U.S. patent application number 13/239491 was filed with the patent office on 2012-11-15 for multi-stage methods and compositions for desensitizing subterranean formations faces.
This patent application is currently assigned to HALLIBURTON ENERGY SERVICES, INC.. Invention is credited to PHILIP D. NGUYEN, RICHARD D. RICKMAN, JIMMIE D. WEAVER.
Application Number | 20120285690 13/239491 |
Document ID | / |
Family ID | 47141098 |
Filed Date | 2012-11-15 |
United States Patent
Application |
20120285690 |
Kind Code |
A1 |
WEAVER; JIMMIE D. ; et
al. |
November 15, 2012 |
Multi-Stage Methods and Compositions for Desensitizing Subterranean
Formations Faces
Abstract
A method of desensitizing a subterranean formation may include
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.
Inventors: |
WEAVER; JIMMIE D.; (DUNCAN,
OK) ; NGUYEN; PHILIP D.; (DUNCAN, OK) ;
RICKMAN; RICHARD D.; (DUNCAN, OK) |
Assignee: |
HALLIBURTON ENERGY SERVICES,
INC.
HOUSTON
TX
|
Family ID: |
47141098 |
Appl. No.: |
13/239491 |
Filed: |
September 22, 2011 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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13106382 |
May 12, 2011 |
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13239491 |
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Current U.S.
Class: |
166/305.1 |
Current CPC
Class: |
C09K 2208/10 20130101;
C09K 8/608 20130101; C09K 8/68 20130101; C09K 8/607 20130101; C09K
2208/12 20130101; C09K 8/57 20130101; C09K 8/66 20130101 |
Class at
Publication: |
166/305.1 |
International
Class: |
E21B 43/16 20060101
E21B043/16 |
Claims
1. A method of desensitizing a subterranean formation, the method
comprising: providing a wellbore penetrating a subterranean
formation; 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.
2. The method of claim 1, wherein the first concentration ranges
from about 0.01% to about 60% v/v of the first desensitizing agent
to the first base fluid.
3. The method of claim 1, wherein the first concentration changes
over time in a manner selected from the group consisting of a
gradient change, a step-wise change, and any combination
thereof.
4. The method of claim 1, wherein the first concentration is about
2 to about 5000 times greater than the second concentration.
5. The method of claim 1, wherein the second concentration ranges
from about 0.0001% to about 20% v/v of the second desensitizing
agent to the second base fluid.
6. The method of claim 1, wherein the second concentration changes
over time in a manner selected from the group consisting of a
gradient change, a step-wise change, and any combination
thereof.
7. The method of claim 1 further comprising: introducing a
transition fluid comprising a third base fluid and a third
desensitizing solution that comprises a third desensitizing agent
between the introduction of the leading-edge fluid and the
treatment fluid, wherein the third desensitizing agent is present
in the third base fluid at a third concentration.
8. The method of claim 7, wherein the third concentration changes
over time in a manner selected from the group consisting of a
gradient change, a step-wise change, and any combination
thereof.
9. The method of claim 1, wherein the first desensitizing agent
comprises at least one selected from the group consisting of: an
inorganic acid, a salt, a polyelectrolyte, a multivalent ion, an
inorganic base, a strong base, an oxide, a resin, a surfactant, a
cationic polymer, a methyl glucoside, a polyglycerol, a polyglycol,
an emulsion facilitating particle, a chelating agent, a phosphine,
a soluble organic stabilizing compound, a silica control agent, an
embrittlement modification agent, a surface modification agent, a
microparticle, a nanoparticle, and any combination thereof.
10. The method of claim 1, wherein the second desensitizing agent
comprises at least one selected from the group consisting of: an
inorganic acid, a salt, a polyelectrolyte, a multivalent ion, an
inorganic base, a strong base, an oxide, a resin, a surfactant, a
cationic polymer, a methyl glucoside, a polyglycerol, a polyglycol,
an emulsion facilitating particle, a chelating agent, a phosphine,
a soluble organic stabilizing compound, a silica control agent, an
embrittlement modification agent, a surface modification agent, a
microparticle, a nanoparticle, and any combination thereof.
11. The method of claim 1, wherein the first desensitizing agent
and the second desensitizing agent are different compositions.
12. The method of claim 1, wherein the leading-edge fluid and
treatment fluid contain a same desensitizing agent such that the
same desensitizing agent is from about 0.01% to about 60% v/v in
the leading-edge fluid and the same desensitizing agent is from
about 0.0001% to about 20% v/v in the treatment fluid.
13. The method of claim 1, wherein introducing the leading-edge
fluid is performed at a fracture pressure.
14. The method of claim 1, wherein the leading-edge fluid further
comprises a proppant.
15. The method of claim 1, wherein introducing the treatment fluid
is performed at a fracture pressure.
16. The method of claim 1, wherein the treatment fluid further
comprises a proppant.
17. A method of remedially desensitizing a subterranean formation,
the method comprising: 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.
18. A method of desensitizing a subterranean formation, the method
comprising: providing a wellbore 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.
19. The method of claim 18, wherein diverting the fluid flow
involves at least one selected from the group consisting of: a
plugging agent, a plug, a packer, a bridge plug, a frac plug,
plugging agent, a perf ball, a gel, a plugging foam, a diverting
agent, a degradable diverting agent, and any combination thereof.
Description
CROSS REFERENCE TO RELATED APPLICATION
[0001] The present application is a continuation-in-part of U.S.
patent application Ser. No. 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, 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 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 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] FIG. 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] FIG. 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] FIG. 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 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] FIGS. 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. FIG. 3 illustrates the injection profile, i.e., the
concentration injected as a function of time. In this 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. FIGS. 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] FIG. 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, FIG. 2 provides the concentration injection profile
at time point 3 of FIG. 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 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.
[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 [0030] (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; [0031] (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; [0032] (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; [0033] (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;
[0034] (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; [0035] (f)
introducing a fourth treatment fluid comprising a diverting agent
to substantially divert subsequent fluids from the second stage of
the wellbore, the fourth treatment fluid optionally comprising a
desensitizing agent and/or a proppant; and [0036] (g) continuing
until several stages, e.g., 50 or more, are treated.
[0037] In some embodiments, the stages may be defined by a
perforation or a cluster of perforations. It should be noted that
the diverting 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., flushing treatments and acidizing treatments,
may be included within the above nonlimiting example. One skilled
in the art, with the benefit of this disclosure, should understand
the plurality of steps that may be included and the order in which
to include them to achieve a desired wellbore treatment design.
[0038] In some embodiments, leading-edge fluids with subsequent
treatment fluids may be used in a high-rate water frac including
multi-stage high-rate water fracs. These are typically done in
shales that have high clay content; therefore, a leading-edge fluid
with a desensitizing agent may be especially useful.
[0039] In some embodiments, leading-edge fluids may be used in a
remedial treatment for a subterranean formation having at least
some formation faces having undergone deleterious chemical and/or
physical changes. By way of nonlimiting example, a leading-edge
fluid may be introduced into a subterranean formation for
remediation at a matrix pressure so as to treat existing formation
faces therein. For example, when the fractures are worn out and
need to be restimulated.
[0040] 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 from a nearby
well. In formations with sensitive minerals, the deleterious
chemical and/or physical changes to formation faces can lead to
higher injection pressures needed to maintain reservoir pressure.
It is believed that employing leading edge fluids and subsequent
treatment fluids, as described in some embodiments herein, could
result in a lower injection pressure being required for injection
wells.
[0041] 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.
[0042] 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.
[0043] 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.
[0044] 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.
[0045] A preferred method for desensitizing minerals calls for the
concentration of the desensitizing agents in the leading-edge fluid
to range from a lower limit of about 0.01%, 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.
[0046] 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 20%, 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.
[0047] 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.
[0048] 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 surface of a
wellbore may indicated fracturing is occurring and a transition to
a leading-edge fluid is necessary.
[0049] 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.
[0050] 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. Pat. Nos.
7,740,071; 5,197,544; and 4,366,073, U.S. Patent Publication No.
2004/0235667, and U.S. patent application Ser. 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
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").
[0051] 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.
[0052] 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 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.
[0053] 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.
[0054] 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.
[0055] Inorganic bases, organic bases, strong bases, and
combinations thereof known in the art suitable for use in
subterranean operations may be 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.
[0056] 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.
[0057] 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 (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,
tetramethylenediamine, trimethylenetetramine,
tetraethylenepentamine, polyethylene amine, cyclen);
organo-polyamines; quaternized polyamines; CLA-STA.RTM. XP (a
water-soluble cationic oligomer, available from Halliburton Energy
Services, Inc.); CLA-STA.RTM. FS (a mineral stabilizing polymer,
available from Halliburton Energy Services, Inc.); and CLA-WEB.TM.
(a stabilizing additive, available from Halliburton Energy
Services, Inc); derivatives thereof; salts thereof; and
combinations thereof.
[0058] 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.
[0059] 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 that may be suitable for use in the present
invention include, but are not limited to C.sub.12 to C.sub.22
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-hydroxyethyl)coco-amine, cetylpyridinium chloride,
N,N,N,trimethyl-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 19N.TM. surfactant (a cationic nonemulsifier,
available from Halliburton Energy Services, Inc.), TWEEN.RTM.
surfactants (a polysorbate surfactant, available from
Sigma-Aldrich), TRITON.RTM. surfactants (a nonionic surfactant,
available from Sigma-Aldrich), and BRIJ.RTM. 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.
[0060] 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.
[0061] 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 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.RTM. silicas (silica silylates, Wacker-Chemie GmbH) such as
HDK.RTM. H20, HDK.RTM. H30, and HDK.RTM. H2000. The HDK.RTM.
silicas are loose white powders that are primarily amorphous
lattice structures of SiO.sub.2. 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.
[0062] 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.
[0063] 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.
[0064] 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 C.sub.1 to C.sub.12
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 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.
[0065] 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)-imidazoliu-
m methyl sulfate,
1-ethyl-4,5-dihydro-3-(2-hydroxyethyl)-2-(8-heptadecenyl)-imidazolium
ethyl sulfate, putrescine, cadaverine, spermidine, spermine,
diethylenetriamine, tetramethylenediamine, trimethylenetetramine,
tetraethylenepentamine, and any combination thereof.
[0066] 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 will be recognized by one of ordinary skill in the art
with the benefit of this disclosure.
[0067] 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.
[0068] 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.
[0069] 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.
[0070] 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.RTM. (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 SiO.sub.2 to Na.sub.2O ranging from about 3.25:1 to
1.5:1. In some preferred embodiments, the silicate may be potassium
silicate having a ratio of SiO.sub.2 to K.sub.2O ranging from about
2.5:1 to 1.5:1.
[0071] Silanes may include chemicals that contain silicone at the
center of the silane molecule that is chemically attached to a
first functional group such 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, N2-(aminoethyl)-3-aminopropyltrimethoxysilane,
3-glycidoxypropyltrimethoxysilane,
n-beta-(aminoethyl)-gamma-aminopropyl trimethoxysilane,
methyltrimethoxysilane, vinyltrimethoxysilane,
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-glycidoxypropyltrimethoxysilanes, vinyltrichlorosilane,
vinyltris(beta-methoxyethoxy)silane, vinyltriethoxysilane,
vinyltrimethoxysilane, 3-metacryloxypropyltrimethoxysilane,
beta-(3,4 epoxycyclohexyl)-ethyltrimethoxysilane,
r-glycidoxypropyltrimethoxysilane,
r-glycidoxypropylmethylidiethoxysilane,
N-B(aminoethyl)-raminopropyl-trimethoxysilane,
N-beta(aminoethyl)-raminopropylmethyldimethoxysilane,
3-aminopropyl-triethoxysilane,
N-phenyl-r-aminopropyltrimethoxysilane,
r-mercaptopropyltrimethoxysilane, vinyltrichlorosilane,
vinyltris(.beta.-methoxyethoxy)silane, vinyltrimethoxysilane,
r-metacryloxypropyltrimethoxysilane, beta-(3,4
epoxycyclohexyl)-ethyltrimethoxysilane,
r-glycidoxypropyltrimethoxysilane,
r-glycidoxypropylmethylidiethoxysilane,
N-beta(aminoethyl)-r-aminopropyltrimethoxysilane,
N-beta(aminoethyl)-r-aminopropylmethyldimethoxysilane,
r-aminopropyltriethoxysilane,
N-phenyl-raminopropyltrimethoxysilane,
r-mercaptopropyltrimethoxysilane, and any derivative thereof, and
any combination thereof.
[0072] 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 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.
[0073] 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.
[0074] 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/m.sup.2);
the practical units are megapascals (MPa or N/mm.sup.2) or
gigapascals (GPa or kN/mm.sup.2). 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:
E .ident. tensile stress tensile strain = .sigma. = F / A 0 .DELTA.
L / L 0 = FL 0 A 0 .DELTA. L Equation 1 ##EQU00001##
[0075] Where:
[0076] E is the Young's modulus (modulus of elasticity);
[0077] F is the force applied to the object;
[0078] A.sub.o is the original cross-sectional area through which
the force is applied;
[0079] .DELTA.L is the amount by which the length of the object
changes; and
[0080] L.sub.0 is the original length of the object.
[0081] 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).
v = - trans axial = - x y Equation 2 ##EQU00002##
[0082] Where:
[0083] v is the resulting Poisson's ratio,
[0084] .epsilon..sub.trans is transverse strain (negative for axial
tension, positive for axial compression); and
[0085] .epsilon..sub.axial is axial strain (positive for axial
tension, negative for axial compression).
[0086] 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.
[0087] 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.
[0088] 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 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.RTM. XP,
CLA-STA.RTM. FS, CLAYFIX.RTM. (an acid salt, available from
Halliburton Energy Services, Inc.), CLAYFIX.RTM.-II (a temporary
clay stabilizing additive, available from Halliburton Energy
Services, Inc.), and CLAYFIX.RTM.-II PLUS (a temporary clay
stabilizing additive, available from Halliburton Energy Services,
Inc.), HPT-1.TM. (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. Pat. Nos. 5,097,094,
4,974,678, 4,424,076, and 4,366,071.
[0089] 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.
[0090] 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.
[0091] 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.
[0092] 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.
[0093] 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. 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
Fe.sub.3O.sub.4 and gamma-Fe.sub.2O.sub.3; 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.degree., 2.degree., or 3.degree.), 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.
[0094] 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 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.
[0095] 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.
[0096] 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, 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.
[0097] 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.
[0098] 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. Pat. No. 5,905,061, U.S. Pat. No. 5,977,031, and U.S. Pat. No.
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.
[0099] 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 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.
[0100] 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.
[0101] 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.
[0102] 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.
[0103] In some embodiments, a method of desensitizing a
subterranean formation may generally include the steps of:
providing a wellbore 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.
[0104] 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.
[0105] 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
Example 1
[0106] 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 clay content identified as swelling clay. Based on this
information, the following treatment recommendations were made:
[0107] (a) Use 1% v/v of CLA-WEB.TM. 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-WEB.TM. clay-stabilization additive was
used in mixing with 25,000 gal of fresh water to prepare the 1% v/v
CLA-WEB.TM. clay-stabilization additive solution.
[0108] (b) Use 0.05% v/v of CLA-WEB.TM. clay-stabilization additive
in the remainder of the fracturing treatment volume, or mix 250 gal
of CLA-WEB.TM. clay-stabilization additive with the remaining
475,000 gal of fluid.
Example 2
[0109] 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-US-00001 TABLE 1 Interval Depth 13,419.3' 13,582.5' Quartz
37% 46% K-feldspar 3% 3% Na-feldspar 3% 4% Dolomite 27% 2% Pyrite
6% 6% Kaolinite 3% 3% Chlorite trace trace Muscovite trace 1%
Illite 12% 22% Mixed layer 7% 7% Smectite trace trace
[0110] 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-WEB.TM. clay-stabilization additive 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-US-00002 TABLE 2 Injected Fluids Injected Volume (mL) 3% KCl
brine 100 3% CLA-WEB .TM. clay- 200 stabilization additive 3% KCl
brine 50 Fresh water 60 3% KCl brine 100
[0111] A decrease in permeability of brine after exposure to fresh
water comparing with brine pressure after treatment of 1%
CLA-WEB.TM. clay-stabilization additive solution indicates that
this 1% CLA-WEB.TM. clay-stabilization additive concentration was
not sufficient for clay protection, which will result in
permeability reduction. The treatment with 3% CLA-WEB.TM.
clay-stabilization additive solution indicates this CLA-WEB.TM.
clay-stabilization additive concentration was more appropriate to
minimize any potential of permeability damage.
[0112] Based on the results of these tests, it was recommended that
a concentration of 5% (v/v) of CLA-WEB.TM. clay-stabilization
additive be used in the pad fluid of the fracturing treatment, and
a concentration of 0.2% (v/v) of CLA-WEB.TM. clay-stabilization
additive be used in the remainder of the fracturing fluid carrying
proppant.
[0113] 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 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.
* * * * *