U.S. patent application number 11/698615 was filed with the patent office on 2007-05-31 for recyclable foamed fracturing fluids and methods of using the same.
This patent application is currently assigned to Halliburton Energy Services, Inc.. Invention is credited to Jiten Chatterji, Bobby J. King, Karen L. King.
Application Number | 20070123429 11/698615 |
Document ID | / |
Family ID | 33130395 |
Filed Date | 2007-05-31 |
United States Patent
Application |
20070123429 |
Kind Code |
A1 |
Chatterji; Jiten ; et
al. |
May 31, 2007 |
Recyclable foamed fracturing fluids and methods of using the
same
Abstract
Fracturing fluids and methods of fracturing a subterranean
formation using such fluids are provided. A fracturing fluid having
a first pH is foamed by introducing a gas to the fluid. The
fracturing fluid comprises a surfactant that facilitates formation
of the foam at the first pH. The foamed fracturing fluid is
subsequently pumped to the subterranean formation to fracture it.
The pH of the fracturing fluid is then changed to a second pH at
which the surfactant facilitates reduction of the foam. The
fracturing fluid releases proppant contained in the fluid to the
subterranean formation. The fracturing fluid is then allowed to
flow back to the surface. It can be recycled by changing the pH of
the fracturing fluid back to the first pH and adding a gas to the
fluid, causing it to foam again.
Inventors: |
Chatterji; Jiten; (Duncan,
OK) ; King; Bobby J.; (Duncan, OK) ; King;
Karen L.; (Duncan, OK) |
Correspondence
Address: |
Halliburton Energy Services, Inc.
2600 S. 2nd Street
Duncan
OK
73536-0440
US
|
Assignee: |
Halliburton Energy Services,
Inc.
|
Family ID: |
33130395 |
Appl. No.: |
11/698615 |
Filed: |
January 26, 2007 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
10956928 |
Oct 1, 2004 |
7205263 |
|
|
11698615 |
Jan 26, 2007 |
|
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10396606 |
Mar 25, 2003 |
6986392 |
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10956928 |
Oct 1, 2004 |
|
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Current U.S.
Class: |
507/129 ;
507/131 |
Current CPC
Class: |
C09K 8/703 20130101;
Y10S 507/922 20130101 |
Class at
Publication: |
507/129 ;
507/131 |
International
Class: |
C09K 8/00 20060101
C09K008/00 |
Claims
1. A foamed fracturing fluid, comprising: water; proppant; a gas
dispersed in the water; and a tertiary alkyl amine ethoxylate for
facilitating the formation of foam at a basic pH and facilitating
the reduction of foam at an acidic pH, wherein the foamed
fracturing fluid has the basic pH, wherein the tertiary alkyl amine
ethoxylate is represented by the following formula: ##STR2##
wherein R is an alkyl group, X is from about 2 to about 15, and Y
is from about 2 to about 15.
2. The foamed fracturing fluid of claim 1, wherein X is from about
10 to about 15, and Y is from about 10 to about 15.
3. The foamed fracturing fluid of claim 1, wherein the basic pH is
greater than about 9, and the acidic pH is less than about 6.
4. The foamed fracturing fluid of claim 1, wherein the fracturing
fluid comprises a gelling agent.
5. The foamed fracturing fluid of claim 1, wherein the foamed
fracturing fluid comprises a delayed release acid in an amount
sufficient to lower the pH of the foamed fracturing fluid from the
basic pH to less than about 6 when acid is released.
6. The foamed fracturing fluid of claim 5, wherein the delayed
release acid is selected from the group consisting of an
encapsulated acid and an acid producing compound.
7. The foamed fracturing fluid of claim 1, wherein the delayed
release acid comprises a compound selected from the group
consisting of an encapsulated formic acid, an encapsulated citric
acid, an encapsulated fumaric acid, an encapsulated mineral acid,
an ethyl acetate, and an ethyl formate.
8. A foamed fracturing fluid, comprising: water; proppant; a gas
dispersed in the water; a base in an amount sufficient to provide
the foamed fracturing fluid with a basic pH; a delayed-release acid
in an amount sufficient to lower the pH of the foamed fracturing
fluid from the basic pH to an acidic pH when acid is released; and
a surfactant mixture for facilitating the formation of foam at the
basic pH and facilitating the reduction of foam at the acidic pH,
the surfactant mixture comprising an amphoteric surfactant and an
anionic surfactant.
9. The foamed fracturing fluid of claim 8, wherein the amphoteric
compound comprises at least one surfactant selected from the group
consisting of a lauryl amine oxide, a myristyl amine oxide, a
cocoamine oxide, a lauryl betaine, and an oleyl betaine.
10. The foamed fracturing fluid of claim 8, wherein the anionic
surfactant comprises at least one surfactant selected from the
group consisting of a C.sub.4-12 alcohol ether sulfate, an
.alpha.-olefin sulfonate, a sulfonated C.sub.15 alcohol substituted
with ethylene oxide, a sodium laureth-2-sulfate, and a
laureth-3-sulfate.
11. The foamed fracturing fluid of claim 8, wherein the anionic
surfactant comprises a sulfonated C.sub.15 alcohol substituted with
from about 12 to about 40 moles of ethylene oxide.
12. The foamed fracturing fluid of claim 8, wherein the amphoteric
surfactant is present in the surfactant mixture in an amount in the
range of from about 32% to about 45% by weight of the surfactant
mixture, and the anionic surfactant is present in the surfactant
mixture in an amount in the range of from about 55% to about 68% by
weight of the surfactant mixture.
13. The foamed fracturing fluid of claim 8, wherein basic pH is
greater than about 9, and the acidic pH is less than about 6.
14. The foamed fracturing fluid of claim 8, wherein the delayed
release acid is selected from the group consisting of an
encapsulated acid and an acid producing compound.
15. The foamed fracturing fluid if claim 8, wherein the delayed
release acid comprises a compound selected from the group
consisting of an encapsulated formic acid, an encapsulated citric
acid, an encapsulated fumaric acid, an encapsulated mineral acid,
an ethyl acetate, and an ethyl formate.
16. The foamed fracturing fluid of claim 8, wherein the fracturing
fluid comprises a gelling agent.
17. The foamed fracturing fluid of claim 8, wherein the fracturing
fluid comprises a bacteriacide.
18. A foamed fracturing fluid, comprising: water; proppant; a gas
dispersed in the water; an acid in an amount sufficient to provide
the foamed fracturing fluid with a pH of less than about 6; a
delayed release base in an amount sufficient to raise the pH of the
foamed fracturing fluid from the pH of below about 6 to a basic pH;
and a surfactant mixture for facilitating the formation of foam at
the pH of below about 6 and facilitating the reduction of foam at
the basic pH, the surfactant mixture comprising an amphoteric
surfactant and a cationic surfactant.
19. The foamed fracturing fluid of claim 18, wherein the cationic
compound comprises at least one surfactant selected from the group
consisting of cocoalkyltriethyl ammonium chloride and
hexadecyltrimethyl ammonium chloride.
20. The foamed fracturing fluid of claim 18, wherein the amphoteric
compound comprises at least one surfactant selected from the group
consisting of a lauryl amine oxide, a myristyl amine oxide, a
cocoamine oxide, a lauryl betaine, and an oleyl betaine.
21. The foamed fracturing fluid of claim 18, wherein the amphoteric
surfactant is present in the surfactant mixture in an amount in the
range of from about 30% to about 40% by weight of the surfactant
mixture, and the cationic surfactant is present in the surfactant
mixture in an amount in the range of from about 60% to about 70% by
weight of the surfactant mixture.
22. The foamed fracturing fluid of claim 18, wherein the basic pH
is greater than about 9.
23. The foamed fracturing fluid of claim 18, wherein the foamed
fracturing fluid comprises a gelling agent.
24. The foamed fracturing fluid of claim 18, wherein the foamed
fracturing fluid comprises a bacteriacide.
25. The foamed fracturing fluid of claim 18, wherein the acid is
selected from the group consisting of an acetic acid, a formic
acid, and a mineral acid.
26. The foamed fracturing fluid of claim 18, wherein the delayed
release base is selected from the group consisting of an
encapsulated base and a base producing compound.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application is a Continuation Application of U.S.
application Ser. No. 10/956,928, filed Oct. 1, 2004, which is a
Divisional Application of U.S. patent application Ser. No.
10/396,606, filed Mar. 25, 2003, now U.S. Pat. No. 6,986,392, each
of which is incorporated by reference herein in its entirety.
FIELD OF THE INVENTION
[0002] This invention generally relates to fracturing fluids and
methods for their use in fracturing subterranean formations. More
specifically, the invention relates to recyclable foamed fracturing
fluids that can be used more than once to fracture a subterranean
formation without replenishing the components in the fluids.
BACKGROUND OF THE INVENTION
[0003] Natural resources such as gas, oil, minerals, and water
residing in a subterranean formation can be recovered by drilling
wells into the formation. The fluids in the subterranean formation
are driven into the wells by, for example, pressure gradients that
exist between the formation and the wells, the force of gravity,
displacement of the fluids using pumps or the force of another
fluid injected into the wells. The production of such fluids is
commonly increased by hydraulically fracturing the subterranean
formations. That is, a viscous fracturing fluid is pumped into a
well to a subterranean formation at a rate and a pressure
sufficient to form fractures that extend into the formation,
providing additional pathways through which the fluids can flow to
the wells.
[0004] Particulate matter known as a proppant, e.g., graded sand,
bauxite, or resin coated sand, is dispersed throughout the
fracturing fluid. The proppant is suspended in the fracturing fluid
such that it is deposited into the fractures created by the
pressure exerted on the fracturing fluid. The presence of the
proppant in the fractures holds the fractures open after the
pressure exerted on the fracturing fluid has been released.
Otherwise, the fractures would close, rendering the fracturing
operation useless. Ideally, the proppant has sufficient compressive
strength to resist crushing.
[0005] The fracturing fluid is usually a water-based fluid
containing a gelling additive to increase the viscosity of the
fluid. The gelling additive thus reduces leakage of liquid from the
fractures into the subterranean formation and improves proppant
suspension capability. The gelling additive is commonly a polymeric
material that absorbs water and forms a gel as it undergoes
hydration. A foaming surfactant is added to the fracturing fluid. A
gas is mixed with the fracturing fluid to produce a foamed
fracturing fluid, thus ensuring that the pressure exerted by the
fracturing fluid on the subterranean formation exceeds the fracture
gradient (psi/ft.) to create the fracture. The surfactant
facilitates the foaming and stabilization of the foam produced when
the gas is mixed with the fracturing fluid.
[0006] After a fracturing fluid has been used to form fractures in
a subterranean formation, it is usually returned to the surface. It
would be desirable to have the ability to recycle the fracturing
fluid to form additional fractures in the same subterranean
formation or to form fractures in one or more different
subterranean formations. However, conventional fracturing fluids
are not suitable for recycling. A need therefore exists for a
fracturing fluid that can be recycled several times to fracture one
or more subterranean formations.
SUMMARY OF THE INVENTION
[0007] According to an embodiment, methods of fracturing
subterranean formations include providing a fracturing fluid having
a first pH, followed by foaming the fracturing fluid by introducing
a gas to the fluid. The fracturing fluid comprises a surfactant
that facilitates formation of the foam at the first pH, which can
be acidic or basic depending on the type of surfactant used. The
foamed fracturing fluid is subsequently pumped to the subterranean
formation to fracture it. The pH of the fracturing fluid is then
changed to a second pH at which the surfactant facilitates
reduction of the foam, thereby defoaming the fracturing fluid. The
nature of the second pH (i.e., acidic or basic), is opposite that
of the first pH. The fracturing fluid releases proppant contained
in the fluid to the subterranean formation. The fracturing fluid is
then allowed to flow back to the surface. It can be recycled to the
same or a different subterranean formation by changing the pH of
the fracturing fluid back to the first pH and adding a gas to the
fluid, causing it to foam again. Preferably, the fracturing fluid
can be re-foamed multiple times in this manner with minimal or no
additional amounts of gelling additive or surfactant being added to
the fracturing fluid beyond the amounts, if any, initially present
in the fracturing fluid.
[0008] In an embodiment, fracturing fluids include a surfactant
capable of allowing the fluids to be foamed at a first pH and
defoamed at a second pH. The surfactant may be a tertiary alkyl
amine ethoxylate, which is a cationic compound, or it may be a
mixture of an amphoteric compound and an anionic compound. In this
case, the first pH at which the fracturing fluid can be foamed is
greater than about 9, and the second pH at which the fluid can be
defoamed is less than about 6. Alternatively, the surfactant may
comprise a mixture of an amphoteric compound and a cationic
compound such that the first pH at which the fracturing fluid can
be foamed is less than about 6 and the second pH at which the fluid
can be defoamed is greater than about 9.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
[0009] According to some embodiments, fracturing fluids for
fracturing a subterranean formation comprise water, surfactants,
gelling additives, and proppants, wherein the surfactants enable
the fracturing fluids to be foamed at a first pH and defoamed at a
second pH. A foamed fracturing fluid is herein defined as a
fracturing fluid that contains gas dispersed in a liquid, wherein
the volume of gas depends on the quality of the foam, which is
directly proportional to the half-life of the foam. The fracturing
fluid can be foamed and defoamed by simply changing its pH and thus
does not require the addition of a gelling agent breaker such as an
enzyme or an oxidizing agent to defoam the fluid. Otherwise, the
breaker could degrade the gelling additive. In the absence of the
breaker, the fracturing fluid can be recycled multiple times for
use in fracturing one or more subterranean formations without
having to replenish the gelling additive and the surfactant.
[0010] The particular pH at which the fracturing fluid can be
foamed by the addition of a gas and the particular pH at which it
undergoes defoaming depend on the nature of the surfactant. Without
being limited by theory, it is believed that the surfactant
facilitates the formation of foam when the fracturing fluid is at a
first pH by reducing the surface tension between the gas and the
liquid therein, thus promoting and stabilizing the gas-liquid
dispersion. On the other hand, the surfactant facilitates reduction
of the foam when the fluid is changed to a second pH. It is further
theorized that at the second pH, the fracturing fluid does not have
the ability to reduce the surface tension between the gas and the
liquid.
[0011] One suitable surfactant that may be used in the fracturing
fluid is a tertiary alkyl amine ethoxylate (a cationic surfactant).
The tertiary alkyl amine may be changed from a foaming surfactant
(i.e., a surfactant that facilitates foaming of the fracturing
fluid) to a defoaming surfactant (i.e., a surfactant that
facilitates defoaming of the fracturing fluid) by the addition of a
hydrogen ion. It may then be changed back to a foaming surfactant
by the addition of a hydroxide ion. The following formula
represents the ability of tertiary alkyl amine to be changed from a
foaming surfactant to a defoaming surfactant: ##STR1## where R is
an alkyl group and X and Y vary from about 2 to about 15 moles of
ethylene oxide, preferably from about 10 to about 15 moles of
ethylene oxide. Triton RW-100 surfactant (X and Y=10 moles of
ethylene oxide) and Triton RW-150 surfactant (X and Y=15 moles of
ethylene oxide) are examples of tertiary alkyl amine ethoxylates
that may be purchased from Dow Chemical Company. For the tertiary
alkyl amine ethoxylate surfactant, the first pH at which the
fracturing fluid foams when a gas is added thereto is greater than
about 9. Also, the second pH at which the fracturing fluid defoams
is less than about 6.
[0012] In another embodiment, the fracturing fluid comprises an
amphoteric surfactant and an anionic surfactant. The relative
amounts of the amphoteric surfactant and the anionic surfactant in
the surfactant mixture are from about 32 to about 45% by weight of
the surfactant mixture and from about 55 to about 68% by weight of
the surfactant mixture, respectively. As used throughout the
specification, "%" represents "percent." The amphoteric surfactant
may be lauryl amine oxide, a mixture of lauryl amine oxide and
myristyl amine oxide (i.e., a lauryl/myristyl amine oxide),
cocoamine oxide, lauryl betaine, oleyl betaine, or combinations
thereof, with the lauryl/myristyl amine oxide being preferred. Such
amine oxides are generally represented by the formula:
R--N.sup.+O.sup.- where R is C.sub.12 (lauryl), C.sub.12-14
(lauryl/myristyl), or C.sub.8-12 (coca). Further, such betaines are
generally represented by the formula:
R--N.sup.+--CH.sub.2--CH.sub.2--COO.sup.- where R is C.sub.12
(lauryl) or C.sub.18 (oleyl). Such amine oxides and betaines are
commercially available from Chemron, a Lubrizol Co., of Paso
Robles, Calif. The anionic surfactant may be C.sub.4-12 alcohol
ether sulfate, .alpha.-olefin sulfonate, sulfonated C.sub.15
alcohol substituted with from about 12 to about 40 moles of
ethylene oxide, sodium laureth-2-sulfate, laureth-3-sulfate, and
combinations thereof, e.g., C.sub.4-12 alcohol ether sulfate
containing 1.5 to 3 moles of ethylene oxide combined with the
.alpha.-olefin sulfonate (C.sub.12-14[OH]SO.sub.3.sup.-Na.sup.+),
with the alcohol ether sulfate and the .alpha.-olefin sulfonate
being preferred. When an amphoteric surfactant and an anionic
surfactant are used in the fracturing fluid, the first pH at which
the fracturing fluid foams when a gas is added thereto is greater
than about 9. Also, the second pH at which the fracturing fluid
defoams is less than about 6.
[0013] In yet another embodiment, the fracturing fluid comprises an
amphoteric surfactant and a cationic surfactant. The relative
amounts of the amphoteric surfactant and the cationic surfactant in
the surfactant mixture are from about 30 to about 40% by weight of
the surfactant mixture and from about 60 to about 70% by weight of
the surfactant mixture, respectively. The amphoteric surfactant may
be at least one of the amphoteric surfactants mentioned above,
i.e., lauryl amine oxide, a mixture of lauryl amine oxide and
myristyl amine oxide (i.e., a lauryl/myristyl amine oxide),
cocoamine oxide, lauryl betaine, and oleyl betaine, with the
lauryl/myristyl amine oxide being preferred. The cationic
surfactant may be cocoalkyltriethyl ammonium chloride,
hexadecyltrimethyl ammonium chloride, or combinations thereof, with
a 50/50 mixture by weight of the cocoalkyltriethyl ammonium
chloride and the hexadecyltrimethyl ammonium chloride being
preferred. In this case, the first pH at which the fracturing fluid
foams is less than about 6, and the second pH at which the
fracturing fluid defoams is greater than about 9.
[0014] The fracturing fluid is preferably a water-based composition
having a balance of water after taking other components of the
fracturing fluid into account. The fracturing fluid may contain
fresh water or salt water, e.g., brines and seawater. The amount of
surfactant present in the water preferably ranges from about 0.5 to
about 2.0% by weight of the water. The particular amount of the
surfactant used in the fracturing fluid depends on the required
degree of foam stability, which is directly proportional to the
half-life of the foam.
[0015] In addition, the fracturing fluid includes a gelling
additive, also known as a gelling agent or a viscosifying agent. As
used herein, gelling additive refers to a material capable of
forming the fracturing fluid into a gel, thereby increasing its
viscosity. The amount of the gelling additive present in the
fracturing fluid preferably ranges from about 0.125 to about 0.375%
by weight of the water. Examples of suitable gelling additives
include, but are not limited to, natural or derivatized
polysaccharides that are soluble, dispersible, or swellable in an
aqueous liquid, modified celluloses and derivatives thereof, and
biopolymers. Examples of polysaccharides include: galactomannan
gums such as gum ghatti, gum karaya, tamarind gum, tragacanth gum,
guar gum, and locust bean gum; modified gums such as carboxyalkyl
derivatives, e.g., carboxymethylguar, and hydroxyalkyl derivatives,
e.g., hydroxypropylguar; and doubly derivatized gums such as
carboxymethylhydroxypropylguar. Examples of water-soluble cellulose
ethers include carboxymethylcellulose, hydroxyethylcellulose,
methylhydroxypropyl-cellulose, and
carboxymethylhydroxyethylcelluose. Examples of biopolymers include
xanthan gum and welan gum.
[0016] Examples of other suitable gelling additives include, but
are not limited to, water dispersible hydrophillic organic polymers
having molecular weights ranging from about 1 to about 10,000,000
such as polyacrylamide and polymethacrylamide, wherein about 5% to
about 7.5% are hydrolyzed to carboxyl groups and a copolymer of
about 5% to about 70% by weight acrylic acid or methacrylic acid
copolymerized with acrylamide or methacrylamide.
[0017] Examples of still more suitable gelling additives include,
but are not limited to, water soluble polymers such as a terpolymer
of an ethylenically unsaturated polar monomer, an ethylenically
unsaturated ester, and a monomer selected from
acrylamido-2-methylpropane sulfonic (AMPS) acid or
N-vinylpyrrolidone; and a terpolymer of an ethylenically
unsaturated polar monomer, an ethylenically unsaturated ester, AMPS
acid, and N-vinylpyrrolidone. Other suitable gelling additives are
polymerizable water soluble monomers, such as acrylic acid,
methacrylic acid, acrylamide, and methacrylamide.
[0018] Of the foregoing gelling additives, galactomannans,
cellulose derivatives, and biopolymers are preferred. Preferred
galactomannans are guar, hydroxypropylguar, and
carboxymethylhydroxypropylguar. Preferred cellulose derivatives are
hydroxyethylcellulose, carboxymethylhydroxyethylcellulose, and
hydroxyethylcellulose grafted with vinyl phosphonic acid. Of the
foregoing biopolymers, xanthan gum is preferred. The amount of
xanthan gum present in the fracturing fluid is preferably in the
range of from about 10 to about 30 pounds (lbs)/1,000 gallons (gal)
of fracturing fluid. Additional disclosure regarding the foregoing
gelling additives can be found in U.S. Pat. No. 6,454,008, which is
incorporated by reference herein in its entirety.
[0019] A proppant, i.e., particulate material, for preventing
fractures formed in the subterranean formation from closing may be
disposed throughout the fracturing fluid. Examples of suitable
proppants include, but are not limited to, resin coated or uncoated
sand, sintered bauxite, ceramic materials, and glass beads. The
proppant is preferably present in the fracturing fluid in an amount
ranging from about 5 to about 10 pounds/gallon of the fluid. A
bacteriacide may also be added to the fracturing fluid for the
purpose of preventing or alleviating a bacterial attack. Examples
of suitable bacteriacides include, but are not limited to, glutaric
aldehyde and hexahydro-1,3,6-tris(hydroxyethyl)-S-triazne. The
concentration of the bactericide added to the fracturing fluid
preferably ranges from about 0.1 to about 0.15 gallon of
bactericide per 1,000 gallons of the water.
[0020] When the surfactant contained in the fracturing fluid is
tertiary alkyl amine ethoxylate or a mixture of amphoteric and
anionic surfactants, the fracturing fluid preferably also includes
an encapsulated acid or an acid producing compound for performing a
delayed release of an acid in the fracturing fluid. The amount of
encapsulated acid or acid producing compound in the fracturing
fluid should be sufficient to lower the pH of the fracturing fluid
to less than about 6. Examples of suitable encapsulated acids
include, but are not limited to, encapsulated formic acid,
encapsulated citric acid, encapsulated furmaric acid, and
encapsulated mineral acids, e.g., hydrochloric acid. The acids may
be encapsulated in accordance with the methods described in U.S.
Pat. Nos. 5,373,901, 5,604,186, and 6,357,527 and U.S. patent
application Ser. No. 10/062,342, filed on Feb. 1, 2002 and entitled
"Treatment of a Well with an Encapsulated Liquid and Process for
Encapsulating a Liquid," each of which is incorporated by reference
herein in its entirety. Examples of suitable acid producing
compounds include, but are not limited to, ethyl acetate, ethyl
formate, and the acid producing compounds described in U.S. Pat.
No. 4,664,342, which is incorporated by reference herein in its
entirety.
[0021] According to preferred embodiments, the foregoing fracturing
fluid may be used to fracture a subterranean formation. The
fracturing fluid is formed by first adding the bacteriacide to an
aqueous salt solution, e.g., an aqueous solution containing 2% KCI
by weight of the water, followed by adding the gelling additive to
the solution. After the gelling additive hydrates, the surfactant
is added to the solution, and the solution is mixed. If the
surfactant is a tertiary alkyl amine ethoxylate or a mixture of
amphoteric and anionic surfactants, the pH of the resulting
fracturing fluid is raised to greater than about 9 by the addition
of a basic solution such as an NaOH, KOH, Ca(OH).sub.2, or sodium
carbonate solution. The encapsulated acid or acid producing
compound is also added to this fracturing fluid for subsequently
lowering the pH of the fluid downhole. On the other hand, if the
surfactant is a mixture of amphoteric and cationic surfactants, the
pH of the fracturing fluid is lowered to less than about 6 by the
addition of an acid solution such as an acetic acid, formic acid,
or mineral acid (e.g., HCl) solution. The encapsulated base or base
producing compound is also added to this fracturing fluid for
subsequently raising the pH of the fluid downhole.
[0022] The foamed fracturing fluid is subsequently pumped into a
well penetrating the subterranean formation. As the fracturing
fluid is being pumped into the well, a sufficient amount of gas is
added to the fracturing fluid to form a foam in the presence of the
surfactant. The gas may be, for example, nitrogen. The foamed
fracturing fluid is pumped to the subterranean formation at a pump
pressure sufficient to exceed the fracturing gradient and start
fracturing the subterranean formation. After the initial fracturing
of the subterranean formation, the proppant can be added to the
fracturing fluid as it continues to be pumped into the well. The
fracturing fluid can be pumped downhole for a period of time
sufficient to achieve a desired amount of fracture geometry in the
subterranean formation. The acid or base contained in the
fracturing fluid is then released, causing the pH of the fracturing
fluid to change to the second pH at which the fluid defoams. Due to
the static condition of the fracturing fluid and to gravity, the
proppant begins settling such that it becomes deposited in the
fractures of the subterranean formation. The proppant holds the
fractures open after the fracturing fluid is removed. The
fracturing fluid is then flowed back to the surface by releasing
the pressured applied to the fluid. At the surface, the fracturing
fluid is passed to a holding tank or vessel and contacted with an
acid or base to change its pH back to the first pH at which the
fluid foams by the addition of a gas; The fracturing fluid is then
re-foamed and recycled to the same or a different subterranean
formation to fracture that formation as described previously. Due
to the presence of the previously described surfactant in the
fracturing fluid, the fluid preferably can be recycled multiple
times in this manner without adding additional surfactant and
gelling additive to the fracturing fluid. The mean foam quality of
the fracturing fluid preferably remains in the range of about 50 to
about 90 despite being recycled one or more times. The foam quality
of the fracturing fluid is represented by the following equation:
Foam .times. .times. Quality = Total .times. .times. Volume .times.
.times. of .times. .times. Foam - Liquid Total .times. .times.
Volume .times. .times. of .times. .times. Foam .times. 100
##EQU1##
EXAMPLES
[0023] The invention having been generally described, the following
examples are given as particular embodiments of the invention and
to demonstrate the practice and advantages hereof. It is understood
that the examples are given by way of illustration and are not
intended to limit the specification or the claims to follow in any
manner.
Example 1
[0024] The following example illustrates the measurement of foam
quality. A fracturing fluid in accordance with the present
invention was prepared by blending 1 Liter (L) of brine water
containing 2 weight (wt.) % KCl by weight of the water and 3.6
grams of a carboxymethylhydroxypropyl guar gelling additive in a
Constant Mixer Model 30-60, which is commercially available from
Chandler Engineering of Tulsa, Okla. The gelling additive was
allowed to hydrate for 30 minutes. A BE-4 bactericide manufactured
by Ondeo Nalco of Houston, Tex. was added to the hydrated gel to
prevent it from being attacked by bacteria. The pH of the hydrated
gel was raised to 10 by adding a buffer of ammonium acetate and
acetic acid. Then 100 milliliters (mL) of the fracturing fluid was
placed in a 1 L plastic beaker, followed by the addition of 0.5
weight % RW-100 surfactant by weight of the fracturing fluid. The
fracturing fluid was vigorously agitated until the foam reached
maximum height in the beaker. The foamed fluid was transferred to a
500 mL graduated cylinder, and the total volumes of the fracturing
fluid and of the foam were measured. The foam quality was
calculated to be 68.
Example 2
[0025] The following example illustrates preparing and using a
recyclable fracturing fluid. A fracturing fluid in accordance with
the present invention was prepared by placing 1 L of brine water
containing 2 wt. percent % KCl by weight of the water in a Constant
Mixer Model 30-60. Then 2.4 grams of hydroxypropyl guar (20
pounds/1000 gallons) gelling additive were vigorously agitated in
brine water, and the gelling additive was allowed to fully hydrate
for 30 minutes. A BE-4 bactericide was added to the hydrated gel to
prevent bacterial growth on the gel. The pH of the hydrated gel was
raised to 10 by adding 0.1 gram of a buffer of ammonium acetate and
acetic acid. Then 100 mL of the fracturing fluid was added to a 1L
beaker and mixed at a low speed with 5 lbs/gal of 20-40 mesh
fracturing sand. A foaming surfactant mixture at a concentration of
0.5 wt. % by weight of the water was added to the fracturing fluid.
The surfactant mixture contained 40 wt. % lauryl/myristyl amine
oxide, 8 wt. % alcohol ether sulfate with 3 moles of ethylene
oxide, 14 wt. % alcohol ether sulfate with 3.5 moles ethylene
oxide, 8 wt. % .alpha.-olefin sulfonate, and 30 wt. % water by
weight of the mixture. The fluid was foamed by vigorously agitating
it until the foam filled the beaker. The foamed fracturing fluid
was transferred to a 500 mL graduated cylinder, and the time
required for the fracturing sand to completely settle to the bottom
of the graduated cylinder was noted as 4 minutes. The pH of the
fluid was adjusted to 4 by the addition of a small amount of HCI.
Lowering the pH in this manner completely destroyed the foam. The
fracturing fluid was decanted into a beaker, and additional
fracturing sand was added. The pH of the fluid was again raised to
10, and the fluid was vigorously agitated to form a foam therein.
The time required for the sand to settle to the bottom of the
graduated cylinder after re-foaming was 8 minutes. This process of
foaming and defoaming was repeated 4 times, exhibiting the
recyclable nature of the foamed fracturing fluid.
COMPARATIVE EXAMPLE 1
[0026] A conventional fracturing fluid was prepared for comparison
to the recyclable fracturing fluid prepared in Example 2. First,
1.2 grams of hydroxypropyl guar gelling additive were hydrated for
30 minutes in brine water containing 2 wt. % KCl by weight of the
water. To the hydrated solution was added 0.3 gram of
hemi-cellulase breaker. Then 20-40 mesh sand at a concentration of
5 lbs/gal was added to the solution, followed by adding 1 wt. %
cocobetaine (amphoteric surfactant) to the solution. The solution
was foamed by agitating it for 30 seconds. Next, 370 mL of the
resulting foamed fluid was transferred to a graduated cylinder. In
1 minute, the sand in the fluid started settling. In 12 minutes,
100 mL of liquid plus sand were observed in the graduated cylinder.
In 15 minutes, 125 mL of liquid plus sand were observed in the
graduated cylinder. The gel broke in 1 hour, forming a thin fluid.
The viscosity of the broken fluid was measured to be 2.5 centipoise
at 300 rpm using a Fann Viscometer Model 30. The broken fluid was
decanted and acidified. It was agitated to form a foam therein.
Then the foam immediately collapsed as soon as the foam began to
defoam. The foam exhibited no stability due to lack of viscosity
and texture. As such, the fracturing fluid was not suitable for
recycling.
[0027] While the preferred embodiments of the invention have been
shown and described, modifications thereof can be made by one
skilled in the art without departing from the spirit and teachings
of the invention. The embodiments described herein are exemplary
only, and are not intended to be limiting. Many variations and
modifications of the invention disclosed herein are possible and
are within the scope of the invention. Use of the term "optionally"
with respect to any element of a claim is intended to mean that the
subject element is required, or alternatively, is not required.
Both alternatives are intended to be within the scope of the
claims.
[0028] Accordingly, the scope of protection is not limited by the
description set out above, but is only limited by the claims which
follow, that scope including all equivalents of the subject matter
of the claims. Each and every claim is incorporated into the
specification as an embodiment of the present invention. Thus, the
claims are a further description and are an addition to the
preferred embodiments of the present invention. The discussion of a
reference in the Description of Related Art is not an admission
that it is prior art to the present invention, especially any
reference that may have a publication date after the priority date
of this application. The disclosures of all patents, patent
applications, and publications cited herein are hereby incorporated
by reference, to the extent that they provide exemplary, procedural
or other details supplementary to those set forth herein.
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