U.S. patent application number 12/008063 was filed with the patent office on 2008-05-15 for methods for controlling water and particulate production in subterranean wells.
This patent application is currently assigned to Halliburton Energy Services, Inc.. Invention is credited to Larry S. Eoff, Philip D. Nguyen, Thomas D. Welton.
Application Number | 20080110624 12/008063 |
Document ID | / |
Family ID | 40445549 |
Filed Date | 2008-05-15 |
United States Patent
Application |
20080110624 |
Kind Code |
A1 |
Nguyen; Philip D. ; et
al. |
May 15, 2008 |
Methods for controlling water and particulate production in
subterranean wells
Abstract
Improved methods for stabilizing unconsolidated subterranean
formation particulates and reducing permeability of a subterranean
formation to water. Some methods describe methods of stabilizing
unconsolidated subterranean formation particulates and reducing the
permeability of water comprising providing a portion of a
subterranean formation that comprises unconsolidated formation
particulates; introducing a fluid comprising a relative
permeability modifier into at least a portion of the subterranean
formation so as to at least partially reduce the permeability of
that portion of the subterranean formation to water; and,
introducing a fluid comprising a consolidating agent into at least
a portion of the subterranean formation so as to at least partially
consolidate the unconsolidated formation particulates.
Inventors: |
Nguyen; Philip D.; (Duncan,
OK) ; Welton; Thomas D.; (Duncan, OK) ; Eoff;
Larry S.; (Duncan, OK) |
Correspondence
Address: |
ROBERT A. KENT
P.O. BOX 1431
DUNCAN
OK
73536
US
|
Assignee: |
Halliburton Energy Services,
Inc.
|
Family ID: |
40445549 |
Appl. No.: |
12/008063 |
Filed: |
January 8, 2008 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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11545136 |
Oct 10, 2006 |
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12008063 |
Jan 8, 2008 |
|
|
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11183028 |
Jul 15, 2005 |
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11545136 |
Oct 10, 2006 |
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Current U.S.
Class: |
166/281 ;
166/294; 166/295; 507/219; 507/224 |
Current CPC
Class: |
C09K 8/508 20130101;
C09K 8/68 20130101; E21B 43/025 20130101; C09K 8/5751 20130101;
C09K 8/685 20130101; C09K 8/575 20130101 |
Class at
Publication: |
166/281 ;
166/294; 166/295; 507/219; 507/224 |
International
Class: |
E21B 43/26 20060101
E21B043/26; E21B 33/138 20060101 E21B033/138 |
Claims
1. A method of treating a portion of a subterranean formation that
comprises unconsolidated formation particulates, the method
comprising: introducing a fluid comprising a relative permeability
modifier into at least a portion of the subterranean formation; and
then, introducing a fluid comprising a consolidating agent into at
least a portion of the subterranean formation so as to at least
partially consolidate the unconsolidated formation
particulates.
2. The method of claim 1 wherein the portion of the subterranean
formation has been previously hydraulically
fracture-stimulated.
3. The method of claim 1 wherein the consolidating agent comprises
at least one consolidating agent selected from the group consisting
of a resin, a tackifying agent, a gelable liquid composition, and
any combination thereof.
4. The method of claim 1 wherein the relative permeability modifier
fluid comprises at least one relative permeability modifier
selected from the group consisting of a water-soluble,
hydrophobically modified polymer; a water-soluble, hydrophilically
modified polymer; a water-soluble polymer without hydrophobic or
hydrophilic modification; and any combination thereof.
5. The method of claim 1 wherein the relative permeability modifier
fluid comprises an amino methacrylate/alkyl amino methacrylate
copolymer.
6. The method of claim 1 further comprising the step of allowing
the consolidating agent to set for a period of time sufficient to
at least partially consolidate the unconsolidated formation
particulates therein.
7. The method of claim 1 further comprising the step of introducing
a preflush fluid into at least a portion of the subterranean
formation before the step of introducing a consolidating agent into
at least a portion of the subterranean formation.
8. The method of claim 7 wherein the preflush fluid comprises at
least one preflush fluid selected from the group consisting of an
aqueous based-fluid, a hydrocarbon-based fluid, a mutual solvent, a
surfactant, and any combination thereof.
9. The method of claim 1 further comprising the step of introducing
an after-flush fluid into the portion of the subterranean formation
after introduction of the consolidating agent.
10. A method of treating a portion of a subterranean formation that
comprises unconsolidated formation particulates, the method
comprising introducing a treatment fluid comprising a relative
permeability modifier and a consolidating agent into at least a
portion of the subterranean formation so as to at least partially
consolidate the unconsolidated formation particulates.
11. The method of claim 10 wherein the portion of the subterranean
formation has been previously hydraulically
fracture-stimulated.
12. The method of claim 10 wherein the consolidating agent
comprises at least one consolidating agent selected from the group
consisting of a resin, a tackifying agent, a gelable liquid
composition, and any combination thereof.
13. The method of claim 10 wherein the relative permeability
modifier fluid comprises at least one relative permeability
modifier selected from the group consisting of a water-soluble,
hydrophobically modified polymer; a water-soluble, hydrophilically
modified polymer; a water-soluble polymer without hydrophobic or
hydrophilic modification; and any combination thereof.
14. The method of claim 10 wherein the relative permeability
modifier fluid comprises an amino methacrylate/alkyl amino
methacrylate copolymer.
15. The method of claim 10 further comprising the step of allowing
the consolidating agent to set for a period of time sufficient to
at least partially consolidate the unconsolidated formation
particulates therein.
16. The method of claim 10 further comprising the step of
introducing a preflush fluid into at least a portion of the
subterranean formation before placing the treatment fluid.
17. The method of claim 16 wherein the preflush fluid comprises at
least one preflush fluid selected from the group consisting of an
aqueous based-fluid, a hydrocarbon-based fluid, a mutual solvent, a
surfactant, and any combination thereof.
18. The method of claim 10 further comprising the step of
introducing an after-flush fluid into the portion of the
subterranean formation after placing the treatment fluid.
19. A method comprising: providing a portion of a subterranean
formation that comprises unconsolidated formation particulates;
introducing a fluid comprising a relative permeability modifier
into at least a portion of the subterranean formation so as to at
least partially reduce the permeability of that portion of the
subterranean formation to water; and, introducing a fluid
comprising a consolidating agent into at least a portion of the
subterranean formation so as to at least partially consolidate the
unconsolidated formation particulates.
20. The method claim 19 where the step of introducing a relative
permeability modifier fluid is performed before the step of
introducing a consolidating agent.
21. The method claim 19 where the step of introducing a relative
permeability modifier fluid is performed substantially
simultaneously with the step of introducing a consolidating
agent.
22. The method claim 19 where the portion of a subterranean
formation that comprises unconsolidated formation particulates has
been previously hydraulically fractured.
23. The method claim 19 further comprises the step of introducing a
preflush fluid into at least a portion of the subterranean
formation before placing the relative permeability modifier
fluid.
24. The method claim 19 further comprises the step of introducing
an after-flush fluid into the portion of the subterranean formation
after placing the consolidating agent.
Description
CROSS REFERENCE TO RELATED APPLICATIONS
[0001] This application is a continuation-in-part of U.S.
application Ser. No. 11/545,136 filed on Oct. 10, 2006 which is a
continuation-in-part of U.S. application Ser. No. 11/183,208 filed
on Jul. 15, 2005.
BACKGROUND
[0002] The present invention relates to the stabilization of
subterranean formations. More particularly, the present invention
relates to methods for stabilizing unconsolidated portions of a
subterranean formation and controlling the production of water from
those portions.
[0003] Hydrocarbon wells are often located in subterranean
formations that contain unconsolidated particulates that may
migrate out of the subterranean formation with the oil, gas, water,
and/or other fluids produced by the wells. The presence of
particulates, such as formation sand and even loose proppant, in
produced fluids is undesirable in that the particulates may abrade
pumping and other producing equipment and reduce the fluid
production capabilities of the producing zones. Unconsolidated
portions of a subterranean formation include those that contain
loose particulates and those wherein the bonded particulates have
insufficient bond strength to withstand the forces created by the
production of fluids through the formation.
[0004] One method of controlling particulates in such
unconsolidated portions has been to produce fluids from the
formations at low flow rates, so that the near well stability of
sand bridges and the like may be substantially preserved. The
collapse of such sand bridges, however, may occur due to
unintentionally high production rates and/or pressure cycling as
may occur from repeated shut-ins and start ups of a well. The
frequency of pressure cycling is critical to the longevity of the
near well formation, especially during the depletion stage of the
well when the pore pressure of the formation has already been
significantly reduced.
[0005] Another method of controlling particulates in unconsolidated
formations involves placing a filtration bed containing gravel near
the well bore to present a physical barrier to the transport of
unconsolidated formation fines with the production of hydrocarbons.
Typically, such "gravel-packing operations" involve the pumping and
placement of a quantity of a desired particulate into the
unconsolidated formation in an area adjacent to a well bore. One
common type of gravel-packing operation involves placing a
gravel-pack screen in the well bore and packing the surrounding
annulus between the screen and the well bore with gravel of a
specific size designed to prevent the passage of formation sand.
The gravel-pack screen is generally a filter assembly used to
retain the gravel placed during the gravel-pack operation. A wide
range of sizes and screen configurations are available to suit the
characteristics of the gravel-pack sand used. Similarly, a wide
range of sizes of gravel is available to suit the characteristics
of the unconsolidated particulates in the subterranean formation.
The resulting structure presents a barrier to migrating sand from
the formation while still permitting fluid flow. When installing
the gravel pack, the gravel is carried to the formation in the form
of a slurry by mixing the gravel with a viscous treatment fluid.
Once the gravel is placed in the well bore, the viscosity of the
treatment fluid is reduced, and it is returned to the surface.
[0006] Gravel packs act, inter alia, to stabilize the formation
while causing minimal impairment to well productivity. The gravel,
inter alia, acts to prevent formation particulates from occluding
the screen or migrating with the produced fluids, and the screen,
inter alia, acts to prevent the gravel from entering the production
tubing. Such packs may be time consuming and expensive to install.
Due to the time and expense needed, it is sometimes desirable to
place a screen without the gravel. Even in circumstances in which
it is practical to place a screen without gravel, it is often
difficult to determine an appropriate screen size to use as
formation sands tend to have a wide distribution of grain sizes.
When small quantities of sand are allowed to flow through a screen,
formation erosion becomes a significant concern. As a result, the
placement of gravel as well as the screen is often necessary to
assure that the formation sands are controlled. Expandable sand
screens have been developed and implemented in recent years. As
part of the installation, an expandable sand screen may be expanded
against the well bore, cased hole, or open hole for sand control
purposes without the need for gravel packing. However, screen
erosion and screen plugging are the main disadvantages of
expandable screens.
[0007] Another method used to control particulates in
unconsolidated formations involves consolidating unconsolidated
subterranean producing zones into stable, permeable masses by
applying a resin followed by a spacer fluid, a catalyst, and an
after-flush fluid. Such resin application may be problematic when,
for example, an insufficient amount of spacer fluid is used between
the application of the resin and the application of the external
catalyst. The resin may come into contact with the external
catalyst in the well bore itself rather than in the unconsolidated
subterranean producing zone. When resin is contacted with an
external catalyst an exothermic reaction occurs that may result in
rapid polymerization, potentially damaging the formation by
plugging pore channels, halting pumping when the well bore is
plugged with solid material, or resulting in a downhole explosion
as a result of the heat of polymerization. Also, using these
conventional processes to treat long intervals of unconsolidated
regions is not practical due to the difficulty in determining if
the entire interval has been successfully treated with both the
resin and the external catalyst. Further, conventional
consolidation techniques have often resulted in limited or
inadequate penetration distances of consolidating agent into
formations.
[0008] Often, unconsolidated formation sands migrate out of the
formation when water is produced from the formation. This migration
of formation sands is due, in part, to the fact that most natural
cementation between formation sand grains disintegrates when in
contact with an aqueous moving phase. The production of water from
a subterranean producing zone is disadvantageous due to its effect
on mobilizing formation sands, and because water production
constitutes a major expense in the recovery of hydrocarbons from
subterranean formations, especially in light of the energy expended
in producing, separating, and disposing of the water.
SUMMARY
[0009] The present invention relates to the stabilization of
subterranean formations. More particularly, the present invention
relates to methods for stabilizing unconsolidated portions of a
subterranean formation and controlling the production of water from
those portions.
[0010] Some embodiments of the present invention provide methods of
treating a portion of a subterranean formation that comprises
unconsolidated formation particulates, the method comprising:
introducing a fluid comprising a relative permeability modifier
into at least a portion of the subterranean formation; and then,
introducing a fluid comprising a consolidating agent into at least
a portion of the subterranean formation so as to at least partially
consolidate the unconsolidated formation particulates.
[0011] Other embodiments of the present invention provide methods
of treating a portion of a subterranean formation that comprises
unconsolidated formation particulates, the method comprising
introducing a treatment fluid comprising a relative permeability
modifier and a consolidating agent into at least a portion of the
subterranean formation so as to at least partially consolidate the
unconsolidated formation particulates.
[0012] Still embodiments of the present invention provide methods
of stabilizing unconsolidated subterranean formation particulates
and reducing the permeability of water comprising: providing a
portion of a subterranean formation that comprises unconsolidated
formation particulates; introducing a fluid comprising a relative
permeability modifier into at least a portion of the subterranean
formation so as to at least partially reduce the permeability of
that portion of the subterranean formation to water; and,
introducing a fluid comprising a consolidating agent into at least
a portion of the subterranean formation so as to at least partially
consolidate the unconsolidated formation particulates.
[0013] The features and advantages of the present invention will be
apparent to those skilled in the art. While numerous changes may be
made by those skilled in the art, such changes are within the
spirit of the invention.
BRIEF DESCRIPTION OF THE DRAWINGS
[0014] These drawings illustrate certain aspects of some of the
embodiments of the present invention and should not be used to
limit or define the invention.
[0015] FIG. 1 shows a cross-sectional view of a subterranean
formation penetrated by a well bore after treatment with a
consolidating agent and a relative permeability modifier fluid, in
which the consolidating agent has been introduced at a rate and
pressure below the fracture pressure of the subterranean
formation.
[0016] FIG. 2A shows a cross-sectional view of a subterranean
formation penetrated by a well bore after treatment with a
consolidating agent, followed by treatment with a relative
permeability modifier fluid which has been introduced at a rate and
pressure sufficient to create or enhance at least one fracture in
the subterranean formation.
[0017] FIG. 2B shows a cross-sectional view of the subterranean
formation of FIG. 2A wherein a fracturing fluid comprising proppant
particulates has been used to extend further the fracture into the
formation.
DESCRIPTION OF PREFERRED EMBODIMENTS
[0018] The present invention relates to the stabilization of
subterranean formations. More particularly, the present invention
relates to methods for stabilizing unconsolidated portions of a
subterranean formation and controlling the production of water from
those portions.
[0019] I. Examples of Methods of the Present Invention
[0020] One embodiment of the present invention describes a method
of stabilizing an unconsolidated subterranean formation that is
penetrated by a well bore comprising introducing a fluid comprising
a consolidating agent into at least a portion of the subterranean
formation so as to transform a portion of the subterranean
formation surrounding the well bore into a consolidated region; and
introducing a relative permeability modifier fluid into the
subterranean formation through the well bore so as to penetrate at
least a portion of the consolidated region. The relative
permeability modifier fluid, in some embodiments, may penetrate
beyond the consolidated region.
[0021] Another embodiment of the present invention described a
method that comprises introducing a relative permeability modifier
fluid into at least a portion of a subterranean formation to form a
treated portion of the subterranean formation; and introducing a
fluid comprising a consolidating agent into the treated portion of
the subterranean formation so as to transform at least a section of
the treated portion of the subterranean formation into a
consolidated region. In some embodiments, the subterranean
formation may have been previously stimulated via hydraulically
fracturing or any other known stimulation method.
[0022] Another embodiment of the present invention described a
method that comprises introducing a fluid that comprises a relative
permeability modifier fluid and a consolidating agent into at least
a portion of a subterranean formation so as to transform at least a
section of the subterranean formation into a treated, consolidated
region. In some embodiments, the subterranean formation may have
been previously stimulated via hydraulically fracturing or any
other known stimulation method.
[0023] As an example of one embodiment of the methods of the
present invention, FIG. 1 shows a cross-sectional view of
subterranean formation 100 penetrated by well bore 110. First
portion 120 of subterranean formation 100 has been treated with a
consolidating agent to consolidate first portion 120 and form a
consolidated region. Prior to the consolidation of first portion
120, an after-flush fluid may optionally be introduced into
subterranean formation 100 to restore the permeability of first
portion 120 after introduction of the consolidating agent. Further,
after introduction of an after-flush fluid, well bore 110 may
optionally be shut-in for a period of time to allow for
consolidation of first portion 120. Second portion 130 of the
subterranean formation 100 may be treated by a relative
permeability modifier fluid introduced into subterranean formation
through well bore 110 so as to penetrate first portion 120.
[0024] As another example of one embodiment of the methods of the
present invention, FIG. 2A shows a cross-sectional view of
subterranean formation 200 penetrated by well bore 210. First
portion 220 of subterranean formation 200 has been treated with a
consolidating agent to consolidate first portion 220 and form a
consolidated region. A relative permeability modifier fluid has
been introduced at a rate and pressure sufficient to create or
enhance fracture 240 in subterranean formation 200. The relative
permeability modifier fluid may flow into and treat second portion
230. Referring now to FIG. 2B, a fracturing fluid has been
introduced at a rate and pressure sufficient to extend fracture 240
in subterranean formation 200. Fracture 240 may be packed with
proppant to keep fracture 240 open. In this way, the relative
permeability modifier fluid may treat regions that are beyond first
portion 220 that have been consolidated using the consolidating
agent and extend into second portion 230.
[0025] The term, "unconsolidated subterranean formation," as used
herein, refers to both unconsolidated and weakly consolidated
formations. The term, "consolidating agent," as used herein, refers
to any agent that may consolidate a portion of the subterranean
formation, which may, at least in part, stabilize particulates such
that loose or weakly consolidated particulates are prevented from
shifting or migrating once the consolidation treatment is complete.
The term, "relative permeability modifier fluid," as used herein
refers to any fluid, which may, among other things, treat a portion
of the subterranean formation so as to reduce the permeability of
the treated portion to water without substantially reducing the
formation permeability as to hydrocarbons.
[0026] Optionally, other embodiments may include the use of a
preflush fluid and/or an after-flush fluid. Additional embodiments
may include introducing a fracturing fluid to create or enhance
fractures in the subterranean formation. The term, "create or
enhance," as used herein also includes the action of extending
previously created, or natural, fractures. In still other
embodiments portions of the subterranean formation may have been
previously hydraulically fractured to stimulate production through
that portion. Further, the well bore may be shut in for a period of
time after introduction of the consolidating agent to allow for
consolidation of the portion of the subterranean formation.
[0027] The term, "preflush fluid," as used herein refers to any
fluid that may be suitable for preparing the subterranean formation
for the later placement of the consolidating agent by, among other
things, removing oil and/or debris from the pore spaces within the
formation matrix of the unconsolidated portion. The term,
"after-flush fluid," as used herein refers to any fluid that may,
among other things, restore the permeability of the treated portion
of the subterranean formation by displacing at least a portion of
the consolidating agent from the pore channels of the subterranean
formation and forcing the displaced portion of the consolidating
agent further into the subterranean formation where it may have
negligible impact on subsequent hydrocarbon production.
[0028] In embodiments of the present invention wherein an optional
preflush fluid is desired, it may be placed into the subterranean
formation either before the placement of the fluid comprising a
consolidating agent or before the placement of the relative
permeability modifier fluid. In some preferred embodiments, the
preflush fluid is placed directly before the fluid comprising a
consolidating agent. The preflush fluid acts, inter alia, to
prepare the subterranean formation for the later placement of the
consolidating agent and/or relative permeability modifier.
Typically, injection of a preflush fluid may occur prior to
consolidating a portion of a subterranean formation. Injecting a
volume of a preflush fluid into an unconsolidated portion of a
subterranean formation may, among other things, help to remove oil
and/or debris from the pore spaces within the formation matrix of
the subterranean formation portion. Generally, the volume of the
preflush fluid placed into the formation is between 0.1 times to 50
times the volume of the fluid comprising the consolidating agent
and/or relative permeability modifier fluid. Preflush fluids
suitable for use with the present invention are described in more
detail below.
[0029] Introducing a volume of consolidating agent into the
unconsolidated portion may among other things, transform a portion
of the subterranean formation into a consolidated region.
Consolidating the region surrounding the well bore may be
advantageous in preventing well bore sloughing, formation sand
production, and the migration of fines.
[0030] In certain embodiments, the consolidation of a portion of a
subterranean formation may result in diminishing the permeability
of that portion. In certain embodiments, fracturing a portion of
the formation may be required to reconnect the well bore with
portions of the formation (e.g., the reservoir formation) outside
the consolidated region, as discussed in more detail below. In
other embodiments, typically when no fracturing step is used, an
after-flush fluid may be used to restore permeability to the
portion of the subterranean formation.
[0031] In certain embodiments of the present invention, after the
placement of the consolidating agent and/or relative permeability
modifier into the subterranean formation, an optional after-flush
fluid may be placed into the subterranean formation, inter alia, to
restore the permeability of the treated portion of the subterranean
formation. When used, the after-flush fluid is preferably placed
into the subterranean formation while the consolidating agent is
still in a flowing state. For example, an after-flush fluid may be
placed into the formation prior to a shut-in period. Among other
things, the after-flush fluid acts to displace at least a portion
of the consolidating agent from the pore channels of the
subterranean formation and to force the displaced portion of the
consolidating agent further into the subterranean formation where
it may have negligible impact on subsequent hydrocarbon production.
Generally, the after-flush fluid may be any fluid that does not
adversely react with the other components used in accordance with
this invention or with the subterranean formation. For example, the
after-flush may be an aqueous-based brine, a hydrocarbon fluid
(such as kerosene, diesel, or crude oil), or a gas (such as
nitrogen or carbon dioxide). In some preferred embodiments, the
after-flush fluid is a brine. The after-flush fluid may be placed
into the formation at a matrix flow rate such that a sufficient
portion of the consolidating agent may be displaced from the pore
channels to restore the formation to a desired permeability.
Generally, a substantial amount of the consolidating agent,
however, should not be displaced therein. For example, sufficient
amounts of the consolidating agent should remain in the treated
portion to provide effective stabilization of the unconsolidated
portions of the subterranean formation therein.
[0032] Generally, the volume of after-flush fluid placed in the
subterranean formation ranges from about 0.1 times to about 50
times the volume of the fluid comprising the consolidating agent.
In some embodiments of the present invention, the volume of
after-flush fluid placed in the subterranean formation ranges from
about 0.1 times to about 5 times the volume of the consolidating
agent.
[0033] In another embodiment of the present invention, no
after-flush fluid is placed into the subterranean formation after
placement of a consolidating agent into the subterranean formation.
Where no after-flush fluid is used, the permeability of the
subterranean formation may be significantly reduced, because the
consolidating agent may remain in the pore spaces therein and may
convert into a consolidated substance. While a significant
reduction in the permeability may occur, the unconsolidated
portions of the formation may be stabilized due, inter alia, to the
consolidating agent remaining in the pore spaces of the formation.
In embodiments in which no after-flush fluid is used, a portion of
the formation may be fractured so as to reconnect the well bore
with portions of the formation outside the consolidated region. In
embodiments wherein no after-flush fluid is placed after the
placement of the fluid comprising a consolidating agent, it may be
desirable to perform a stimulation operation, such as hydrajetting
or mini-frac operation, to create one or more conduits through the
consolidated portion of the subterranean formation. However,
stimulations operations are not required. Retained permeability of
a treated formation is function of, among other things, the volume
and concentration of the consolidating agent, and the volume of any
after-flush fluid. For example, in embodiments wherein a relatively
low amount of consolidating agent is used in the fluid comprising
the consolidating agent, the treated portion of the subterranean
formation may show relatively low consolidation strength is
obtained and high retained permeability, even without applying
after-flush fluid. In other embodiments, wherein a relatively high
amount of consolidating agent is used in the fluid comprising the
consolidating agent, the retained permeability may be low, in which
case a stimulation operation, or use of a higher volume of
after-flush fluid may be useful to restore formation permeability
and for the production of hydrocarbons.
[0034] According to the methods of the present invention, after
placement of the consolidating agent, the subterranean formation
may be shut in for a period of time to allow the consolidating
agent to consolidate at least a portion of the subterranean
formation. The shutting-in of the well bore for a period of time
may, inter alia, stabilize unconsolidated portions of the
subterranean formation, for example, by enhancing the coating and
curing of the resin between formation particulates. Additionally,
if a relative permeability modifier is placed in the subterranean
formation after the placement of the consolidating agent rather
than before, the shutting in of the well bore may also minimize the
washing away of the consolidating agent during later placement of a
relative permeability modifier.
[0035] Typically, the shut-in period of the well bore occurs after
placement of the consolidating agent. In embodiments using an
after-flush fluid, the shut-in period preferably occurs after the
use of the after-flush fluid. In embodiments in which a fracturing
step is performed subsequent to introducing the consolidating agent
into the subterranean formation, preferably, no shut-in period is
used.
[0036] The necessary shut-in time period is dependent, among other
things, on the composition of the consolidating agent used and the
temperature of the formation. Generally, the chosen period of time
will be between about 0.5 hours and about 72 hours or longer.
Determining the proper period of time to shut in the formation is
within the ability of one skilled in the art with the benefit of
this disclosure.
[0037] Generally, the relative permeability modifier fluid should
reduce the permeability of the treated portion to water without
substantially reducing the hydrocarbon permeability. In some
embodiments wherein the relative permeability modifier fluid is
introduced into the formation after the consolidating agent, the
relative permeability modifier fluid may displace excess portions
of the consolidating agent into the formation and at least
partially restore the permeability to hydrocarbons in that treated
portion. Relative permeability modifier fluids may be introduced
into the subterranean formation through the well bore. For example,
in some embodiments, the relative permeability modifier fluids may
penetrate through the consolidated region and into portion of the
subterranean formation (e.g., unconsolidated portions) that are
adjacent to the consolidated region.
[0038] In certain embodiments, a relative permeability modifier
fluid is introduced into a portion of a subterranean formation
after a consolidating agent has been placed into at least a portion
of that portion of a subterranean formation. In such embodiments,
the relative permeability modifier fluid may be introduced into the
subterranean formation either before or after an after-flush fluid
has been placed into the portion of the subterranean formation. In
certain embodiments, the relative permeability modifier fluids may
be introduced into the subterranean formation at a rate and
pressure sufficient to create or enhance at least one fracture in a
portion of the subterranean formation. In such embodiments, it may
be desirable that the fracture or fractures extend from a
consolidated region of the subterranean formation into an
unconsolidated region of the subterranean formation. In such
embodiments, the relative permeability modifier fluid may leak off
into the unconsolidated portion of the formation along the
fracture; this affecting regions of the formation beyond the
consolidated region of the formation. In certain embodiments,
following the placement of, at least, a consolidating agent and a
relative permeability modifier fluid an after-flush fluid may be
used to displace at least a portion of the relative permeability
fluid further into the formation.
[0039] In those embodiments in which a fracture is initiated
through the use of a relative permeability modifier fluid, the
fracture may be extended and packed using any suitable fracturing
methodology known to one skilled in the art with the benefit of
this disclosure. For example, a fracture may be extended using a
crosslinked gelled fracturing fluid to further extend the fracture
into the formation followed by a crosslinked gelled fluid
containing proppant, or a viscoelastic surfactant fluid containing
proppant. The proppant may be coated with a curable resin or
consolidating agent to form a hard, permeable solid mass in the
fracture or fractures, among other things, to prevent proppant flow
back during production from the well. The proppant also may be
blended with fibrous particulates that may act to form a stable
network with the proppant and/or to control proppant flow back.
[0040] In certain embodiments a relative permeability modifier
fluid may be placed into a portion of a subterranean formation
before a consolidating agent is placed into the subterranean
formation. In addition, in some embodiments, the relative
permeability modifier fluid is placed into the subterranean
formation at a rate and pressure sufficient to create or an enhance
at least one fracture in that portion of the subterranean
formation. In such embodiments, the relative permeability modifier
fluid may be used as a component in a fracturing fluid. It may be
desirable to place the relative permeability modifier fluid before
placing a fluid comprising a consolidating agent in situations
wherein, if placed first, the consolidating agent might coat the
subterranean formation surfaces, preventing the relative
permeability modifier from optimally performing its function.
Generally, the placement of a relative permeability modifier will
not act to prevent a consolidating agent from performing its
function. Some embodiments may also involve the placement of a
relative permeability modifier fluid before a stimulation
treatment, such as fracturing, frac-packing, or hydrajetting,
followed by the placement of a fluid comprising a consolidating
agent. Placing a relative permeability modifier before performing a
stimulation operation may act to increase the fluid efficiency of
the fracturing fluid by improving the fluid loss characteristics
and in reducing the amount of water inflow into the propped
fracture. Moreover, if the relative permeability modifier is placed
before a fluid comprising a consolidating agent, the placement of
the consolidating agent may act to displace the relative
permeability modifier further into the subterranean formation and
further away from the well bore.
[0041] In certain embodiments a relative permeability modifier
fluid may be placed into a portion of a subterranean formation
substantially simultaneously along with a consolidating agent. In
some such embodiments, a treatment fluid comprising a relative
permeability modifier and a consolidating agent may be placed into
a portion of a subterranean formation as a pre-pad to a hydraulic
fracturing or frac-pack completion. Such a pre-pad frac-pack
placement may, among other things, allow the pre-pad fluid to enter
the regions of a subterranean formation surrounding fracture faces
to, among other things, mitigate the production of water from the
portion of the subterranean formation and to control particulate
migration. As used herein, the term "frac-pack completion" refers
to subterranean operations wherein fracturing and gravel packing
are preformed in a single operation. In other embodiments, a
treatment fluid comprising a relative permeability modifier and a
consolidating agent may be placed into a portion of a subterranean
formation as a pre-pad to a gravel pack completion. In embodiments
wherein a fluid comprising both a relative permeability modifier
and a consolidating agent is used, are those in which a
water-soluble consolidating agent is chosen that does not contain
significant quantities of anionic substances. In still other
embodiments where it is desirable to use an oil-soluble
consolidating agent, the fluid comprising both a relative
permeability modifier and a consolidating agent may be formed into
a stable emulsion. Such a pre-pad gravel pack placement may, among
other things, allow the pre-pad fluid to enter the regions of a
subterranean formation surrounding a gravel pack to, among other
things, mitigate the production of water from the portion of the
subterranean formation and to control particulate migration. In
other embodiments, a treatment fluid comprising a relative
permeability modifier and a consolidating agent may be placed into
a portion of a subterranean formation as a remedial treatment. Such
remedial treatment placement may be used in portions of well bores
that are experiencing undesirable production of water and/or
particulates to, among other things, mitigate the production of
water from the portion of the subterranean formation and to control
particulate migration. In other embodiments, a treatment fluid
comprising a relative permeability modifier and a consolidating
agent may be placed into a portion of a subterranean formation as
an after treatment following an acidizing treatment to that portion
of a subterranean formation. Such remedial post-acidizing placement
may be used mitigate the production of water from the portion of
the subterranean formation and to control particulate
migration.
[0042] The methods described herein may be performed repeatedly as
desired. In those instances in which steps are repeated, it may be
desirable, for example, to recommence the steps described herein
starting first with the lowest zones of the formation and moving up
to higher zones.
[0043] II. Examples of Fluids Useful in the Methods of the Present
Invention
[0044] A. Examples of Preflush Fluids
[0045] Preflush fluids suitable for use with the present invention
may comprise a brine, a mutual solvent, a surfactant, or any
mixture thereof.
[0046] The preflush fluid of the present invention may include any
fluid that does not adversely interact with the other components
used in accordance with this invention or with the subterranean
formation. For example, the preflush fluid may be an aqueous-based
fluid or a hydrocarbon-based fluid. In certain embodiments of the
present invention, the preflush fluid may comprise an aqueous fluid
and a surfactant. The aqueous-fluid component may be fresh water,
salt water, brine, or seawater, or any other aqueous-based fluid
that does not adversely react with the other components used in
accordance with this invention or with the subterranean formation.
Any surfactant compatible with the later-used consolidating agent
and relative permeability modifier and capable of aiding the
consolidating agent in flowing to the contact points between
adjacent particulates in the formation may be used in the present
invention. Such surfactants include, but are not limited to,
ethoxylated nonyl phenol phosphate esters, mixtures of one or more
cationic surfactants, one or more non-ionic surfactants, and an
alkyl phosphonate surfactant. Suitable mixtures of one or more
cationic and nonionic surfactants are described in U.S. Pat. No.
6,311,773, the relevant disclosure of which is incorporated herein
by reference. A C.sub.12-C.sub.22 alkyl phosphonate surfactant is
preferred. The surfactant or surfactants used are included in the
preflush fluid in an amount sufficient to prepare the subterranean
formation to receive a treatment of a consolidating agent. In some
embodiments of the present invention, the surfactant is present in
the preflush fluid in an amount in the range of from about 0.1% to
about 3% by weight of the aqueous fluid.
[0047] B. Examples of Consolidating Agents
[0048] Suitable consolidating agents include any suitable
composition for consolidating a portion of the subterranean
formation to stabilize unconsolidated particulates therein.
Examples of suitable consolidating agents include resins,
tackifying agents, and gelable liquid compositions.
[0049] 1. Examples of Resins
[0050] Resins suitable for use in the consolidation fluids of the
present invention include any suitable resin that is capable of
forming a hardened, consolidated mass. Many such resins are
commonly used in subterranean consolidation operations, and some
suitable resins include two component epoxy based resins, novolak
resins, polyepoxide resins, phenol-aldehyde resins, urea-aldehyde
resins, urethane resins, phenolic resins, furan resins,
furan/furfuryl alcohol resins, phenolic/latex resins, phenol
formaldehyde resins, polyester resins and hybrids and copolymers
thereof, polyurethane resins and hybrids and copolymers thereof,
acrylate resins, and mixtures thereof. Some suitable resins, such
as epoxy resins, may be cured with an internal catalyst or
activator so that when pumped downhole, they may be cured using
only time and temperature. Other suitable resins, such as furan
resins generally require a time-delayed catalyst or an external
catalyst to help activate the polymerization of the resins if the
cure temperature is low (i.e., less than 250.degree. F.) but will
cure under the effect of time and temperature if the formation
temperature is above about 250.degree. F., preferably above about
300.degree. F. It is within the ability of one skilled in the art,
with the benefit of this disclosure, to select a suitable resin for
use in embodiments of the present invention and to determine
whether a catalyst is required to trigger curing.
[0051] Selection of a suitable resin may be affected by the
temperature of the subterranean formation to which the fluid will
be introduced. By way of example, for subterranean formations
having a bottom hole static temperature ("BHST") ranging from about
60.degree. F. to about 250.degree. F., two-component epoxy-based
resins comprising a hardenable resin component and a hardening
agent component containing specific hardening agents may be
preferred. For subterranean formations having a BHST ranging from
about 300.degree. F. to about 600.degree. F., a furan-based resin
may be preferred. For subterranean formations having a BHST ranging
from about 200.degree. F. to about 400.degree. F., either a
phenolic-based resin or a one-component HT epoxy-based resin may be
suitable. For subterranean formations having a BHST of at least
about 175.degree. F., a phenol/phenol formaldehyde/furfuryl alcohol
resin may also be suitable.
[0052] Any solvent that is compatible with the chosen resin and
achieves the desired viscosity effect is suitable for use in the
present invention. Some preferred solvents are those having high
flash points (e.g., about 125.degree. F.) because of, among other
things, environmental and safety concerns; such solvents include
butyl lactate, butylglycidyl ether, dipropylene glycol methyl
ether, dipropylene glycol dimethyl ether, dimethyl formamide,
diethyleneglycol methyl ether, ethyleneglycol butyl ether,
diethyleneglycol butyl ether, propylene carbonate, methanol, butyl
alcohol, d'limonene, fatty acid methyl esters, and combinations
thereof. Other preferred solvents include aqueous dissolvable
solvents such as, methanol, isopropanol, butanol, glycol ether
solvents, and combinations thereof. Suitable glycol ether solvents
include, but are not limited to, diethylene glycol methyl ether,
dipropylene glycol methyl ether, 2-butoxy ethanol, ethers of a
C.sub.2 to C.sub.6 dihydric alkanol containing at least one C.sub.1
to C.sub.6 alkyl group, mono ethers of dihydric alkanols,
methoxypropanol, butoxyethanol, hexoxyethanol, and isomers thereof.
Selection of an appropriate solvent is dependent on the resin
chosen and is within the ability of one skilled in the art with the
benefit of this disclosure. In general, the amount of solvent
needed is based on the final desired viscosity of the fluid
comprising the resin consolidating agent.
[0053] 2. Examples of Tackifying Agents
[0054] Tackifying agents suitable for use in the methods of the
present invention exhibit a sticky character and, thus, impart a
degree of consolidation to unconsolidated particulates in the
subterranean formation. As used herein, a "tackifying agent" refers
to a composition having a nature such that it is (or may be
activated to become) somewhat sticky to the touch. Examples of
suitable tackifying agents suitable for use in the present
invention include non-aqueous tackifying agents; aqueous tackifying
agents; and silyl-modified polyamides.
[0055] One type of tackifying agent suitable for use in the present
invention is a non-aqueous tackifying agent. An example of a
suitable tackifying agent may comprise polyamides that are liquids
or in solution at the temperature of the subterranean formation
such that they are, by themselves, non-hardening when introduced
into the subterranean formation. A particularly preferred product
is a condensation reaction product comprised of commercially
available polyacids and a polyamine. Such commercial products
include compounds such as mixtures of C.sub.36 dibasic acids
containing some trimer and higher oligomers and also small amounts
of monomer acids that are reacted with polyamines. Other polyacids
include trimer acids, synthetic acids produced from fatty acids,
maleic anhydride, acrylic acid, and the like. Such acid compounds
are commercially available from companies such as Witco
Corporation, Union Camp, Chemtall, and Emery Industries. The
reaction products are available from, for example, Champion
Technologies, Inc. and Witco Corporation. Additional compounds
which may be used as non-aqueous tackifying compounds include
liquids and solutions of, for example, polyesters, polycarbonates
and polycarbamates, natural resins such as shellac and the like.
Other suitable non-aqueous tackifying agents are described in U.S.
Pat. Nos. 5,853,048 and 5,833,000, the entire disclosures of which
are herein incorporated by reference.
[0056] Non-aqueous tackifying agents suitable for use in the
present invention may be either used such that they form a
non-hardening coating, or they may be combined with a
multifunctional material capable of reacting with the non-aqueous
tackifying agent to form a hardened coating. A "hardened coating,"
as used herein, means that the reaction of the tackifying compound
with the multifunctional material will result in a substantially
non-flowable reaction product that exhibits a higher compressive
strength in a consolidated agglomerate than the tackifying compound
alone with the particulates. In this instance, the non-aqueous
tackifying agent may function similarly to a hardenable resin.
Multifunctional materials suitable for use in the present invention
include, but are not limited to, aldehydes such as formaldehyde,
dialdehydes such as glutaraldehyde, hemiacetals or aldehyde
releasing compounds, diacid halides, dihalides such as dichlorides
and dibromides, polyacid anhydrides such as citric acid, epoxides,
furfuraldehyde, glutaraldehyde or aldehyde condensates and the
like, and combinations thereof. In some embodiments of the present
invention, the multifunctional material may be mixed with the
tackifying compound in an amount of from about 0.01 to about 50
percent by weight of the tackifying compound to effect formation of
the reaction product. In some preferable embodiments, the compound
is present in an amount of from about 0.5 to about 1 percent by
weight of the tackifying compound. Suitable multifunctional
materials are described in U.S. Pat. No. 5,839,510, the entire
disclosure of which is herein incorporated by reference.
[0057] Solvents suitable for use with the non-aqueous tackifying
agents of the present invention include any solvent that is
compatible with the non-aqueous tackifying agent and achieves the
desired viscosity effect. The solvents that can be used in the
present invention preferably include those having high flash points
(most preferably above about 125.degree. F.). Examples of solvents
suitable for use in the present invention include, but are not
limited to, butylglycidyl ether, dipropylene glycol methyl ether,
butyl bottom alcohol, dipropylene glycol dimethyl ether,
diethyleneglycol methyl ether, ethyleneglycol butyl ether,
methanol, butyl alcohol, isopropyl alcohol, diethyleneglycol butyl
ether, propylene carbonate, d'limonene, 2-butoxy ethanol, butyl
acetate, furfuryl acetate, butyl lactate, dimethyl sulfoxide,
dimethyl formamide, fatty acid methyl esters, and combinations
thereof. It is within the ability of one skilled in the art, with
the benefit of this disclosure, to determine whether a solvent is
needed to achieve a viscosity suitable to the subterranean
conditions and, if so, how much. In general, the amount of solvent
needed is based on the final desired viscosity of the fluid
comprising the non-aqueous tackifier consolidating agent. In some
embodiments, the amount of solvent needed is based on a target
viscosity of less than about 20 cP, in still other embodiments, the
target viscosity may be less than about 5 cP.
[0058] Aqueous tackifier agents suitable for use in the present
invention are preferably not significantly tacky when placed onto a
particulate, but are capable of being "activated" (that is,
destabilized, coalesced, and/or reacted) to transform the compound
into a sticky, tackifying compound at a desirable time. Such
activation may occur before, during, or after the aqueous tackifier
agent is placed in the subterranean formation. In some embodiments,
a pretreatment may be first contacted with the surface of a
particulate to prepare it to be coated with an aqueous tackifier
agent. Suitable aqueous tackifying agents are generally charged
polymers that comprise compounds that, when in an aqueous solvent
or solution, will form a non-hardening coating (by itself or with
an activator) and, when placed on a particulate, will increase the
continuous critical resuspension velocity of the particulate when
contacted by a stream of water. The aqueous tackifier agent may
enhance the grain-to-grain contact between the individual
particulates within the formation (be they proppant particulates,
formation fines, or other particulates), helping bring about the
consolidation of the particulates into a cohesive, flexible, and
permeable mass.
[0059] Examples of aqueous tackifier agents suitable for use in the
present invention include, but are not limited to, acrylic acid
polymers, acrylic acid ester polymers, acrylic acid derivative
polymers, acrylic acid homopolymers, acrylic acid ester
homopolymers (such as poly(methyl acrylate), poly(butyl acrylate),
and poly(2-ethylhexyl acrylate)), acrylic acid ester co-polymers,
methacrylic acid derivative polymers, methacrylic acid
homopolymers, methacrylic acid ester homopolymers (such as
poly(methyl methacrylate), poly(butyl methacrylate), and
poly(2-ethylhexyl methacrylate)), acrylamido-methyl-propane
sulfonate polymers, acrylamido-methyl-propane sulfonate derivative
polymers, acrylamido-methyl-propane sulfonate co-polymers, and
acrylic acid/acrylamido-methyl-propane sulfonate co-polymers, and
combinations thereof. Methods of determining suitable aqueous
tackifier agents and additional disclosure on aqueous tackifier
agents can be found in U.S. patent application Ser. No. 10/864,061,
filed Jun. 9, 2004, and U.S. Pat. No. 7,131,491 issued Nov. 7,
2006, the entire disclosures of which are hereby incorporated by
reference. In some embodiments, the concentration of aqueous
tackifier agent is from about 0.01 to 10% wt./vol. of the fluid
comprising a consolidating agent. In other embodiments, the
concentration of aqueous tackifier agent is from about 0.1 to 2%
wt. vol. of the fluid comprising a consolidating agent.
[0060] Silyl-modified polyamide compounds suitable for use in the
tackifying agents in the methods of the present invention may be
described as substantially self-hardening compositions that are
capable of at least partially adhering to particulates in the
unhardened state, and that are further capable of self-hardening
themselves to a substantially non-tacky state to which individual
particulates such as formation fines will not adhere to, for
example, in formation or proppant pack pore throats. Such
silyl-modified polyamides may be based, for example, on the
reaction product of a silating compound with a polyamide or a
mixture of polyamides. The polyamide or mixture of polyamides may
be one or more polyamide intermediate compounds obtained, for
example, from the reaction of a polyacid (e.g. diacid or higher)
with a polyamine (e.g., diamine or higher) to form a polyamide
polymer with the elimination of water. Other suitable
silyl-modified polyamides and methods of making such compounds are
described in U.S. Pat. No. 6,439,309, the entire disclosure of
which is herein incorporated by reference. In some embodiments, the
concentration of silyl-modified polyamide is from about 0.01 to 10%
wt./vol. of the fluid comprising a consolidating agent. In other
embodiments, the concentration of silyl-modified polyamide is from
about 1 to 3% wt. vol. of the fluid comprising a consolidating
agent.
[0061] 3. Exemplary Gelable Liquid Compositions
[0062] The gelable liquid composition may be any gelable liquid
composition capable of converting into a gelled substance capable
of substantially plugging the permeability of the formation while
allowing the formation to remain flexible. That is, the gelled
substance should negatively impact the ability of the formation to
produce desirable fluids such as hydrocarbons. As discussed above,
the permeability of the formation may be restored through use of an
after-flush fluid or by fracturing through the consolidated region.
As referred to herein, the term "flexible" refers to a state
wherein the treated formation is relatively malleable and elastic
and able to withstand substantial pressure cycling without
substantial breakdown of the formation. Thus, the resultant gelled
substance should be a semi-solid, immovable, gel-like substance,
which, among other things, stabilizes the treated portion of the
formation while allowing the formation to absorb the stresses
created during pressure cycling. As a result, the gelled substance
may aid in preventing breakdown of the formation both by
stabilizing and by adding flexibility to the formation sands.
Examples of suitable gelable liquid compositions include, but are
not limited to, resin compositions that cure to form flexible gels,
gelable aqueous silicate compositions, crosslinkable aqueous
polymer compositions, and polymerizable organic monomer
compositions.
[0063] Certain embodiments of the gelable liquid compositions of
the present invention comprise curable resin compositions. Curable
resin compositions are well known to those skilled in the art and
have been used to consolidate portions of unconsolidated formations
and to consolidate proppant materials into hard, permeable masses.
While the curable resin compositions used in accordance with the
present invention may be similar to those previously used to
consolidate sand and proppant into hard, permeable masses, they are
distinct in that resins suitable for use with the present invention
do not cure into hard, permeable masses; rather they cure into
flexible, gelled substances. That is, suitable curable resin
compositions form resilient gelled substances between the
particulates of the treated zone of the unconsolidated formation
and thus allow that portion of the formation to remain flexible and
to resist breakdown. It is not necessary or desirable for the cured
resin composition to solidify and harden to provide high
consolidation strength to the treated portion of the formation. On
the contrary, upon being cured, the curable resin compositions
useful in accordance with this invention form semi-solid,
immovable, gelled substances.
[0064] Generally, the curable resin compositions useful in
accordance with this invention may comprise a curable resin, a
diluent, and a resin curing agent. When certain resin curing
agents, such as polyamides, are used in the curable resin
compositions, the compositions form the semi-solid, immovable,
gelled substances described above. Where the resin curing agent
used may cause the organic resin compositions to form hard, brittle
material rather than a desired gelled substance, the curable resin
compositions may further comprise one or more "flexibilizer
additives" (described in more detail below) to provide flexibility
to the cured compositions.
[0065] Examples of curable resins that can be used in the curable
resin compositions of the present invention include, but are not
limited to, organic resins such as polyepoxide resins (e.g.,
bisphenol A-epichlorihydrin resins), polyester resins,
urea-aldehyde resins, furan resins, urethane resins, and mixtures
thereof. Of these, polyepoxide resins are preferred. One of skill
in the art will be able to determine a desired amount of curable
resin to be included in the fluid through, for example, porosity
fill calculation determinations based on estimated depth of
coverage for the volume and quantity of resin needed for the
particular formation. In some embodiments, the concentration of
curable resin is from about 0.1 to 25% wt./vol. of the fluid
comprising a consolidating agent. In other embodiments, the
concentration of curable resin is from about 1 to 5% wt. vol. of
the fluid comprising a consolidating agent.
[0066] Any diluent that is compatible with the curable resin and
achieves the desired viscosity effect is suitable for use in the
present invention. Examples of diluents that may be used in the
curable resin compositions of the present invention include, but
are not limited to, phenols; formaldehydes; furfuryl alcohols;
furfurals; alcohols; ethers such as butyl glycidyl ether and cresyl
glycidyl etherphenyl glycidyl ether; and mixtures thereof. In some
embodiments of the present invention, the diluent comprises butyl
lactate. The diluent may be used to reduce the viscosity of the
curable resin composition to from about 3 to about 3,000
centipoises ("cP") at 80.degree. F. Among other things, the diluent
acts to provide flexibility to the cured composition. The diluent
may be included in the curable resin composition in an amount
sufficient to provide the desired viscosity effect. Generally, the
diluent used is included in the curable resin composition in amount
in the range of from about 5% to about 75% by weight of the curable
resin.
[0067] Generally, any resin curing agent that may be used to cure
an organic resin is suitable for use in the present invention. When
the resin curing agent chosen is an amide or a polyamide, generally
no flexibilizer additive will be required because, inter alia, such
curing agents cause the curable resin composition to convert into a
semi-solid, immovable, gelled substance. Other suitable resin
curing agents (such as an amine, a polyamine, methylene dianiline,
and other curing agents known in the art) will tend to cure into a
hard, brittle material and will thus benefit from the addition of a
flexibilizer additive. Generally, the resin curing agent used is
included in the curable resin composition, whether a flexibilizer
additive is included or not, in an amount in the range of from
about 5% to about 75% by weight of the curable resin. In some
embodiments of the present invention, the resin curing agent used
is included in the curable resin composition in an amount in the
range of from about 20% to about 75% by weight of the curable
resin.
[0068] As noted above, flexibilizer additives may be used, inter
alia, to provide flexibility to the gelled substances formed from
the curable resin compositions. Flexibilizer additives should be
used where the resin curing agent chosen would cause the organic
resin composition to cure into a hard and brittle material--not the
desired gelled substances described herein. For example,
flexibilizer additives may be used where the resin curing agent
chosen is not an amide or polyamide. Examples of suitable
flexibilizer additives include, but are not limited to, an organic
ester, an oxygenated organic solvent, an aromatic solvent, and
combinations thereof. Of these, ethers, such as dibutyl phthalate,
are preferred. Where used, the flexibilizer additive may be
included in the curable resin composition in an amount in the range
of from about 5% to about 80% by weight of the curable resin. In
some embodiments of the present invention, the flexibilizer
additive may be included in the curable resin composition in an
amount in the range of from about 20% to about 45% by weight of the
curable resin.
[0069] In other embodiments, the gelable liquid compositions of the
present invention may comprise a gelable aqueous silicate
composition. Generally, the gelable aqueous silicate compositions
that are useful in accordance with the present invention generally
comprise an aqueous alkali metal silicate solution and a
temperature activated catalyst for gelling the aqueous alkali metal
silicate solution.
[0070] The aqueous alkali metal silicate solution component of the
gelable aqueous silicate compositions generally comprises an
aqueous liquid and an alkali metal silicate. The aqueous liquid
component of the aqueous alkali metal silicate solution generally
may be fresh water, salt water (e.g., water containing one or more
salts dissolved therein), brine (e.g., saturated salt water),
seawater, or any other aqueous liquid that does not adversely react
with the other components used in accordance with this invention or
with the subterranean formation. Examples of suitable alkali metal
silicates include, but are not limited to, one or more of sodium
silicate, potassium silicate, lithium silicate, rubidium silicate,
or cesium silicate. Of these, sodium silicate is preferred. While
sodium silicate exists in many forms, the sodium silicate used in
the aqueous alkali metal silicate solution preferably has a
Na.sub.2O-to-SiO.sub.2 weight ratio in the range of from about 1:2
to about 1:4. Most preferably, the sodium silicate used has a
Na.sub.2O-to-SiO.sub.2 weight ratio in the range of about 1:3.2.
Generally, the alkali metal silicate is present in the aqueous
consolidating fluid in an amount in the range of from about 0.1% to
about 42% by weight of the aqueous consolidating fluid. Typically,
the alkali metal silicate is present in the aqueous consolidating
fluid in an amount in the range of from about 3% to about 8% by
weight of the aqueous consolidating fluid.
[0071] The temperature activated catalyst component of the gelable
aqueous silicate gelable liquid compositions is used, inter alia,
to convert the gelable aqueous silicate compositions into the
desired semi-solid, immovable, gelled substance described above.
Selection of a temperature activated catalyst is related, at least
in part, to the temperature of the subterranean formation to which
the gelable aqueous silicate composition will be introduced. The
temperature activated catalysts which can be used in the gelable
aqueous silicate compositions of the present invention include, but
are not limited to, ammonium sulfate, which is most suitable in the
range of from about 60.degree. F. to about 240.degree. F.; sodium
acid pyrophosphate, which is most suitable in the range of from
about 60.degree. F. to about 240.degree. F.; citric acid, which is
most suitable in the range of from about 60.degree. F. to about
120.degree. F.; and ethyl acetate, which is most suitable in the
range of from about 60.degree. F. to about 120.degree. F.
Generally, the temperature activated catalyst is present in the
aqueous consolidating fluid in the range of from about 0.1% to
about 5% by weight of the aqueous consolidating fluid.
[0072] In other embodiments, the gelable liquid composition
consolidating fluids of the present invention may comprise
crosslinkable aqueous polymer compositions. Generally, suitable
crosslinkable aqueous polymer compositions may comprise an aqueous
solvent, a crosslinkable polymer, and a crosslinking agent.
[0073] The aqueous solvent may be any aqueous solvent in which the
crosslinkable composition and the crosslinking agent may be
dissolved, mixed, suspended, or dispersed therein to facilitate gel
formation. For example, the aqueous solvent used may be fresh
water, salt water, brine, seawater, or any other aqueous liquid
that does not adversely react with the other components used in
accordance with this invention or with the subterranean
formation.
[0074] Examples of crosslinkable polymers that can be used in the
crosslinkable aqueous polymer compositions include, but are not
limited to, carboxylate-containing polymers and
acrylamide-containing polymers. Preferred acrylamide-containing
polymers include polyacrylamide, partially hydrolyzed
polyacrylamide, copolymers of acrylamide and acrylate, and
carboxylate-containing terpolymers and tetrapolymers of acrylate.
Additional examples of suitable crosslinkable polymers include
hydratable polymers comprising polysaccharides and derivatives
thereof and that contain one or more of the monosaccharide units
galactose, mannose, glucoside, glucose, xylose, arabinose,
fructose, glucuronic acid, or pyranosyl sulfate. Suitable natural
hydratable polymers include, but are not limited to, guar gum,
locust bean gum, tara, konjak, tamarind, starch, cellulose, karaya,
xanthan, tragacanth, and carrageenan, and derivatives of all of the
above. Suitable hydratable synthetic polymers and copolymers that
may be used in the crosslinkable aqueous polymer compositions
include, but are not limited to, polyacrylates, polymethacrylates,
polyacrylamides, maleic anhydride, methylvinyl ether polymers,
polyvinyl alcohols, and polyvinylpyrrolidone. The crosslinkable
polymer used should be included in the crosslinkable aqueous
polymer composition in an amount sufficient to form the desired
gelled substance in the subterranean formation. In some embodiments
of the present invention, the crosslinkable polymer is included in
the crosslinkable aqueous polymer composition in an amount in the
range of from about 1% to about 30% by weight of the aqueous
solvent. In another embodiment of the present invention, the
crosslinkable polymer is included in the crosslinkable aqueous
polymer composition in an amount in the range of from about 1% to
about 20% by weight of the aqueous solvent.
[0075] The crosslinkable aqueous polymer compositions of the
present invention may further comprise a crosslinking agent for
crosslinking the crosslinkable polymers to form the desired gelled
substance. In some embodiments, the crosslinking agent may be a
molecule or complex containing a reactive transition metal cation.
A most preferred crosslinking agent comprises trivalent chromium
cations complexed or bonded to anions, atomic oxygen, or water.
Examples of suitable crosslinking agents include, but are not
limited to, compounds or complexes containing chromic acetate
and/or chromic chloride. Other suitable transition metal cations
include chromium VI within a redox system, aluminum III, iron II,
iron III, and zirconium IV.
[0076] The crosslinking agent should be present in the
crosslinkable aqueous polymer compositions of the present invention
in an amount sufficient to provide, inter alia, the desired degree
of crosslinking. In some embodiments of the present invention, the
crosslinking agent is present in the crosslinkable aqueous polymer
compositions of the present invention in an amount in the range of
from 0.01% to about 5% by weight of the crosslinkable aqueous
polymer composition. The exact type and amount of crosslinking
agent or agents used depends upon the specific crosslinkable
polymer to be crosslinked, formation temperature conditions, and
other factors known to those individuals skilled in the art.
[0077] Optionally, the crosslinkable aqueous polymer compositions
may further comprise a crosslinking delaying agent, such as a
polysaccharide crosslinking delaying agents derived from guar, guar
derivatives, or cellulose derivatives. The crosslinking delaying
agent may be included in the crosslinkable aqueous polymer
compositions, inter alia, to delay crosslinking of the
crosslinkable aqueous polymer compositions until desired. One of
ordinary skill in the art, with the benefit of this disclosure,
will know the appropriate amount of the crosslinking delaying agent
to include in the crosslinkable aqueous polymer compositions for a
desired application.
[0078] In other embodiments, the gelled liquid compositions of the
present invention may comprise polymerizable organic monomer
compositions. Generally, suitable polymerizable organic monomer
compositions may comprise an aqueous-base fluid, a water-soluble
polymerizable organic monomer, an oxygen scavenger, and a primary
initiator.
[0079] The aqueous-base fluid component of the polymerizable
organic monomer composition generally may be fresh water, salt
water, brine, seawater, or any other aqueous liquid that does not
adversely react with the other components used in accordance with
this invention or with the subterranean formation.
[0080] A variety of monomers are suitable for use as the
water-soluble polymerizable organic monomers in the present
invention. Examples of suitable monomers include, but are not
limited to, acrylic acid, methacrylic acid, acrylamide,
methacrylamide, 2-methacrylamido-2-methylpropane sulfonic acid,
2-dimethylacrylamide, vinyl sulfonic acid,
N,N-dimethylaminoethylmethacrylate,
2-triethylammoniumethylmethacrylate chloride,
N,N-dimethyl-aminopropylmethacryl-amide,
methacrylamidepropyltriethylammonium chloride, N-vinyl pyrrolidone,
vinyl-phosphonic acid, and methacryloyloxyethyl trimethylammonium
sulfate, and mixtures thereof. Preferably, the water-soluble
polymerizable organic monomer should be self crosslinking. Examples
of suitable monomers which are self crosslinking include, but are
not limited to, hydroxyethylacrylate, hydroxymethylacrylate,
hydroxyethylmethacrylate, N-hydroxymethylacrylamide,
N-hydroxymethyl-methacrylamide, polyethylene glycol acrylate,
polyethylene glycol methacrylate, polypropylene glycol acrylate,
polypropylene glycol methacrylate, and mixtures thereof. Of these,
hydroxyethylacrylate is preferred. An example of a particularly
preferable monomer is hydroxyethylcellulose-vinyl phosphoric
acid.
[0081] The water-soluble polymerizable organic monomer (or monomers
where a mixture thereof is used) should be included in the
polymerizable organic monomer composition in an amount sufficient
to form the desired gelled substance after placement of the
polymerizable organic monomer composition into the subterranean
formation. In some embodiments of the present invention, the
water-soluble polymerizable organic monomer(s) are included in the
polymerizable organic monomer composition in an amount in the range
of from about 1% to about 30% by weight of the aqueous-base fluid.
In another embodiment of the present invention, the water-soluble
polymerizable organic monomer(s) are included in the polymerizable
organic monomer composition in an amount in the range of from about
1% to about 20% by weight of the aqueous-base fluid.
[0082] The presence of oxygen in the polymerizable organic monomer
composition may inhibit the polymerization process of the
water-soluble polymerizable organic monomer or monomers. Therefore,
an oxygen scavenger, such as stannous chloride, may be included in
the polymerizable monomer composition. In order to improve the
solubility of stannous chloride so that it may be readily combined
with the polymerizable organic monomer composition on the fly, the
stannous chloride may be pre-dissolved in a hydrochloric acid
solution. For example, the stannous chloride may be dissolved in a
0.1% by weight aqueous hydrochloric acid solution in an amount of
about 10% by weight of the resulting solution. The resulting
stannous chloride-hydrochloric acid solution may be included in the
polymerizable organic monomer composition in an amount in the range
of from about 0.1% to about 10% by weight of the polymerizable
organic monomer composition. Generally, the stannous chloride may
be included in the polymerizable organic monomer composition of the
present invention in an amount in the range of from about 0.005% to
about 0.1% by weight of the polymerizable organic monomer
composition.
[0083] The primary initiator is used, inter alia, to initiate
polymerization of the water-soluble polymerizable organic
monomer(s) used in the present invention. Any compound or compounds
which form free radicals in aqueous solution may be used as the
primary initiator. The free radicals act, inter alia, to initiate
polymerization of the water-soluble polymerizable organic
monomer(s) present in the polymerizable organic monomer
composition. Compounds suitable for use as the primary initiator
include, but are not limited to, alkali metal persulfates;
peroxides; oxidation-reduction systems employing reducing agents,
such as sulfites in combination with oxidizers; and azo
polymerization initiators. Preferred azo polymerization initiators
include 2,2'-azobis(2-imidazole-2-hydroxyethyl)propane,
2,2'-azobis(2-aminopropane), 4,4'-azobis(4-cyanovaleric acid), and
2,2'-azobis(2-methyl-N-(2-hydroxyethyl)propionamide. Generally, the
primary initiator should be present in the polymerizable organic
monomer composition in an amount sufficient to initiate
polymerization of the water-soluble polymerizable organic
monomer(s). In certain embodiments of the present invention, the
primary initiator is present in the polymerizable organic monomer
composition in an amount in the range of from about 0.1% to about
5% by weight of the water-soluble polymerizable organic
monomer(s).
[0084] Optionally, the polymerizable organic monomer compositions
further may comprise a secondary initiator. A secondary initiator
may be used, for example, where the immature aqueous gel is placed
into a subterranean formation that is relatively cool as compared
to the surface mixing, such as when placed below the mud line in
offshore operations. The secondary initiator may be any suitable
water-soluble compound or compounds that may react with the primary
initiator to provide free radicals at a lower temperature. An
example of a suitable secondary initiator is triethanolamine. In
some embodiments of the present invention, the secondary initiator
is present in the polymerizable organic monomer composition in an
amount in the range of from about 0.1% to about 5% by weight of the
water-soluble polymerizable organic monomer(s).
[0085] Optionally, the polymerizable organic monomer compositions
of the present invention further may comprise a crosslinking agent
for crosslinking the polymerizable organic monomer compositions in
the desired gelled substance. In some embodiments, the crosslinking
agent is a molecule or complex containing a reactive transition
metal cation. A most preferred crosslinking agent comprises
trivalent chromium cations complexed or bonded to anions, atomic
oxygen, or water. Examples of suitable crosslinking agents include,
but are not limited to, compounds or complexes containing chromic
acetate and/or chromic chloride. Other suitable transition metal
cations include chromium VI within a redox system, aluminum III,
iron II, iron III, and zirconium IV. Generally, the crosslinking
agent may be present in polymerizable organic monomer compositions
in an amount in the range of from 0.01% to about 5% by weight of
the polymerizable organic monomer composition.
[0086] C. Examples of Relative Permeability Modifier Fluids
[0087] The relative permeability modifier fluids of the present
invention may comprise an aqueous fluid and a relative permeability
modifier. As used herein, "relative permeability modifier" refers
to any material capable of reducing the permeability of a
subterranean formation to aqueous fluids without substantially
reducing the permeability of the subterranean formation to
hydrocarbons. A variety of additional additives suitable for use in
subterranean operations also may be included in the relative
permeability modifier fluids as desired. The aqueous fluid of the
relative permeability modifier fluids of the present invention may
include freshwater, saltwater, brine (e.g., saturated or
unsaturated saltwater), or seawater. Generally, the aqueous fluid
may be from any source, provided that it does not contain
components that may adversely affect other components in the
treatment fluid.
[0088] The relative permeability modifiers useful in the present
invention may be any relative permeability modifier that is
suitable for use in subterranean operations. After introducing the
relative permeability modifier fluid into a portion of the
subterranean formation, the relative permeability modifier
preferably attaches to surfaces within the porosity of the
subterranean formation, so as to reduce the permeability of the
portion of the subterranean formation to aqueous fluids without
substantially changing its permeability to hydrocarbons. Examples
of suitable relative permeability modifiers include water-soluble
polymers with or without hydrophobic or hydrophilic modification.
As used herein, "water-soluble" refers to at least 0.01 weight
percent soluble in distilled water. A water-soluble polymer with
hydrophobic modification is referred to herein as a
"hydrophobically modified polymer." As used herein, the term
"hydrophobic modification," or "hydrophobically modified," refers
to the incorporation into the hydrophilic polymer structure of
hydrophobic groups, wherein the alkyl chain length is from about 4
to about 22 carbons. A water-soluble polymer with hydrophilic
modification is referred to herein as a "hydrophilically modified
polymer." As used herein, the term "hydrophilic modification," or
"hydrophilically modified," refers to the incorporation into the
hydrophilic polymer structure of hydrophilic groups, such as to
introduce branching or to increase the degree of branching in the
hydrophilic polymer. Combinations of hydrophobically modified
polymers, hydrophilically modified polymers, and water-soluble
polymers without hydrophobic or hydrophilic modification may be
included in the relative modifier fluids of the present
invention.
[0089] The hydrophobically modified polymers useful in the present
invention typically have molecular weights in the range of from
about 100,000 to about 10,000,000. While these hydrophobically
modified polymers have hydrophobic groups incorporated into the
hydrophilic polymer structure, they should remain water-soluble. In
some embodiments, a mole ratio of a hydrophilic monomer to the
hydrophobic compound in the hydrophobically modified polymer is in
the range of from about 99.98:0.02 to about 90:10, wherein the
hydrophilic monomer is a calculated amount present in the
hydrophilic polymer. In certain embodiments, the hydrophobically
modified polymers may comprise a polymer backbone, the polymer
backbone comprising polar heteroatoms. Generally, the polar
heteroatoms present within the polymer backbone of the
hydrophobically modified polymers include, but are not limited to,
oxygen, nitrogen, sulfur, or phosphorous.
[0090] The hydrophobically modified polymers may be synthesized
using any suitable method. In one example, the hydrophobically
modified polymers may be a reaction product of a hydrophilic
polymer and a hydrophobic compound. In another example, the
hydrophobically modified polymers may be prepared from a
polymerization reaction comprising a hydrophilic monomer and a
hydrophobically modified hydrophilic monomer. Those of ordinary
skill in the art, with the benefit of this disclosure, will be able
to determine other suitable methods for the synthesis of suitable
hydrophobically modified polymers.
[0091] In certain embodiments, suitable hydrophobically modified
polymers may be synthesized by the hydrophobic modification of a
hydrophilic polymer. The hydrophilic polymers suitable for forming
hydrophobically modified polymers of the present invention should
be capable of reacting with hydrophobic compounds. Suitable
hydrophilic polymers include, homo-, co-, or terpolymers such as,
but not limited to, polyacrylamides, polyvinylamines,
poly(vinylamines/vinyl alcohols), alkyl acrylate polymers in
general, and derivatives thereof. Additional examples of alkyl
acrylate polymers include, but are not limited to,
polydimethylaminoethyl methacrylate, polydimethylaminopropyl
methacrylamide, poly(acrylamide/dimethylaminoethyl methacrylate),
poly(methacrylic acid/dimethylaminoethyl methacrylate),
poly(2-acrylamido-2-methyl propane sulfonic acid/dimethylaminoethyl
methacrylate), poly(acrylamide/dimethylaminopropyl methacrylamide),
poly(acrylic acid/dimethylaminopropyl methacrylamide), and
poly(methacrylic acid/dimethylaminopropyl methacrylamide). In
certain embodiments, the hydrophilic polymers comprise a polymer
backbone and reactive amino groups in the polymer backbone or as
pendant groups, the reactive amino groups capable of reacting with
hydrophobic compounds. In some embodiments, the hydrophilic
polymers comprise dialkyl amino pendant groups. In some
embodiments, the hydrophilic polymers comprise a dimethyl amino
pendant group and a monomer comprising dimethylaminoethyl
methacrylate or dimethylaminopropyl methacrylamide. In certain
embodiments of the present invention, the hydrophilic polymers
comprise a polymer backbone, the polymer backbone comprising polar
heteroatoms, wherein the polar heteroatoms present within the
polymer backbone of the hydrophilic polymers include, but are not
limited to, oxygen, nitrogen, sulfur, or phosphorous. Suitable
hydrophilic polymers that comprise polar heteroatoms within the
polymer backbone include homo-, co-, or terpolymers, such as, but
not limited to, celluloses, chitosans, polyamides, polyetheramines,
polyethyleneimines, polyhydroxyetheramines, polylysines,
polysulfones, gums, starches, and derivatives thereof. In one
embodiment, the starch is a cationic starch. A suitable cationic
starch may be formed by reacting a starch, such as corn, maize,
waxy maize, potato, tapioca, and the like, with the reaction
product of epichlorohydrin and trialkylamine.
[0092] The hydrophobic compounds that are capable of reacting with
the hydrophilic polymers of the present invention include, but are
not limited to, alkyl halides, sulfonates, sulfates, organic acids,
and organic acid derivatives. Examples of suitable organic acids
and derivatives thereof include, but are not limited to, octenyl
succinic acid; dodecenyl succinic acid; and anhydrides, esters,
imides, and amides of octenyl succinic acid or dodecenyl succinic
acid. In certain embodiments, the hydrophobic compounds may have an
alkyl chain length of from about 4 to about 22 carbons. In another
embodiment, the hydrophobic compounds may have an alkyl chain
length of from about 7 to about 22 carbons. In another embodiment,
the hydrophobic compounds may have an alkyl chain length of from
about 12 to about 18 carbons. For example, where the hydrophobic
compound is an alkyl halide, the reaction between the hydrophobic
compound and hydrophilic polymer may result in the quaternization
of at least some of the hydrophilic polymer amino groups with an
alkyl halide, wherein the alkyl chain length is from about 4 to
about 22 carbons.
[0093] As previously mentioned, in certain embodiments, suitable
hydrophobically modified polymers also may be prepared from a
polymerization reaction comprising a hydrophilic monomer and a
hydrophobically modified hydrophilic monomer. Examples of suitable
methods of their preparation are described in U.S. Pat. No.
6,476,169, the entire disclosure of which is incorporated herein by
reference. The hydrophobically modified polymers synthesized from
the polymerization reactions may have estimated molecular weights
in the range of from about 100,000 to about 10,000,000 and mole
ratios of the hydrophilic monomer(s) to the hydrophobically
modified hydrophilic monomer(s) in the range of from about
99.98:0.02 to about 90:10.
[0094] A variety of hydrophilic monomers may be used to form the
hydrophobically modified polymers useful in the present invention.
Examples of suitable hydrophilic monomers include, but are not
limited to acrylamide, 2-acrylamido-2-methyl propane sulfonic acid,
N,N-dimethylacrylamide, vinyl pyrrolidone, dimethylaminoethyl
methacrylate, acrylic acid, dimethylaminopropylmethacrylamide,
vinyl amine, vinyl acetate, trimethylammoniumethyl methacrylate
chloride, methacrylamide, hydroxyethyl acrylate, vinyl sulfonic
acid, vinyl phosphonic acid, methacrylic acid, vinyl caprolactam,
N-vinylformamide, N,N-diallylacetamide, dimethyldiallyl ammonium
halide, itaconic acid, styrene sulfonic acid,
methacrylamidoethyltrimethyl ammonium halide, quaternary salt
derivatives of acrylamide, and quaternary salt derivatives of
acrylic acid.
[0095] A variety of hydrophobically modified hydrophilic monomers
also may be used to form the hydrophobically modified polymers
useful in the present invention. Examples of suitable
hydrophobically modified hydrophilic monomers include, but are not
limited to, alkyl acrylates, alkyl methacrylates, alkyl
acrylamides, alkyl methacrylamides alkyl dimethylammoniumethyl
methacrylate halides, and alkyl dimethylammoniumpropyl
methacrylamide halides, wherein the alkyl groups have from about 4
to about 22 carbon atoms. In another embodiment, the alkyl groups
have from about 7 to about 22 carbons. In another embodiment, the
alkyl groups have from about 12 to about 18 carbons. In certain
embodiments, the hydrophobically modified hydrophilic monomer
comprises octadecyldimethylammoniumethyl methacrylate bromide,
hexadecyldimethylammoniumethyl methacrylate bromide,
hexadecyldimethylammoniumpropyl methacrylamide bromide,
2-ethylhexyl methacrylate, or hexadecyl methacrylamide.
[0096] Suitable hydrophobically modified polymers that may be
formed from the above-described reactions include, but are not
limited to, acrylamide/octadecyldimethylammoniumethyl methacrylate
bromide copolymer, dimethylaminoethyl methacrylate/vinyl
pyrrolidone/hexadecyldimethylammoniumethyl methacrylate bromide
terpolymer, and acrylamide/2-acrylamido-2-methyl propane sulfonic
acid/2-ethylhexyl methacrylate terpolymer. Another suitable
hydrophobically modified polymer formed from the above-described
reaction is an amino methacrylate/alkyl amino methacrylate
copolymer. A suitable dimethylaminoethyl
methacrylate/alkyl-dimethylammoniumethyl methacrylate copolymer is
a dimethylaminoethyl methacrylate/hexadecyl-dimethylammoniumethyl
methacrylate copolymer. As previously discussed, these copolymers
may be formed by reactions with a variety of alkyl halides. For
example, in some embodiments, the hydrophobically modified polymer
may be a dimethylaminoethyl
methacrylate/hexadecyl-dimethylammoniumethyl methacrylate bromide
copolymer.
[0097] In another embodiment of the present invention, the relative
permeability modifier fluid of the present invention may comprise a
water-soluble hydrophilically modified polymer. The hydrophilically
modified polymers of the present invention typically have molecular
weights in the range of from about 100,000 to about 10,000,000. In
certain embodiments, the hydrophilically modified polymers comprise
a polymer backbone, the polymer backbone comprising polar
heteroatoms. Generally, the polar heteroatoms present within the
polymer backbone of the hydrophilically modified polymers include,
but are not limited to, oxygen, nitrogen, sulfur, or
phosphorous.
[0098] The hydrophilically modified polymers may be synthesized
using any suitable method. In one example, the hydrophilically
modified polymers may be a reaction product of a hydrophilic
polymer and a hydrophilic compound. Those of ordinary skill in the
art, with the benefit of this disclosure, will be able to determine
other suitable methods for the preparation of suitable
hydrophilically modified polymers.
[0099] In certain embodiments, suitable hydrophilically modified
polymers may be formed by additional hydrophilic modification, for
example, to introduce branching or to increase the degree of
branching, of a hydrophilic polymer. The hydrophilic polymers
suitable for forming the hydrophilically modified polymers used in
the present invention should be capable of reacting with
hydrophilic compounds. In certain embodiments, suitable hydrophilic
polymers include, homo-, co-, or terpolymers, such as, but not
limited to, polyacrylamides, polyvinylamines,
poly(vinylamines/vinyl alcohols), and alkyl acrylate polymers in
general. Additional examples of alkyl acrylate polymers include,
but are not limited to, polydimethylaminoethyl methacrylate,
polydimethylaminopropyl methacrylamide,
poly(acrylamide/dimethylaminoethyl methacrylate), poly(methacrylic
acid/dimethylaminoethyl methacrylate), poly(2-acrylamido-2-methyl
propane sulfonic acid/dimethylaminoethyl methacrylate),
poly(acrylamide/dimethylaminopropyl methacrylamide), poly(acrylic
acid/dimethylaminopropyl methacrylamide), and poly(methacrylic
acid/dimethylaminopropyl methacrylamide). In certain embodiments,
the hydrophilic polymers comprise a polymer backbone and reactive
amino groups in the polymer backbone or as pendant groups, the
reactive amino groups capable of reacting with hydrophilic
compounds. In some embodiments, the hydrophilic polymers comprise
dialkyl amino pendant groups. In some embodiments, the hydrophilic
polymers comprise a dimethyl amino pendant group and at least one
monomer comprising dimethylaminoethyl methacrylate or
dimethylaminopropyl methacrylamide. In other embodiments, the
hydrophilic polymers comprise a polymer backbone comprising polar
heteroatoms, wherein the polar heteroatoms present within the
polymer backbone of the hydrophilic polymers include, but are not
limited to, oxygen, nitrogen, sulfur, or phosphorous. Suitable
hydrophilic polymers that comprise polar heteroatoms within the
polymer backbone include homo-, co-, or terpolymers, such as, but
not limited to, celluloses, chitosans, polyamides, polyetheramines,
polyethyleneimines, polyhydroxyetheramines, polylysines,
polysulfones, gums, starches, and derivatives thereof. In one
embodiment, the starch is a cationic starch. A suitable cationic
starch may be formed by reacting a starch, such as corn, maize,
waxy maize, potato, tapioca, and the like, with the reaction
product of epichlorohydrin and trialkylamine.
[0100] The hydrophilic compounds suitable for reaction with the
hydrophilic polymers include polyethers that comprise halogens,
sulfonates, sulfates, organic acids, and organic acid derivatives.
Examples of suitable polyethers include, but are not limited to,
polyethylene oxides, polypropylene oxides, and polybutylene oxides,
and copolymers, terpolymers, and mixtures thereof. In some
embodiments, the polyether comprises an epichlorohydrin-terminated
polyethylene oxide methyl ether.
[0101] The hydrophilically modified polymers formed from the
reaction of a hydrophilic polymer with a hydrophilic compound may
have estimated molecular weights in the range of from about 100,000
to about 10,000,000 and may have weight ratios of the hydrophilic
polymers to the polyethers in the range of from about 1:1 to about
10:1. Suitable hydrophilically modified polymers having molecular
weights and weight ratios in the ranges set forth above include,
but are not limited to, the reaction product of
polydimethylaminoethyl methacrylate and epichlorohydrin-terminated
polyethyleneoxide methyl ether; the reaction product of
polydimethylaminopropyl methacrylamide and
epichlorohydrin-terminated polyethyleneoxide methyl ether; and the
reaction product of poly(acrylamide/dimethylaminopropyl
methacrylamide) and epichlorohydrin-terminated polyethyleneoxide
methyl ether. In some embodiments, the hydrophilically modified
polymer comprises the reaction product of a polydimethylaminoethyl
methacrylate and epichlorohydrin-terminated polyethyleneoxide
methyl ether having a weight ratio of polydimethylaminoethyl
methacrylate to epichlorohydrin-terminated polyethyleneoxide methyl
ether of about 3:1.
[0102] In another embodiment of the present invention, the
water-soluble relative permeability modifiers comprise a
water-soluble polymer without hydrophobic or hydrophilic
modification. Examples of suitable water-soluble polymers include,
but are not limited to, homo-, co-, and terpolymers of acrylamide,
2-acrylamido-2-methyl propane sulfonic acid,
N,N-dimethylacrylamide, vinyl pyrrolidone, dimethylaminoethyl
methacrylate, acrylic acid, dimethylaminopropylmethacrylamide,
vinyl amine, vinyl acetate, trimethylammoniumethyl methacrylate
chloride, methacrylamide, hydroxyethyl acrylate, vinyl sulfonic
acid, vinyl phosphonic acid, methacrylic acid, vinyl caprolactam,
N-vinylformamide, N,N-diallylacetamide, dimethyldiallyl ammonium
halide, itaconic acid, styrene sulfonic acid,
methacrylamidoethyltrimethyl ammonium halide, quaternary salt
derivatives of acrylamide and quaternary salt derivatives of
acrylic acid.
[0103] Sufficient concentrations of a suitable relative
permeability modifier may be present in the treatment fluids of the
present invention to provide the desired degree of diversion. The
amount of the relative permeability modifier to include in the
treatment fluid depends on a number of factors including, the
composition of the fluid to be diverted and the porosity of the
formation. In some embodiments, a relative permeability modifier
may be present in a treatment fluid of the present invention in an
amount in the range of from about 0.02% to about 10% by weight of
the composition. In some embodiments, a relative permeability
modifier may be present in an amount in the range of from about
0.05% to about 1.0% by weight of the composition. In certain
embodiments of the present invention, the relative permeability
modifier may be provided in a concentrated aqueous solution prior
to its combination with the other components necessary to form a
treatment fluid of the present invention.
[0104] Additional additives may be included in the treatment fluids
of the present invention as deemed appropriate for a particular
application by one skilled in the art, with the benefit of this
disclosure. Examples of such additives include, but are not limited
to, acids, weighting agents, surfactants, scale inhibitors,
antifoaming agents, bactericides, salts, foaming agents, fluid loss
control additives, viscosifying agents, gel breakers, clay
stabilizers, and combinations thereof.
[0105] Therefore, the present invention is well adapted to attain
the ends and advantages mentioned as well as those that are
inherent therein. While numerous changes may be made by those
skilled in the art, such changes are encompassed within the spirit
of this invention as defined by the appended claims. The terms in
the claims have their plain, ordinary meaning unless otherwise
explicitly and clearly defined by the patentee.
[0106] Water control treatments are often considered as the last
resort to provide solutions to the problems affecting the
production and operation of the wells. Instead of treating
subterranean formations with water and sand production problems
separately, the present invention allows for water and sand control
treatments to be performed simultaneously or one directly after the
other. Although experimental testing showed that relative
permeability modifiers may be applied either before or after that
of a consolidation treatment, it may be more convenient and cost
effective to treat the interval with RPM solution before the
consolidating agent such that the action of placing the
consolidating agent displaces the relative permeability modifier
deeper into the formation.
[0107] To facilitate a better understanding of the present
invention, the following examples of certain aspects of some
embodiments are given. In no way should the following examples be
read to limit, or define, the scope of the invention.
Examples
[0108] Preparation of Sand Packs. Both synthetic sand packs and
brown sandstone outcrop material were used in the study. Sand-pack
samples were prepared from a sand mixture composed of 88% (wt/wt)
70/170-mesh sand, 10% silica flour, and 2% smectite. The sand
mixture was blended using a kitchen mixer to help ensure
homogeneity of the sand pack. After being well blended, each sand
mixture was hand packed into the Hassler sleeve and assembled in a
consolidation chamber. The Hassler sleeve had a diameter of 2.54 cm
and a length of 13.3 cm. Each sand column was packed in the Hassler
sleeve in the following order of materials: 10 g of 70/170-mesh
sand, 20 g of resieved 20/40-mesh Ottawa sand, 175 g of sand
mixture (described above), and 10 g of resieved 20/40-mesh Ottawa
sand. Screen pieces with 60-mesh size were installed on top and at
the bottom of the sand pack. The chamber was equipped with a heated
jacket to simulate downhole temperatures during curing. A piston
displacement ISCO pump was used to inject all fluids with a
backpressure of 50 psi applied during injection and an annular
confining pressure of 2,500 psi placed on the sand pack to ensure
no fluid bypassed the pack. The entire system was maintained at
170.degree. F. during treatment.
[0109] Relative Permeability Modifier. The selected relative
permeability modifier was a hydrophobically modified, water-soluble
polymer. A relative permeability modifier solution with
concentration of 2,000 ppm was prepared in 2% KCl that was then
adjusted with an acid buffer to obtain a pH of 6.0.
[0110] Consolidating Agent. The selected consolidating agent was an
epoxy-based resin system capable of acting as a consolidating agent
at temperatures between 170-325.degree. F. An epoxy based resin
with a volume of 30 mL, (i.e., 15 mL of hardenable resin component
and 15 mL of internal activator component) was prepared to form a
single mixture just before the consolidation treatment. This resin
mixture has a viscosity of about 15 cP at 72.degree. F.
[0111] Test 1--Consolidation Treatment of Sand Pack without RPM
Treatment. This test was performed to determine the consolidation
performance of the consolidating agent on the sand pack. All
injections were maintained at 5 mL/min pump rate. Initial
permeability values of kerosene and API brine for the sand pack
were first established in the production direction. The
consolidation treatment was then followed in the injection
direction. The consolidation treatment typically involved injecting
a preflush fluid, the resin mixture described above having a
viscosity of about 15 cP at 72.degree. F., and an after -flush
fluid. Once the after-flush treatment was completed, the treated
sand pack was then shut in for 48 hours at 170.degree. F. to allow
complete curing of the epoxy-based resin consolidating agent. After
curing, the regained permeability of the sand pack was determined
with kerosene in the production direction. The consolidated sand
pack was then cut into cores of desired length and unconfined
compressive strengths (UCS) of the cores were determined.
[0112] Test 2--Relative Permeability Modifier Followed by a
Consolidating Agent. This test was performed to determine the
compatibility of a relative permeability modifier treatment with
that of consolidating agent treatment in a sand pack. Following
measurements of initial permeability of kerosene and API brine
through the sand pack, as described above, a relative permeability
modifier treatment was performed on the sand pack. The relative
permeability modifier treatment typically consists of injecting an
API brine, followed by a relative permeability modifier solution,
followed by an after-flush brine displacement, followed by
treatment with the resin mixture described above having a viscosity
of about 15 cP at 72.degree. F. The treated sand pack was then
allowed to cure at 170.degree. F. for 48 hours. Both kerosene and
API brine were used in determining the regained permeability with
respect to kerosene and brine. The UCS, consolidation strength
values were then obtained for the consolidated sand pack.
[0113] Test 3--Relative Permeability Modifier Followed by a
Consolidating Agent. This test was performed to determine if
consolidation of a sand pack could be achieved when a very low
viscosity fluid comprising a consolidating agent is used following
the placement of a relative permeability modifier. Similar to the
procedure described in Test 2, above, a sand pack was first treated
with a relative permeability modifier solution and followed by
placement of the resin mixture described above having a viscosity
of about 15 cP at 72.degree. F.
[0114] Test 4--Treatments of Consolidating Agent and Relative
Permeability Modifier on Sequential Set Up of Sand Pack and Brown
Sandstone Core. This test was performed to examine the performance
of a relative permeability modifier treatment in a sand pack and in
a Brown sandstone core after the placement of a consolidating
agent. A flow chamber which had a Hassler sleeve containing a sand
pack, as described above, was set up in front of the flow chamber
with Hassler sleeve containing the Brown sandstone core. The
Hassler sleeve containing sandstone core was equipped with
multitaps where pressure transducers were installed to allow
measurements of differential pressures between various interval
lengths of the cores. The Brown sandstone had a 6-in. length and a
1-in. diameter. Initial values of permeability of kerosene and API
brine were obtained for the sand pack and sandstone core in the
production direction. A consolidation treatment was then performed
on the sand pack in the injection direction. The sandstone core was
never exposed to consolidating agent. Following the consolidation
treatment, a relative permeability modifier treatment was applied
also in the injection direction sequentially through both the sand
pack and the sandstone. The treated sand pack and sandstone core
were then shut in for 48 hours at 170.degree. F. After the shut-in
period, kerosene and API brine were used in regained permeability
measurements by injecting in the production direction. The UCS,
consolidation strength, values were then obtained for the
consolidated sand pack.
[0115] Results. Table 1 , below, provides summary results of
regained permeability of kerosene, the amount of water shutoff, and
consolidation strengths (i.e., UCS) obtained for the treated sand
packs in these tests. TABLE-US-00001 Test 3 Test 4 Test 2 Relative
Sand Pack: Relative Permeability Relative Permeability Modifier
Permeability Sandstone: Test 1 Modifier followed by Modifier
Relative treatment Resin followed by Low Viscosity followed
Permeability type only Resin Resin by Resin Modifier only %
regained 74 84 98 92 80 permeability to kerosene % water -- 38 65
62 75 shut off UCS (psi) 990 1010 <10 1270 --
[0116] Therefore, the present invention is well adapted to attain
the ends and advantages mentioned as well as those that are
inherent therein. The particular embodiments disclosed above are
illustrative only, as the present invention may be modified and
practiced in different but equivalent manners apparent to those
skilled in the art having the benefit of the teachings herein.
Furthermore, no limitations are intended to the details of
construction or design herein shown, other than as described in the
claims below. It is therefore evident that the particular
illustrative embodiments disclosed above may be altered or modified
and all such variations are considered within the scope and spirit
of the present invention. In particular, every range of values (of
the form, "from about a to about b," or, equivalently, "from
approximately a to b," or, equivalently, "from approximately a-b")
disclosed herein is to be understood as referring to the power set
(the set of all subsets) of the respective range of values, and set
forth every range encompassed within the broader range of values.
Moreover, the indefinite articles "a" or "an", as used in the
claims, are defined herein to mean one or more than one of the
element that it introduces. Also, the terms in the claims have
their plain, ordinary meaning unless otherwise explicitly and
clearly defined by the patentee.
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