as 7.0 Darcy under high rate flow conditions.
Inventors: |
Kalfayan, Leonard J.;
(Houston, TX) ; Dawson, Jeffrey C.; (Spring,
TX) |
Correspondence
Address: |
LOCKE LIDDELL & SAPP LLP
600 TRAVIS
3400 CHASE TOWER
HOUSTON
TX
77002-3095
US
|
Family ID: |
32093720 |
Appl. No.: |
10/386160 |
Filed: |
March 10, 2003 |
Current U.S.
Class: |
166/270 ;
166/281; 166/295; 507/211; 507/219; 507/225; 507/234 |
Current CPC
Class: |
E21B 43/25 20130101;
C09K 8/607 20130101; C09K 8/5083 20130101; C09K 8/5086
20130101 |
Class at
Publication: |
166/270 ;
166/281; 166/295; 507/219; 507/234; 507/211; 507/225 |
International
Class: |
E21B 033/138; E21B
043/267 |
Claims
What is claimed is:
1. A method for reducing or eliminating the production of water in
an oil or gas well by introducing into the well an aqueous
composition comprising a mixture of: (a) an organosilicon compound
capable of forming a water-soluble silanol by hydrolysis; and (b) a
relative permeability modifier (RPM) macromolecule capable of
impeding the production of water.
2. The method of claim 1, wherein the concentration of RPM in the
aqueous composition is between from about 100 to about 80,000
ppm.
3. The method of claim 1, wherein the concentration of
organosilicon compound is between from about 500 to about 20,000
ppm.
4. The method of claim 1, wherein the organosilicon compound is
capable of binding both to the RPM as well as formation substrate
minerals in the well.
5. The method of claim 4, wherein the formation substrate minerals
include quartz, clay, shale, silt, chert, zeolite, or a combination
thereof.
6. The method of claim 1, wherein the formation permeability in the
oil or gas well is between from about 0.1 to about 8,000 md.
7. The method of claim 1, wherein the organosilicon compound is an
organosilane halide of the formula: 7wherein X is a halogen,
R.sub.1 is an organic radical having from 1 to about 50 carbon
atoms, and R.sub.2 and R.sub.3 are the same or different halogens
or organic radicals having from 1 to about 50 carbon atoms.
8. The method of claim 7, wherein X is a halogen selected from the
group consisting of chlorine, bromine and iodine, R.sub.1 is an
alkyl, alkenyl, alkoxide or aryl group having from 1 to about 18
carbon atoms and R.sub.2 and R.sub.3 are the same or different
halogens selected from the group consisting of chlorine, bromine
and iodine or alkyl, alkenyl, alkoxide or aryl group having from 1
to about 18 carbon atoms.
9. The method of claim 8, wherein X is chlorine.
10. The method of claim 7, wherein the organosilane halide is
selected from methyldiethylchlorosilane, dimethyldichlorosilane,
methyltrichlorosilane, dimethyldibromosilane, diethyldiiodosilane,
dipropyldichlorosilane, dipropyldibromosilane,
butyltrichlorosilane, phenyltribromosilane, diphenyldichlorosilane,
tolyltribromosilane, propyldimethoxychlorosilane and
methylphenyldichlorosilane.
11. The method of claim 1, wherein the organosilicon compound is an
organosilane alkoxide of the formula: 8wherein R.sub.4, R.sub.5 and
R.sub.6 are independently selected from hydrogen and organic
radicals having from 1 to about 50 carbon atoms, provided 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 about 50 carbon atoms.
12. The method of claim 11, wherein R.sub.4, R.sub.5 and R.sub.6
are independently selected from hydrogen, amine, alkyl, alkenyl,
aryl and carbohydroxyl groups having from 1 to about 18 carbon
atoms, with at least one of the R.sub.4, R.sub.5 and R.sub.6 groups
not being hydrogen, and R.sub.7 is selected from amine, alkyl,
alkenyl, and aryl groups having from 1 to 18 carbon atoms.
13. The method of claim 1, wherein the RPM macromolecule has a
molecular weight between from about 50,000 to about 20,000,000
g/mole.
14. The method of claim 13, wherein the RPM macromolecule has a
molecular weight between from about 100,000 to about 5,000,000
g/mole.
15. The method of claim 14, wherein the RPM macromolecule has a
molecular weight between from about 250,000 to about 2,000,000
g/mole.
16. The method of claim 1, wherein the RPM macromolecule is derived
from acrylamide.
17. The method of claim 16, wherein the RPM macromolecule is a
homopolymer or copolymer of acrylamide which has been sulfonated or
quaternized.
18. The method of claim 16, wherein the RPM macromolecule is a
copolymer of acrylamide and at least one monomer selected from
acrylic acid, (meth)acrylic acid, dimethyldiallylammonium chloride,
acrylamidoethyltrimethylammonium chloride,
methacrylamidoethyltrimethylam- monium chloride,
acrylamidomethylpropanesulfonic acid, N-vinyl pyrrolidone, N-vinyl
formamide, N-vinyl acetamide, N-vinylmethylacetamide,
acrylamidoethyltrimethylammonium chloride, vinyl sulfonic acid,
maleic acid, itaconic acid, styrene sulfonic acid, vinylsulfonic
acid, methylenebisacrylamide and vinylphosphonic acid and sulfonate
monomers thereof.
19. The method of claim 1, wherein the RPM macromolecule is a
polyvinyl alcohol or polysiloxane.
20. The method of claim 19, wherein the polyvinylalcohol has a
degree of hydrolysis between from about 50% to about 100%.
21. The method of claim 1, wherein the RPM macromolecule is a
hydrophilic polymer selected from natural gums and a chemically
modified derivative thereof.
22. The method of claim 21, wherein the RPM macromolecule is guar,
carrageenan, gum Arabic, gum ghatti, karaya, tragacanth, pectin,
starch, locust bean gum, scleroglucan, tamarind, xanthan gums or a
hydroxyethyl, hydroxypropyl, hydroxypropylcarboxymethyl,
hydroxyethylcarboxymethyl, carboxymethyl or methyl cellulose
derivative.
23. A method for controlling water by treating a subterranean
formation in a production well, comprising introducing a water
control treatment fluid into said formation through said production
well, said water control treatment fluid comprising: (a) an
organosilicon compound comprising an organosilane halide or an
organosilane alkoxide; and (b) a relative permeability modifier
(RPM) macromolecule capable of impeding the production of water
wherein said water control treatment fluid is introduced at a flow
rate less than that necessary to fracture said formation.
24. The method of claim 23, wherein the organosilicon compound is
capable of binding both to the RPM macromolecule as well as to
formation substrate minerals.
25. The method of claim 24, wherein the formation substrate
minerals include quartz, clay, shale, silt, chert, zeolite, or a
combination thereof.
26. The method of claim 23, wherein the formation permeability in
the subterranean formation is from about 0.1 to about 8,000 md.
27. A method for treating a subterranean formation, comprising: (a)
introducing a water control treatment fluid into said formation,
said water control treatment fluid comprising: (i.) an
organosilicon compound comprising an organosilane halide or an
organosilane alkoxide; and (ii.) a relative permeability modifier
(RPM) macromolecule capable of impeding the production of water
wherein said water control treatment fluid is introduced into said
subterranean formation prior to, together with, or following a
hydraulic fracturing or stimulation fluid into said subterranean
formation.
28. The method of claim 27, wherein the organosilicon compound is
capable of binding both to the RPM as well as to formation
substrate minerals.
29. The method of claim 28, wherein the formation substrate
minerals include quartz, clay, shale, silt, zeolite or a
combination thereof.
30. The method of claim 27, wherein the formation permeability
ranges from about 0.1 to about 8,000 md.
31. A method of treating a subterranean water injection well by
introducing a treatment fluid into said formation through said
water injection well, said treatment fluid comprising: (a) an
organosilicon compound capable of forming a water-soluble silanol
by hydrolysis; and (b) a relative permeability modifier (RPM)
macromolecule capable of reducing the permeability of the primary
water pathway within the formation wherein said treatment fluid is
introduced at a flow rate below that necessary to fracture said
formation.
32. The method of claim 31, wherein the organosilicon compound is
capable of binding both to the RPM macromolecule as well as to
formation substrate minerals.
33. The method of claim 32, wherein the formation substrate
minerals include quartz, clay, shale, silt, chert, zeolite, or a
combination thereof.
34. The method of claim 31, wherein the formation permeability of
the subterranean water injection well is from about 0.1 to about
8,000 md.
35. The method of claim 1, wherein the organosilicon compound and
RPM macromolecule is present in the aqueous composition in an
amount capable of imparting a resistance factor for water of
greater than about 5 and a resistance factor for oil of less than
about 2, each of said water and oil resistance factors being
measured at a laminar stable flow rate at constant pressure.
36. The method of claim 27, wherein the water control treatment is
introduced into the formation at flow rates below a flow rate that
would cause pressures to exceed those necessary to fracture the
formation.
37. The method of claim 1, wherein the aqueous composition is a
stimulation fluid.
38. The method of claim 23, wherein the aqueous composition is
introduced into the subterranean formation prior to, together with,
or following a stimulation fluid.
39. The method of claim 23, wherein the water control treatment
fluid further comprises a mutual solvent.
40. The method of claim 35, wherein the resistance factor for water
is greater than 8.0.
41. A water treatment fluid for use in an oil or gas well
comprising a mixture of: (a) an organosilicon compound capable of
forming a water soluble silanol by hydrolysis; and (b) a relative
permeability modifier (RPM) macromolecule capable of impeding the
production of water in the oil or gas well.
42. The water treatment fluid of claim 41, wherein the
concentration of RPM in the water treatment fluid is between from
about 100 to about 80,000 ppm.
43. The water treatment fluid of claim 41, wherein the
concentration of organosilicon compound is between from about 500
to about 20,000 ppm.
44. The water treatment fluid of claim 41, wherein the
organosilicon compound is capable of binding both to the RPM as
well as formation substrate minerals in the well.
45. The water treatment fluid of claim 41, wherein the
organosilicon compound is an organosilane halide of the formula:
9wherein X is a halogen, R.sub.1 is an organic radical having from
1 to 50 carbon atoms, and R.sub.2 and R.sub.3 are the same or
different halogens or organic radicals having from 1 to 50 carbon
atoms.
46. The water treatment fluid of claim 45, wherein X is a halogen
selected from the group consisting of chlorine, bromine and iodine,
R.sub.1 is an alkyl, alkenyl or aryl group having from 1 to about
18 carbon atoms and R.sub.2 and R.sub.3 are the same or different
halogens or alkyl, alkenyl or aryl group having from 1 to about 18
carbon atoms.
47. The water treatment fluid of claim 46, wherein X is
chlorine.
48. The water treatment fluid of claim 41, wherein the
organosilicon compound is an organosilane halide selected from
methyldiethylchlorosilan- e, dimethyldichlorosilane,
methyltrichlorosilane, dimethyldibromosilane, diethyldiiodosilane,
dipropyldichlorosilane, dipropyldibromosilane,
butyltrichlorosilane, phenyltribromosilane, diphenyldichlorosilane,
tolyltribromosilane, propyldimethoxychlorosilane and
methylphenyldichlorosilane.
49. The method of claim 41, wherein the organosilicon compound is
an organosilane alkoxide of the formula: 10wherein R.sub.4, R.sub.5
and R.sub.6 are independently selected from hydrogen and organic
radicals having from 1 to about 50 carbon atoms, provided 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 about 50 carbon atoms.
50. The water treatment fluid of claim 49, wherein R.sub.4, R.sub.5
and R.sub.6 are independently selected from hydrogen, amine, alkyl,
alkenyl, aryl and carbohydroxyl groups having from 1 to about 18
carbon atoms, with at least one of the R.sub.4, R.sub.5 and R.sub.6
groups not being hydrogen and R.sub.7 is selected from amine,
alkyl, alkenyl, and aryl groups having from 1 to about 18 carbon
atoms.
51. The water treatment fluid of claim 41, wherein the RPM
macromolecule has a molecular weight between from about 50,000 to
about 20,000,000 g/mole.
52. The water treatment fluid of claim 51, wherein the RPM
macromolecule has a molecular weight between from about 100,000 to
about 5,000,000 g/mole.
53. The water treatment fluid of claim 52, wherein the RPM
macromolecule has a molecular weight between from about 250,000 to
about 2,000,000 g/mole.
54. The water treatment fluid of claim 41, wherein the RPM
macromolecule is derived from acrylamide.
55. The water treatment fluid of claim 54, wherein the RPM
macromolecule is a homopolymer or copolymer of acrylamide which has
been sulfonated or quaternized.
56. The water treatment fluid of claim 41, wherein the RPM
macromolecule is a copolymer of acrylamide and at least one monomer
selected from acrylic acid, (meth)acrylic acid,
dimethyldiallylammonium chloride, acrylamidoethyltrimethylammonium
chloride, methacrylamidoethyltrimethylam- monium chloride,
acrylamidomethylpropanesulfonic acid, N-vinyl pyrrolidone, N-vinyl
formamide, N-vinyl acetamide, N-vinylmethylacetamide,
acrylamidoethyltrimethylammonium chloride, vinyl sulfonic acid,
maleic acid, itaconic acid, styrene sulfonic acid,
methylenebisacrylamide, vinylsulfonic acid and vinylphosphonic acid
and sulfonate monomers thereof.
57. The water treatment fluid of claim 41, wherein the RPM
macromolecule is a polyvinylalcohol or polysiloxane.
58. The water treatment fluid of claim 57, wherein the
polyvinylalcohol has a degree of hydrolysis between from about 50%
to about 100%.
59. The water treatment fluid of claim 41, wherein the RPM
macromolecule is a hydrophilic polymer selected from natural gums
and a chemically modified derivative thereof.
60. The water treatment fluid of claim 59, wherein the RPM
macromolecule is guar, carrageenan, gum Arabic, gum ghatti, karaya,
tragacanth, pectin, starch, locust bean gum, scleroglucan,
tamarind, xanthan gums or hydroxyethyl, hydroxypropyl,
hydroxypropylcarboxymethyl, hydroxyethylcarboxymethyl,
carboxymethyl or methyl cellulose derivative.
Description
FIELD OF THE INVENTION
[0001] This invention relates generally to methods and compositions
for modifying the permeability of subterranean formations. In
particular, this invention relates to methods and compositions for
selectively reducing the production of water from subterranean
formations; the composition being a water control treatment fluid
containing a relative permeability modifier (RPM) macromolecule and
an organosilicon compound.
BACKGROUND OF THE INVENTION
[0002] Production of water and aqueous fluids from oil and gas
wells is a common phenomenon which poses a variety of problems. For
example, water production typically reduces the amount of oil
and/or gas that may be ultimately recovered from a well since the
water takes the place of other fluids that may flow or be lifted
from the well. Thus, water production from oil and gas wells causes
significant economic drawbacks. High water rates cause a reduction
in well productivity and increase in operating expenditures.
Furthermore, operating costs associated with disposal of produced
water in an environmentally safe manner typically increase with the
volume of produced water, thus increasing the threshold amount of
hydrocarbons that must be produced in order to continue economical
production of the well.
[0003] U.S. Pat. No. 5,228,812 discloses a chemical treatment that
selectively reduces water production. Such treatments employ
relative permeability modifiers (RPMs). The use of RPMs offer
several advantages. For instance, the use of RPMs reduces costs
since the chemicals are used in limited quantities and the
treatment does not require zonal isolation. In addition, the use of
RPMs entails low risk since the polymer reduces the water
permeability without affecting oil permeability. Further, RPMs are
simple to apply and do not require expensive equipment, such as
rigs, for their application.
[0004] However, even the most superior RPMs are not certain to
impart long-lasting effectiveness, nor exhibit a high degree of
water flow resistance relative to oil flow, especially when
formation permeability rises above 1 Darcy. New RPM systems are
needed for higher permeability applications.
SUMMARY OF THE INVENTION
[0005] Compositions useful for selective permeability modification
of subterranean formations to reduce or substantially eliminate the
amount of water produced from oil and/or gas wells comprise a
relative permeability modifier (RPM) macromolecule capable of
impeding the production of water and an organosilicon compound. The
compositions of the invention reduce or eliminate the production of
water in an oil or gas well without substantially affecting the
production of hydrocarbons.
[0006] Suitable as the RPM are homopolymers and copolymers of
acrylamide, optionally having been sulfonated or quaternized,
polyvinylalcohol, polysiloxane, or a hydrophilic polymer selected
from natural gums and chemically modified derivatives thereof.
[0007] In a preferred embodiment, the organosilicon compound is of
the formula: 1
[0008] wherein R is a halogen, hydrogen, or an amine radical which
can be substituted with hydrogen, organic radicals, or silyl
groups, R.sub.1 is hydrogen, an amine, or an organic radical having
from 1 to 50 carbon atoms, and R.sub.2 and R.sub.3 are hydrogen or
the same or different halogens, alkyl, alkenyl, aryl or amines
having 1 to 50 carbon atoms; or 2
[0009] wherein R.sub.4, R.sub.5 and R.sub.6 are independently
selected from hydrogen, amine, halogen, alkoxide, and organic
radicals having from 1 to 50 carbon atoms, provided 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.
[0010] The organosilicon compound increases flow resistance and is
believed to attach to the RPM polymer as well as to the mineral
surfaces of the formation. As a result, the effective RPM
permeability application range is significantly extended with the
novel compositions.
[0011] The compositions of the invention are designed to partition
both onto reservoir rock and into reservoir brines. Such behavior
results in significant reduction of permeability in water-rich
environments.
[0012] Advantageously, the disclosed method and compositions are
relatively non-damaging to oil permeability, for example, in oil
saturated sandstone while exhibiting the ability to decrease water
permeability substantially in water saturated zones. Therefore, the
disclosed compositions may be applied successfully to a productive
zone without the necessity of mechanical isolation in the wellbore.
It will be understood with benefit of this disclosure that
mechanical isolation, such as isolation of a water producing
section or perforations, may be employed if so desired, however,
such measures may add significant costs to a water control
treatment. Consequently, treatments utilizing the disclosed method
and compositions without mechanical isolation are considerably less
expensive than conventional methods which require such
measures.
[0013] In one respect, disclosed is a method for treating a
subterranean formation, including introducing an aqueous
composition into the formation wherein the concentration of RPM in
the aqueous composition is between from about 100 to about 80,000
ppm, preferably from about 500 to about 10,000 ppm, and the
concentration of organosilicon compound is between from about 500
to about 20,000 ppm. While not intending to be bound to any theory,
it is believed that the organosilicon compound is capable of
binding both to the RPM as well as formation substrate minerals in
the well.
[0014] The invention has particular applicability in those
situations where the formation permeability in the oil or gas well
is between from about 0.1 to about 8,000 md. Further, the formation
substrate minerals may include quartz, clay, shale, silt, chert,
zeolite, or a combination thereof.
[0015] In the practice of this method, the composition is a water
control treatment fluid which may optionally be a stimulation
fluid. The water control treatment fluid may be introduced into the
subterranean formation prior to, together with, or following a
hydraulic fracturing or stimulation fluid treatment.
[0016] In one embodiment, the composition of the invention may be
used to contact the subterranean formation and substantially reduce
permeability to water within the formation without substantially
reducing permeability to oil within the formation. In another
embodiment, the composition of the invention may be used to contact
the subterranean formation so that it has a post-treatment
resistance factor, for water of greater than or equal to about 5
and a post-treatment resistance factor for oil of less than 2, as
measured across a Berea core, such as about 2.5 cm diameter by
about 4 cm long and having a permeability to nitrogen of about 1000
md, each of the water and oil resistance factors being measured at
stable laminar flow rate at constant pressure.
BRIEF DESCRIPTION OF THE DRAWINGS
[0017] In order to more fully understand the drawings referred to
herein, a brief description of each drawing is presented, in
which:
[0018] FIG. 1 illustrates results obtained by use of a water
treatment fluid containing 3% RPM and 0.5% of an aqueous solution
containing approximately 50% organosilicon compound in a high
permeability Berea core. As used herein all percentages are weight
percentages unless otherwise noted.
[0019] FIG. 2 illustrates results obtained by use of a water
treatment fluid containing 4% RPM and 0.3% of an aqueous solution
containing approximately 50% organosilicon compound in a high
permeability Berea core.
[0020] FIG. 3 illustrates results obtained by use of a water
treatment fluid containing 5% RPM and 0.5% of an aqueous solution
containing approximately 50% organosilicon compound in a high
permeability Berea core.
[0021] Each of the figures demonstrates that treatment of an oil or
gas well with the aqueous system of the invention significantly
reduces water flow relative to oil flow in very high permeability
cores.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
[0022] The aqueous compositions of the invention described herein
may be utilized in well treatment methods to selectively reduce the
permeability of a subterranean formation to water, while at the
same time leaving the permeability of the formation to oil
virtually unchanged. In a preferred embodiment, the post-treatment
resistance factor for water is greater than or equal to 5.0,
preferably in excess of 9 or more. 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.
[0023] The aqueous compositions of the invention contain a relative
permeability modifier (RPM) and an organosilicon compound.
[0024] The RPM for use in the invention is any polymer that can
impede the production of water and which provides suitable
attachment, such as grafting, sites for the organosilicon compound.
Most often the RPM is hydrophilic having the ability to remain
hydrated in the formation waters and simultaneously having an
affinity to adsorb onto the solid formation material. Such RPMs
typically have weight average molecular weights ranging from about
50,000 to about 20,000,000 g/mole, preferably from about 100,000 to
about 5,000,000 g/mole, most preferably from about 250,000 to about
2,000,000 g/mole.
[0025] In addition to the molecular weight, the RPMs must also have
specific sites that allow interaction with the organosilicon
compound. Most often, interaction of the RPM polymeric material and
the silicon-containing organic compound occurs with any oxygen
containing pendent group on the polymeric material, particularly
the hydroxyl group. However, many of the silicon-based agents are
multifunctional having additional functional groups attached to the
silicon-based agent. In most cases, these additional groups are
generally non-oxygen-bearing groups, but could also interact with
specific sites on the RPM. The additional functional groups on the
silicon-containing organic compound include amines, isocyanates,
amides, thio-based and phosphorus-based groups. These additional
functional groups can also interact with the specific sites of the
RPM. For example, amine functional groups on the silicon-containing
organic compound can interact with polymers having carboxylic acid
groups or aldehyde groups to form either amides or Schiff bases.
Another example is silicon-based agents having isocyanate or
isothiocyanate functional groups that can interact with amine- or
alcohol-based RPMs to produce urethane type linkages.
[0026] Any RPM that offers an attachment site for the organosilicon
compound will provide, to some degree, a favorable response to
impede water production and thus be sufficient as the RPM. Suitable
RPMs include those referenced in U.S. Pat. Nos. 5,735,349;
6,169,058; and 6,228,812, herein incorporated by reference.
[0027] Suitable RPMs include copolymers of hydrophilic monomers and
a second monomer. Hydrophilic 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. In addition,
an anionic monomer, such as salts of acrylates, may be used in
conjunction with a cationic monomer. Examples of suitable nonionic
hydrophillic monomers include, but are not limited to acrylamide,
(meth)acrylamide, N-vinyl pyrrolidone, N-vinyl formamide and
N-vinylacetamide. 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"), acrylic acid,
(meth)acrylic acid, 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. Suitable as the second
monomer are N-vinylformamide, N-methylacetamide,
N,N-diallylacetamide, methylenebisacrylamide or a mixture
thereof.
[0028] Preferred polymers applicable for use in the invention as
the RPM include homopolymers, copolymers and terpolymers based on
acrylamide, particularly those that are sulfonated or quaternized
for solubility in high saline formation brines. In a preferred
mode, such acrylamide copolymers may contain other components such
as acrylic acid or (meth)acrylic acid, or a salt thereof,
dimethyldiallylammonium chloride, acrylamidoethyltrimethylammonium
chloride, methacrylamidoethyltrimethylam- monium chloride,
acrylamidomethylpropanesulfonic acid (AMPS), N-vinyl pyrrolidone,
N-vinyl formamide, N-vinyl acetamide, N-vinylmethylacetamide,
acrylamidoethyltrimethylammonium chloride, vinyl sulfonic acid,
maleic acid, itaconic acid, styrene sulfonic acid, vinylsulfonic
acid, methylenebisacrylamide and vinylphosphonic acid and sulfonate
monomers thereof.
[0029] RPMs may further include homopolymers or copolymers which
include the following monomeric units: acrylic acid, (meth)acrylic
acid, dimethyldiallylammonium chloride as well as
acrylamidoethyltrimethylammon- ium chloride,
methacrylamidoethyltrimethylammonium chloride,
acrylamidomethylpropanesulfonic acid (AMPS), N-vinyl pyrolidone,
N-vinyl formamide, N-vinyl acetamide, N-vinylmethylacetamide,
acrylamido ethyltrimethylammonium chloride, maleic acid, itaconic
acid, styrene sulfonic acid, vinylsulfonic acid and vinylphosphonic
acid and sulfonate monomers, i.e., those monomers containing
SO.sub.3 pendant or functional groups and salts thereof, such as
those derived with sodium or potassium, or quaternary ammonium
salts. The chloride counter ion referenced above may also be
substituted, for example, with any other halogen, sulfate, or
phosphate. Other suitable monomeric units include dimethyldiallyl
ammonium sulfate, methacrylamido propyl trimethyl ammonium bromide,
and methacrylmaido propyl trimethyl ammonium bromide.
[0030] For example, in one embodiment of the invention, the RPM may
include at least one nonionic vinylamide monomer of the
formula:
CH.sub.2=C(R)--C(O)N(R').sub.2 (I)
[0031] where R and R' independently represent a hydrogen, methyl,
ethyl or propyl moiety. In a second embodiment, the RPM may further
include at least one monomer containing anionic moieties of the
formula:
CH.sub.2=CHC(O)X (II)
[0032] where X represents a moiety containing a carboxylic acid or
salt of that acid or a moiety containing a salt of a sulfonic acid
or the salt of a sulfuric acid.
[0033] Lastly, synthetic polymers based on vinyl acetate to produce
polyvinylalcohol (PVA) are also applicable as are polysiloxanes or
silicones. The most preferred polymers are PVA having degrees of
hydrolysis between from about 50% to about 100% and polyacrylamides
as described in U.S. Pat. No. 6,228,812 B1 and 5,379,841.
[0034] In general the silicones are polymers containing the
following units: 3
[0035] of molecular weight sufficient to afford a viscosity
suitable for use in well treatment methods known to those of skill
in the art. Generally, the polysiloxanes for use as the RPM have a
maximum molecular weight of about 20,000 to about 30,000 or an n
value from 2 to about 500, though higher molecular weights may be
formed in situ.
[0036] Preferred polysiloxanes include polysiloxane polyalkyl
polyether copolymers. The preferred organo group is a mixture of
hydrocarbon such as alkyl and alkoxide and most preferably being
methyl and methoxide or ethoxide. Inclusive of preferred
polysiloxanes are those of the formula: 4
[0037] Suitable hydrophilic polymers further include natural gums
such as guar, carrageenan, gum Arabic, gum ghatti, karaya,
tragacanth, pectin, starch, locust bean gum, scleroglucan, tamarind
and xanthan gums and any chemically modified derivatives of these
gums including derivatives of cellulose such as the pendent
derivatives hydroxyethyl, hydroxypropyl,
hydroxypropylcarboxymethyl, hydroxyethylcarboxymethyl,
carboxymethyl or methyl.
[0038] The organosilicon compounds for use in the aqueous
compositions are generally capable of binding both to the RPM as
well as to formation substrate minerals including quartz, clay,
chert, shale, silt, zeolite or a combination thereof.
[0039] Suitable water-soluble organosilicon compounds for the
invention include, without limitation, amino silanes such as
3-aminopropyltriethoxy silane and
N-2-aminoethyl-3-aminopropyltrimethoxy silane, and vinyl silane
compounds such as vinyl tris-(2-methoxyethoxy) silane. However, as
discussed by M. R. Rosen, "From Treating Solution to Filler Surface
and Beyond. The Life History of a Silane Coupling Agent," Journal
of Coatings Technology, Vol. 50, No. 644, pages 70-82 (1978), many
organosilane compounds are water-soluble for prolonged periods of
time after they hydrolyze to form silanols, and temperatures can
serve to aid the hydrolysis. For purposes of the present invention,
then, compounds which form water-soluble silanols by hydrolysis
will be considered as equivalent to the originally water-soluble
organosilicon compounds. Such organosilicon compounds include
organosilane halides and organosilane alkoxides.
[0040] Among the organosilanes especially suitable for use in this
invention are those organosilane halides of the formula: 5
[0041] wherein X is a halogen, R.sub.1 is an organic radical having
from 1 to 50 carbon atoms, and R.sub.2 and R.sub.3 are the same or
different halogens as X or organic radicals of R.sub.1. Preferably,
X is a halogen selected from the group consisting of chlorine,
bromine and iodine with chlorine being preferred, R.sub.1 is an
alkyl, alkenyl, alkoxide or aryl group having from 1 to 18 carbon
atoms and R.sub.2 and R.sub.3 are the same or different halogens,
or alkyl, alkenyl, alkoxide or aryl group having from 1 to 18
carbon atoms.
[0042] Suitable specific organosilane halides include
methyldiethylchlorosilane, dimethyldichlorosilane,
methyltrichlorosilane, dimethyldibromosilane, diethyldiiodosilane,
dipropyldichlorosilane, dipropyldibromosilane,
butyltrichlorosilane, phenyltribromosilane, diphenyldichlorosilane,
tolyltribromosilane, methylphenyldichlorosilane,
propyldimethoxychlorosilane and the like.
[0043] Among the organosilane alkoxides suitable for use in this
invention are those having the formula: 6
[0044] 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, provided 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. Preferably, R.sub.4, R.sub.5, and R.sub.6 are
independently selected from hydrogen, amine, alkyl, alkenyl, aryl,
and carbhydryloxy groups having from 1 to 18 carbon atoms, with at
least one of the R.sub.4, R.sub.5, and R.sub.6 groups not being
hydrogen, and R.sub.7 is selected from amine, alkyl, alkenyl, and
aryl groups having from 1 to 18 carbon atoms. When R.sub.4,
R.sub.5, and R.sub.6 are carbhydryloxy groups, alkoxy groups are
preferred.
[0045] Suitable specific organosilane alkoxides include
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-aminopropyltrim- ethoxysilane,
3-aminopropyltriethoxysilane, tetraethoxysilane and the like.
[0046] The presence of the amine function appears to result in a
stronger adsorption of the silane on the formation rock. The
resultant polymer renders the treated portion of the formation less
oil wet than when a non-amine-containing silane is employed. Thus,
in subsequent production of oil through the formation, less oil is
retained by the formation and more of the oil is produced.
[0047] For purposes of brevity and clarity, the terms "amine,"
"alkyl," "alkenyl," "aryl," and "carbhydryloxy" have been used
above to describe substituents of organosilanes and alkoxides of
organosilanes which are useful in the practice of the invention. It
is to be understood that these substituents may themselves be
substituted or unsubstituted and that each, except for aryl
species, may be branched or unbranched.
[0048] Such organosilicon compounds are disclosed in U.S. Pat. No.
4,580,633 and 4,708,207, herein incorporated by reference.
[0049] 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.
[0050] In one embodiment, a subterranean formation may be treated
using the disclosed aqueous composition by introducing the aqueous
composition of the invention into the formation through a wellbore.
Such a water control treatment fluid may be formulated with the
aqueous composition and an aqueous base fluid. The weight
percentage of aqueous composition being the RPM macromolecule and
organosilane together in the composition of the invention is
generally about 0.01 to about 15.0 weight percent. As set forth in
Example 1, the amount of combined RPM macromolecule and
organosilicon compound in the aqueous composition of the invention
may be between from about 0.02% to about 4.60%, preferably from
about 0.17% to 0.70%, weight percentage.
[0051] 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 etc.
[0052] 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, glycol-ether (such as ethylene glycol monobutyl ether,
"EGMBE"), or mixtures thereof.
[0053] 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, surfactants, thickeners,
diversion agents, pH buffers, etc. may 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.
[0054] 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.).
[0055] It will also be understood with benefit of this disclosure
that the disclosed aqueous composition may be mixed with an aqueous
base fluid to form a "spearhead" fluid to precede the introduction
of a stimulation fluid or other well treatment fluid. This may be
done, for example, to achieve diversion of a stimulation fluid into
hydrocarbon bearing areas of the formation by virtue of the
copolymer's deleterious effect on permeability to water in water
bearing areas of the formation. Alternatively, or additionally, the
aqueous composition may follow such a well treatment fluid and/or
be combined with the body of such a well treatment fluid, or used
in any combination thereof. In any case, the introduction of the
aqueous composition into a subterranean formation in conjunction
with a well treatment, such as a stimulation treatment, may be used
to advantageously place the composition in a position to reduce
production of water following the stimulation treatment. Examples
of procedural details for use of water control materials in
conjunction with well treatments may be found in U.S. Pat. No.
6,169,058, incorporated herein by reference.
[0056] 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 organosilicon compounds are present in the
treatment fluid at a total concentration of from about 500 ppm to
about 10,000 ppm polymer, alternatively from about 1000 ppm to
about 5,000 ppm polymer, based on the total weight of the water
control treatment fluid.
[0057] 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.
[0058] 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.
[0059] 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.
[0060] When employed in conjunction with a non-fracture treatment
water control treatment fluid, introduction rates for either batch
or continuous mixed water control treatment fluids are typically
held below flow rates that would cause pressures to exceed those
necessary to fracture the formation being treated. In this regard,
flow rates may be adjusted during treatment fluid introduction to
ensure that pressures are maintained below those necessary for
fracturing.
[0061] When used in conjunction with well treatments such as
stimulation treatments, treatment fluid introduction flow rates
typically depend on the nature of the treatment being performed.
For example, in the case of a matrix acid treatment the disclosed
copolymer compositions may be included in a "spearhead" fluid ahead
of the acid treatment, in the acid treatment, or following the acid
treatment (or in any combination of steps before, in, or after the
acid treatment), and are typically introduced at a rate below the
flow rate necessary to fracture the formation in a manner similar
to the rate employed for a water control treatment fluid injected
alone. When used in conjunction with a hydraulic fracture
treatment, fluid introduction rates (whether utilized as a
spearhead, in the fracture treatment fluid, or both) are typically
above rates that cause pressures to exceed those necessary to
fracture a formation. Whether employed as a stand-alone fluid or in
a stimulation fluid (such as an acid fluid or hydraulic fracture
fluid), similar concentrations of copolymer compositions are
typically employed.
[0062] In one water control treatment embodiment for treating a
subterranean formation in a production well, the well may be
shut-in from about 6 to about 48 hours after introduction of a
water control treatment fluid in order to allow maximum anchoring
and retention of the aqueous composition. Following such a shut-in
period, the well may be placed back on production. In another water
control treatment embodiment for treating an injection well, a
water control treatment fluid may be injected in a manner similar
to that described for treatment of a production well, with the
exception that the injection well is not typically shut-in after
injecting the treatment fluid, but is instead placed back on
injection immediately. In this embodiment, the aqueous composition
is expected to ultimately improve the water sweep efficiency in the
reservoir by reducing water channeling from the injector to
surrounding producing wells. Such a condition may be the case, for
example, in injection wells where water channeling is suspected to
be occurring through high permeability streaks in the formation
strata penetrated by the injection well.
[0063] With benefit of the present disclosure, it will be
understood that the disclosed aqueous composition when placed in a
subterranean formation may induce an artificial pressure barrier
and, in the case of the treatment of vertical coning problems, may
be placed beyond the wellbore to an area beyond that influenced by
the critical draw down pressure responsible for vertical water
migration.
[0064] Although the disclosed method and compositions may be
employed as a water control treatment at any time in the producing
life of a production well or the injection life of an injection
well, it may be desirable to perform such treatment as soon as a
coning or channeling problem (or potential coning or channeling
problem) is identified, rather than waiting to the point where
coning or channeling becomes severe.
[0065] In a preferred embodiment, permeability to water in a
subterranean formation may advantageously be reduced without
substantially reducing permeability to oil in the formation. In
this regard, the measure of reduction of permeability of a
subterranean formation to a given fluid may be expressed as the
resistance factor, R.sub.f. For example, the quotient of
permeability to water at irreducible oil saturation prior to
treatment (K.sub.wi) to the permeability to water at irreducible
oil saturation after treatment (K.sub.wf) is defined herein as the
resistance factor, R.sub.f for water. In this regard, the disclosed
methods and compositions are capable of achieving a water
resistance factor, R.sub.f, of greater than or equal to about 5,
preferably greater than 8 or 9, measured at laminar flow rates of
about 0.05 to 10.0 ml/min across a 2.5 cm diameter core.
[0066] Similarly, the quotient of permeability to oil at
irreducible water saturation before treatment (K.sub.oi) to
permeability to oil at irreducible water saturation after treatment
(K.sub.of) is defined herein as the resistance factor, R.sub.f, for
oil. Advantageously, the disclosed method and compositions may be
used to obtain an oil resistance factor, R.sub.f, of from about 1
to about 2, alternatively from about 1 to about 1.5, and
alternatively of less than about 2 at flow rates of about 0.05 to
6.0 ml/min across a 2.5 cm diameter core, at the same time the
above-described water resistance factors are achieved.
[0067] Use of the aqueous compositions of the invention is
applicable in high permeability producing wells previously not
considered by RPM-containing compositions of the prior art. In a
preferred embodiment, the aqueous compositions of the invention are
used with a systematic approach consisting of proper pre-flushes
and post-flushes. In a preferred embodiment, wells to be treated
are produced from multi-layered sandstone formations with one or
more layers that are still saturated with hydrocarbon. Otherwise
distinct water and hydrocarbon production within the production
interval(s) is desirable. Preferably, no cross-flow between layers
exists.
[0068] The aqueous compositions of the invention have particular
applicability in those instances where the formation permeability
is between from about 0.1 to about 8,000 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 7.0 Darcy under high rate flow
conditions.
[0069] If the RPM treatment is placed in homogeneous zones
producing both water and hydrocarbon (fractional flow), both water
and hydrocarbon permeability may be decreased significantly.
Ideally, resistance to water flow will substantially exceed
resistance to hydrocarbon (oil or gas) flow, following RPM
treatment.
[0070] RPM treatment is ideally designed for radial penetration of
10 ft. However, as a practical matter, adequate treatment design
may be for radial penetration of 5 to 8 ft. The RPM treatment can
be bullheaded. However, it may be preferable to place the treatment
through coiled tubing, especially in longer intervals.
[0071] The following examples will illustrate the practice of the
present invention in its preferred embodiment. Other embodiments
within the scope of the claims herein will be apparent to one
skilled in the art from consideration of the specification and
practice of the invention as disclosed herein. It is intended that
the specification, together with the example, be considered
exemplary only, with the scope and spirit of the invention being
indicated by the claims which follow.
EXAMPLES
[0072] The Examples illustrate that the compositions of the
invention are highly effective in sandstone formations having
absolute permeabilities to brine of 1.5 to 7.0 Darcy in that water
flow relative to oil flow is significantly reduced in such high
permeability sandstone cores. Unless specified to the contrary, all
percentages herein refer to weight percentages.
Example 1
[0073] The treatment fluid used in this test contains an RPM
macromolecule concentrate containing 15% N-vinylformamide, 30%
AMPS, 54.9% acrylamide and at most, about 0.1%
methylenebisacrylamide packaged as a 3% polymer solution in 1%
sodium chloride and the polymer has a Fikentcher K value of about
250 prior to the addition of salt. The treating fluid was prepared
by diluting 3% (wt) of the RPM macromolecule concentrate in 2%
aqueous potassium chloride and adding 0.5% (wt) organosilane
binding agent, 3-aminopropyltriethoxysilane. The polymer solution
is mixed well prior to use in the test.
[0074] Core flow tests were conducted on Berea core plug cylinders,
measuring 1 in diameter and 3 inches in length, having N.sub.2
permeabilities of 1000 md. The core plugs were evacuated with air
and then saturated with 2% aqueous solution of potassium chloride
(KCl). The core was then installed in a core holder. Approximately
200 psi back pressure was applied at the exit end and approximately
1,000 psi confining stress (overburden pressure) was applied around
the entire cylinder. The confining stress pressure simulates stress
in the downhole formation. After these pressures are applied and
set, the temperature was elevated to 150.degree. F. (simulation of
the reservoir temperature). Sequential flows of water and oil were
injected through the core as discussed in the paragraph below. The
water composition was 2% KCl and the oil was a 50% (wt.) White
Mineral Oil in Isopar L.TM. (Exxon). Each fluid was injected and
pumped at a constant rate of between 0.3 ml/min to 5 ml/min. while
measuring pressure drop along the length of the core. After
obtaining a stable pressure differential, permeabilities were
calculated using Darcy's equation for laminar flow through a
cylindrical core:
k=Q.multidot..mu..multidot.L/.DELTA.P.multidot.A
[0075] where
[0076] k=permeability to liquid, Darcies
[0077] Q=rate of flow, ml/sec
[0078] A=Area, cm.sup.2
[0079] .mu.=viscosity, centipoises
[0080] L=length, cm
[0081] .DELTA.P=pressure differential, atm.
[0082] The water composition was first injected in a production
direction. This simulates the production of water from the
formation into the wellbore. The specific permeability to water
(brine), kw, md (absolute), is tabulated in Column III of Table I.
After introduction of the White Mineral Oil in Isopar L solution,
the effective permeability of the oil at residual oil saturation
was then calculated, represented as ko, md (before) in Column IV of
Table I. The water composition was then injected in the production
direction. Effective permeability to water at residual oil
saturation, represented as kw, md (before) in Column V of Table I,
was then calculated. This is somewhat lower than first water
measurement solution since this simulates water flowing through a
previously oil saturated formation. Approximately 10 pore volumes
of the treatment fluid (the solution of Example 1 in the water
composition) was then injected in the reverse (injection) direction
at a constant rate of 1 ml/min. (This simulates injection from the
wellbore perforation into the formation.) A pore volume is the
volume of fluid that the core can hold at complete fluid
saturation. Shut-in of the treatment fluid at test temperature and
confining pressure was allowed to occur for the designated shut-in
period. The water solution was then injected in the production
direction at a constant rate of 1 ml/min while collecting produced
fluids and monitoring differential pressure. Flow was continued
until a stable differential pressure was obtained. The effective
permeability to water following treatment was then calculated,
represented as kw, md (after) in Column 6 of Table I. ISOPAR-L was
then injected in the production direction at a constant rate of
<10 ml/min. The effective permeability to oil following
treatment, represented as ko, md (after) in Column VI of Table 1
was then calculated.
[0083] Specific core flow tests were conducted on the water
completion fluids of Example 1 at various levels of permeability,
as high as 7.0 Darcy, under high rate flow conditions as
follows:
[0084] The water composition was first injected in a production
direction. This simulates the production of water from the
formation into the wellbore. The specific permeability to water
(brine), kw, md (absolute), is tabulated in Column III of Table I.
After introduction of the White Mineral Oil in Isopar L solution,
the effective permeability of the oil at residual oil saturation
was then calculated, represented as ko, md (before) in Column IV of
Table I. The water composition was then injected in the production
direction. Effective permeability to water at residual oil
saturation, represented as kw, md (before) in Column V of Table I,
was then calculated. This is somewhat lower than first water
measurement solution since this simulates water flowing through a
previously oil saturated formation. Approximately 10 pore volumes
of the treatment fluid (the solution of Example 1 in the water
composition) was then injected in the reverse (injection) direction
at a constant rate of 1 ml/min. (This simulates injection from the
wellbore perforation into the formation.) A pore volume is the
volume of fluid that the core can hold at complete fluid
saturation. Shut-in of the treatment fluid at test temperature and
confining pressure was allowed to occur for the designated shut-in
period. The water solution was then injected in the production
direction at a constant rate of 1 ml/min while collecting produced
fluids and monitoring differential pressure. Flow was continued
until a stable differential pressure was obtained. The effective
permeability to water following treatment was then calculated,
represented as kw, md (after) in Column 6 of Table I. ISOPAR-L was
then injected in the production direction at a constant rate of
<10 ml/min. The effective permeability to oil following
treatment, represented as ko, md (after) in Column VI of Table 1
was then calculated.
[0085] Specific core flow tests were conducted on the water
completion fluids of Example 1 at various levels of permeability,
as high as 7.0 Darcy, under high rate flow conditions as
follows:
[0086] Run 1 (Comparative). 6% RPM macromolecule concentrate in the
treating fluid (without organosilane agent)--4.5 D core
[0087] Run 2: 6% RPM macromolecule concentrate in the treating
fluid with organosilane--1.5 D core
[0088] Run 3: 6% RPM macromolecule concentrate in the treating
fluid with organosilane--1.7 D core
[0089] Run 4: 6% RPM macromolecule concentrate in the treating
fluid with organosilane--7.0 D core
[0090] Run 5: 6% RPM macromolecule concentrate in the treating
fluid with organosilane--5.0 D core
[0091] The test results are summarized in Table 1. To screen
effectiveness in reducing relative permeability to water only, oil
permeabilities were not measured in Runs 1-4. Once the
effectiveness of the Water Control treating fluid system was
determined, the effect on oil permeability was measured with Run 5.
Post-treatment shut-in time, concentrations of the Water Completion
Fluid and effects of buffering the system (from pH>9 to between
7 and 8) were also varied to maximize treatment effectiveness in
reducing permeability to water while maintaining adequate oil
permeability.
1TABLE 1 I. II. III. IV. V. VI. VII. Run Fluid kw, md ko, md kw, md
kw, md ko, md VIII. No. Tested (absolute) (before) (before) (after)
(after) R.sub.fw/R.sub.fo 1 6% RPM 4480 -- 4480 1014 -- 4.4/--
Concentrate 2 6% RPM 1500 -- 1500 80 -- 18.8/-- Concentrate and
Organosilane 3.sup.(1) 6% RPM 1700 -- 1700 180 -- 9.4/--
Concentrate and Organosilane 4 6% RPM 7000 4500 870 151 2255
5.8/2.0 Concentrate and Organosilane 5.sup.(2) 6% RPM 4953 -- 4953
170 -- 29.1/-- Concentrate and Organosilane (buffered)
.sup.(1)Permeability = 400 md after 24-hour shut-in; reduced to 180
md after 72 hours. .sup.(2)Permeability = 170 md after 72-hour
shut-in; increased to 225 md after 84 hours. All Runs were
conducted at 150.degree. F. and post-treatment shut-in time of 72
hours - unless noted.
[0092] System pH buffered to 7.4 (to increase long-term treatment
solution stability). Runs 1 through 5 were evaluations of 6% Water
Control treating Fluid containing 1% by volume of the organosilane,
3-aminopropyltriethoxysilane solution). Tests resulted in no less
than 76% reduction in permeability to water in any case. Run 4
illustrates the effect of Water Completion Fluid on the relative
permeability to oil, as well as to water. After a 72-hour shut-in
period, an 83% reduction in permeability to water was followed by a
50% return permeability to oil. Return oil permeability reached a
point at which the value seemed to stabilize and the test was
halted. Continuation of the flow stage might have resulted in even
higher return values.
[0093] In Run 4, the oil flow stage permeability continued to
increase with time until it reached a point where the values seemed
to stabilize. Continuing oil flow might have possibly increased the
value over a longer time period. Reduction in oil permeability was
similar to the reduction in brine permeability, indicating excess
binding agent relative to Water Control treating Fluid
concentration in this specific test case. Initial oil permeability
was nearly twice the absolute brine permeability--anomalous among
the Berea cores used by both laboratories in this study. Typically,
initial oil permeability is less than absolute brine
permeability.
[0094] Run 5 was also performed using a buffered Water Control
treating Fluid system. A low pH buffer was used to reduce the final
pH of the system from over 9 to between 7 and 8. Lowering the pH of
the system resulted in a higher reduction in permeability to water
when comparing test results where core permeability, treatment
concentration and shut-in time were relatively similar. Runs 4 and
5 were used for this comparison. Absolute permeabilities were 7000
and 4953 md respectively. After the 72-hour shut-in time, the
buffered system (Run 5) resulted in a 97% reduction in permeability
to water compared to 83% for the non-buffered system.
[0095] In each case, permeabilities to water were measured, and the
resistance factor to water was calculated. In those tests in which
oil pre- and post-treatment oil permeabilities were measured,
resistance factor to oil was also calculated. Resistance factors
(Rf) are calculated as follows:
[0096] Rf Water=kw (BT).div.kw (AT)
[0097] Rf Oil=ko (BT).div.ko (AT)
[0098] where kw=permeability to water (brine) at residual oil
saturation
[0099] ko=permeability to oil at residual water (brine)
saturation
[0100] BT=Before Treatment with RPM
[0101] AT=After Treatment with RPM
[0102] High Rf Water (>5-10) relative to Rf Oil (<2-2.5) is
desirable. If water permeability is completely shut off (kw
(AT)=0), then Rf Water=.Yen..
[0103] Results of these tests indicates that the Water Treatment
Fluid of Example 1 effectively reduced relative permeability to
water in high permeability sandstones.
Example 2
[0104] Core flow tests were conducted on Berea core plug cylinders,
measuring 1 in diameter and 3 inches in length, having N.sub.2
permeabilities of 1000 md. The core plugs were evacuated with air
and then saturated with a simulated formation brine comprising a
mixture of 2% potassium chloride (KCl), 5% sodium chloride (NaCl)
and 1% calcium chloride (CaCl.sub.2) Each sample was installed in a
specially designed core holder, with a pressure tap at 1 inch from
the injection face, which was located in an air bath oven. In
addition, approximately 200 psi back pressure was applied at the
exit end and approximately 1,000 psi confining stress (overburden
pressure) was applied around the entire cylinder. The temperature
was then elevated to 150.degree. F. and the test brine was then
injected in the production direction at a constant rate (<10
ml/min) while the produced fluids were collected and differential
pressure versus time was monitored. Specific permeability to brine
was then calculated for each section of the core (Section 1 being
one inch penetration and Section 2 being the remainder of the
core). An oil blend of a 50:50 weight mixture of ISOPAR-L:Chevron
Superla White Oil was then injected in the production direction at
stepwise increasing rates while produced fluids were collected and
differential pressure was monitored until an equilibrium
permeability was established at each rate level. Effective
permeability to oil at initial water saturation versus injection
pressure data was calculated for each section of the core. Test
brine was then injected in the production direction at stepwise
increasing rates while collecting produced fluids and monitoring
differential pressure and elapsed time until an equilibrium
permeability was established at each rate level. Effective
permeability to water at residual oil saturation versus injection
pressure data was calculated for each section of the core.
Approximately 10 pore volumes of the treatment fluid of Example 1
was injected in the injection direction at a constant rate of 0.3
ml/min while produced fluids were collected and differential
pressure was monitored. The sample was then shut in with the
treatment fluid in place for 24 hours. The test brine was then
injected in the production direction at stepwise increasing rates
while the produced fluids were collected and differential pressure
was monitored until an equilibrium permeability was established at
each rate level. Effective permeability to water at residual oil
saturation versus injection pressure data was calculated for each
section of the core. An oil blend of 50:50 weight mixture of
ISOPAR-L:Chevron Superla White Oil was then injected in the
production direction at stepwise increasing rates while produced
fluids were collected and differential pressure was monitored until
an equilibrium permeability was established at each rate level.
Effective permeability to oil at initial water saturation versus
injection pressure data were calculated for each section of the
core. Additional test brine was then injected in the production
direction, differential pressure monitored, effective permeability
calculated and oil blend injected in the production direction and
effective permeability to oil at initial water saturation versus
injection pressure data was calculated for each section of the
core. Return permeability to water and oil data for each section
for each cycle was then calculated.
[0105] Results of these core flow screening tests indicated that
the composition of the invention effectively reduced relative
permeability to water in high permeability sandstones. The results
confirm that the Water Control treating Fluid of the invention was
most effective under the test conditions of 150.degree. F. and over
2-3 Darcy permeability. Treatment effectiveness was sufficiently
retained as flow differential pressure was increased--unprecedented
in cores with greater than Darcy permeability.
[0106] Three tests with high permeability Berea cores were
undertaken. Results are summarized in FIGS. 1, 2 and 3. In each
test, permeabilities to oil and water were measured in two core
sections. The first section (wellbore) was 1" penetration distance,
and the second section (formation) was the remaining core length.
Cores were typically about 4" long. Permeabilities were measured at
stepwise increasing rates. Core section permeabilities were
measured at rates corresponding to 30-40 psi/ft. Core section
permeabilities measured at the highest rate for each flow step are
graphically reported.
[0107] Under these tests, the Water Control treating Fluid system
of Example 1 did not contain buffer to reduce pH to between 7 and
8. Such buffer may increase effectiveness further, as indicated in
Example 2.
[0108] Test 1. In Test 1, a low concentration Water Completion
Fluid system of Example 1 was evaluated (containing 3% Water
Control treating Fluid, 0.5% organosilane,
3-aminopropyltriethoxysilane solution in aqueous 2% KCl solution.
The treatment was effective in significantly decreasing the
relative permeability to water in both sections of the Berea
core--nearly completely shutting off water flow. The substantial
reduction in permeability was retained during the second cycle
injection, indicating binding agent effectiveness. The effective
permeability to oil was reduced to about 40-45% of the original
permeability. This translates to an Rf Oil value of about 1.7. Flow
performance following the second oil cycle was similar; also
showing an increase in oil permeability. The results are reported
in FIG. 1.
[0109] Test 2. In Test 2, a 4% Water Control treating Fluid of
Example 1 containing approximately 0.3% of organosilane,
3-aminopropyltriethoxysila- ne solution was employed. The treatment
did not reduce relative permeability to water in the sections of
the core (overall 41 percent of initial value)--apparently due to
the reduced level of binding agent used. However, this degree of
permeability reduction (Rf Water.about.2.5) was retained during the
second cycle injection--which would not be expected with Water
Control treating Fluid alone at this high permeability level. The
effective permeability to oil was reduced, but to acceptable levels
of 63.4 percent and 66.1 percent initial value overall after cycles
1 and 2, respectively (R.sub.f Oil.about.1.5).
[0110] Test 3. In Test 3, a 5% Water Control treating Fluid system
of Example 1 was tested. The binding agent concentration was
increased to the level used in Test 1, following the results of
Test 2. The 5% Water Control treating Fluid treatment reduced
relative permeability to water significantly (overall 17.5 percent
of initial value). More importantly, the degree of reduction in
brine permeability was retained during the second cycle injection.
The effective permeability to oil was only modestly reduced in this
case (to 74.8 percent of initial value in both flow cycles).
[0111] In summary, the Water Control treating Fluid of the
invention is effective in reducing water flow relative to oil in
very high permeability sandstone (>1.5 Darcy)--extending the
previous estimated practical permeability application range of
Water Control treating Fluids without organosilanes.
[0112] Results of flow testing in high permeability Berea cores
indicate that treatment with the inventive Water Completion Fluid
system significantly reduced water flow relative to oil flow--and
maintained effectiveness with repeated flow cycles--indicating
binding agent effectiveness.
[0113] From the foregoing, it will be observed that numerous
variations and modifications may be effected without departing from
the true spirit and scope of the novel concepts of the
invention.
* * * * *