Note: Descriptions are shown in the official language in which they were submitted.
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MULTI-STAGE METHODS AND COMPOSITIONS FOR DESENSITIZING
SUBTERRANEAN FORMATIONS FACES
CROSS REFERENCE TO RELATED APPLICATION
[0001]
The present application is a continuation-in-part of U.S. Patent
Application Serial Number 13/106,382 filed on May 12, 2011, the entire
disclosure of which is incorporated herein by reference.
BACKGROUND
[0002] The present invention relates to multi-stage methods for
treating a subterranean formation in order to desensitize formation faces to
deleterious chemical or physical changes.
[0003] The recovery of fluids such as oil and gas from subterranean
formations has been troublesome in formations that contain sensitive minerals
capable of undergoing chemical and physical changes along the formation faces,
e.g., minerals that swell, slough, degrade, release fines, or become ductile.
As
used herein, "formation faces" refers to any portion of the formation that is
exposed to, for example, a treatment fluid, and includes fracture faces and
platelet faces. As used herein, "ductile" refers to becoming able to deform
under
pressure.
[0004] Often these troublesome formations undergo chemical and
physical changes when exposed to aqueous fluids, a common base for
subterranean treatment fluids. Troublesome formations may include, but not be
limited to, water-sensitive clays, tight gas formations, shales, and coal
beds.
The terms "clays" and "water-sensitive clays" are used herein interchangeably
to
generally indicate water-sensitive clays that, when contacted by aqueous
fluids
in disequilibrium with the minerals in the formation, tend to swell and/or
migrate. The clay content of the formations may be a single species of a clay
mineral or several species, including, but not limited to, the mixed-layer
types of
clay. As used herein, the term "tight gas" refers to gas found in sedimentary
rock that is cemented together so that permeabilities are relatively low. 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, "coal bed" refers to a rock formation that may be comprised
of,
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inter alia, one or more types of coal, including, but not limited to, peat,
lignite,
sub-bituminous coal, bituminous coal, anthracite, and graphite.
[0005] The chemical and physical changes in the formation faces often
results in the blockage and/or closure of passageways that penetrate the
subterranean formation (e.g., fracture network, pore throats, etc.), thereby
causing a loss in permeability of the formation. This loss in permeability
impairs
the flow of fluid through the wellbore and, in some cases, may even completely
block the flow of fluids through portions of the formation. Loss in
permeability
often leads to a decrease in the production for the well. Moreover, some
changes in the formation faces, e.g., migrating fines, can be produced with
the
formation fluids, thereby presenting potential abrasion and other problems
with
the production equipment and potential reduction in fracture conductivity.
[0006] In an effort to overcome these problems, various methods have
been developed for treating problematic formations to desensitize the
formation
faces from chemical and physical changes. For example, it has been common
practice to add salts to aqueous drilling fluids. The salts adsorb to the clay
surfaces in an ion exchange process that can reduce the swelling and/or
migration of the clays. Another method used to deter migration is to coat the
region with a polymer and/or a consolidating resin in order to physically
block
the migration of the clays. The term "desensitizing solution" as used herein
refers to any solution or suspension used to reduce the sensitivity of
minerals
within a subterranean formation to chemical and physical changes. The terms
"desensitizing components" and "desensitizing agents" as used herein refer to
the components of a desensitizing solution that interacts with formation faces
to
reduce the sensitivity of minerals to chemical and physical changes.
[0007] When a desensitizing solution is exposed to formation faces of
problematic formations, the desensitizing agents are removed from the
desensitizing solution by the formation faces through known mechanisms
including, but not limited to, adsorption, ion exchange, and chemical
reaction.
As the concentration of the desensitizing agents decreases in the remaining
solution, untreated formation faces are exposed to aqueous fluids which
promotes the deleterious chemical and physical changes. Current state-of-the-
art implementation of desensitizing solutions call for injection of a single
bolus of
a relatively high concentration of desensitizing solution into the
subterranean
formation. Using such a method results in the depletion of desensitizing
agents
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most notably at the leading-edge of the desensitizing solution as the solution
migrates through the subterranean formation.
SUMMARY OF THE INVENTION
[0008] The present invention relates to multi-stage methods for
treating a subterranean formation in order to desensitize formation faces to
deleterious chemical or physical changes.
[0009] In some embodiments of the present invention, a method of
desensitizing a subterranean formation may comprise: introducing a leading-
edge fluid comprising a first base fluid and a first desensitizing agent,
wherein
the first desensitizing agent is present in the first base fluid at a first
concentration; then introducing a treatment fluid comprising a second base
fluid
and a second desensitizing agent, wherein the second desensitizing agent is
present in the second base fluid at a second concentration; and wherein the
first
concentration is higher than the second concentration.
[0010] In some embodiments of the present invention, a method of
desensitizing a subterranean formation may comprise: introducing a leading-
edge fluid into a subterranean formation at or above the matrix pressure,
wherein the leading-edge fluid comprises a first base fluid and a first
desensitizing agent, wherein the first desensitizing agent is present in the
first
base fluid at a first concentration; then introducing a treatment fluid into
the
subterranean formation at or above the matrix pressure, wherein the treatment
fluid comprises a second base fluid and a second desensitizing agent, wherein
the second desensitizing agent is present in the second base fluid at a second
concentration; and wherein the first concentration is higher than the second
concentration.
[0011] In some embodiments of the present invention, a method of
desensitizing a subterranean formation may comprise: introducing a leading-
edge fluid comprising a first base fluid and a first desensitizing agent above
the
matrix pressure into the subterranean formation, wherein the first
desensitizing
agent is present in the first base fluid at a first concentration, wherein the
first
concentration ranges from about 0.1% to about 15% v/v of first desensitizing
agent to first base fluid; then introducing a treatment fluid comprising a
second
base fluid and a second desensitizing agent, wherein the second desensitizing
agent is present in the second base fluid at a second concentration, wherein
the
second concentration ranges from about 0.001% to about 5% v/v of second
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desensitizing agent to second base fluid; and wherein the desensitizing
solution
is the same chemical composition in the leading-edge fluid and treatment
fluid.
[0012] The features and advantages of the present invention will be
readily apparent to those skilled in the art upon a reading of the description
of
the preferred embodiments that follows.
BRIEF DESCRIPTION OF THE DRAWINGS
[0013] The following figures are included to illustrate certain aspects of
the present invention, and should not be viewed as exclusive embodiments. The
subject matter disclosed is capable of considerable modification, alteration,
and
equivalents in form and function, as will occur to those skilled in the art
and
having the benefit of this disclosure.
[0014] Figure 1 provides illustrative graphs of the concentration of the
desensitizing agent within the fluid phase as a function of depth of
penetration
from the wellbore.
[0015] Figure 2 provides illustrative graphs of the concentration of the
desensitizing agent at the formation faces as a function of depth of
penetration
from the wellbore.
[0016] Figure 3 provides an illustrative graph of a nonlimiting example
of an injection profile of a wellbore treatment according to the present
invention.
DETAILED DESCRIPTION
[0017] The present invention relates to multi-stage methods for
treating a subterranean formation in order to desensitize formation faces to
deleterious chemical or physical changes.
[0018] Of the many advantages, the present invention provides for
methods yielding formation face desensitization, i.e., mineral
desensitization,
against deleterious chemical and/or physical changes that penetrate deeper
into
the subterranean formation while decreasing the overall amount of the
desensitizing agents. Reduction in the amount of desensitizing agents used can
result in a significant cost savings for the operator and may help reduce the
environmental impact of the treatment. It should be noted that the term
"penetration" refers to both the distance traversed from the wellbore within a
fracture network and the radially distance from the fracture into the
formation,
e.g., penetrating radially several clay platelets deep into the formation
along a
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fracture. It should be noted that the term "formation face" includes the faces
encountered radially from the fracture network into the formation.
[0019] In some embodiments, a method of desensitizing a
subterranean formation may generally include the steps of:
introducing a
leading-edge fluid comprising a first base fluid and a first desensitizing
agent
into at least a portion of the subterranean formation, wherein the first
desensitizing agent is present in the first base fluid at a first
concentration; and
then introducing a treatment fluid comprising a second base fluid and a second
desensitizing agent into at least a portion of the subterranean formation,
wherein the second desensitizing agent is present in the second base fluid at
a
second concentration, and wherein the first concentration is higher than the
second concentration.
[0020] Because the leading-edge fluid enters the formation first, it
contacts formation faces, such as water-sensitive clays, before other liquids
are
placed into the formation. That is, the leading-edge fluid is highly likely to
encounter sensitive minerals. The depletion of desensitizing agents in the
leading-edge fluids, as to contacts new formation faces, may be extensive.
Therefore, a high concentration of desensitizing solution in the leading-edge
fluid
may effectively desensitize minerals as the fluid penetrates the subterranean
formation and maintains a desensitizing solution concentration above the
necessary amount to desensitize minerals deeper into the subterranean
formation. The treatment fluids placed subsequent to the leading-edge fluid
may exhibit lower levels of desensitizing solution than required in
traditional
methods. Because the leading-edge fluid has been placed before the treatment
fluid, so long as the interval to be treated by the treatment fluid has been
fully
contacted by the leading-edge fluid, the treatment fluid needs not act as the
primary desensitization fluid. Rather, the desensitizing agents in the
treatment
fluid following the leading-edge fluid may be used to desensitize any newly
exposed minerals during the treatment. Therefore, the concentration of the
desensitizing agents in the fracturing fluid is significantly lower than in
the
leading-edge fluid.
[0021] Figures 1-3 compare a nonlimiting example of a treatment
according to an embodiment of the present invention to current methods of
injecting desensitizing agents at a constant concentration. Figure 3
illustrates
the injection profile, Ý.e., the concentration injected as a function of time.
In this
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nonlimiting example, the leading-edge method injects first a higher
concentration of destabilizing agent than a lower concentration. The method to
which this example compares injects a single concentration over the same
amount of time. Figures 1 and 2 provide a series of illustrative snapshots of
what may be occurring over time in the subterranean formation as the two
methods would be implemented.
[0022] Figure 1 looks at the concentration remaining in the fluid phase
as a function of depth of penetration into the formation. It should be noted
this
is meant to illustrate the concentration in solution in the formation, e.g.,
down
the length of a fracture, at a specific time point and not the injection
profile.
The various time points show the fluid in both treatments being depleted. In
the
leading-edge fluid method illustrated, the treatment fluid, which has a
significantly lower concentration, injected after the leading-edge fluid
maintains
the level of desensitization and therefore is not significantly depleted.
Further
illustrated is the level of desensitization of the formation face with a line
indicating "fully" desensitized minerals. One skilled in the art, with the
benefit of
this disclosure, should understand "fully" desensitized minerals includes
substantially desensitized and most likely varies based on depth of
penetration
into the formation. In this example, it is only used to illustrate the point
that as
desensitizing agents are depleted from the fluid, the leading-edge of the
fluid
may not have a high enough concentration of desensitizing agents to interact
with the formation faces, i.e., sensitive minerals may undergo deleterious
chemical and/or physical changes at the leading-edge of a treatment. In some
embodiments, the methods of the present invention aim to overcome this
problem by introducing a leading-edge fluid that comprises a higher
concentration of desensitizing agents so that at the leading-edge of a
treatment
sensitive minerals are effectively desensitized.
[0023] Further, Figure 2 provides the concentration injection profile at
time point 3 of Figure 1. The illustrative method of the present invention
uses
less desensitizing agent than the method currently implemented. These figures
illustrate that the methods provided herein are suited for desensitizing
mineral
further into a subterranean formation with the need for less overall
desensitizing
agent.
[0024] The compositions and methods of the present invention may be
used in subterranean formations containing water-sensitive clays, tight gas
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formations, shales, and coal beds. Specifically, subterranean formations may
include minerals like, but not limited to, silica; iron minerals; alkaline
earth
metal carbonates, feldspars, biotite, illite, and chlorite; smectite clays
such as
montmorillonite, beidellite, nontronite, saponite hectorite and sauconite;
kaolin
clays such as kaolinite, nacrite, dickite, endellite and halloysite; illite
clays such
as hydrobiotite, glauconite and illite; chlorite clays such as chlorite,
greenalite
and chamosite; other clay minerals not belonging to the above groups such as
vermiculite, palygorskite, sepiolite; mixed-layer (both regular and irregular)
varieties of the above minerals; and any combination thereof.
[0025] Some suitable methods of the present invention may comprise
placing a leading-edge fluid comprising a concentrated desensitizing solution
into
the subterranean reservoir to expose formation faces to the desensitizing
agent
so as to reduce, or remediate, their sensitivity to deleterious chemical
and/or
physical changes. Subsequently placed treatment fluids may comprise a lower
concentration of desensitizing solution to preserve the existing level of
mineral
desensitization and/or inhibit sensitization of newly exposed formation faces.
[0026] As used herein, the term "treatment," or "treating," refers to
any subterranean operation that uses a fluid in conjunction with a desired
function and/or for a desired purpose. The term "treatment," or "treating,"
does
not imply any particular action by the fluid. By way of nonlimiting examples,
a
treatment fluid introduced into a subterranean formation subsequent to a
leading-edge fluid may be a fracturing fluid, an acidizing fluid, a
stimulation
fluid, a sand control fluid, a completion fluid, a frac-packing fluid, or
gravel
packing fluid. The methods, leading-edge fluids, and subsequent treatment
fluids of the present invention may be used in full-scale operations, pills,
or any
combination thereof. As used herein, a "pill" is a type of relatively small
volume
of specially prepared treatment fluid placed or circulated in the wellbore.
[0027] In some embodiments, leading-edge fluids and/or subsequent
treatment fluids may be introduced at or above "fracture pressure," which as
used herein refers to pressures necessary to create or extend at least one
fracture within the subterranean formation. In some embodiments, leading-
edge fluids and/or subsequent treatment fluids may be introduced at "matrix
pressure," which as used herein refers to pressures below the fracture
pressure
of the formation.
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[0028] In some embodiments, leading-edge fluids may be introduced
into a single wellbore multiple times, e.g., multi-stage fracturing operations
where sections of the formation are fractured then plugged sequentially where
each fracturing includes introducing a leading-edge fluid followed by at least
one
subsequent treatment fluid.
[0029] In some embodiments, a fracturing method according to the
present invention may comprise multiple stages (or sections). The stages may
include, but not be limited to, introducing a leading-edge fluid or a
treatment
fluid, each with the appropriate concentration of desensitizing agent, that
comprise an additive that may include, but not be limited to, proppants;
diverting agents including degradable diverting agents; plugs; plugging
agents;
and any combination thereof. By way of nonlimiting example, a multi-stage
treatment may include
(a) introducing a first leading-edge fluid comprising a first
concentration of a desensitizing agent into a first stage of a wellbore
penetrating a subterranean formation, the first leading-edge fluid
optionally comprising a proppant;
(b) introducing a first treatment fluid comprising a second
concentration of desensitizing agent that is lower than the first
concentration into the first stage of the wellbore, the first treatment fluid
optionally comprising a proppant;
(c) introducing a second treatment fluid comprising a diverting
agent to substantially divert subsequent fluids from the first stage of the
wellbore, the second treatment fluid optionally comprising a desensitizing
agent and/or a proppant;
(d) introducing a second leading-edge fluid comprising a third
concentration of a desensitizing agent into a second stage of a wellbore
penetrating a subterranean formation, the second leading-edge fluid
optionally comprising a proppant;
(e)
introducing a third treatment fluid comprising a fourth
concentration of desensitizing agent that is lower than the third
concentration into the second stage of the wellbore, the third treatment
fluid optionally comprising a proppant;
(f)
introducing a fourth treatment fluid comprising a diverting agent
to substantially divert subsequent fluids from the second stage of the
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wellbore, the fourth treatment fluid optionally comprising a desensitizing
agent and/or a proppant; and
(9) continuing until several stages, e.g., 50 or more, are
treated.
[0030] In some embodiments, the stages may be defined by a
agent in any of the above steps may be interchanged with a plug, e.g., a
packer,
a bridge plug, a frac plug, or the like, or a plugging agent, e.g., perf
balls, gels,
plugging foams, degradable diverting agents, and the like. Also, said
treatment
fluid may be a fracturing fluid. Further, it should be noted that other steps,
e.g.,
[0031] In some embodiments, leading-edge fluids with subsequent
[0032] In some embodiments, leading-edge fluids may be used in a
[0033] In some embodiments, leading-edge fluids with subsequent
treatment fluids may be used for injection wells. As used herein, "injection
wells" refer to wells in which fluids are injected rather than produced with
the
primary objective of maintaining reservoir pressure that may assist in
production
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[0034] In some embodiments, leading-edge fluids with subsequent
treatment fluids may be used in a well completion operation, such as a pre-pad
fluid in gravel packing operations. The higher concentration of desensitizing
agents in a leading-edge fluid would protect the surrounding formation during
the wellbore completion operations.
[0035] The optimal concentration of desensitizing agents to use in the
leading-edge fluid can be determined by one skilled in the art. One suitable
method for determining the optimal concentration of desensitizing agents to be
used in the leading-edge fluid involves a four-step analysis. First, determine
the
total mineral concentration(s) and mineral type(s) from known methods
including, but not limited to, x-ray analysis and scanning electron
microscopy.
Second, determine the desensitizing capacity of a formation sample. By way of
non-limiting example, the cation exchange capacity of a formation sample can
be determined by Langmuir adsorption isotherms, surface roughness, and cation
exchange capacity. Third, estimate the generated surface area during the
fracture treatment using known simulation methods. Finally, estimate the mass
of desensitizing agents required using the values determined in the first
three
steps.
[0036] An approximate concentration of desensitizing agents to use in
the leading-edge fluid can be determined by one skilled in the arts by
generally
characterizing the degree to which the mineral(s) in the subterranean
formation
require desensitization. By way of non-limiting example, water-sensitive clays
may be categorized as very water sensitive, moderately water sensitive, or
minimally water sensitive. Additionally, one skilled in the arts may be able
to
estimate the necessary desensitization of the minerals in the subterranean
formation based on known characteristics of the formation, nearby wells, and
similar formations.
[0037] It should be noted that when "about" is provided at the
beginning of a numerical list, "about" modifies each number of the numerical
list.
It should be noted that in some numerical listings of ranges, some lower
limits
listed may be greater than some upper limits listed. One skilled in the art
will
recognize that the selected subset will require the selection of an upper
limit in
excess of the selected lower limit.
[0038] A preferred method for desensitizing minerals calls for the
concentration of the desensitizing agents in the leading-edge fluid to range
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a lower limit of about 0.01 /o, 0.05%, 0.1%, 0.5%, 1%, 2%, 5%, or 10% to an
upper limit of about 60%, 50%, 25%, 15%, 10%, or 5% v/v, and wherein the
concentration may range from any lower limit to any upper limit and encompass
any subset therebetween. Minerals requiring more desensitization may require
more concentrated desensitizing solution in the leading-edge fluid relative to
the
fracturing fluid.
[0039] A preferred method for desensitizing minerals calls for the
concentration of the desensitizing agents in subsequent treatment fluids to
range
from a lower limit of about 0.0001%, 0.001%, 0.01%, 0.1%, or 1% to an upper
limit of about 2O%, 10%, 5%, 2%, 1%, or 0.1% v/v, where the concentration
may range from any lower limit to any upper limit and encompass any subset
therebetween. In some embodiments, the concentration of desensitizing agents
in the leading-edge fluid may range from a lower limit of about 2, 3, 5, 10,
or 25
times to an upper limit of about 5000, 2500, 1000, 500, 100, 75, 50, or 25
times greater than the concentration of desensitizing agents in the treatment
fluid, and wherein the concentration may range from any lower limit to any
upper limit and encompass any subset therebetween. In some embodiments,
the concentration of desensitizing agents may vary during the fracturing
operation, i.e., during the introduction of the fracturing fluid.
In some
embodiments, the concentration change may be step-wise, gradient, or any
combination thereof.
[0040] In some embodiments, a transition fluid may be used between
the leading-edge fluid and subsequent treatment fluids. The transition fluid
may
comprise desensitizing agents at an intermediate concentration relative to the
leading-edge fluid and subsequent treatment fluids. In some embodiments, a
transition fluid may provide for a step-wise, gradient, or combination thereof
concentration reduction of the desensitizing agents from the leading-edge
fluid
to the subsequent treatment fluids. In some embodiments, the transition fluid
may be introduced to the subterranean formation at a matrix pressure, at or
above formation pressure, or any combination thereof.
[0041] In some embodiments, the concentration of desensitizing agents
in leading-edge fluids, transition fluids, and/or subsequent treatment fluids
may
be adjusted on-the-fly. In some embodiments, the fluid being introduced into
the wellbore may be changed based on a pressure change observed at the
surface of the wellbore. By way of nonlimiting example, a pressure drop at the
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surface of a wellbore may indicated fracturing is occurring and a transition
to a
leading-edge fluid is necessary.
[0042] Nearly all desensitizing agents suitable for use in subterranean
operations may be used in the methods of the present invention including, but
not limited to, inorganic acids, salts, polyelectrolytes, multivalent ions,
inorganic
bases, strong bases, oxides, resins, surfactants, polymers, cationic polymers,
methyl glucosides, polyglycerols, polyglycols, emulsion facilitating
particles,
chelating agents, phosphines, soluble organic stabilizing compounds, silica
control agents, embrittlement modification agents, surface modification
agents,
microparticles, nanoparticles, and any combination thereof. The desensitizing
agents may be the same or different chemical compositions within the various
fluids for use in the methods provided herein.
Utilizing different chemical
compositions may be advantageous to further reduce costs.
By way of
nonlimiting example, the leading-edge fluid may comprise an expensive
desensitizing agent that is more effective at desensitizing formation faces.
Subsequent fluids may be less expensive desensitizing agents that maintain the
level of desensitization at the formation faces. Further, the desensitizing
agents
may be for desensitizing a single mineral composition or multiple mineral
compositions, e.g., desensitizing water-swellable clays and shales in a single
treatment fluid.
When more than one desensitizing agent is used, the
desensitizing agents can be at the same or different concentrations relative
to
one another within the various fluids for use in the methods provided herein.
The preparation of a desensitizing solution is expected to be according to a
preferred preparation embodiment for the desensitizing solution, which is
known
by one skilled in the arts. The desensitizing agents may be in various forms:
foams, latexes, microemulsions, emulsions, simple solutions, surfactants,
nanoparticles, microparticles, degradable particulates, dry form that later
breaks
up, gelled form, and combinations thereof.
[0043] Examples of suitable desensitizing agents and mechanisms of
desensitization may be found in the following documents, all of which are
incorporated herein by referenced: U.S. Patent Nos. 7,740,071; 5,197,544; and
4,366,073, U.S. Patent Publication No. 2004/0235667, and U.S. Patent
Application Serial Nos. 13/113,533 (filed May 23, 2011 and titled "Silica
Control
Agents for Use in Subterranean Treatment Fluids"); 12/751,770 (filed May 31,
2010 and titled "Methods for Strengthening Fractures in Subterranean
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Formations"); 12/826,426 (filed Jun. 29, 2010 and titled "Methods Relating to
Improved Stimulation Treatments and Strengthening Fractures in Subterranean
Formations"; and 12/851,953 (filed Aug. 6, 2010 and titled "Methods for
Strengthening Fractures in Subterranean Formations").
[0044] Desensitizing agents may interact with the surfaces, interlayers,
and cores of minerals and mineral platelets to mitigate or reverse mineral
hydration, swelling, and sloughing.
Charges on the minerals and mineral
platelets may permit interaction with dissolved/suspended molecules and ions
in
fluids, both native and non-native to the formation. The net negative charge
on
a platelet may be typically balanced mainly by cationic molecules and ions,
e.g.,
sodium ions and silicates. The cations, or charge-balancing ions, associated
with
the platelet faces are termed "exchangeable" as they can be readily
substituted
with other cations when presented to the clay platelets. Each macroscopic
mineral particle may be comprised of many thousands of sandwiched mineral
platelets, each having exchangeable cations and a layer of water therebetween.
When the mineral and water are mixed, water may penetrate between the
platelets, forcing them further apart. The cations present at the platelet
faces
may begin to diffuse away from platelet faces. Further, the amount of water
contained within the platelets may be dependant upon the pressure under which
the mineral is located, typically the depth of the mineral deposit in the
subterranean formation. Mechanisms of mineral hydration may include surface
hydration through bonding of water molecules to oxygen atoms on the surface of
mineral platelets; ionic hydration through hydration of interlayer cations
with
surrounding shells of water molecules; and osmotic hydration, which occurs in
some minerals after they are completely surface hydrated and ionically
hydrated, usually at 100% humidity. Suitable desensitizing agents may include,
but not be limited to, salts, resins, soluble organic stabilizing compounds,
silica
control agents, embrittlement modification agents, and any combination
thereof.
[0045] Nearly all inorganic acids, organic acids, salts thereof, and
combinations thereof known in the art that are suitable for use in
subterranean
operations may be used in the methods of the present invention including, but
not limited to, inorganic acids, salts of inorganic acids, organic acids,
salts of
organic acids, or any combination thereof. A "salt" of an acid, as that term
is
used herein, refers to any compound that shares the same base formula as the
referenced acid, but one of the hydrogen cations thereon is replaced by a
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different cation (e.g., an antimony, bismuth, potassium, sodium, calcium,
magnesium, cesium, zinc cation). Suitable inorganic salts may include cations
of
Group I and II elements. The term "inorganic acid" refers to any acidic
compound that does not comprise a carbon atom. Examples of suitable salts of
inorganic acids include, but are not limited to, sodium chloride, calcium
chloride,
potassium chloride, sodium bromide, calcium bromide, potassium bromide,
sodium sulfate, calcium sulfate, sodium phosphate, calcium phosphate, sodium
nitrate, calcium nitrate, cesium chloride, cesium sulfate, cesium phosphate,
cesium nitrate, cesium bromide, potassium sulfate, potassium phosphate,
potassium nitrate, zinc chloride, magnesium chloride, magnesium bromide, zinc
bromide, and the like. Suitable salts may be Group I and II salts. The term
"organic acid" refers to any acidic compound that comprises a carbon atom.
Examples of suitable salts of organic acids include, but are not limited to,
sodium
acetate, sodium formate, calcium acetate, calcium formate, cesium acetate,
cesium formate, potassium acetate, potassium formate, magnesium acetate,
magnesium formate, zinc acetate, zinc formate, antimony acetate, antimony
formate, bismuth acetate, and bismuth formate.
[0046] Suitable inorganic acids may include, but not be limited to,
hydrochloric acid, nitric acid, phosphoric acid, sulfuric acid, boric acid,
and the
like, or any combination thereof. Suitable organic acids may include, but not
be
limited to, acetic acid, formic acid, citric acid, oxalic acid, and the like,
or any
combination thereof.
[0047] When included, the various fluids for use in the methods
provided herein may comprise any combination of inorganic acids, salts of
inorganic acids, organic acids, and/or salts of organic acids. The one or more
inorganic acids and/or organic acids (or salts thereof) may be present in the
various fluids for use in the methods provided herein in an amount sufficient
to
provide the desired effect. The amount of the inorganic acid(s) and/or organic
acid(s) (or salts thereof) included in the various fluids for use in the
methods
provided herein may depend upon the particular acid and/or salt thereof used,
as well as other components of the various fluids, and/or other factors that
will
be recognized by one of ordinary skill in the art with the benefit of this
disclosure.
[0048] Inorganic bases, organic bases, strong bases, and combinations
thereof known in the art suitable for use in subterranean operations may be
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used in the methods of the present invention. Suitable inorganic bases may
include, but not be limited to, sodium hydroxide, ammonium hydroxide, barium
hydroxide, calcium hydroxide, magnesium hydroxide, potassium hydroxide,
sodium carbonate, ammonium carbonate, barium carbonate, calcium carbonate,
magnesium carbonate, potassium carbonate, magnesium chloride triethylamine,
sodium amide, and the like, or any combinations thereof. Suitable organic
bases
may include, but not be limited to, pyridine, methyl amine, imidazole,
benzimidazole, histidine, phophazene, dimethylaniline, trimethylamine,
piperidine, and the like, or any combination thereof. Suitable strong bases
may
include, but not be limited to, sodium hydroxide, potassium hydroxide, calcium
hydroxide, barium hydroxide, and the like, or any combination thereof.
[0049] When included, the various fluids for use in the methods
provided herein may comprise any combination of inorganic bases, organic
bases, and strong bases. The one or more inorganic bases, organic bases, and
strong bases may be present in the various fluids for use in the methods
provided herein in an amount sufficient to provide the desired effect. The
amount of the inorganic bases, organic bases, and strong bases included in the
various fluids for use in the methods provided herein may depend upon the
particular base used, as well as other components of the various fluids,
and/or
other factors that will be recognized by one of ordinary skill in the art with
the
benefit of this disclosure.
[0050] To the extent they are useful as desensitizing agents, any
polymer or resin known in the art that is suitable for use in subterranean
operations may be used in the methods of the present invention, including
salts
thereof. Of these, cationic polymer may be preferred, e.g., amines and imines.
The polymers and resins can be synthetic or natural and non-hardenable or
hardenable. Polymers and resins suitable for use in the present invention
include all polymers, resins, and combinations thereof known in the art that
desensitize clay. Examples of polymers and resins suitable for use in the
present invention include, but are not limited to: acrylic acid polymers;
partially
hydrolyzed polyacrylamide (PHA); 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
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(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; acrylic acid/acrylamido-methyl-propane
sulfonate co-polymers; bisphenol A diglycidyl ether resins; butoxymethyl butyl
glycidyl ether resins; bisphenol A-epichlorohydrin resins; bisphenol F resins;
polyepoxide resins; novolak resins; polyester resins; phenol-aldehyde resins;
urea-aldehyde resins; furan resins; urethane resins; glycidyl ether resins;
other
epoxide resins; polyacrylamide; partially hydrolyzed polyacrylamide;
copolymers
of acrylamide and acrylate; carboxylate-containing terpolymers; tetrapolymers
of acrylate; galactose; mannose; glucoside; glucose; xylose; arabinose;
fructose; glucuronic acid; pyranosyl sulfate; guar gum; locust bean gum; tara;
konjak; tamarind; starch; cellulose; karaya; xanthan; tragacanth; carrageenan;
polycarboxylates such as polyacrylates and polymethacrylates; polyacrylamides;
methylvinyl ether polymers; polyvinyl alcohols; polyvinylpyrrolidone;
polyalkylene imines (such as polyethylene imine and polypropylene imine);
polyamines (such as putrescine, cadaverine, spermidine, spermine,
diethylenetriamine, tetra methylened ia mine,
trimethylenetetramine,
tetraethylenepentamine, polyethylene amine, cyclen); organo-polyamines;
quaternized polyamines; CLA-STA XP (a water-soluble cationic oligomer,
available from Halliburton Energy Services, Inc.); CLA-STA FS (a mineral
stabilizing polymer, available from Halliburton Energy Services, Inc.); and
CLA-
WEBTM (a stabilizing additive, available from Halliburton Energy Services,
Inc);
derivatives thereof; salts thereof; and combinations thereof.
[0051] The polymers or resins (or salts thereof) and combinations
thereof may be present in the various fluids for use in the methods provided
herein in an amount sufficient to provide the desired effect. The amount of
the
polymer or resin (or salts thereof) included in the various fluids for use in
the
methods provided herein may depend upon the particular polymer, resin, and/or
salt thereof used, as well as other components of the various fluids, and/or
other
factors that will be recognized by one of ordinary skill in the art with the
benefit
of this disclosure.
[0052] Suitable surfactants and combinations thereof for use in the
present invention may include anionic surfactants, cationic surfactants,
amphoteric surfactants, and/or nonionic surfactants. Examples of surfactants
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that may be suitable for use in the present invention include, but are not
limited
to C12 to C22 alkyl phosphonate surfactants, ethoxylated nonyl phenol
phosphate
esters, ethoxylated fatty acids, sodium dodecyl sulfate, poly(vinyl alcohol),
sodium dodecylbenzenesulfonic acid, cetyltrimethylammonium bromide,
cetylpyridinium bromide, hexadecylmaltoside, trimethylcocoammonium chloride,
trimethyltallowammonium chloride, dimethyldicocoammonium chloride, bis(2-
hydroxyethyl)tallowamine, bis(2-hydroxyethyl)erucylamine, erucyl methyl bis(2-
hydroxyethyl) ammonium chloride,
bis(2-hyd roxyethyl)coco-a mine,
cetylpyridinium chloride, N,N,N,trimethy1-1-octadecamonium chloride, fatty
amine salts, polyamines, ammonium salts, quaternary ammonium compounds
(e.g., alkyl quaternary ammonium salts), alkyl pyridinium salts, and any
derivatives thereof. An example of commercially-available surfactants that may
be suitable in certain embodiments of the present invention is 19NTM
surfactant
(a cationic nonemulsifier, available from Halliburton Energy Services, Inc.),
TWEEN surfactants (a polysorbate surfactant, available from Sigma-Aldrich),
TRITON surfactants (a nonionic surfactant, available from Sigma-Aldrich), and
BRIJ surfactants (a nonionic surfactant, available from Sigma-Aldrich).
Certain
cationic surfactants may be incompatible or undesirable to use with certain
anionic polymers, minerals present on the mineral surface, and/or other
elements or conditions in a treatment fluid (e.g., pH) and/or subterranean
formation present in a particular application of the present invention. One of
skill in the art, with the benefit of this disclosure, should be able to
select a
cationic surfactant that is compatible with these elements.
[0053] The surfactants (or salts thereof) and combinations thereof may
be present in the various fluids for use in the methods provided herein in an
amount sufficient to provide the desired effect. The amount of the surfactant
(or
salts thereof) included in the various fluids for use in the methods provided
herein may depend upon the particular surfactant and/or salt thereof used, as
well as other components of the various fluids, and/or other factors that will
be
recognized by one of ordinary skill in the art with the benefit of this
disclosure.
[0054] In some embodiments, particulates may comprise emulsion
facilitating particles, i.e., any particle with a size smaller than a
discontinuous
phase droplet in the emulsion. In some exemplary embodiments, the emulsion
facilitating particles have a size less than about 75 microns. Generally,
smaller
emulsion facilitating particles are preferred. Suitable examples of
emulsion
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facilitating particles include particles that have or exhibit a suitable fluid
contact
angle, such as any organically modified material, metal sulfate, or polymer.
Suitable organically modified materials may include modified silicas, modified
fumed silicas, or various clay types. Fumed silicas may have slightly
different
degrees of organic modification when small amounts of dimethyldichlorosilane
are added in the process of fuming the silica. Examples of suitable modified
silicas or modified fumed silicas include, but not be limited to, HDK silicas
(silica
silylates, Wacker-Chemie GmbH) such as HDK H20, HDK H30, and HDK
H2000. The HDK silicas are loose white powders that are primarily amorphous
lattice structures of Si02. Suitable organically modified materials also
may
include organically modified aluminum, titanium, zirconium, or various clay
types. Various clay types may include non-kaolinitic clays such as bentonite,
kaolin clays, and any other clay types capable of cation exchange.
[0055] The emulsion facilitating particles and combinations thereof may
be present in the various fluids for use in the methods provided herein in an
amount sufficient to provide the desired effect. The amount of the emulsion
facilitating particles included in the various fluids for use in the methods
provided herein may depend upon the particular emulsion facilitating particles
used, as well as other components of the various fluids, and/or other factors
that
will be recognized by one of ordinary skill in the art with the benefit of
this
disclosure.
[0056] Nearly all organic stabilizing compounds and combinations
thereof known in the art that are suitable for use in subterranean operations
may be used in the methods of the present invention.
[0057] Examples of suitable organic acids include, but are not limited
to, formic acid, acetic acid, citric acid, glycolic acid, lactic acid, 3-
hydroxypropionic acid, a C1 to C12 carboxylic acid, an aminopolycarboxylic
acid
such as hydroxyethylethylenediamine triacetic acid, and combinations thereof.
Alternatively or in combination with the one or more organic acids, the
various
fluids for use in the methods provided herein may comprise a salt of an
organic
acid. A "salt" of an acid, as that term is used herein, refers to any compound
that shares the same base formula as the referenced acid, but one of the
hydrogen cations thereon is replaced by a different cation (e.g., an antimony,
bismuth, potassium, sodium, calcium, magnesium, cesium, or zinc cation).
Examples of suitable salts of organic acids include, but are not limited to,
sodium
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acetate, sodium formate, calcium acetate, calcium formate, cesium acetate,
cesium formate, potassium acetate, potassium formate, magnesium acetate,
magnesium formate, zinc acetate, zinc formate, antimony acetate, antimony
formate, bismuth acetate, and bismuth formate. The one or more organic acids
(or salts thereof) may be present in the various fluids for use in the methods
provided herein in an amount sufficient to provide the desired effect. The
amount of the organic acid(s) (or salts thereof) included in the various
fluids for
use in the methods provided herein may depend upon the particular acid and/or
salt used, as well as other components of the treatment fluid, and/or other
factors that will be recognized by one of ordinary skill in the art with the
benefit
of this disclosure.
[0058] A variety of monomers (or salts thereof) are suitable for use as
an organic stabilizing compound 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,
dimethylacrylamide, vinyl sulfonic acid, N,N-dimethylaminoethylmethacrylate, 2-
triethylammoniumethylmethacrylate chloride,
N,N-dimethyl-
aminopropylmethacryl-amide, methacrylamidepropyltriethylammonium chloride,
N-vinyl pyrrolidone, quaternary amines, imidazolium salts, phosphonium salts,
vinyl-phosphonic acid, methacryloyloxyethyl trimethylammonium sulfate, 1-
carboxy-N,N,N-trimethyl methanaminium chloride, 2-hydroxy-N,N,N-trimethyl
ethanaminium acetate, 2-hydroxy-N,N,N-trimethyl 1-propanaminium acetate,
tetra alkyl ammonium, bis-(hydrogenated tallow)-dimethyl-ammonium chloride,
bis-(hydrogenated tallow)-benzyl-methyl-ammonium chloride, 4,5-dihydro-1-
methyl-2-nortallow-alkyl-1-(2-tallow-amidoethyl)-imidazolium methyl sulfate, 1-
ethyl-4,5-dihydro-3-(2-hydroxyethyl)-2-(8-heptadeceny1)-imidazolium
ethyl
sulfate, putrescine, cadaverine, spermidine, spermine, diethylenetriamine,
tetramethylenediamine, trimethylenetetra mine, tetraethylenepentamine, and
any combination thereof.
[0059] The organic stabilizing compounds and combinations thereof
may be present in the various fluids for use in the methods provided herein in
an
amount sufficient to provide the desired effect. The amount of the organic
stabilizing compounds included in the various fluids for use in the methods
provided herein may depend upon the particular organic stabilizing compounds
used, as well as other components of the various fluids, and/or other factors
that
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will be recognized by one of ordinary skill in the art with the benefit of
this
disclosure.
[0060] Nearly all chelating agents and combinations thereof known in
the art that are suitable for use in subterranean operations may be used in
the
methods of the present invention. Suitable chelating agents may comprise
amines, esters, carboxylic acids, alcohols, ethers, aldehydes, ketones,
mercaptans, thiols, and/or combinations thereof. Examples of suitable
chelating
agents include ethylenediaminetetraacetic acid ("EDTA"), nitrilotriacetic acid
("NTA"), hydroxyethylethylenediaminetriacetic acid ("HEDTA"), dicarboxymethyl
glutamic acid tetrasodium salt ("GLDA"), diethylenetriaminepentaacetic acid
("DTPA"), propylenediaminetetraacetic acid ("PDTA"), ethylenediaminedi(o-
hydroxyphenylacetic) acid ("EDDHA"), glucoheptonic acid, gluconic acid, amino
tri(methylene phosphonic acid), penta sodium salt of aminotri(methylene
phosphonic acid), tetra sodium salt of aminotri(methylene phosphonic acid), 1-
hydroxyethylidene-1,1,-diphosphonic acid,
hexamethylenediamine
tetra(methylene phosphonic acid), diethylenetriamine penta(methylene
phosphonic acid), bis(hexamethylene triamine penta(methylene phosphonic
acid)), 2-phosphonobutane-1,2,4-
tricarboxylic acid, monoethanloamine
diphosphonate, etidronic acid, potassium salts of (1-hydroxyethylidene)
diphosphonic acid, tetrasodium (1-hydroxyethylidene) biphosphonate, sodium
salts of (1-hydroxyethylidene) diphosphonic acid, disodium salts of
hydroxyethylidene 1,1-diphosphonic acid, sodium salts of diethylene triamine
penta(methylene phosphonic acid), sodium salts of bis hexamethylene triamine
penta(methylene phosphonic acid), sodium salts of 2-phosphonobutane-1,2,4-
tricarboxylic acid, tetrasodium etidronate, maleic acid, polymers of modified
polyacrylic acid, sulphonated polyacrylic acid, carboxymethyl inulin, any salt
thereof, any derivative thereof, and any combination thereof.
[0061] The chelating agents and combinations thereof may be present
in the various fluids for use in the methods provided herein in an amount
sufficient to provide the desired effect. The amount of the chelating agents
included in the various fluids for use in the methods provided herein may
depend
upon the particular chelating agents used, as well as other components of the
various fluids, and/or other factors that will be recognized by one of
ordinary
skill in the art with the benefit of this disclosure.
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[0062] Nearly all silica control agents and combinations thereof known
in the art that are suitable for use in subterranean operations may be used in
the methods of the present invention. Without limiting the invention to a
particular theory or mechanism of action, it is nevertheless currently
believed
that silica may act as a binder of clay, sand, diageneous minerals, clasts,
and/or
other fine particulates in subterranean formations.
[0063] In some embodiments, the silica control agent may comprise a
compound chosen from the group consisting of: silica, silicates (e.g.,
orthosilicates, pyrosilicates, cyclic-silicates, single chain silicates,
double chain
silicates, sheet silicates, colloidal silicates), silanes, organo-silanes, and
any
combination thereof. In some embodiments, the silica control agent may be
provided by a natural mineral comprising silica or a silicate. Suitable
examples
of naturally occurring minerals comprising silica or a silicate include, but
are not
limited to, phenacite, willemite, zircon, olivine, garnet, thortveitite,
benitoite,
beryl, pyroxenes, enstatite, spodumene, pollucite, tremolite, crocidolite,
talc,
petalite, cristobalite, and any combination thereof. One skilled in the art
will
recognize that in order to be able to use naturally occurring silicates they
would
need to be finely ground in order to be sufficiently soluble/suspendable. As
used
herein, the term "finely ground" refers to mesh sizes smaller than or equal to
270 U.S. Mesh (53 microns), 325 U.S. Mesh (44 microns), 400 U.S. Mesh (37
microns), 550 U.S. Mesh (25 microns), 800 U.S. Mesh (15 microns), or 1250
U.S. Mesh (10 microns). Other suitable silicates include, but are not limited
to,
potassium silicate, calcium silicate, sodium aluminum silicate, and sodium
silicate.
Suitable commercially available silica control agents may include
INJECTROL (a sealant, available from Halliburton Energy Services, Inc).
However, dilution to near the saturation point may be required for such
products
to be suitable silica control agents in order to avoid precipitation and
plugging of
the formation. In some preferred embodiments non-polymeric metal silicates,
such as sodium silicate or potassium silicate, may be preferred. In some
preferred embodiments, the silicate may be sodium silicate having a weight
ratio
of 5i02 to Na20 ranging from about 3.25:1 to 1.5:1.
In some preferred
embodiments, the silicate may be potassium silicate having a ratio of 5i02 to
K20 ranging from about 2.5:1 to 1.5:1.
[0064] Silanes may include chemicals that contain silicone at the center
of the silane molecule that is chemically attached to a first functional group
such
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as vinyl, amino, chloro, epoxy, mercapto, and a second functional group such
as
methoxy or ethoxy.
Examples of suitable silanes and organo-silanes may
include, but not be limited to, N-2-(aminoethyl)-3-
aminopropyltrimethoxysilane,
3-glycidoxypropyltrimethoxysilane,
n-beta-(aminoethyl)-gamma-aminopropyl
trimethoxysilane, methyltrimethoxysila ne,
vinyltrimethoxysila ne,
methyltriethoxysilane, tetraethoxysilane, methyltriacetoxysilane, methyl tris-
(N-
methylbenzamidosilane), methyl tris-(methyl ethyl ketoximino) silane, methyl
tris-(methylisobutylketoximino) silane, methyl vinyl bis-(methyl
ethylketoximino)
silane, tetrakis-(methyl ethylketoximino) silane, methyl tris-(isprenoxy)
silane,
methyl tris-(cyclohexylamino) silane, gamma-aminopropyltriethoxysilane, N-
beta-(aminoethyl)-gamma-aminopropyltrimethoxysilanes, aminoethyl-N-beta-
(aminoethyl)-gamma-aminopropyl-trimethoxysilanes,
gamma-ureidopropyl-
triethoxysilanes, beta-(3-4 epoxy-cyclohexyl)-ethyl-trimethoxysilane, gamma-
glycidoxypropyltrimethoxysila nes, vinyltrichlorosila
ne, vinyltris (beta-
methoxyethoxy) silane, vinyltriethoxysilane, vinyltrimethoxysilane, 3-
metacryloxypropyltrimethoxysila ne, beta-(3,4
epoxycyclohexyl)-
ethyltrimethoxysilane, r-
glycidoxypropyltrimethoxysilane, r-
glycidoxypropylmethylidiethoxysilane, N-B
(aminoethyl)-raminopropyl-
trimethoxysilane, N-beta (aminoethyl)-raminopropylmethyldimethoxysilane, 3-
a minopropyl-triethoxysilane, N-phenyl-r-
aminopropyltrimethoxysilane, r-
mercaptopropyltrimethoxysilane,
vinyltrichlorosilane, vinyltris ([3-
methoxyethoxy) silane,
vinyltrimethoxysila ne, r-
metacryloxypropyltrimethoxysilane, beta-(3,4
epoxycyclohexyl)-
ethyltrimethoxysilane, r-
glycidoxypropyltrimethoxysilane, r-
g lycidoxypropylmethyl id iethoxysilane, N-beta (am inoethyl)-r-
aminopropyltrimethoxysilane, N-beta
(aminoethyl)-r-
a minopropyl methyld imethoxysila ne, r-
aminopropyltriethoxysilane, N-phenyl-
ram inopropyltrimethoxysilane,
r-mercaptopropyltrimethoxysilane, and any
derivative thereof, and any combination thereof.
[0065] The silica control agents and combinations thereof may be
present in the various fluids for use in the methods provided herein in an
amount sufficient to provide the desired effect. The amount of the silica
control
agents included in the various fluids for use in the methods provided herein
may
depend upon the particular silica control agent used, as well as other
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components of the various fluids, and/or other factors that will be recognized
by
one of ordinary skill in the art with the benefit of this disclosure.
[0066] Nearly all embrittlement modification agents and combinations
thereof known in the art that are suitable for use in subterranean operations
may be used in the methods of the present invention. The term "embrittlement"
and its derivatives as used herein refers to a process by which the properties
of
a material are changed through a chemical interaction such that a material
that
originally behaves in a ductile or plastic manner is transformed to a material
that
behaves in a more brittle manner. This may be determined by examining the
Young's modulus and the Poisson's ratio of the natural rock before treatment.
If
the rock has become embrittled, the Young's modulus should be higher and the
Poisson's ratio should be lower as compared to the natural rock before
treatment.
[0067] Young's modulus is the ratio of stress, which has units of
pressure, to strain, which is dimensionless; therefore Young's modulus itself
has
units of pressure. The SI unit of modulus of elasticity (E, or less commonly
Y) is
the pascal (Pa or N/m2); the practical units are megapascals (MPa or N/mm2) or
gigapascals (GPa or kN/mm2). In United States customary units, it is expressed
as pounds (force) per square inch (psi). Young's modulus, E, can be calculated
by dividing the tensile stress by the tensile strain:
tensile ArmsTV 4
o FLo
E= =
tensile str AL/ Lo =
Equation I
[0068] Where:
[0069] E is the Young's modulus (modulus of elasticity);
[0070] F is the force applied to the object;
[0071] Ao is the original cross-sectional area through which the force is
applied;
[0072] AL is the amount by which the length of the object changes; and
[0073] Lo is the original length of the object.
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[0074] Poisson's ratio (v) is the ratio, when a sample object is
stretched, of the contraction or transverse strain (perpendicular to the
applied
load), to the extension or axial strain (in the direction of the applied
load).
= ___________________________________________
Equation 2
[0075] Where:
[0076] v is the resulting Poisson's ratio,
[0077] Etrans is transverse strain (negative for axial tension, positive for
axial compression); and
[0078] Eaxial is axial strain (positive for axial tension, negative for axial
compression).
[0079] Suitable embrittlement modification agents for use in the
present invention may comprise high alkaline materials. Suitable examples may
include, but not be limited to, lithium hydroxide, sodium hydroxide, potassium
hydroxide, rubidium hydroxide, calcium hydroxide, strontium hydroxide, barium
hydroxide, cesium hydroxide, sodium carbonate, sodium silicate, lime, amines,
ammonia, borates, Lewis bases, other strong bases, and any derivative or
combination thereof. The concentration of the embrittlement modification agent
in a treatment fluid may depend on the desired pH (e.g., about 10 or above at
downhole conditions) of the fluid given the factors involved in the treatment.
[0080] The embrittlement modification agents and combinations thereof
may be present in the various fluids for use in the methods provided herein in
an
amount sufficient to provide the desired effect.
The amount of the
embrittlement modification agents included in the various fluids for use in
the
methods provided herein may depend upon the particular embrittlement
modification agent used, as well as other components of the treatment fluid,
and/or other factors that will be recognized by one of ordinary skill in the
art
with the benefit of this disclosure.
[0081] Optionally, embrittlement modification agents for use in the
present invention may comprise cationic additives, such as cationic polymers
and cationic organic additives, to enhance the plasticity modification.
Divalent
cationic additives may be more stable. If used, such cationic additives may be
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used in an amount of about 0.01% to about 1% by weight of the embrittlement
modification agents.
Hydroxy aluminum and zirconium oxychloride are
examples. Other examples may include, but not be limited to, CLA-STA XP,
CLA-STA FS, CLAYFIX (an acid salt, available from Halliburton Energy
Services, Inc.), CLAYFIX -II (a temporary clay stabilizing additive, available
from Halliburton Energy Services, Inc.), and CLAYFIX -II PLUS (a temporary
clay stabilizing additive, available from Halliburton Energy Services, Inc.),
HPT-
1Tm (a cationic polymer, available from Halliburton Energy Services, Inc.),
and
combinations thereof. Suitable additives are described in the following
patents,
each of which are hereby incorporated by reference, U.S. Patent Nos.
5,097,094,
4,974,678, 4,424,076, and 4,366,071.
[0082] Optionally, embrittlement modification agents for use in the
present invention may comprise salt(s) such as salts of lithium, sodium,
potassium, rubidium, calcium, strontium, barium, cesium, magnesium, and
manganese. The ion exchange resulting from the presence of the salt is useful
in aiding in the shrinkage of the rock.
[0083] Optionally, including surfactants in the embrittlement
modification agents may facilitate ultra low surface tensions and allow these
fluids to penetrate into a subterranean formation more easily, e.g., via
microfractures and between mineral platelets.
[0084] The term "microparticles" as used herein refers to particles less
than 500 microns in one dimension, but larger than nanoparticles. The term
"nanoparticles" as used herein refers to particles with at least one dimension
less
than about 100 nm.
[0085] Nearly all microparticles and combinations thereof known in the
art that are suitable for use in subterranean operations and can adsorb and/or
bind to minerals may be used in the methods of the present invention.
Examples of suitable microparticles may include, but not be limited to, metal
oxide microparticles like silica, titania, alumina, magnesium oxide, calcium
oxide, and the like; minerals like slag, zeolite, vitrified shale, silica
flour, silica
sand; polymeric microparticles including those that comprise the polymers
and/or resins disclosed herein; or any combination thereof.
[0086] Nearly all nanoparticles and combinations thereof known in the
art that are suitable for use in subterranean operations and can adsorb and/or
bind to minerals may be used in the methods of the present invention.
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Examples of suitable nanoparticles may include, but not be limited to, carbon
nanoparticles like fullerenes (spherical or otherwise), endofullerenes,
nanotubes
(single or multi-walled), filled nanotubes, carbon nanohorns, carbon nano-
bamboo, graphene (single to few layer thick), and carbon quantum dots; metal
oxide nanoparticles like silica, titania, alumina, iron oxide, manganese
oxide,
zinc oxide, molybdenum oxide, magnesium oxide, and calcium oxide; metal
nanoparticles like gold, palladium, silver, and palladium; nitride
nanoparticles;
carbide nanoparticles; magnetic nanoparticles like Fe304 and gamma-Fe203;
quantum dots like CdSe and ZnS; any derivative thereof; and any combination
thereof. It should be noted that nanoparticles include nanorods, nanospheres,
nanorices, nanowires, nanostars (like nanotripods and nanotetrapods), hollow
nanostructures, hybrid nanostructures that are two or more nanoparticles
connected as one, and non-nano particles with nano-coatings or nano-thick
walls. It should be further noted that nanoparticles include the
functionalized
derivatives of nanoparticles including, but not limited to, nanoparticles that
have
been functionalized covalently and/or non-covalently, e.g., pi-stacking,
physisorption, ionic association, van der Waals association, and the like.
Suitable functional groups may include, but not be limited to, moieties
comprising amines (1 , 2 , or 3 ), amides, carboxylic acids, aldehydes,
ketones,
ethers, esters, peroxides, silyls, organosilanes, hydrocarbons, aromatic
hydrocarbons, and any combination thereof; polymers; chelating agents like
ethylenediamine tetraacetate, diethylenetriaminepentaacetic acid,
triglycollamic
acid, and a structure comprising a pyrrole ring; and any combination thereof.
[0087] As described above, the various fluids described herein may
comprise proppants. Proppants suitable for use in the present invention may
comprise any material suitable for use in subterranean operations. Suitable
materials for these proppants include, but are not limited to, sand, bauxite,
ceramic materials, glass materials, polymer materials, polytetrafluoroethylene
materials, nut shell pieces, cured resinous particulates comprising nut shell
pieces, seed shell pieces, cured resinous particulates comprising seed shell
pieces, fruit pit pieces, cured resinous particulates comprising fruit pit
pieces,
wood, composite particulates, and combinations thereof. Suitable composite
particulates may comprise a binder and a filler material wherein suitable
filler
materials include silica, alumina, fumed carbon, carbon black, graphite, mica,
titanium dioxide, meta-silicate, calcium silicate, kaolin, talc, zirconia,
boron, fly
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ash, hollow glass microspheres, solid glass, and combinations thereof. The
mean particulate size generally may range from about 2 mesh to about 400
mesh on the U.S. Sieve Series; however, in certain circumstances, other mean
particulate sizes may be desired and will be entirely suitable for practice of
the
present invention. In particular embodiments, preferred mean particulates size
distribution ranges are one or more of 6/12, 8/16, 12/20, 16/30, 20/40, 30/50,
40/60, 40/70, or 50/70 mesh.
It should be understood that the term
"particulate," as used in this disclosure, includes all known shapes of
materials,
including substantially spherical materials, fibrous materials, polygonal
materials
(such as cubic materials), and combinations thereof.
Moreover, fibrous
materials, that may or may not be used to bear the pressure of a closed
fracture, may be included in certain embodiments of the present invention. In
certain embodiments, the proppant may be present in the various fluids
described herein in an amount in the range of from about 0.5 pounds per gallon
("ppg") to about 30 ppg by volume of the treatment fluid, and encompass any
subset therebetween.
[0088] The base fluid of a leading-edge fluid, transition fluid, and/or
treatment fluid may comprise oil-based fluids, aqueous-based fluids, aqueous-
miscible fluids, water-in-oil emulsions, or oil-in-water emulsions. Suitable
oil-
based fluids may include alkanes, olefins, aromatic organic compounds, cyclic
alkanes, paraffins, diesel fluids, mineral oils, desulfurized hydrogenated
kerosenes, and any combination thereof.
[0089] Suitable aqueous-based fluids may include fresh water,
saltwater (e.g., water containing one or more salts dissolved therein), brine
(e.g., saturated salt water), seawater, and any combination thereof.
Generally,
the water may be from any source, provided that it does not contain
components that might adversely affect the stability and/or performance of the
leading-edge fluid or the fracturing fluid of the present invention. In
certain
embodiments, the density of the aqueous base fluid can be adjusted, among
other purposes, to provide additional particulate transport and suspension in
the
leading-edge fluid or the fracturing fluid used in the methods of the present
invention. In certain embodiments, the pH of the aqueous base fluid may be
adjusted (e.g., by a buffer or other pH adjusting agent), among other
purposes,
to reduce the viscosity of the leading-edge fluid or fracturing fluid. In
these
embodiments, the pH may be adjusted to a specific level, which may depend on,
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among other factors, the types of gelling agents, acids, and other additives
included in the leading-edge fluid or fracturing fluid. One of ordinary skill
in the
art, with the benefit of this disclosure, will recognize when such density
and/or
pH adjustments are appropriate.
[0090] Suitable aqueous-miscible fluids may include, but not be limited
to, alcohols, e.g., methanol, ethanol, n-propanol, isopropanol, n-butanol, sec-
butanol, isobutanol, and t-butanol; glycerins; glycols, e.g., polyglycols,
propylene glycol, and ethylene glycol; polyglycol amines; polyols; any
derivative
thereof; any in combination with salts, e.g., sodium chloride, calcium
chloride,
calcium bromide, zinc bromide, potassium carbonate, sodium formate,
potassium formate, cesium formate, sodium acetate, potassium acetate, calcium
acetate, ammonium acetate, ammonium chloride, ammonium bromide, sodium
nitrate, potassium nitrate, ammonium nitrate, ammonium sulfate, calcium
nitrate, sodium carbonate, and potassium carbonate; any in combination with an
aqueous-based fluid; and any combination thereof.
[0091] Suitable water-in-oil emulsions, also known as invert emulsions,
may have an oil-to-water ratio from a lower limit of greater than about 50:50,
55:45, 60:40, 65:35, 70:30, 75:25, or 80:20 to an upper limit of less than
about 100:0, 95:5, 90:10, 85:15, 80:20, 75:25, 70:30, or 65:35 by volume in
the base treatment fluid, and wherein the amount may range from any lower
limit to any upper limit and encompass any subset therebetween. Examples of
suitable invert emulsions include those disclosed in U.S. Patent Number
5,905,061, U.S. Patent Number 5,977,031, and U.S. Patent Number 6,828,279,
each of which are incorporated herein by reference. It should be noted that
for
water-in-oil and oil-in-water emulsions, any mixture of the above may be used
including the water being an aqueous-miscible fluid.
[0092] In some embodiments, the base fluid may be foamed, i.e., may
comprise a foaming agent and a gas. Suitable foaming agents may be any
known foaming agent that does not cause deleterious chemical and/or physical
changes to the formation faces and may be used in a sufficient amount to
achieve a desired foam, which should be known to one skilled in the art. In
some embodiments, the gas is selected from the group consisting of nitrogen,
carbon dioxide, air, methane, helium, argon, and any combination thereof. In
some embodiments, the quality of the foamed fracturing fluid may range from a
lower limit of about 5%, 10%, 25%, 40%, 50%, 60%, or 70% gas volume to an
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upper limit of about 99%, 90%, 80%, 75%, 60%, or 50% gas volume, and
wherein the quality of the foamed fracturing fluid may range from any lower
limit to any upper limit and encompass any subset therebetween.
[0093] The various fluids described herein can further comprise
additives including, but not limited to, salts, weighting agents, inert
solids, fluid
loss control agents, emulsifiers, dispersion aids, corrosion inhibitors,
emulsion
thinners, emulsion thickeners, viscosifying agents, high-pressure and high-
temperature emulsifier-filtration control agents, surfactants, particulates,
proppants, lost circulation materials, foaming agents, gases, pH control
additives, breakers, biocides, crosslinkers, stabilizers, scale inhibitors,
mutual
solvents, oxidizers, reducers, friction reducers, and any combination thereof.
[0094] In some embodiments, a method of desensitizing a
subterranean formation may generally include the steps of:
introducing a
leading-edge fluid comprising a first base fluid and a first desensitizing
agent
into at least a portion of the subterranean formation, wherein the first
desensitizing agent is present in the first base fluid at a first
concentration; and
then introducing a treatment fluid comprising a second base fluid and a second
desensitizing agent into at least a portion of the subterranean formation,
wherein the second desensitizing agent is present in the second base fluid at
a
second concentration, and wherein the first concentration is higher than the
second concentration.
[0095] In some embodiments, a method of remedially desensitizing a
subterranean formation may generally include the steps of: providing a
wellbore
penetrating a subterranean formation that comprises a plurality of formation
faces, the formation faces having undergone deleterious chemical and/or
physical changes; introducing a leading-edge fluid comprising a first base
fluid
and a first desensitizing agent into at least a portion of the subterranean
formation, wherein the first desensitizing agent is present in the first base
fluid
at a first concentration; and then introducing a treatment fluid comprising a
second base fluid and a second desensitizing agent into at least a portion of
the
subterranean formation, wherein the second desensitizing agent is present in
the
second base fluid at a second concentration, and wherein the first
concentration
is higher than the second concentration.
[0096] In some embodiments, a method of desensitizing a
subterranean formation may generally include the steps of: providing a
wellbore
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penetrating a subterranean formation; introducing a leading-edge fluid
comprising a first base fluid and a first desensitizing agent into a first
portion of
the subterranean formation, wherein the first desensitizing agent is present
in
the first base fluid at a first concentration; then introducing a treatment
fluid
comprising a second base fluid and a second desensitizing agent into the first
portion of the subterranean formation, wherein the second desensitizing agent
is
present in the second base fluid at a second concentration, and wherein the
first
concentration is higher than the second concentration; then diverting fluid
flow
from the first portion of the subterranean formation to a second portion of
the
subterranean formation; then introducing a second leading-edge fluid
comprising
a third base fluid and a third desensitizing agent into the second portion of
the
subterranean formation, wherein the third desensitizing agent is present in
the
third base fluid at a third concentration; and then second introducing a
treatment fluid comprising a fourth base fluid and a fourth desensitizing
agent
into the second portion of the subterranean formation, wherein the fourth
desensitizing agent is present in the fourth base fluid at a second
concentration,
and wherein the third concentration is higher than the fourth concentration.
[0097] It should be noted that while this disclosure is drawn to
desensitizing problematic formations, one skilled in the art with the benefit
of
this disclosure could adapt the methods provided herein for other multi-stage
treatments of subterranean formations.
Further many of the advantages
disclosed herein may translate to the adapted methods including, but not
limited
to, effective penetration of a treatment deeper into the subterranean
formation
while decreasing the overall concentration of treatment fluid components. This
reduction in the amount of treatment fluid components used can result in a
significant cost savings for the operator and may help reduce the
environmental
impact of the treatment.
[0098] To facilitate a better understanding of the present invention, the
following examples of preferred embodiments are given. In no way should the
following examples be read to limit, or to define, the scope of the invention.
EXAMPLES
[0099] Example I. X-Ray analysis of the field shale samples in South
Texas revealed a clay concentration of about 40% to 50% with about 1% of the
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clay content identified as swelling clay. Based on this information, the
following
treatment recommendations were made:
(a) Use 1% v/v of CLA-WEBTM clay-stabilization additive in the first
5% of the fracturing treatment volume as the spearhead fluid. Thus, for a
500,000-gal fracturing treatment volume, an amount of 250 gal of CLA-WEBTM
clay-stabilization additive was used in mixing with 25,000 gal of fresh water
to
prepare the 1% v/v CLA-WEBTM clay-stabilization additive solution.
(b) Use 0.05% v/v of CLA-WEBTM clay-stabilization additive in the
remainder of the fracturing treatment volume, or mix 250 gal of CLA-WEBTM
clay-stabilization additive with the remaining 475,000 gal of fluid.
[0100] Example 2. For a well located in Saudi, X-ray
diffraction
analysis (Table 1) indicates only trace amounts of smectite clay in the
obtained
shale samples with a significant amount of mixed layers which may contain
swelling clays.
Table 1
Interval Depth 13,419.3' 13,582.5'
Quartz 37 % 46 %
K-feldspar 3 wo 3 wo
Na-feldspar 3 wo 4 %
Dolomite 27 % 2 %
Pyrite 6 % 6 %
Kaolinite 3 wo 3 wo
Chlorite trace trace
Muscovite trace 1 %
Illite 12 % 22 %
Mixed layer 7 % 7 wo
Smectite trace trace
[0101] Shale samples of the two intervals were crushed and sieved to
obtained mesh size less than 200 U.S. mesh. Equal amounts of each sample
was mixed to form a homogeneous blend which was used to form a sand pack
column with the composition of 85% (w/w) of 70/170-mesh quartz sand, 10%
(w/w) of silica flour, and 5% (w/w) of crushed, mixed shale samples. Flow
tests
were performed through the packed columns to evaluate the desensitize
performance of 1% (v/v) and 3% (v/v) CLA-WEBTM clay-stabilization additive
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solutions. The series of treatment fluids and volumes are listed in Table 2.
All
fluids were injected through the column at 10 mL/min flow rate.
Table 2
Injected Fluids Injected Volume (mL)
3% KCI brine 100
3% CLA-WEBTM clay- 200
stabilization additive
3% KCI brine 50
Fresh water 60
3% KCI brine 100
[0102] A decrease in permeability of brine after exposure to fresh water
comparing with brine pressure after treatment of 1% CLA-WEBTM clay-
stabilization additive solution indicates that this 1% CLA-WEBTM clay-
stabilization
additive concentration was not sufficient for clay protection, which will
result in
permeability reduction. The treatment with 3% CLA-WEBTM clay-stabilization
additive solution indicates this CLA-WEBTM clay-stabilization additive
concentration was more appropriate to minimize any potential of permeability
damage.
[0103] Based on the results of these tests, it was recommended that a
concentration of 5% (v/v) of CLA-WEBTM clay-stabilization additive be used in
the pad fluid of the fracturing treatment, and a concentration of 0.2% (v/v)
of
CLA-WEBTM clay-stabilization additive be used in the remainder of the
fracturing
fluid carrying proppant.
[0104] Therefore, the present invention is well adapted to attain the
ends and advantages mentioned as well as those that are inherent therein. The
particular embodiments disclosed above are illustrative only, as the present
invention may be modified and practiced in different but equivalent manners
apparent to those skilled in the art having the benefit of the teachings
herein.
Furthermore, no limitations are intended to the details of construction or
design
herein shown, other than as described in the claims below. It is therefore
evident that the particular illustrative embodiments disclosed above may be
altered, combined, or modified and all such variations are considered within
the
scope and spirit of the present invention. While compositions and methods are
described in terms of "comprising," "containing," or "including" various
components or steps, the compositions and methods can also "consist
essentially
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of" or "consist of" the various components and steps. All numbers and ranges
disclosed above may vary by some amount. Whenever a numerical range with a
lower limit and an upper limit is disclosed, any number and any included range
falling within the range is specifically disclosed. In particular, every range
of
values (of the form, "from about a to about b," or, equivalently, "from
approximately a to b," or, equivalently, "from approximately a-b") disclosed
herein is to be understood to set forth every number and range encompassed
within the broader range of values. Also, the terms in the claims have their
plain, ordinary meaning unless otherwise explicitly and clearly defined by the
patentee. Moreover, the indefinite articles "a" or "an," as used in the
claims, are
defined herein to mean one or more than one of the element that it introduces.
If there is any conflict in the usages of a word or term in this specification
and
one or more patent or other documents that may be incorporated herein by
reference, the definitions that are consistent with this specification should
be
adopted.
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