U.S. patent application number 12/157774 was filed with the patent office on 2009-12-17 for method of enhancing treatment fluid placement in shale, clay, and/or coal bed formations.
This patent application is currently assigned to Halliburton Energy Services, Inc.. Invention is credited to Ronald G. Dusterhoft, Philip D. Nguyen, Jimmie D. Weaver.
Application Number | 20090308599 12/157774 |
Document ID | / |
Family ID | 41413711 |
Filed Date | 2009-12-17 |
United States Patent
Application |
20090308599 |
Kind Code |
A1 |
Dusterhoft; Ronald G. ; et
al. |
December 17, 2009 |
Method of enhancing treatment fluid placement in shale, clay,
and/or coal bed formations
Abstract
Provided are methods that include a method comprising: placing a
treatment fluid into a well bore that penetrates a subterranean
formation, wherein the subterranean formation comprises at least
one selected from the group consisting of: a shale, a clay, a coal
bed, and a combination thereof; and applying a pressure pulse to
the treatment fluid.
Inventors: |
Dusterhoft; Ronald G.;
(Katy, TX) ; Weaver; Jimmie D.; (Duncan, OK)
; Nguyen; Philip D.; (Duncan, OK) |
Correspondence
Address: |
ROBERT A. KENT
P.O. BOX 1431
DUNCAN
OK
73536
US
|
Assignee: |
Halliburton Energy Services,
Inc.
|
Family ID: |
41413711 |
Appl. No.: |
12/157774 |
Filed: |
June 13, 2008 |
Current U.S.
Class: |
166/249 ;
166/308.3 |
Current CPC
Class: |
E21B 28/00 20130101;
E21B 43/006 20130101; E21B 43/26 20130101; E21B 43/003
20130101 |
Class at
Publication: |
166/249 ;
166/308.3 |
International
Class: |
E21B 43/18 20060101
E21B043/18; E21B 43/26 20060101 E21B043/26 |
Claims
1. A method comprising: placing a treatment fluid into a well bore
that penetrates a subterranean formation, wherein the subterranean
formation comprises at least one selected from the group consisting
of: a shale, a clay, a coal bed, and a combination thereof; and
applying a pressure pulse to the treatment fluid.
2. The method of claim 1 wherein the subterranean formation further
comprises at least one fracture and the treatment fluid is placed
into the subterranean formation so that the at least one fracture
is at least partially dilated.
3. The method of claim 1 further comprising pressurizing the
treatment fluid above the ambient fluid pressure in the well bore
prior to applying the pressure pulse.
4. The method of claim 1 wherein the pressure pulse exceeds the
formation fracture gradient.
5. The method of claim 1 wherein the pressure pulse straddles the
formation fracture gradient.
6. The method of claim 1 wherein the subterranean formation further
comprises one or more pairs of adjacent bedding planes and the
treatment fluid is placed into the subterranean formation so that
the one or more pairs of adjacent bedding planes is at least
partially separated.
7. The method of claim 1 wherein the pressure pulse applied to the
treatment fluid generates a pressure pulse in a portion of the
subterranean formation in the range of from about 10 psi to about
3,000 psi.
8. The method of claim 1 wherein the pressure pulse is applied at a
frequency in the range of from about 0.001 Hz to about 1 Hz.
9. The method of claim 1 further comprising generating a pressure
pulse having an amplitude different from the amplitude of a
previous pressure pulse.
10. The method of claim 1 further comprising at least one of the
following: allowing the treatment fluid to at least partially
dehydrate at least a portion of the subterranean formation;
allowing the treatment fluid to at least partially stabilize at
least a portion of the subterranean formation; and allowing the
treatment fluid to at least partially shrink at least a portion of
the subterranean formation.
11. The method of claim 1 wherein the treatment fluid comprises at
least one selected from the group consisting of: a cationic
polymer; a cationic oligomer; a methanol; a glycerin; an ethylene
glycol; a low molecular weight consolidation fluid; a polymeric
composition; a quaternary ammonium compound having inorganic anions
and carboxylate anions; a polymeric composition; a rheology
stabilizer; a rheology thinner; a consolidation fluid; a
stimulation fluid; a relative permeability modifier; and a
combination thereof.
12. The method of claim 1 wherein the treatment fluid comprises at
least one selected from the group consisting of: a potassium ion, a
calcium ion, an ammonium ion, a hydrogen ion, a tetramethylammonium
ion, potassium chloride, calcium chloride, sodium chloride,
ammonium chloride, tetramethylammonium chloride, and a combination
thereof.
13. A method comprising: placing a treatment fluid into a well bore
that penetrates a subterranean formation, wherein the subterranean
formation comprises at least one selected from the group consisting
of: a shale, a clay, a coal bed, and a combination thereof; and
applying a pressure pulse that exceeds the formation fracture
gradient to the treatment fluid.
14. The method of claim 13 further comprising pressurizing the
treatment fluid above the ambient fluid pressure in the well bore
prior to applying the pressure pulse.
15. The method of claim 13 further comprising at least one of the
following: allowing the treatment fluid to at least partially
dehydrate at least a portion of the subterranean formation;
allowing the treatment fluid to at least partially stabilize at
least a portion of the subterranean formation; and allowing the
treatment fluid to at least partially shrink at least a portion of
the subterranean formation.
16. The method of claim 13 wherein the treatment fluid comprises at
least one selected from the group consisting of: a cationic
polymer; a cationic oligomer; a methanol; a glycerin; an ethylene
glycol; a low molecular weight consolidation fluid; a polymeric
composition; a quaternary ammonium compound having inorganic anions
and carboxylate anions; a polymeric composition; a rheology
stabilizer; a rheology thinner; a consolidation fluid; a
stimulation fluid; a relative permeability modifier; and a
combination thereof.
17. The method of claim 13 wherein the treatment fluid comprises at
least one selected from the group consisting of: a potassium ion, a
calcium ion, an ammonium ion, a hydrogen ion, a tetramethylammonium
ion, potassium chloride, calcium chloride, sodium chloride,
ammonium chloride, tetramethylammonium chloride, and a combination
thereof.
18. A method comprising: placing a treatment fluid into a well bore
that penetrates a subterranean formation, wherein the subterranean
formation comprises at least one selected from the group consisting
of: a shale, a clay, a coal bed, and a combination thereof;
pressurizing the treatment fluid to a first pressure wherein the
first pressure exceeds the ambient fluid pressure in the well bore;
and applying a pressure pulse to the treatment fluid, wherein the
minimum pressure of the pressure pulse exceeds the first pressure;
and the maximum pressure of the pressure pulse exceeds the
formation fracture gradient.
19. The method of claim 18 wherein the minimum pressure of the
pressure pulse exceeds the formation fracture gradient.
20. The method of claim 18 wherein the treatment fluid comprises at
least one selected from the group consisting of: a cationic
polymer; a cationic oligomer; a cation; a methanol; a glycerin; an
ethylene glycol; a low molecular weight consolidation fluid; a
polymeric composition; a quaternary ammonium compound having
inorganic anions and carboxylate anions; a polymeric composition; a
rheology stabilizer; a rheology thinner; a consolidation fluid; a
stimulation fluid; a relative permeability modifier; and a
combination thereof.
Description
BACKGROUND
[0001] The present invention relates to methods of treating a
subterranean formation, and, at least in some embodiments, to
methods of using one or more pressure pulses to enhance the
effectiveness of placing a treatment fluid into a portion of a
subterranean formation which comprises shales, clays, and/or coal
beds.
[0002] A well bore drilled in a subterranean formation may
penetrate portions of the formation that comprise shales, clays,
and/or coal beds, which may be susceptible to degradation. For
example, when contacted by aqueous fluids found in the subterranean
formation or introduced therein as a treatment fluid, swelling of
shales and/or clays can result in undesirable interference with
subterranean operations. Additionally, degradation may
substantially decrease the stability of the well bore, which may
cause irregularities in the diameter of the well bore, e.g., the
diameter of some portions of the well bore may be either smaller or
greater than desired. In an extreme case, degradation may decrease
the stability of the well bore to such an extent that the well bore
collapses.
[0003] Subterranean formations comprising shales, clays, and/or
coal beds generally have a low permeability. As used herein, the
term "shale" refers to a sedimentary rock formed from the
consolidation of fine clay and silt materials into laminated, thin
bedding planes. As used herein, the term "clay" refers to a rock
that may be comprised of, inter alia, one or more types of clay,
including, but not limited to kaolinite, montmorillonite/smectite,
illite, chlorite, and any mixture thereof. The clay content of the
formations may be a single species of a clay mineral or several
species, including the mixed-layer types of clay. As used herein,
"coal bed" refers to a rock formation that may be comprised of,
inter alia, one or more types of coal, including, but not limited
to, peat, lignite, sub-bituminous coal, bituminous coal,
anthracite, and graphite.
[0004] Many shales and/or clays are reactive with fresh water,
resulting in ion exchange and absorption of aqueous fluids. The
presence of aqueous fluids found in the subterranean formation or
introduced therein as a treatment fluid may lead to significant
swelling of the shales and/or clays and corresponding reductions in
the mechanical strength of the subterranean formation. Moreover,
the fine aggregate that composes shales and/or clays can pose
problems if exposed to high stresses. For example, under high
stress, shale can mechanically fail, resulting in the generation of
fine clay materials that can be highly mobile in produced fluids.
This can result in well bore sloughing and large quantities of
solids production, plugging screens or filling separators on the
surface. In some formations, the bonding between bedding plane
layers may be weaker than the bonding between particles in a given
layer. In such formations, the bedding plane may represent a
weakness susceptible to mechanical failure or separation. To combat
these problems, brines are often used that contain high ion
concentration so that ion exchange will not occur and the
reactivity of the shales and/or clays will be reduced. In extreme
cases, oil-based fluids may be used to avoid exposing the shales
and/or clays to aqueous fluids.
[0005] Several different types of treatments have been employed in
subterranean operations to prevent the flow of aqueous fluids
present in a well bore into the subterranean formation, and
conversely, to prevent the flow of aqueous fluids residing in the
subterranean formation into the well bore. For example, relative
permeability modifiers and other substances (e.g., silicates,
emulsion polymers) may be placed into the subterranean formation
that may reduce the water-wettability of sands and rock in the
formation matrix and/or the diffusion of water into the formation
matrix. However, in order for these treatments to be effective, it
may be necessary to place these substances with substantial
penetration and relative uniformity throughout the formation, which
may require high hydraulic pressures and/or complicated isolation
techniques and equipment.
[0006] Pressure pulsing techniques have been used to enhance water
injection for secondary oil recovery and to enhance fluid placement
in matrix injection applications. The pressure pulsing techniques
practiced heretofore have typically been conducted under matrix
flow conditions. The pressure pulsing process may act through
localized energy, overcoming capillary forces and formation
dilatency to improve placement of fluids under matrix flow
conditions. In low permeability formations, the ability to place
large volumes of treatment fluids may be limited by the low
effective porosity and permeability of these formations.
[0007] Finally, layered formations, such as formations comprising
shales, clays, and/or coal beds may contain naturally occurring
microfractures. Traditionally, these unconventional formations have
been associated with non-productive rock by the petroleum industry.
Recently, however, there have been a number of significant natural
gas discoveries where the gas is located in a naturally fractured
formation. In these applications, most of the effective porosity
may be limited to the fracture network within the formation, but
some gas may have also been trapped in the formation matrix or in
the bedding planes.
SUMMARY
[0008] The present invention relates to methods of treating a
subterranean formation, and, at least in some embodiments, to
methods of using one or more pressure pulses to enhance the
effectiveness of placing a treatment fluid into a portion of a
subterranean formation which comprises shales, clays, and/or coal
beds.
[0009] In one embodiment, a method of treating a subterranean
formation comprises the following steps. Placing a treatment fluid
into a well bore that penetrates a subterranean formation, wherein
the subterranean formation comprises at least one selected from the
group consisting of: a shale, a clay, a coal bed, and a combination
thereof. Applying a pressure pulse to the treatment fluid.
[0010] In another embodiment, a method of treating a subterranean
formation comprises the following steps. Placing a treatment fluid
into a well bore that penetrates a subterranean formation, wherein
the subterranean formation comprises at least one selected from the
group consisting of: a shale, a clay, a coal bed, and a combination
thereof. Applying a pressure pulse that exceeds the formation
fracture gradient to the treatment fluid.
[0011] In another embodiment, a method of treating a subterranean
formation comprises the following steps. Placing a treatment fluid
into a well bore that penetrates a subterranean formation, wherein
the subterranean formation comprises at least one selected from the
group consisting of: a shale, a clay, a coal bed, and a combination
thereof. Pressurizing the treatment fluid to a first pressure
wherein the first pressure exceeds the ambient fluid pressure in
the well bore. Applying a pressure pulse to the treatment fluid. In
this embodiment, the minimum pressure of the pressure pulse exceeds
the first pressure, and the maximum pressure of the pressure pulse
exceeds the formation fracture gradient.
[0012] The features and advantages of the present invention will be
readily 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.
DESCRIPTION OF PREFERRED EMBODIMENTS
[0013] The present invention relates to methods of treating a
subterranean formation, and, at least in some embodiments, to
methods of using one or more pressure pulses to enhance the
effectiveness of placing a treatment fluid into a portion of a
subterranean formation which comprises shales, clays, and/or coal
beds.
[0014] As used herein, the term "shale" refers to a sedimentary
rock formed from the consolidation of fine clay and silt materials
into laminated, thin bedding planes.
[0015] As used herein, the term "clay" refers to a rock that may be
comprised of, inter alia, one or more types of clay, including, but
not limited to kaolinite, montmorillonite/smectite, illite,
chlorite, and any mixture thereof. The clay content of the
formations may be a single species of a clay mineral or several
species, including the mixed-layer types of clay.
[0016] As used herein, "coal bed" refers to a rock formation that
may be comprised of, inter alia, one or more types of coal,
including, but not limited to, peat, lignite, sub-bituminous coal,
bituminous coal, anthracite, and graphite.
[0017] "Pressure pulse" or "pressure pulsing," as referred to
herein, will be understood to mean the effect or action of
deliberately varying the fluid pressure in a subterranean formation
through the application of periodic increases, or "pulses," in the
pressure of a fluid being placed into the formation. A "pressure
pulse" should be understood to be a time-dependent raising and
lowering of a fluid pressure, as would be clear to a person of
ordinary skill in the art.
[0018] As used herein, a pressure pulse which "straddles or exceeds
the formation fracture gradient" would be a pressure pulse wherein
the maximum fluid pressure of the pulse is greater than the
fracture gradient, and the minimum fluid pressure of the pulse may
be either less than (in the case of "straddles") or greater than
(in the case of "exceeds") the fracture gradient of the
formation.
[0019] As used herein, the term "matrix flow conditions" is defined
as a placement of a fluid conducted below the fracture gradient
pressure of a subterranean formation, and/or below the parting
pressure of a layered formation.
[0020] The term "formation fracture gradient" is defined to include
a fluid pressure sufficient to create or enhance one or more
fractures in the subterranean formation. As used herein, the
"fracture gradient" of a layered formation also encompasses a
parting fluid pressure sufficient to separate two or more adjacent
bedding planes in a layered formation. It should be understood that
a person of ordinary skill in the art could perform a simple
leak-off test on a core sample of a formation to determine the
fracture gradient of a particular formation.
[0021] "Enhance one or more fractures in a subterranean formation,"
as that phrase is used herein, is defined to include the extension
or enlargement of one or more natural or previously created
fractures in the subterranean formation.
[0022] As used herein, the term "treatment fluid" refers to any
fluid that may be used in a subterranean application in conjunction
with a desired function and/or for a desired purpose. The term
"treatment fluid" does not imply any particular action by the fluid
or any component thereof.
[0023] As used herein, the term "dilation" refers to an expansion
of a fracture and/or separation of a pair of adjacent bedding
planes due to the force exerted by a fluid pressure pulse against
the fracture walls and/or bedding plane surfaces.
[0024] No particular mechanism of consolidation or stabilization is
implied by the term "consolidating agent." The consolidating agents
used in the present invention may provide adhesive bonding between
formation particulates to alter the distribution of the
particulates within the formation in an effort to reduce their
potential negative impact on permeability and/or fracture
conductivity. In some embodiments, the consolidating agents may
cause formation particulates to become involved in collective
stabilized masses and/or stabilize the formation particulates in
place to prevent their migration that might negatively impact
permeability and/or fracture conductivity.
[0025] If there is any conflict in the usages of a word or term in
this specification and one or more patent or other documents that
may be incorporated herein by reference, the definitions that are
consistent with this specification should be adopted.
[0026] The present invention provides, inter alia, methods for
placing treatment fluids into a subterranean formation which
comprises shales, clays, and/or coal beds using one or more
pressure pulses which straddle or exceed the formation fracture
gradient. One of the advantages of the present invention, many of
which are not discussed or alluded to herein, is that a treatment
fluid may be placed with more substantial penetration and relative
uniformity throughout a subterranean formation. Moreover, the
methods of the present invention may be used to increase the
coverage of a treatment fluid into zones with different
permeabilities, without requiring the use of an additive diverter.
Additionally, the methods of the present invention may allow for
the placement of an increased amount of a treatment fluid into low
permeability formations versus the amount that is able to be placed
into such formations under matrix flow conditions. In some
applications, the introduction of a treatment fluid into a
subterranean formation comprising shales, clays, and/or coal beds
may cause the formation to shrink in volume and/or increase in
mechanical strength. This may also act to stabilize the formation
against production of fine particles. In some embodiments, this may
be a result of introducing a treatment fluid into the subterranean
formation that removes aqueous fluids from the formation. In some
embodiments, the introduction of a treatment fluid may stabilize a
formation comprising shales and/or clays, minimizing or ideally
stopping swelling, crumbling, or dispersion of the clay or shale
particles in the formation.
[0027] In certain embodiments, the methods of the present invention
may comprise placing a treatment fluid into a well bore that
penetrates a subterranean formation which comprises shales, clays,
and/or coal beds, and applying a pressure pulse that straddles or
exceeds the formation fracture gradient to the treatment fluid.
Such a pressure pulse may affect the dilatency of existing and/or
created fractures and act, inter alia, to provide additional energy
to help overcome the effects of surface tension and capillary
pressure within the fractures. By overcoming such effects, a
treatment fluid may be able to penetrate the formation more
substantially and with greater uniformity. In some embodiments
where the pressure pulse straddles the formation fracture gradient,
the pressure pulse may effectively introduce a treatment fluid into
an existing fracture without substantially enhancing the existing
fracture. In certain embodiments, pressure pulses that straddle the
formation fracture gradient may be used in combination with
pressure pulses that exceed the formation fracture gradient.
[0028] Without limiting the invention to a particular theory or
mechanism of action, it is nevertheless currently believed that a
pressure pulse or a series of pressure pulses as described herein
may cause the dilation of one or more fractures, networks of
fractures, and/or pairs of adjacent bedding planes in a
subterranean formation. This dilation may be elastic in nature such
that, as the energy dissipates from the formation, a pressure wave
may efficiently propagate along a length of the fracture and/or
bedding plane.
[0029] As previously mentioned, in certain embodiments, a pressure
pulse that straddles or exceeds the formation fracture gradient is
applied to a treatment fluid. The treatment fluid may be
pressurized above the ambient fluid pressure in the well bore prior
to the application of the pressure pulse. If the amplitude of the
pressure pulse exceeds the formation fracture gradient, the
treatment fluid may dilate any existing fracture, network of
fractures, and/or pair of adjacent bedding planes and propagate
there through. In addition, if the amplitude of the pressure pulse
exceeds the formation fracture gradient, the treatment fluid may
also create or enhance one or more fractures in the formation. As
the pressure of the treatment fluid drops below the formation
fracture gradient, the fracture or pairs of adjacent bedding planes
may constrict, and the fluid placed therein may leak off into the
formation along the expanded fracture walls or bedding plane
surfaces. The surface area available for placing the treatment
fluid into the formation may thereby be significantly
increased.
[0030] In some embodiments, a second pressure pulse may be applied
to the treatment fluid, wherein the pressure pulse again straddles
or exceeds the formation fracture gradient so as to enhance the one
or more fractures in the subterranean formation. As the fluid
pressure again drops below the formation fracture gradient, the
fracture or pairs of adjacent bedding planes may again constrict,
thereby allowing the fluid placed therein to leak off into the
formation along the expanded fracture walls or bedding plane
surfaces. The process may be repeated, which may allow the one or
more fractures, networks of fractures, and/or pairs of adjacent
bedding planes to provide a larger surface area for placing the
treatment fluid into the formation. This larger surface area may
allow for much better placement of the treatment fluid in low
permeability reservoirs than could be achieved through matrix
injection. Pressure pulsing may limit fracture growth as compared
to constant application of fluid pressure above the fracture
gradient. Dilation and constriction of the fractures or pairs of
adjacent bedding planes may result in more substantial penetration
of the treatment fluid into the formation. Furthermore, local
pressurization resulting from fluid placement may generate uniform
stresses in the leak off area, thereby allowing a relatively
uniform fracture network to be created.
[0031] The methods of the present invention may have utility for
treating layered formations, such as for example, shales, clays,
and/or coal beds. Layered formations may contain microfractures,
which may be naturally occurring. Thus, in these embodiments, one
or more pressure pulses may dilate one or more pairs of adjacent
bedding planes and/or microfractures present in the layered
formation. The dilation of the pairs of adjacent bedding planes
and/or microfractures may result in a path for fluid flow that
creates a large area for contact of a treatment fluid with the
formation. Accordingly, in certain embodiments, the methods of the
present invention may comprise placing a treatment fluid into a
well bore penetrating a subterranean formation which comprises
shales and/or coal beds, wherein the subterranean formation
comprises one or more pairs of adjacent bedding planes, applying a
pressure pulse to the treatment fluid straddles or exceeds the
formation fracture gradient so as to at least partially separate
one or more pairs of adjacent bedding planes. In some embodiments,
dilation of the microfractures or pairs of adjacent bedding planes
may significantly increase the surface area available for placement
of a treatment fluid.
[0032] The pressure pulses of the methods of the present invention
may be supplied by any device capable of applying a pressure pulse
to a treatment fluid that straddles or exceeds the fracture
gradient of a formation. In certain embodiments, the pressure of
the treatment fluid in the well bore P.sub.0 may be increased in a
steady, rather than staccato, manner such that P.sub.0 approaches
the formation fracture gradient P.sub.f. This resulting state of
such a pressurization may be described according to Equation I.
P.sub.0>P.sub.f-P.sub.0 (I)
When the conditions of Equation I are met, the amplitude of the
pressure pulse P.sub.p necessary to straddle or exceed the
formation fracture gradient P.sub.f may be relatively small
compared to P.sub.0. Alternatively, P.sub.0 may be small compared
to the formation fracture gradient P.sub.f, as described by
Equation II.
P.sub.0<P.sub.f-P.sub.0 (II)
When the condition of Equation II are met, the amplitude of the
pressure pulse P.sub.p necessary to straddle or exceed the
formation fracture gradient P.sub.f may be relatively large
compared to P.sub.0.
[0033] The pulsing parameters may be selected to achieve desired
results. For example, the pressure of the treatment fluid in the
well bore, the amplitude of the pulse, and the frequency of the
pulses may be adjusted. As would be understood by a person of
ordinary skill in the art, factors to consider when selecting these
parameters may include, inter alia, the viscosity of the treatment
fluid, the fracture gradient of the subterranean formation, and the
porosity of the subterranean formation. In some embodiments, the
amplitude of the pulse may be in the range of from about 10 psi to
about 3,000 psi. In some embodiments, the frequency of the pulse
may be in the range of from about 0.001 Hz to about 1 Hz. Pressure
pulsing methods are further discussed in U.S. Pat. No 7,114,560,
issued to Nguyen, which is hereby incorporated by reference.
[0034] Placement of a treatment fluid with pressure pulsing may be
advantageous for a variety of applications. For example, placement
of a consolidation fluid into a subterranean formation comprising
shales, clays, and/or coal beds may provide consolidation in the
formation. Similarly, placement of a treatment fluid in a
subterranean formation comprising shales, clays, and/or coal beds
with pressure pulsing may result in shrinking of the formation
and/or dehydration of the subterranean formation, which may
increase the permeability and/or porosity of the subterranean
formation. Remedial treatments, such as well bore cleanout, may
also benefit by placing a treatment fluid with pressure
pulsing.
[0035] Suitable pressure pulsing devices may include any device
capable of applying a pressure pulse to a treatment fluid such that
the pressure pulse straddles or exceeds the formation fracture
gradient. Suitable pressure pulsing devices may include those
attached to a wellhead and those placed within a well bore.
Pressure pulsing devices attached to a wellhead may be connected to
multiple well bores and may be operated to selectably supply
pressure pulses to one or more of the well bores. One example of a
pressure pulsing device that may be suitable for use in the methods
of the present invention is the surface pressure pulsing system
disclosed in U.S. Pat. No. 7,025,134 issued to Byrd et al., which
is incorporated by reference herein. In some embodiments, the
pressure pulsing device may be a high amplitude device. Lower
amplitude devices may also be suitable according to other
embodiments. One of ordinary skill in the art would be able to
select an appropriate pressure pulsing device based on several
factors, including the characteristics of the subterranean
formation and/or the treatment fluid to be used. Another example of
a pressure pulsing device that may be suitable for use in the
methods of the present invention is a fluidic oscillator, examples
of which are disclosed in U.S. Pat. Nos. 5,135,051, 5,165,438, and
5,893,383, which are incorporated by reference herein. Examples of
commercially available pressure pulsing devices or systems may
include Deepwave.sup.SM, available from Halliburton Energy
Services, Duncan, Okla. (see also U.S. Patent Application No.
2006/0272821), and PowerWave.TM. Technology, commercially available
from Wavefront Energy and Environmental Services USA Inc. of
Cypress, Tex.
[0036] Generally, when treating subterranean formations comprising
shales, clays, and/or coal beds, suitable treatment fluids may
include, but are not limited to, treatment fluids that shrink or
dehydrate the formation, treatment fluids that stabilize the
formation, and treatment fluids that coat the formation surfaces.
Such treatment fluids may, inter alia, affect the mechanical
strength of at least a portion of the formation, reduce the volume
of at least a portion of the formation, increase the flow capacity
of the natural fractures and/or bedding planes within the
formation, and/or make the formation less reactive to aqueous based
fluids. Examples of suitable treatment fluids may include a
treatment fluid comprising a cationic polymer, a cationic oligomer,
a cation, a methanol, a glycerin, an ethylene glycol, a low
molecular weight consolidation fluid, a polymeric composition, a
quaternary ammonium compound having inorganic anions and
carboxylate anions, a polymeric composition, a rheology stabilizer,
a rheology thinner, a consolidation fluid, a stimulation fluid, a
relative permeability modifier, or any combination thereof.
[0037] Suitable treatment fluids may include cationic polymers and
oligomers, for example, poly(dimethyldiallylammonium chloride),
cationic co-polymers of poly(acrylamide), and cationic
poly(diemethylaminoethylmethacrylate). Commercially available
suitable treatment fluids include BARACAT.RTM., BARASIL-S.TM.,
BARO-TROL PLUS.RTM., BORE-HIB.TM., BXR.TM., BXR.TM.-L, CLAY
FIRM.RTM., CLAY SYNC.TM., CLAY SYNC II.TM., Cla-Sta.RTM. FS,
Cla-Sta.RTM. XP, Clayfix.TM., Clayfix II.TM., Clayfix 3.TM.,
GEM.TM. CP, GEM.TM. GP, and HYDRO-GUARD.RTM. Fluid, each available
from Halliburton's Baroid Fluid Services of Houston, Tex.
[0038] Another example of a treatment fluid suitable for use in the
present invention is a treatment fluid comprising cations
(including, but not limited to, potassium ions, calcium ions,
ammonium ions, hydrogen ions, tetramethylammonium ion), salts that
provide cations (including, but not limited to, potassium chloride,
calcium chloride, sodium chloride, ammonium chloride,
tetramethylammonium chloride, and other cationic oligomers), or
mixtures thereof, any of which may be delivered by aqueous
solutions or ionic liquids. Without limiting the invention to a
particular theory or mechanism of action, it is nevertheless
currently believed that when a treatment fluid comprising a high
concentration of cations contacts a subterranean formation
comprising shales and/or clays, the ions of the cationic salts may
exchange with sodium ions commonly found in shale layers. This ion
exchange may have the effect of reducing the volume of the shales
and/or clays, wherein the shrinkage may increase the flow
capability and/or affect the mechanical properties of the
formation. In some embodiments, it may be desirable to select
cations with a small ionic radius, a high charge density, and/or a
small hydration sphere. For example, in some embodiments, the
cations may have hydration spheres with diameters in the range of
about 10 to about 25 Angstroms.
[0039] Other suitable treatment fluids which dehydrate shales,
clays, and/or coal beds may include, for example, methanol,
glycerin, and ethylene glycol.
[0040] Suitable treatment fluids may also include low molecular
weight consolidation fluids. As used herein, the term "low
molecular weight consolidation fluid" refers to a consolidation
fluid with a molecular weight of less than about 1000. It is
believed that low molecular weight consolidation fluids would
exhibit low viscosities during pumping operations, such as
viscosities less than about 100 centipoise, when measured at room
temperature when using a Fann model 50. Such fluids may include,
for example, monomeric or oligomeric compositions which may be
polymerized, acrylics, maleic acid derivatives, and furfuryl
alcohol. (See "An Improved Sand Consolidation Process with Clay
Conditioning," SPE 1339 (1965), B. M. Young, Society of Petroleum
Engineers.)
[0041] Suitable treatment fluids also include certain quaternary
ammonium compounds having inorganic anions and carboxylate anions,
as discussed in U.S. Pat. No. 5,097,904, which is herein
incorporated by reference. Those quaternary ammonium compounds
having carboxylate anions being entirely organic in nature are
biodegradable and thus enjoy a greater environmental acceptance
than those which do not have carboxylate anions.
[0042] Another example of a suitable treatment fluid may include a
polymeric composition that may be used to, inter alia, stabilize
reactive shales and/or clays in subterranean formations. As
discussed in U.S. Pat. No. 7,091,159 issued to Eoff et al., which
is hereby incorporated by reference, such polymeric compositions
may stabilize the shales and/or clays, minimizing or ideally
stopping degradation.
[0043] Suitable treatment fluids may also include rheology
stabilizers or thinners for high-temperature high-pressure high
mineralized degree drilling fluids as discussed in U.S. Pat. No.
6,436,878, issued to Wang et al., which is hereby incorporated by
reference. Any of the previously discussed suitable treatment
fluids may be delivered downhole in a pumpable multiple phase
composition, as discussed in U.S. Pat. No. 6,464,009, issued to
Bland et al., which is hereby incorporated by reference.
[0044] Other treatment fluids that may be useful according to the
methods of the present invention may include, but are not limited
to, consolidation fluids, stimulation fluids, and treatment fluids
comprising substances such as relative permeability modifiers.
[0045] In some embodiments, suitable treatment fluids may include
stimulation fluids. Stimulation fluids that may be suitable for use
in the present invention may be acid or solvent-based. For example,
hydrochloric acid may be a suitable stimulation fluid.
[0046] Consolidation fluids that may be suitable for use in the
present invention may comprise at least one consolidation fluid
selected from the group consisting of a resin, a tackifying agent,
a gelable composition, and a combination thereof. Suitable
tackifying agents may comprise any compound that, when in liquid
form or in a solvent solution, will form a non-hardening coating
upon a particulate. Suitable resins include all resins known in the
art that are capable of forming a hardened, consolidated mass.
Suitable gelable compositions may include those compositions that
cure to form a semi-solid, immovable, gel-like substance. Examples
of suitable gelable compositions include, but are not limited to,
gelable resin compositions, gelable aqueous silicate compositions,
crosslinkable aqueous polymer compositions, polymerizable organic
monomer compositions, and combinations thereof. Consolidation
fluids that may be suitable for use in the present invention may be
further discussed in U.S. Pat. No. 7,114,560, issued to Nguyen,
which is hereby incorporated by reference.
[0047] The concentration of treatment fluids may vary depending on
the characteristics of the formation being treated. For example,
shale formations may exhibit greater surface area and lower
permeability than sandstone formations. Considerations when
determining the concentration of a treatment fluid may include such
factors as the surface area of the formation, or the viscosity
required to provide appropriate pulsing parameters, as previously
discussed. It should be understood that a person of ordinary skill
in the art would be capable of analyzing these factors to determine
appropriate the appropriate concentrations.
[0048] Consolidation fluids suitable for use in the present
invention generally comprise at least one consolidating agent
selected from the group consisting of a resin, a tackifying agent,
a gelable composition, and a combination thereof. In some
embodiments of the present invention, the viscosity of the
consolidation fluid is less than about 100 cP, preferably less than
about 50 cP, and still more preferably less than about 10 cP.
[0049] Resins suitable for use in the consolidation fluids of the
present invention include all resins known in the art that are
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 down hole, 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.
[0050] Any solvent that is compatible with the resin and achieves
the desired viscosity effect is suitable for use in the present
invention. Preferred solvents include those listed above in
connection with tackifying compounds. It is within the ability of
one skilled in the art, with the benefit of this disclosure, to
determine whether and how much solvent is needed to achieve a
suitable viscosity.
[0051] Tackifying agents suitable for use in the consolidation
fluids of the present invention comprise any compound that, when in
liquid form or in a solvent solution, will form a non-hardening
coating upon a particulate. A particularly preferred group of
tackifying agents 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
tackifying compounds include liquids and solutions of, for example,
polyesters, polycarbonates, and polycarbamates, natural resins such
as shellac and the like. Other suitable tackifying agents are
described in U.S. Pat. No. 5,853,048 issued to Weaver, et al. and
U.S. Pat. No. 5,833,000 issued to Weaver, et al., which are herein
incorporated by reference.
[0052] Tackifying agents suitable for use in the present invention
may be either used such that they form non-hardening coating or
they may be combined with a multifunctional material capable of
reacting with the tackifying compound 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 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 issued to
Weaver, et al., which is herein incorporated by reference.
[0053] Solvents suitable for use with the tackifying agents of the
present invention include any solvent that is compatible with the
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.
[0054] Gelable compositions suitable for use in the present
invention include those compositions that cure to form a
semi-solid, immovable, gel-like substance. The gelable 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.
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 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 treated region. Examples of suitable
gelable liquid compositions include, but are not limited to, (1)
gelable resin compositions, (2) gelable aqueous silicate
compositions, (3) crosslinkable aqueous polymer compositions, and
(4) polymerizable organic monomer compositions.
[0055] Certain embodiments of the gelable liquid compositions of
the present invention comprise gelable resin compositions that cure
to form flexible gels. Unlike the resin compositions described
above, which generally cure into hardened masses, the gelable resin
compositions cure into flexible, gelled substances that form
resilient gelled substances. Gelable resin compositions allow the
treated portion of the formation to remain flexible and to resist
breakdown.
[0056] Generally, the gelable resin compositions useful in
accordance with this invention 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.
[0057] Examples of gelable resins that can be used in 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.
[0058] Any solvent that is compatible with the gelable resin and
achieves the desired viscosity effect is suitable for use in the
present invention. Examples of solvents that may be used in the
gelable 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 solvent comprises butyl
lactate. Among other things, the solvent acts to provide
flexibility to the cured composition. The solvent may be included
in the gelable resin composition in an amount sufficient to provide
the desired viscosity effect.
[0059] 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 gelable 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 gelable 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 gelable resin composition in an amount in the
range of from about 20% to about 75% by weight of the curable
resin.
[0060] 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 may be used
where the resin curing agent chosen would cause the gelable resin
composition to cure into a hard and brittle material--rather than a
desired gelled substance. 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 gelable resin
composition in an amount in the range of from about 5% to about 80%
by weight of the gelable 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.
[0061] In other embodiments, the consolidation fluids 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.
[0062] The aqueous alkali metal silicate solution component of the
gelable aqueous silicate compositions generally comprise 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
alkali metal silicate solution component in an amount in the range
of from about 0.1% to about 10% by weight of the aqueous alkali
metal silicate solution component.
[0063] The temperature-activated catalyst component of the gelable
aqueous silicate 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 that 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
gelable aqueous silicate composition in the range of from about
0.1% to about 5% by weight of the gelable aqueous silicate
composition.
[0064] In other embodiments, the consolidation fluids suitable for
use in the methods of the present invention comprise a
crosslinkable aqueous polymer compositions. Generally, suitable
crosslinkable aqueous polymer compositions comprise an aqueous
solvent, a crosslinkable polymer, and a crosslinking agent. Such
compositions are similar to those used to form gelled treatment
fluids, such as fracturing fluids, but, according to the methods of
the present invention, they are not exposed to breakers or
de-linkers, and so they retain their viscous nature over time.
[0065] 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.
[0066] 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.
[0067] The crosslinkable aqueous polymer compositions of the
present invention further comprise a crosslinking agent for
crosslinking the crosslinkable polymers to form 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.
[0068] 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 about 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.
[0069] Optionally, the crosslinkable aqueous polymer compositions
may further comprise a crosslinking delaying agent, such as a
polysaccharide crosslinking delaying agent 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.
[0070] In other embodiments, the consolidation fluids suitable for
use in the methods of the present invention comprise polymerizable
organic monomer compositions. Generally, suitable polymerizable
organic monomer compositions comprise an aqueous-base fluid, a
water-soluble polymerizable organic monomer, and a primary
initiator. Optionally, the polymerizable organic monomer
compositions may also include an oxygen scavenger and/or a
surfactant.
[0071] The aqueous-based 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.
[0072] 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 gylcol acrylate,
polypropylene glycol methacrylate, and mixtures thereof. Of these,
hydroxyethylacrylate is preferred. An example of a particularly
preferable monomer is hydroxyethylcellulose-vinyl phosphoric
acid.
[0073] 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 is 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 is 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.
[0074] 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.
[0075] 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
that 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
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).
One skilled in the art will recognize that as the polymerization
temperature increases, the required level of activator
decreases.
[0076] 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).
[0077] Also 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.
[0078] 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. All numbers and ranges disclosed above
may vary slightly. Moreover, any numerical range defined by two R
numbers as defined in the above is also specifically disclosed.
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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