U.S. patent application number 12/718382 was filed with the patent office on 2011-09-08 for clean viscosified treatment fluids and associated methods.
Invention is credited to Phillip C. Harris, Feng Liang, David M. Loveless, Rajesh K. Saini, Narongsak Tonmukayakul.
Application Number | 20110214859 12/718382 |
Document ID | / |
Family ID | 44063919 |
Filed Date | 2011-09-08 |
United States Patent
Application |
20110214859 |
Kind Code |
A1 |
Loveless; David M. ; et
al. |
September 8, 2011 |
Clean Viscosified Treatment Fluids and Associated Methods
Abstract
Treatment fluids comprising an aqueous base fluid, a compliant
cellulosic viscosifying agent, a crosslinking agent, and a
protective ligand are provided. The present invention provides
methods of using the treatment fluids in subterranean formations.
One example of a suitable method includes providing a fracturing
fluid comprising an aqueous base fluid, a compliant cellulosic
viscosifying agent, a crosslinking agent, and a protective ligand
and introducing the fracturing fluid into at least a portion of a
subterranean formation at a rate and pressure sufficient to create
or enhance at least one or more fractures in the subterranean
formation.
Inventors: |
Loveless; David M.; (Duncan,
OK) ; Harris; Phillip C.; (Duncan, OK) ;
Saini; Rajesh K.; (Duncan, OK) ; Tonmukayakul;
Narongsak; (Duncan, OK) ; Liang; Feng;
(Duncan, OK) |
Family ID: |
44063919 |
Appl. No.: |
12/718382 |
Filed: |
March 5, 2010 |
Current U.S.
Class: |
166/275 |
Current CPC
Class: |
C09K 8/10 20130101; C09K
8/685 20130101 |
Class at
Publication: |
166/275 |
International
Class: |
E21B 43/16 20060101
E21B043/16 |
Claims
1. A method comprising: providing a treatment fluid having a first
viscosity comprising: an aqueous base fluid, a compliant cellulosic
viscosifying agent, a crosslinking agent, and a protective ligand;
and placing the treatment fluid in a subterranean formation.
2. The method of claim 1 wherein the treatment fluid forms a
crosslinked gel having a second viscosity, the second viscosity
being higher than the first viscosity prior to being placed in the
subterranean formation.
3. The method of claim 1 wherein the treatment fluid forms a
crosslinked gel having a second viscosity, the second viscosity
being higher than the first viscosity after being placed in the
subterranean formation.
4. The method of claim 1 wherein the compliant cellulosic
viscosifying agent is a carboxylated viscosifying agent selected
from the group consisting of a carboxyethylcellulose, a
carboxymethylcellulose, a carboxymethylhydroxyethylcellulose, and
any combination thereof.
5. The method of claim 1 wherein the crosslinking agent is a
compound capable of supplying a metal ion selected from the group
consisting of: a zirconium ion, an iron ion, a titanium ion, an
aluminum ion, a chromium ion, an antimony ion, and any combination
thereof.
6. The method of claim 4 wherein the crosslinking agent comprises a
compound capable of supplying an aluminum ion and wherein treatment
fluid has a pH in the range of from about 3.5 to about 5.
7. The method of claim 1 wherein the protective ligand is an acid
selected from the group consisting of formic acid, acetic acid,
propionic acid, lactic acid, butyric acid, isobutyric acid, malonic
acid, succinic acid, malic acid, tartaric acid, citric acid,
ethylenediaminetetraacetic acid, sulfuric acid and any combination
thereof.
8. The method of claim 1 wherein the treatment fluid is placed in
the subterranean formation as part of a subterranean operation
selected from the group consisting of a drilling operation, a
fracturing operation, a completion operation, and a workover
operation.
9. The method of claim 1 wherein the subterranean formation
comprises a bottom hole temperature of up to and including about
275.degree. F.
10. A method comprising: providing a fracturing fluid having a
first viscosity comprising: an aqueous base fluid, a compliant
cellulosic viscosifying agent, a crosslinking agent, and a
protective ligand; and introducing the fracturing fluid into at
least a portion of a subterranean formation at a rate and pressure
sufficient to create or enhance at least one or more fractures in
the subterranean formation.
11. The method of claim 10 wherein the fracturing fluid forms a
crosslinked gel having a second viscosity, the second viscosity
being higher than the first viscosity prior to being placed in the
subterranean formation.
12. The method of claim 10 wherein the fracturing fluid forms a
crosslinked gel having a second viscosity, the second viscosity
being higher than the first viscosity after being placed in the
subterranean formation.
13. The method of claim 10 wherein the compliant cellulosic
viscosifying agent is a carboxylated viscosifying agent selected
from the group consisting of a carboxyethylcellulose, a
carboxymethylcellulose, a carboxymethylhydroxyethylcellulose, and
any combination thereof.
14. The method of claim 10 wherein the crosslinking agent is a
compound capable of supplying a metal ion selected from the group
consisting of: a zirconium ion, an iron ion, a titanium ion, an
aluminum ion, a chromium ion, an antimony ion, and any combination
thereof.
15. The method of claim 10 wherein the protective ligand is an acid
selected from the group consisting of formic acid, acetic acid,
propionic acid, lactic acid, butyric acid, isobutyric acid, malonic
acid, succinic acid, malic acid, tartaric acid, citric acid,
sulfuric acid, ethylenediaminetetraacetic acid, and any combination
thereof.
16. The method of claim 10 wherein the subterranean formation
comprises a bottom hole temperature of up to and including about
275.degree. F.
17. A method comprising: providing a treatment fluid having a pH in
the range of about 3.5 to about 5 comprising: an aqueous base
fluid, a cellulosic, carboxylated viscosifying agent, an aluminum
crosslinking agent, and a protective ligand; and placing the
treatment fluid in a subterranean formation.
18. The method of claim 10 wherein the compliant cellulosic
viscosifying agent is a carboxylated viscosifying agent selected
from the group consisting of a carboxyethylcellulose, a
carboxymethylcellulose, a carboxymethylhydroxyethylcellulose, and
any combination thereof.
19. The method of claim 10 wherein the crosslinking agent is a
compound capable of supplying a metal ion selected from the group
consisting of: a zirconium ion, an iron ion, a titanium ion, an
aluminum ion, a chromium ion, an antimony ion, and any combination
thereof.
20. The method of claim 17 wherein the protective ligand is an acid
selected from the group consisting of formic acid, acetic acid,
propionic acid, lactic acid, butyric acid, isobutyric acid, malonic
acid, succinic acid, malic acid, tartaric acid, citric acid,
sulfuric acid, ethylenediaminetetraacetic acid, and any combination
thereof.
Description
BACKGROUND OF THE INVENTION
[0001] The present invention relates to fluids useful for
subterranean operations, and more particularly, to treatment fluids
comprising a compliant cellulosic viscosifying agent having at
least one ligand complex crosslink, and methods of use employing
such treatment fluids to treat subterranean formations.
[0002] Viscosified treatment fluids have been used in a variety of
subterranean treatments. 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. In well completion and stimulation
operations, viscosified treatment fluids are often used to carry
particulates into a subterranean formation for various purposes,
e.g., to deliver particulates to a desired location within a well
bore. Examples of subterranean operations that use viscosified
treatment fluids include servicing and completion operations such
as fracturing, gravel packing, frac-packing, acidizing, acid
fracturing, and fluid-loss pill formation.
[0003] In fracturing for example, fractures may be created or
enhanced by introducing a viscosified fracturing fluid into the
formation at a rate sufficient to exert a sufficient pressure on
the formation to create and extend fractures therein. Generally,
the viscosified fracturing fluid is introduced into the hydrocarbon
producing zone within a subterranean formation. The viscous
fracturing fluid suspends proppant particles that are to be placed
in the fractures to prevent the fractures from fully closing (once
the hydraulic pressure is released), thereby forming conductive
channels within the formation through which hydrocarbons can flow
toward the well bore for production. In sand control operations,
for example, gravel packing operations, a screen, slotted liner, or
other mechanical device is often placed into a portion of a well
bore. A viscosified gravel pack fluid is used to deposit
particulates, often referred to as a gravel, into the annulus
between the mechanical device and the formation or casing to
inhibit the flow of particulates from a portion of the subterranean
formation to the well bore.
[0004] The viscosified treatment fluids used in subterranean
operations are oftentimes aqueous-based fluids comprising
viscosifying agents that increase the viscosities of the treatment
fluids to, among other things, enhance the ability of the treatment
fluids to suspend sand or other particulate materials. These
viscosifying agents are typically polysaccharides which, when
hydrated and at sufficient concentration, are capable of forming a
viscous solution.
[0005] Numerous polysaccharides are used in the art to help
viscosify a treatment fluid for use in subterranean operations.
Some typical viscosifying agents include diutan gums, xanthan gums,
galactomannans, and scleroglucans. However, the use of these
conventional viscosifying agents may give rise to other problems.
First, these viscosifying agents contain a considerable amount of
insoluble residue that may lead to poor permeability and
conductivity thereby leading to decreased hydrocarbon production.
Furthermore, most fluid systems employing such polysaccharides also
include a crosslinking agent such as metal ion crosslinkers. In
some instances, the crosslinked viscosified treatment fluids,
particularly non-reversible crosslinked fluids may be unstable at
high temperatures and shear-sensitive. In particular, high
temperature or shear may lead to loss of viscosity. It would also
be desirable to generate treatment fluid that do not suffer shear
degradation and thereby avoid the above limitations. In addition,
fluid systems may be harmful to the environment and require special
processing prior to disposal. Thus, it is desirable to use clean
viscosifying agents for treatment fluids to produce low
environmental impact treatment fluids.
SUMMARY OF THE INVENTION
[0006] The present invention relates to fluids useful for
subterranean operations, and more particularly, to treatment fluids
comprising a compliant cellulosic viscosifying agent having at
least one ligand complex crosslink, and methods of use employing
such treatment fluids to treat subterranean formations.
[0007] In one embodiment, the methods of the present invention
comprise: providing a treatment fluid having a first viscosity
comprising: an aqueous base fluid, a compliant cellulosic
viscosifying agent, a crosslinking agent, and a protective ligand;
and placing the treatment fluid in a subterranean formation.
[0008] In another embodiment, the methods of the present invention
comprise: providing a fracturing fluid having a first viscosity
comprising: an aqueous base fluid, a compliant cellulosic
viscosifying agent, a crosslinking agent, and a protective ligand;
and introducing the fracturing fluid into at least a portion of a
subterranean formation at a rate and pressure sufficient to create
or enhance at least one or more fractures in the subterranean
formation.
[0009] In yet another embodiment, the methods of the present
invention comprise: providing a treatment fluid having a pH in the
range of about 3.5 to about 5 and having a first viscosity
comprising: an aqueous base fluid, a cellulosic, carboxylated
viscosifying agent, an aluminum crosslinking agent, and a
protective ligand and placing the treatment fluid in a subterranean
formation.
[0010] Other features and advantages of the present invention will
be readily apparent to those skilled in the art upon a reading of
the description of preferred embodiments that follows.
BRIEF DESCRIPTION OF THE DRAWINGS
[0011] These drawings illustrate certain aspects of some of the
embodiments of the present invention, and should not be used to
limit or define the invention.
[0012] FIG. 1 shows the thermal stability of a CMC gel at different
pH and temperatures.
[0013] FIGS. 2 and 3 show the thermal stability of various amounts
of CMC crosslinked with various amounts of metal cation
crosslinker.
[0014] FIG. 4 shows the thermal stability of a cation crosslinked
CMC gel after adding a gel stabilizer.
[0015] FIG. 5 shows the thermal stability of a cation crosslinked
CMC gel at adjusted pH with HCl or buffer solution.
[0016] FIG. 6 shows the delayed crosslinking of a CMC gel with a
cation crosslinker.
[0017] FIG. 7 shows the breaking of the viscosified treatment
fluids of the present invention with various oxidizers.
[0018] FIG. 8 shows the dynamic behavior of the viscosified
treatment fluids of the present invention at 120.degree. C.
[0019] FIG. 9 shows the evolution of the storage (G') and loss
(G'') moduli during the crosslinking at 25.degree. C. in terms of
the frequency sweep.
[0020] FIG. 10 shows the evolution of time-dependent storage (G')
and loss (G'') moduli during the crosslinking at 25.degree. C.
obtained through the multiwave technique and compared to using a
single frequency time sweep.
[0021] FIG. 11 shows the proppant settling properties in the
viscosified treatment fluids of the present invention.
[0022] FIG. 12 depicts the proppant settling analysis under static
settling conditions for the treatment fluids of the present
invention.
[0023] FIG. 13 shows the proppant settling properties for the
treatment fluids of the present invention under imposed shear rate
of 20 s.sup.-1.
[0024] FIG. 14 shows the settling analysis under imposed shear rate
of 20 s.sup.-1 for the treatment fluids of the present invention
after aging the sample for 1 hour.
[0025] FIG. 15 shows the settling analysis under imposed shear rate
of 20 s.sup.-1 for the treatment fluids of the present invention
after aging the sample for 3 hours.
[0026] FIG. 16 shows the viscosity profile of a CMC/A1 crosslinked
system at 200.degree. F.
[0027] FIG. 17 shows the viscosity profile of a CMC/A1 crosslinked
system at 180.degree. F.
[0028] FIG. 18 shows the shear stability profile of CMC/A1
crosslinked system at 180.degree. F.
DESCRIPTION OF PREFERRED EMBODIMENTS
[0029] The present invention relates to fluids useful for
subterranean operations, and more particularly, to treatment fluids
comprising a compliant cellulosic viscosifying agent having at
least one ligand complex crosslink, and methods of use employing
such treatment fluids to treat subterranean formations.
[0030] The treatment fluids of the present invention may comprise a
compliant cellulosic viscosifying agent with a protective ligand.
As used herein, the term "compliant" refers to materials described
in 21 CFR .sctn..sctn.170-199 (substances approved as food items,
approved for contact for food, or approved for use as an additive
to food) and that are prepared from food-grade materials.
[0031] Of the many advantages of the compositions and related
methods of the present invention, is that treatment fluids of the
present invention may improve oil and/or gas production by using a
compliant cellulosic viscosifying agent having at least one ligand
complex crosslink. The compliant cellulosic viscosifying agents of
the invention, as defined above potentially eliminates the need for
costly procedures needed to dispose of the treatment fluids
containing non-compliant viscosifying agents and may help reduce
negative impacts on the marine environment and groundwater.
Additionally, the compliant viscosifying agent may provide
effective treatment of the formation without excessive damage
caused by the use of multiple or non-compliant viscosifiers. The
compliant cellulosic viscosifying agent used in the present
invention may result in treated portions of a subterranean
formation that experience enhanced regain permeability and better
conductivity due to the absence of insoluble residue. Moreover,
treatment fluids of the present invention may be more shear-stable
and may be more temperature stable may exhibit enhanced elastic
properties, and may exhibit enhanced particulate carrying
ability.
[0032] In accordance with embodiments of the present invention, the
treatment fluids generally comprise an aqueous base fluid, a
compliant cellulosic viscosifying agent, a crosslinking agent, and
a protective ligand. Wherein at least a portion of the polymers of
the compliant cellulosic viscosifying agent are crosslinked with
ligand complex crosslinks. As used herein, the term "ligand complex
crosslink" refers to the crosslink between a crosslinking
agent/protective ligand complex and two polymers of the compliant
cellulosic viscosifying agent. In certain embodiments, the ligand
complex crosslink may be formed prior to the treatment fluid being
placed into the subterranean formation. In other embodiments, the
ligand complex crosslink may be delayed such that it forms once the
treatment fluid is placed in a subterranean formation.
[0033] By way of example, the aqueous base fluid of embodiments of
the treatment fluids of the present invention may be any fluid
comprising an aqueous component. Suitable aqueous components
include, but not limited to, fresh water, salt water, brine (e.g.,
saturated or unsaturated saltwater), seawater, pond water and any
combination thereof. Generally, the aqueous component may be from
any source. Suitable aqueous base fluids may include foams. In
certain embodiments, the viscosifying agents of the present
invention may be difficult to dissolve in brines. To solve this
problem, in one embodiment of the present invention, the cellulosic
viscosifying agent may be hydrated in fresh water prior to addition
of the salt solution. One of ordinary skill in the art, with the
benefit of the present disclosure, will recognize suitable aqueous
base fluids for use in the treatment fluids and methods of the
present invention. Some embodiments, the aqueous base fluid may be
present in a treatment fluid of the present invention in an amount
in the range of about 75% to about 99.9% of the treatment fluid. In
some embodiments, fresh water may be the preferred aqueous base
fluid.
[0034] Compliant cellulosic viscosifying agents suitable for use in
the present invention include any carboxylated, cellulosic
viscosifying agent capable of increasing the viscosity of the
treatment fluids and capable of forming a crosslink in the presence
of a crosslinking agent. Examples of suitable compliant cellulosic
viscosifying agents include, but are not limited to
carboxyethylcellulose, carboxymethylcellulose (CMC),
carboxymethylhydroxyethylcellulose, and any combination thereof.
The term "derivative" includes any compound that is made from one
of the listed compounds, for example, by replacing one atom in the
listed compound with another atom or group of atoms, rearranging
two or more atoms in the listed compound, ionizing one of the
listed compounds, or creating a salt of one of the listed
compounds.
[0035] The compliant cellulosic viscosifying agent may be present
in the treatment fluids useful in the methods of the present
invention in an amount sufficient to provide the desired viscosity.
In some embodiments, the cellulosic viscosifying agents may be
present in an amount in the range of from about 0.01% to about 15%
by weight of the treatment fluid. In some preferred embodiments,
the cellulosic viscosifying agents may be present in an amount in
the range of from about 0.1% to about 3% by weight of the treatment
fluid.
[0036] It generally takes greater horsepower to pump fluids that
are more viscous; thus, it may be desirable to delay the crosslink
of the treatment fluids of the present invention until the fluid is
close to the area to be treated. Such delay allows the operator to
pump a non-crosslinked (and thus less viscous) fluid over a longer
distance before having to add horsepower to place the more viscous,
crosslinked fluid. One skilled in the art will be familiar with
known methods to delay crosslinking, such as encapsulation,
chemical delays (e.g. chelating agents), etc. In some embodiments,
the activation of the crosslinking agent may be delayed by
encapsulation with a coating (e.g., a porous coating through which
the crosslinking agent may diffuse slowly, or a degradable coating
that degrades down hole) that delays the release of the
crosslinking agent until a desired time or place. In other
embodiments, chelating agents, such as lactic acid and oxalic acid,
may be added to delay the crosslinking of the viscosifying agent.
One skill in the art will recognize that selection of a particular
crosslinking agent will be governed by several considerations such
as the type and molecular weight of the viscosifying agent(s), the
conditions (such as temperature and pH) in the subterranean
formation being treated, the safety handling requirements, and the
conditions (such as temperature and pH) of the treatment fluid.
[0037] The crosslinking agents may be present in the treatment
fluids useful in the methods of the present invention in an amount
sufficient to provide a desired degree of crosslinking between
molecules of the viscosifying agent. In certain embodiments, the
crosslinking agent may be present in the treatment fluids of the
present invention in an amount in the range of from about 0.001% to
about 1% by weight of the treatment fluid. In other embodiments,
the crosslinking agent may be present in the treatment fluids of
the present invention in an amount in the range of from about
0.005% to about 0.1% by weight of the treatment fluid. While
crosslinking agents may be added in a concentrated solution, the
numerical ranges given above refer to the percentage of metal ions
by weight of the treatment fluid. One of ordinary skill in the art,
with the benefit of this disclosure, will recognize the appropriate
amount of crosslinking agent to include in a treatment fluid of the
present invention based on, among other things, the temperature
conditions of a particular application, the type of viscosifying
agents used, the molecular weight of the viscosifying agents, the
desired degree viscosity, and/or the pH of the treatment fluid.
[0038] Suitable crosslinking agents comprise a metal ion or similar
component that is capable of crosslinking at least two molecules of
the viscosifying agent. Examples of suitable crosslinking agents
include, but are not limited to, magnesium ions, zirconium ions,
titanium ions, aluminum ions, antimony ions, chromium ions, iron
ions, copper ions, magnesium ions, and zinc ions. These ions may be
provided by providing any compound that is capable of producing one
or more of these ions as is well known in the art. In certain
embodiments of the present invention, the crosslinking agent may be
formulated to remain inactive until it is "activated" by, among
other things, certain conditions in the fluid (e.g., pH,
temperature, etc.) and/or interaction with some other
substance.
[0039] In some preferred embodiments, a compliant crosslinking
agent may be used. Examples of suitable compliant crosslinking
metal ions (that is, metal ions capable of crosslinking) include,
but are not limited to, zirconium compounds contained within 21 CFR
.sctn..sctn.170-199, aluminum compounds contained within 21 CFR
.sctn..sctn.170-199, titanium compounds contained within 21 CFR
.sctn..sctn.170-199, chromium(III) compounds contained within 21
CFR .sctn..sctn.170-199, iron(II) compounds contained within 21 CFR
.sctn..sctn.170-199, iron(III) compounds contained within 21 CFR
.sctn..sctn.170-199, copper compounds contained within 21 CFR
.sctn..sctn.170-199, zinc compounds contained within 21 CFR
.sctn..sctn.170-199, and combinations thereof. Examples of such
suitable compliant ion-containing compounds include but are not
limited to ammonium zirconium carbonate, zirconium citrate,
zirconium lactate citrate, zirconium oxide, titanium dioxide,
aluminum nicotinate, aluminum sulfate, aluminum sodium sulfate,
aluminum ammonium sulfate, chromium caseinate, chromium potassium
sulfate, zinc sulfate, zinc hydrosulfite, magnesium chloride,
magnesium sulfate, magnesium gulconate, copper sulfate, and copper
gluconate.
[0040] In an embodiment of the present invention, a protective
ligand may be added to the treatment fluids of the present
invention. The protective ligand may comprise any substance capable
of reacting with the metal ion crosslinking agent and forming
reversible ligand complex crosslink between polymers of the
compliant cellulosic viscosifying agent to form a crosslinked
treatment fluid. In some embodiments, the protective ligand of the
present invention may be capable of preventing the metal ion
crosslinker from forming insoluble residue. In certain embodiments,
a suitable protective ligand may be an acid that allows the pH of
the treatment fluid to reduce to less than about 5. Shear
resistance, temperature stability, and viscosity recovery rate may
be significantly increased in crosslinked compliant cellulosic
treatment fluids when the pH of the treatment fluid is in the range
of from about 3.5 to about 5. Suitable protective ligands for use
in the present invention include, but are not limited to, foimic
acid, acetic acid, propionic acid, lactic acid, butyric acid,
isobutyric acid, malonic acid, succinic acid, malic acid, tartaric
acid, citric acid, sulfuric acid, ethylenediaminetetraacetic, and
any combination thereof. In certain embodiments, the protective
ligand that may be used in the treatment fluids useful in the
methods of the present invention may comprise any substance capable
of degrading into an acid. In some embodiments, the acid may
provide a protective effect on the metal ion crosslinking agent as
well as lowering the pH of the treatment fluid. In certain
embodiments, the protective ligand may comprise any ester capable
of degrading into an acid. Suitable esters include, but are not
limited to, diesters, triesters, etc. Examples of suitable esters
include, but are not limited to, ethyl formate, propyl formate,
butyl formate, amyl formate, anisyl formate, methyl acetate, propyl
acetate, triacetin, butyl propionate, isoamyl propionate, ethyl
lactate, methyl butyrate, ethyl isobutyrate, butyl isobutyrate,
diethyl malonate, butyl ethyl malonate, dimethyl succinate, diethyl
succinate, diethyl malate, diethyl tartrate, dimethyl tartrate,
triethyl citrate, and any derivative and combination thereof. The
protective ligand may be present in the treatment fluids useful in
the methods of the present invention in an amount sufficient to
provide the desired effect. In some embodiments, the protective
ligand may be present in an amount in the range of from about 1:3
to about 1:10 ratio of crosslinking agent to protective ligand. One
of ordinary skill in the art, with the benefit of this disclosure,
will recognize the appropriate protective ligand to include in a
treatment fluid of the present invention based on, among other
things, the temperature conditions of a particular application, the
type of viscosifying agents used, the molecular weight of the
viscosifying agents, the desired degree viscosity, and/or the pH of
the treatment fluid.
[0041] Without wishing to be limited by theory, it is believed that
the protective ligand may function by acting as a competitive
ligand for the metal center of the crosslinking agent thereby
forming a reversible crosslink afforded by the chemically liable
bond between the metal ion and the protective ligand. The treatment
fluids of the present invention exhibit increased shear resistance,
better proppant suspension properties, and high temperature
stability. In particular, the treatment fluids of the present
invention may be used in high temperature environments of up to
275.degree. F. or more. The protective ligand may also act to both
protect the aluminum from forming insoluble particles and to act as
a competitive ligand once the gel is formed. These properties
causing a reversible bond to be formed that gives rise to the
elastically dominated gel properties and the ability to reheal,
both of which are desirable properties in subterranean treatment
fluids, such as fracturing fluids. As used herein, the term
"reheal" refers to a fluid's ability to repair damage caused by
shear forces, such as the shear forces due to the process of the
fluid being placed down hole. In some preferred embodiments, one
compliant crosslinker may be a compound formed from the combination
of aluminum sulfate and lactic acid.
[0042] In certain embodiments, the treatment fluids of the present
invention may be a foamed fluid (e.g., a liquid that comprises a
gas such as nitrogen, carbon dioxide, air, or methane). As used
herein, the term "foamed" also refers to fluids such as co-mingled
fluids. In some embodiments, it may be desirable that the treatment
fluid is foamed to, among other things, reduce the amount of fluid
that is required in a water sensitive subterranean formation, to
reduce fluid loss in the formation, and/or to provide enhanced
proppant suspension. In examples of such embodiments, the gas may
be present in the range of from about 5% to about 98% by volume of
the treatment fluid, and more preferably in the range of from about
20% to about 90% by volume of the treatment fluid. The amount of
gas to incorporate in the fluid may be affected by many factors
including the viscosity of the fluid and the wellhead pressures
involved in a particular application. One of ordinary skill in the
art, with the benefit of this disclosure, will recognize the how
much gas, if any, to incorporate into the treatment fluids of the
present invention.
[0043] Depending on the use of the treatment fluid, in some
embodiments, other additives may optionally be included in the
treatment fluids of the present invention. Examples of such
additives may include, but are not limited to, salts, pH control
additives, surfactants, breakers, biocides, fluid loss control
agents, stabilizers, chelating agents, scale inhibitors, gases,
mutual solvents, particulates, corrosion inhibitors, oxidizers,
reducers, and any combination thereof. A person of ordinary skill
in the art, with the benefit of this disclosure, will recognize
when such optional additives should be included in a treatment
fluid used in the present invention, as well as the appropriate
amounts of those additives to include.
[0044] The treatment fluids of the present invention also may
comprise breakers capable of reducing the viscosity of the
treatment fluid at a desired time. Examples of such suitable
breakers for treatment fluids of the present invention include, but
are not limited to, sodium chlorites, hypochlorites, perborate,
persulfates, peroxides, including organic peroxides. Other suitable
breakers include, but are not limited to, suitable acids and
peroxide breakers, delinkers, as well as enzymes that may be
effective in breaking viscosified treatment fluids. In some
preferred embodiments, the breaker may be a compliant breaker such
as citric acid, other acids ore chelating molecules found in 21 CFR
.sctn..sctn.170-199 (e.g. tetrasodium EDTA 175.300), oxidizers
found in 21 CFR .sctn..sctn.170-199 (e.g. ammonium persulfate
175.150), enzymes found within 21 CFR .sctn..sctn.170-199 (e.g.
cellulose enzymes 173.120). A breaker may be included in a
treatment fluid of the present invention in an amount and form
sufficient to achieve the desired viscosity reduction at a desired
time. The breaker may be formulated to provide a delayed break, if
desired. For example, a suitable breaker may be encapsulated if
desired. Suitable encapsulation methods are known to those skilled
in the art. One suitable encapsulation method involves coating the
selected breaker in a porous material that allows for release of
the breaker at a controlled rate. Another suitable encapsulation
method that may be used involves coating the chosen breakers with a
material that will degrade when downhole so as to release the
breaker when desired. Resins that may be suitable include, but are
not limited to, polymeric materials that will degrade when
downhole. The terms "degrade," "degradation," or "degradable" refer
to both the two relatively extreme cases of degradation that the
degradable material may undergo, i.e., heterogeneous (or bulk
erosion) and homogeneous (or surface erosion), and any stage of
degradation in between these two. This degradation can be a result
of, among other things, a chemical or thermal reaction or a
reaction induced by radiation.
[0045] In certain embodiments of the present invention, the
breakers may be encapsulated by synthetic and natural waxes. Waxes
having different melting points may be used in order to control the
delay of breaking based on the temperature of a specific
subterranean operation. In an embodiment, the encapsulation of the
breaker is performed by mixing the breaker and wax above the
melting temperature for the specific wax and then extruding the
composition to form small particles of the encapsulated material.
The resulting product may be annealed by briefly heating the
product to the point of the coating to seal cracks in the coating,
thus preventing premature release. The encapsulation may also be
achieved by melt spraying the wax on the breaker (e.g. citric acid)
particles or by any other technique known by a person of ordinary
skill in the art. If used, a breaker should be included in a
treatment fluid of the present invention in an amount sufficient to
facilitate the desired reduction in viscosity in a treatment fluid.
For instance, peroxide concentrations that may be used vary from
about 0.1 to about 30 gallons of peroxide per 1000 gallons of the
treatment fluid. Similarly, for instance, when citric acid is used
as a breaker, concentrations of from 0.11 b/Mgal to 30 lb/Mgal are
appropriate.
[0046] Other suitable breakers include compliant breakers such as
ethyl formate, propyl foiniate, butyl formate, amyl formate, anisyl
formate, methyl acetate, propyl acetate, triacetin, butyl
propionate, isoamyl propionate, ethyl lactate, methyl butyrate,
ethyl isobutyrate, butyl isobutyrate, diethyl malonate, butyl ethyl
malonate, dimethyl succinate, diethyl succinate, diethyl malate,
diethyl tartrate, dimethyl tartrate, triethyl citrate, and any
combination thereof.
[0047] Optionally, a treatment fluid of the present invention may
comprise an activator or a retarder to, among other things,
optimize the break rate provided by the breaker. Any known
activator or retarder that is compatible with the particular
breaker used is suitable for use in the present invention. Examples
of such suitable activators include, but are not limited to, acid
generating materials, chelated iron, copper, cobalt, and reducing
sugars. Examples of suitable retarders include sodium thiosulfate,
methanol, and diethylenetriamine. In some embodiments, the sodium
thiosulfate may be used in a range of from about 1 to about 100
lbs/Mgal of treatment fluid. A preferred range may be from about 5
to about 20 lbs/Mgal. An artisan of ordinary skill with the benefit
of this disclosure will be able to identify a suitable activator or
retarder and the proper concentration of such activator or retarder
for a given application.
[0048] The treatment fluids of the present invention also may
comprise suitable fluid loss control agents. Such fluid loss
control agents may be particularly useful when a treatment fluid of
the present invention is being used in a fracturing application or
in a fluid used to seal a formation from invasion of fluid from the
well bore. Any fluid loss control agent that is compatible with the
treatment fluids of the present invention is suitable for use in
the present invention. Examples include, but are not limited to,
starches (as used herein, "starch" refers to a polysaccharide gum),
silica flour, gas bubbles (energized fluid or foam), benzoic acid,
soaps, resin particulates, relative permeability modifiers,
degradable gel particulates, and other immiscible fluids. It is
also known in the art to use a dispersion of diesel in fluid as a
fluid loss control agent; however, its use may have negative
environmental impacts.
[0049] Alternatively, other materials that have better
environmental impact such as esters (e.g., triethyl citrate, ethyl
formate, triethyl orthoformate, amyl formate, diethyl malate, etc.)
can be used as fluid loss liquids. These materials generate acid
upon hydrolysis that helps in breaking the gel. In some cases, like
triethyl citrate, the material generates citric acid that chelates
with crosslinking metal ion in the fluid and break the fluid by
taking away the metal crosslinker. A variety of organic acids are
available in the form of esters that are compliant. Most of these
are described as Synthetic Flavoring Substances and Adjuvants (21
CFR .sctn.172.515). Another example of a suitable fluid loss
control additive is one that comprises a degradable material. If
included, a fluid loss additive should be added to a treatment
fluid of the present invention in an amount necessary to give the
desired fluid loss control. In some embodiments, a fluid loss
additive may be included in an amount of about 5 to about 2000
lbs/Mgal of the treatment fluid. In some embodiments, the fluid
loss additive may be included in an amount from about 10 to about
50 lbs/Mgal of the treatment fluid. For some liquid additives that
function as fluid loss additives, these may be included in an
amount from about 0.01% to about 20% by volume; in some
embodiments, these may be included in an amount from about 1.0% to
about 10% by volume. Suitable compliant fluid loss control
additives include ethyl formate, propyl formate, butyl formate,
amyl formate, anisyl formate, methyl acetate, propyl acetate,
triacetin, butyl propionate, isoamyl propionate, ethyl lactate,
methyl butyrate, ethyl isobutyrate, butyl isobutyrate, diethyl
malonate, butyl ethyl malonate, dimethyl succinate, diethyl
succinate, diethyl malate, diethyl tartrate, dimethyl tartrate,
triethyl citrate, and any derivative and combination thereof.
[0050] The treatment fluids of the present invention may comprise
particulates, such as proppant particulates or gravel particulates.
Such particulates may be included in the treatment fluids of the
present invention, for example, when a gravel pack is to be formed
in at least a portion of the well bore or a proppant pack is to be
formed in one or more fractures in the subterranean formation.
Particulates suitable for use in the present invention may comprise
any material suitable for use in subterranean operations. Suitable
materials for these particulates may 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 particulate
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 mixtures 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 particulates
included in the treatment fluids of the present invention may be
coated with any suitable resin or tackifying agent known to those
of ordinary skill in the art. In certain embodiments, the
particulates may be present in the treatment fluids of the present
invention 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.
[0051] A biocide may be included to the treatment fluids of the
present invention to reduce bioburden of the fluid to avoid
introducing an undesirable level of bacteria into the subterranean
formation. Suitable examples of biocides may include both oxidizing
biocides and nonoxidizing biocides. Examples of oxidizing biocides
include, but are not limited to, sodium hypochlorite, hypochlorous
acid, chlorine, bromine, chlorine dioxide, and hydrogen peroxide.
Examples of nonoxidizing biocides include, but are not limited to,
aldehydes, quaternary amines, isothiazolines, carbamates,
phosphonium quaternary compounds, and halogenated compounds.
Factors that determine what biocide will be used in a particular
application may include, but are not limited to, cost, performance,
compatibility with other components of the treatment fluid, kill
time, and environmental compatibility. One skilled in the art with
the benefit of this disclosure will be able to choose a suitable
biocide for a particular application.
[0052] In some embodiments, UV radiation may be used to reduce the
bioburden of a fluid in place of chemical biocides or used in
conjunction with chemical biocides. One method of using UV light to
reduce bioburden suitable for use in the present invention involves
adding a photoinitiator to the treatment fluid and then exposing
the treatment fluid to a UV light source. Such photoinitiators may
absorb the UV light and undergo a reaction to produce a reactive
species of free radicals that may in turn trigger or catalyze
desired chemical reactions. Suitable organic photoinitiators for
use in the present invention may include, but are not limited to,
acetophenone, propiophenone, benzophenone, xanthone, thioxanthone,
fluorenone, benzaldehyde, anthraquinone, carbazole, thioindigoid
dyes, phosphine oxides, ketones, benzoin ethers, benzyl ketals,
alpha-dialkoxyacetophenones, alpha-hydroxyalkylphenones,
alpha-aminoalkylphenones, and acylphosphine oxides; any combination
or derivative thereof. Suitable inorganic photoinitiators for use
in the present invention are substances that, when exposed to UV
light, will generate free radicals that will interact with the
microorganisms as well as other organics in a given treatment
fluid. Some suitable inorganic photoinitiators include, but are not
limited to, nanosized metal oxides (e.g., those that have at least
one dimension that is 1 nm to 1000 nm in size) such as titanium
dioxide, iron oxide, cobalt oxide, chromium oxide, magnesium oxide,
aluminum oxide, copper oxide, zinc oxide, manganese oxide, and any
combination or derivative thereof.
[0053] Salts may optionally be included in the treatment fluids of
the present invention for many purposes, including, for reasons
related to compatibility of the treatment fluid with the formation
and formation fluids. To determine whether a salt may be
beneficially used for compatibility purposes, a compatibility test
may be performed to identify potential compatibility problems. From
such tests, one of ordinary skill in the art with the benefit of
this disclosure will be able to determine whether a salt should be
included in a treatment fluid of the present invention. Suitable
salts include, but are not limited to, calcium chloride, sodium
chloride, magnesium chloride, potassium chloride, sodium bromide,
potassium bromide, ammonium chloride, sodium formate, potassium
formate, cesium formate, mixtures thereof, and the like. The amount
of salt that should be added should be the amount necessary for
formation compatibility, such as stability of clay minerals, taking
into consideration the crystallization temperature of the brine,
e.g., the temperature at which the salt precipitates from the brine
as the temperature drops.
[0054] Examples of suitable pH control additives that may
optionally be included in the treatment fluids of the present
invention are bases and/or acid compositions. A pH control additive
may be necessary to maintain the pH of the treatment fluid at a
desired level, e.g., to improve the effectiveness of certain
breakers and to reduce corrosion on any metal present in the well
bore or formation, etc. In some instances, it may be beneficial to
maintain the pH at 3.5-5. One of ordinary skill in the art with the
benefit of this disclosure will be able to recognize a suitable pH
for a particular application.
[0055] The pH control additive also may comprise a base to elevate
the pH of the treatment fluid. Generally, a base may be used to
elevate the pH of the mixture. Any known base that is compatible
with the viscosifying agents of the present invention can be used
in the treatment fluids of the present invention. Examples of
suitable bases include, but are not limited to, sodium hydroxide,
potassium carbonate, potassium hydroxide, sodium carbonate, and
sodium bicarbonate. One of ordinary skill in the art with the
benefit of this disclosure will recognize the suitable bases that
may be used to achieve a desired pH elevation.
[0056] In some embodiments, the treatment fluids of the present
invention may include surfactants, e.g., to improve the
compatibility of the treatment fluids of the present invention with
other fluids (like any formation fluids) that may be present in the
well bore. One of ordinary skill in the art with the benefit of
this disclosure will be able to identify the type of surfactant as
well as the appropriate concentration of surfactant to be used.
Suitable surfactants may be used in a liquid or powder form. Where
used, the surfactants may be present in the treatment fluid in an
amount sufficient to prevent incompatibility with formation fluids,
other treatment fluids, or well bore fluids. In an embodiment where
liquid surfactants are used, the surfactants are generally present
in an amount in the range of from about 0.01% to about 5.0% by
volume of the treatment fluid. In one embodiment, the liquid
surfactants are present in an amount in the range of from about
0.1% to about 2.0% by volume of the treatment fluid. In embodiments
where powdered surfactants are used, the surfactants may be present
in an amount in the range of from about 0.001% to about 0.5% by
weight of the treatment fluid.
[0057] In some embodiments, the surfactant may be a viscoelastic
surfactant. These viscoelastic surfactants may be cationic,
anionic, nonionic, amphoteric, or zwitterionic in nature. The
viscoelastic surfactants may comprise any number of different
compounds, including methyl ester sulfonates (e.g., as described in
U.S. Patent Application Nos. 2006/0180310, 2006/0180309,
2006/0183646 and U.S. Pat. No. 7,159,659, the relevant disclosures
of which are incorporated herein by reference), hydrolyzed keratin
(e.g., as described in U.S. Pat. No. 6,547,871, the relevant
disclosure of which is incorporated herein by reference),
sulfosuccinates, taurates, amine oxides, ethoxylated amides,
alkoxylated fatty acids, alkoxylated alcohols (e.g., lauryl alcohol
ethoxylate, ethoxylated nonyl phenol), ethoxylated fatty amines,
ethoxylated alkyl amines (e.g., cocoalkylamine ethoxylate),
betaines, modified betaines, alkylamidobetaines (e.g.,
cocoamidopropyl betaine), quaternary ammonium compounds (e.g.,
trimethyltallowammonium chloride, trimethylcocoammonium chloride),
derivatives thereof, and combinations thereof. In certain
embodiments, the surfactant may comprise a compliant surfactant
such as sodium lauryl sulfate, polyoxyethylene (20) sorbitan
monolaurate (commonly known as Polysorbate 20 or Tween 20),
polysorbate 60 polysorbate 65, polysorbate 80, or sorbitan
monostearate.
[0058] It should be noted that, in some embodiments, it might be
beneficial to add a surfactant to a treatment fluid of the present
invention as that fluid is being pumped down hole to help eliminate
the possibility of foaming. However, in those embodiments where it
is desirable to foam the treatment fluids of the present invention,
surfactants such as HY-CLEAN (HC-2) surface-active suspending agent
or AQF-2 additive, both commercially available from Halliburton
Energy Services, Inc., of Duncan, Okla., may be used. Additional
examples of foaming agents that may be used to foam and stabilize
the treatment fluids of this invention include, but are not limited
to, betaines, amine oxides, methyl ester sulfonates,
alkylamidobetaines such as cocoamidopropyl betaine, alpha-olefin
sulfonate, trimethyltallowammonium chloride, C.sub.8 to C.sub.22
alkylethoxylate sulfate and trimethylcocoammonium chloride. Other
suitable foaming agents and foam stabilizing agents may be included
as well, which will be known to those skilled in the art with the
benefit of this disclosure.
[0059] The methods and treatment fluids of the present invention
may be used during or in preparation for any subterranean operation
wherein a fluid may be used. Suitable subterranean operations may
include, but are not limited to, drilling operations, fracturing
operations, sand control treatments (e.g., gravel packing),
acidizing treatments (e.g., matrix acidizing, fracture acidizing,
removal of filter cakes and fluid loss pills), "frac-pack"
treatments, well bore clean-out treatments, and other suitable
operations where a treatment fluid of the present invention may be
useful. One of ordinary skill in the art, with the benefit of the
present disclosure, will recognize suitable operations in which the
treatment fluids of the present invention may be used.
[0060] In certain embodiments, the present invention provides
methods that include a method comprising: providing a fracturing
fluid comprising an aqueous base fluid, a compliant cellulosic
viscosifying agent, a crosslinking agent, and a protective ligand;
and introducing the fracturing fluid into at least a portion of a
subterranean formation at a rate and pressure sufficient to create
or enhance at least one or more fractures in the subterranean
formation. In these embodiments, a treatment fluid of the present
invention may be pumped into a well bore that penetrates a
subterranean formation at a sufficient hydraulic pressure to create
or enhance one or more cracks, or "fractures," in the subterranean
formation. "Enhancing" one or more fractures in a subterranean
formation, as that term is used herein, is defined to include the
extension or enlargement of one or more natural or previously
created fractures in the subterranean formation. The treatment
fluids of the present invention used in these embodiments
optionally may comprise particulates, often referred to as
"proppant particulates," that may be deposited in the fractures.
The proppant particulates may function, among other things, to
prevent one or more of the fractures from fully closing upon the
release of hydraulic pressure, forming conductive channels through
which fluids may flow to the well bore. Once at least one fracture
is created and the proppant particulates are substantially in
place, the viscosity of the treatment fluid of the present
invention may be reduced (e.g., using a gel breaker, or allowed to
reduce naturally over time) to allow it to be recovered.
[0061] In certain embodiments, the treatment fluids of the present
invention may be used in acidizing and/or acid fracturing
operations. In these embodiments, a portion of the subterranean
formation is contacted with a treatment fluid of the present
invention comprising one or more organic acids (or salts thereof)
and one or more inorganic acids (or salts thereof), which interact
with subterranean formation to form "voids" (e.g., cracks,
fractures, wormholes, etc.) in the formation. After acidization is
completed, the treatment fluid of the present invention (or some
portion thereof) may be recovered to the surface. The remaining
voids in the subterranean formation may, among other things,
enhance the formation's permeability, and/or increase the rate at
which fluids subsequently may be produced from the formation. In
certain embodiments, a treatment fluid of the present invention may
be introduced into the subterranean formation at or above a
pressure sufficient to create or enhance one or more fractures
within the subterranean formation. In other embodiments, a
treatment fluid of the present invention may be introduced into the
subterranean formation below a pressure sufficient to create or
enhance one or more fractures within the subterranean
formation.
[0062] To facilitate a better understanding of the present
invention, the following examples of the preferred embodiments are
given. In no way should the following examples be read to limit, or
define, the scope of the invention.
EXAMPLES
[0063] The following examples are submitted for the purpose of
demonstrating the performance characteristics of the treatment
fluids of the present invention.
Example 1
[0064] In these examples, the viscosity of a treatment fluid that
did not contain a protective ligand was obtained to provide a
reference point for comparison. The viscosity of treatment fluids
containing 40 lb/Mgal, 60 lb/Mgal, and 120 lb/Mgal of
carboxymethylcellulose (CMC) was measured. The treatment fluids
containing 60 lb/Mgal of CMC were prepared by adding 720 mg of
sodium CMC to 100 mL of DI water in a blender at low speed and left
to hydrate for 30 minutes to form a hydrated base gel. The amount
of CMC added varied according to the final concentration of CMC
desired. To the hydrated base gel was added 2 grams of KCl either
in solid form or by dissolving in a minimum amount of water. The
base gel was mixed to distribute the salt uniformly thought the
mixture. Then the gel stabilizer (GEL-STA) was added to the base
gel followed by addition of an appropriate amount of breaker when
desired. Samples were aged for 1 hr before any measurement was
taken.
[0065] The viscosity of the samples was measured using a Chandler
viscometer with a B5X Bob at shear rate of 40 sec.sup.-1. A 44 mL
sample of gelled fluid was transferred to the viscometer cup at
75.degree. F. and placed on the viscometer. The temperature was
ramped to 180.degree. F. in 20 minutes. For the test at 250.degree.
F., the temperature was ramped to 250.degree. F. in 30 minutes and
maintained for 3 hours. FIGS. 2 and 3 plot the viscosity curves as
a function of time for the zirconium crosslinked CMC fluids at
various temperatures between 180.degree. F. and 250.degree. F. The
viscosity of each sample was measured at a constant shear rate.
Both FIGS. 1 and 2 show that the treatment fluids of the present
invention are stable at high temperatures. After an initial
thinning of the crosslinked gel, the viscosity of the gel remained
virtually steady for 3 hours at the lower temperatures and 1.5
hours at the higher temperatures.
[0066] To be useful for various oil field applications the CMC base
gel must be stable to various conditions of temperature and pH
encountered in the down hole conditions. Therefore 120 lb/Mgal CMC
base gel was prepared and tested at different pH and temperature
ranges to establish the robustness of the polymer chain. The tests
were run in Chandler viscometer as discussed above. The results are
shown in FIG. 1 and indicated that the base gel degraded gradually
in acidic condition but found to be very stable in the neutral to
basic conditions.
[0067] FIGS. 16 and 17 show the viscosity plots for treatment
fluids having 60 lb/Mgal of CMC crosslinked with aluminum only or
crosslinked with an crosslinking agent and a protective ligand
complex comprising a 1:4 ratio of aluminum to lactic acid. The
protective ligand provides increased stability for the treatment
fluids, especially at temperatures above 200.degree. F. FIG. 18
shows the shear stability profile of CMC/A1 crosslinked system at
180.degree. F.
Example 2
[0068] It has been found during this study that a thickened
solution of sodium CMC can be prepared by first hydrating the
polymer in fresh water followed by the addition of the required
amount of salt either as solid or in solution form. Once hydrated
the addition of salt has minimal effect on the viscosity of the
base gel as shown in Table 2. The viscosity of CMC in high
concentration brines was high enough to be useful for a variety of
oil field applications. When CMC was added directly to a brine
solution it did not hydrate quickly and the final viscosity did not
reach the level reached when the base gel was prepared by the
method of described herein. This problem was even more severe for
concentrated brines (10% NaCl) or for higher valent salts (e.g.
CaCl.sub.2). "ClayFix II" refers to a temporary clay-stabilization
additive commercially available from Halliburton Energy Services,
Inc. of Duncan Okla.
TABLE-US-00001 TABLE 1 Rheology of 40 lb/Mgal CMC in water and salt
solution Salt Fann 35 Dial reading @ rpm Base Fluid (g/100 mL
water) 600 300 200 100 6 Deionized Water None 77.0 56.0 45.5 31.0
5.0 Tap water None 65.0 45.5 36.0 24.0 4.0 Deionized Water 1 g KCl
52.0 36.0 27.5 18.0 3.0 Deionized Water 2 g KCl 50.0 34.0 26.5 17.5
2.5 Deionized Water 2 g CaCl.sub.2 48.0 33.0 26.0 17.0 2.5
Deionized Water 11.1 g NaCl 53.0 36.0 28.0 18.0 3.0 Deionized Water
0.2 g of ClayFix II 63.0 44.5 35.5 24.5 4.0 Deionized Water API
Standard Brine Solution (10 g 51.5 35.0 27.0 17.5 2.5 NaCl &
1.1 g CaCl.sub.2) Deionized Water 7.5g NaCl; 0.82 g CaCl.sub.2;
0.385 g MgCl.sub.2 6H.sub.2O 52.0 35.5 27.5 18.0 3.0
Example 3
[0069] Some treatment fluids were crosslinked with 3 gal/Mgal of a
crosslinker with and without 1:4 ratio of crosslinker
(A1):protective ligand (lactic acid). The CMC base gel prepared in
brine solution was crosslinked with polyvalent metal ions of
zirconium and aluminum. The zirconium-based crosslinker, such as
CL-23 commercially available from Halliburton Energy Services, Inc.
of Duncan, Okla., gave the best result in term of viscosity and
stability. CL-23 formed stable gels with CMC in the pH range of 4
to 8 and more specifically in the range of 5 to 6.5. It was
critical to keep the pH in this narrow range for optimum
crosslinked viscosity. The crosslinked gels obtained from CL-23 and
CMC fluid were much more stable at high temperature (250.degree.
F.) if the fluid is aged at room temperature for 1 hr. This
increased stability may be due to the additional crosslinking
between zirconium and carboxyl groups present in the CMC based
fluid. The crosslinked fluids were tested on a Chandler viscometer
for the gel stability at various temperatures. After an initial
thermal thinning of the crosslinked gel the viscosity of the gels
remained virtually steady for more than 3 hours at temperature of
180.degree. F. and 225.degree. F. At 250.degree. F., the
crosslinked gel viscosity remained higher than 500 cP at 40
sec.sup.-1 for only 1.5 hours. Addition of gel stabilizer such as
GEL-STA commercially available from Halliburton Energy Services,
Inc. of Duncan, Okla. or purging with nitrogen gas improved the
thermal stability of the gel at high temperature as seen in FIG. 4.
This may be explained by the exclusion of oxygen from the base gel,
which otherwise oxidizes the polymer. Thermal stability was also
improved by aging the crosslinked gel overnight presumably by
increasing the number of crosslinking sites. Best viscosity was
obtained by using 60 lb/Mgal CMC gel in distilled water crosslinked
with 3 gal/Mgal of CL-23 at pH 5.9 in 2% KCl.
Example 4
[0070] The control of pH played an important role in the
crosslinking and stability of the CMC gel. The pH of the CMC gel
was adjusted with either diluted HCl or an ammonium acetate buffer
solution, such as BA-20 commercially available from Halliburton
Energy Services, Inc. of Duncan, Okla. If the amount of BA-20 added
is greater than 2 gal/Mgal then the viscosity of the final gel is
lower. This may be due to the competition for zirconium ions
between carboxylic group present in CMC and the acetic acid present
in the BA-20. However, when added in small amount (<1 gal/Mgal)
BA-20 did not effect the final viscosity as shown in FIG. 5. The
sequence of gel preparation follows the following steps: First CMC
was hydrated in Duncan tap water followed by addition of KCl, then
CL-23 and finally pH was adjusted by addition of HCl or BA-20.
Example 5
[0071] The CMC base gel tends to crosslink immediately on addition
of CL-23, as shown in previous figures. FIG. 6 shows the delay in
crosslinking caused by the addition of lactic acid. The lactic acid
prevents the crosslinking at lower temperature and when temperature
reaches 130.degree. F. the rate of crosslinking increases and leads
to a sudden rise in the viscosity of the fluid. The delayed
crosslinking can be tailored by controlling the amount of the
delaying agent, in this case lactic acid, used in the system.
Example 6
[0072] The metal ion crosslinked CMC gels could be easily broken
down by traditional oxidizer breakers such as persulfates and
t-butylhydroperoxide (HT Breaker) to afford clear solution without
any trace of insoluble materials. The results are shown in FIG. 7.
The absence of insoluble materials in the broken fluid was
important because these insoluble materials can plug the formation
and thereby reduce the permeability of the formation. Reduced
permeability leads to impaired conductivity and reduced rate of oil
production. The Optiflo III and HT breaker, both commercially
available from Halliburton Energy Services, Inc., of Duncan, Okla.,
at temperature of 180-200.degree. F. delay the breaking of gel for
about 2 hours before the viscosity of crosslinked fluid goes below
500 cP.
Example 7
[0073] The conductivity of the treatment fluids was tested on
samples containing 60 lb/Mgal CMC gel crosslinked with 3 gal/Mgal
of CL-23. The gel also contained 2% KCl and the pH was adjusted to
a narrow range of 5-6.5 with BA-20. Two set of tests were run by
adding 4 gal/Mgal and 8 gal/Mgal of HT breaker commercially
available from Halliburton Services, Inc. of Duncan, Okla. to the
crosslinked fluid at 200.degree. F. 2 lb/ft.sup.2 of 30/50 mesh
proppants (ECONOPROP available from CarboCeramics, Inc. of Irving,
Tex.) were used in the cell at 6000 and 8000 psi closure pressure
for the test. The results are shown in Table 2, each of the tested
fluids contained 60 lb/Mgal of a CMC viscosifying agent and 3
gal/Mgal of a zirconium crosslinker (CL-23, commercially available
from Halliburton Energy Services, Inc. in Duncan, Okla.) in an Ohio
Sandstone core.
TABLE-US-00002 TABLE 2 Conductivity test of CMC based crosslinked
treatment fluids Conduc- Regain Temp Stress Baseline tivity Perme-
Proppant Breaker (.degree. F.) (psi) (mD-ft) (MD-ft) ability 2
lb/ft.sup.2 30/50 4 gpt HT 200 6000 2730 1147 42% EconoProp breaker
2 lb/ft.sup.2 30/50 4 gpt HT 200 8000 1810 687 38% EconoProp
breaker 2 lb/ft.sup.2 30/50 8 gpt HT 200 6000 2730 1236 45%
EconoProp breaker 2 lb/ft.sup.2 30/50 8 gpt HT 200 8000 1810 769
42% EconoProp breaker
Example 8
[0074] Dynamic moduli were measured as a function of frequency, and
the behavior of the storage (G') and loss (G'') moduli of the 40
lb/Mgal CMC gel crosslinked with 4 gal/Mgal of CL-23 tested at
120.degree. C. are shown in FIG. 8. The experimental results show
one distinct trend of the moduli with respect to the frequency
region. Gel-like behavior was observed, where the G' is greater
than the G'' and both moduli exhibit their independency to
frequency. Also, over the frequency range tested, G' displays a
characteristic plateau G'.sub.P region. The G'.sub.P behavior is
typical of a "strong gel" material that is observed when the
characteristic relaxation time of the material is longer than the
process time, that is, time per cycle of oscillation.
[0075] The isothermal cure of the crosslinking system was followed
by a dynamic time sweep, where the moduli G' and G'' were monitored
as a function of cure time at constant frequency. The G' versus
time curve was then fitted to an empirical kinetic model such that
suggested by Hsich. The ultimate modulus reached on cure was
obtained from this experiment. However, it was shown that a single
time sweep at a constant frequency is not sufficient for accurate
determination of the gel time. The gel point (GP) of a crosslinking
polymer is an important parameter, both from scientific and
technological standpoints. Therefore, the evolution of tan .delta.
with cure time was measured at different frequencies. The various
curves coincide at a single point, corresponding to the GP. The
dynamic moduli were obtained at different frequencies as
crosslinking progressed using multiple waveform rheology where a
compound waveform was applied on the sample. From the results of
the mulitwave experiment, the GP was detected by the criteria
mentioned above. Simultaneously, data for G' and G'' as a function
of curing time was extracted, for use in an appropriate kinetic
model. The objective of this work was to characterize the cure of
CMC crosslinking by Zr at room temperature, and effects of elastic
and viscous properties on proppant transport under static and
dynamic (applied shear rate).
[0076] Rheological studies were conducted on an Anton-Parr
controlled Strain/stress rheometer (MCR501) using 50 mm with
2.degree. cone angle. The time for loading the sample was kept to a
minimum so as to reduce the lag time for crosslinking. The
multiwave experiment was run with a fundamental frequency of 1
rad.s.sup.-1 (.omega..sub.k) and the strains (.epsilon..sub.i) were
kept at 0.1% at each harmonic. A total of six waveforms were added
to create the composite strain input, with the frequency ranging
from 0.1 to 40 rad.s.sup.-1. The instrument software had the
capability to automatically perform the Fourier transformation of
the raw data.
[0077] The multiwave technique generated frequency sweeps from 0.1
to 10 rad.s.sup.-1, as the sample cures. For isothermal cure at
25.degree. C., the evolution of microstructure with time is shown
in terms of the frequency sweep as shown in FIG. 9. It was observed
that the G' increases in magnitude and becomes increasingly
independent of frequency as the crosslinking progresses.
Correspondingly, the level of G'' dropped steadily with cure time.
These observations indicated that the sample develops a
predominantly elastic character and simultaneously lost its viscous
characteristics. Qualitatively, the above behavior of the storage
and loss moduli with cure time (shown in FIG. 10) was typical of
many thermosetting systems. The validity of the data obtained was
verified using the multiwave technique by comparing it with
continuous time sweep conducted at the same temperature. A time
sweep performed at 1 rad.s.sup.-1 frequency and 0.1% strain shows
excellent overlap with data from the multiwave experiment,
corresponding to the same frequency as shown in FIG. 10. The
experiment results reveal that the crosslinked CMC with Zr sample
has predominantly elastic character over the entire curing time,
and reaches reach its gel stage after 3 hour of curing process at
25.degree. C.
Example 9
[0078] Suspending ability of the invented fluid under a given
imposed shear condition was directly determined using the developed
flow through device as described in Patent Application Publication
No. 2010/0018294 and incorporated by reference herein. The settling
profile was obtained from a standard CCD camera (resolution
1024.times.1000 pixels) captured at different time interval using a
proprietary particle-interface software that operates on
MATLAB.RTM. software and the ImageJ image processing package. The
one dimension settling velocity fields (v.sub.yz) of the settling
interface was calculated by cross-correlating corresponding
intensity region in two successive images to determine the settling
interface between proppant and crosslinked fluid.
[0079] FIG. 11 shows a typical proppant suspending characteristic
of 40 lb/Mgal CMC gel crosslinked with 2 gal/Mgal of CL-23 tested
under static, defined as zero-imposed shear rate, condition. The
sample was aged for 1 hour prior to taking any of the measurements.
FIG. 12 shows the settling profile analysis of the system using the
proprietary particle interface software. The result reveals that
crosslinked fluid supported the proppant particle for over the
tested period. Analysis of the relationship between settling
interface with processing time revealed that the settling velocity
of proppant equaled to 0 cm/min. This might implies that under
static settling conditions, the invented fluid achieved a perfect
suspending characteristic. However, settling of proppant particles
was observed under dynamic settling condition, defined as there is
an imposed shear rate onto the material, as shown in FIGS. 14 and
15.
[0080] FIGS. 13 and 14 show typical settling characteristics of
proppant in 40 lb/Mgal CMC gel crosslinked with 4 gal/Mgal of CL-23
under dynamic settling, defined as having a shear rate directly
imposed on to the sample while measuring proppant-settling profile.
In this experiment, the dynamic settling was performed with an
imposed shear rate of 20 s.sup.-1 condition. The dynamic settling
experiments were conducted at two different curing times, 1 hour
and 3 hour of curing processes. This is to investigate effect of
elastic and gel structure on proppant suspending ability.
Dissimilarity in suspending ability of the CMC-Zr crosslinked
sample were observed in FIGS. 14 and 15, indicating the
significance of curing time on proppant support ability of the
system. The proppant settled within 90 minutes of shearing process
for the sample being cured for 1 hour and shown in FIG. 14, while
the sample developed a geater suspendability when it was aged for 3
hours prior to commence the settling experiment as shown in FIG.
15. Qualitatively, the settling behavior as a function of curing
time indicated the significance of the crosslinking behavior as a
function of time on proppant support ability. As the cure time
progressed, the material became more dominant in its elastic
character and lost its viscous characteristics.
[0081] Therefore, the present invention is well adapted to attain
the ends and advantages mentioned as well as those that are
inherent therein. The particular embodiments disclosed above are
illustrative only, as the present invention may be modified and
practiced in different but equivalent manners apparent to those
skilled in the art having the benefit of the teachings herein.
Furthermore, no limitations are intended to the details of
construction or design herein shown, other than as described in the
claims below. It is therefore evident that the particular
illustrative embodiments disclosed above may be altered or modified
and all such variations are considered within the scope and spirit
of the present invention. 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 hereby 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.
* * * * *