Note: Descriptions are shown in the official language in which they were submitted.
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FORMATION CONDITIONING FLUIDS COMPRISING PEROXIDE AND
CONDITIONING AGENT AND METHODS RELATING THERETO
Technical Field
The present invention relates to enhancing the production of hydrocarbons from
a
subterranean formation. More particularly, the invention relates to formation
conditioning fluids comprising peroxide generating compounds and their methods
of use
relative to enhancing the placement and performance of consolidating agents in
subterranean
formations.
Hydrocarbon wells are often located in subterranean formations that contain
unconsolidated particulates (e.g., sand, gravel, proppant, fines, etc.) that
may migrate out of
the subterranean formation with the oil, gas, water, and/or other fluids
produced by the wells.
The presence of such particulates in produced fluids is undesirable in that
the particulates
may abrade pumping and other producing equipment and/or reduce the production
of desired
fluids from the well. Moreover, particulates that have migrated into a well
bore (e.g., inside
the casing and/or perforations in a cased hole), among other things, may clog
portions of the
well bore, hindering the production of desired fluids from the well. The term
"unconsolidated
particulates," and derivatives thereof, is defined herein to include loose
particulates and
particulates bonded with insufficient bond strength to withstand the forces
created by
the production of fluids through the formation.
Unconsolidated particulates may comprise, among other things, sand, gravel,
fines and/or proppant particulates in the subterranean formation, for example,
proppant
particulates placed in the subterranean formation in the course of a
fracturing or
gravel-packing operation. The terms "unconsolidated subterranean formations,"
"unconsolidated portions of a subterranean formation," and derivatives thereof
are defined
herein to include any formations that contain unconsolidated particulates, as
that term is
defined herein.
One method used to control particulates in unconsolidated formations involves
consolidating unconsolidated particulates into stable, permeable masses by
applying a
consolidating agent (e.g., a resin or tackifying agent) to a portion of the
subterranean
formation. The application of such resins or tackifying agents is often
referred to as a
consolidation treatment. One problem that may be experienced in such
consolidation
treatments is the failure of the resin or tackifying agent to adhere to the
rock surfaces of the
formation. This failure may be due to the presence of oil, condensates, or
other debris
(collectively referred to herein as "contaminants") on the rock surfaces.
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To combat this contaminants problem, oftentimes the formation may be
pretreated
with a mutual solvent prior to the consolidation treatment in an attempt to
remove the oil
and/or the debris and prepare the surface of the formation rock in the
fonnation to allow the
resin or tackifier to adhere to its surface. Glycol ethers are an example of
the type of solvent
that may be used in such pre-treatments. The use of such solvents is very
expensive because
high concentrations of the solvent are necessary to achieve any sort of
contaminant reduction.
For example, it is often recommended that solutions comprising about 50% to
about
100% of the solvent be used in relatively large pre-treatments. Additionally,
many of these
solvents present toxicity and handling concerns.
Disclosure of the Invention
The present invention relates to enhancing the production of hydrocarbons from
a
subterranean formation. More particularly, the invention relates to formation
conditioning fluids comprising peroxide generating compounds and their methods
of use
relative to enhancing the placement and performance of consolidating agents in
subterranean
formations.
In one embodiment, the present invention provides a method comprising:
providing a
clean-up fluid comprising a peroxide-generating compound and an aqueous base
fluid;
placing the clean-up fluid in a subterranean formation; removing contaminants
from at
least a portion of the subterranean formation to form a cleaned portion of the
formation; providing a consolidation agent; placing the consolidation agent on
at least
a portion of the cleaned portion of the formation; and allowing the
consolidation agent to
adhere to at least a plurality of unconsolidated particulates in the cleaned
portion of the
formation.
In one embodiment, the present invention provides a method comprising:
providing a
clean-up fluid comprising a peroxide-generating compound and an aqueous base
fluid;
placing the clean-up fluid in a subterranean formation; allowing the clean-up
fluid to
penetrate a portion of the subterranean formation; and allowing the clean-up
fluid to remove
contaminants from the portion of the subterranean formation to form a cleaned
portion of the
subterranean formation, wherein the cleaned portion of the formation comprises
at
least a plurality of cleaned flow paths.
The features and advantages of the present invention will be readily apparent
to
those skilled in the art. While numerous changes may be made by those skilled
in the art,
such changes are within the spirit of the invention.
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In accordance with one aspect of the present invention, there is provided a
method
comprising:
providing a clean-up fluid comprising an aqueous base fluid and a peroxide-
generating
compound selected from the group consisting of: a sodium percarbonate, a
sodium carbonate
peroxyhydrate, a dichromate, a permanganate, a peroxydisulfate, a potassium
diperphosphate, an
ammonium salt of dipersulfuric acid, an alkali metal salt of dipersulfuric
acid, an alkali
percarbonate, an alkaline earth percarbonate, an alkali perchlorate, an
alkaline earth perchlorate,
and combinations thereof;
placing the clean-up fluid in a subterranean formation; removing contaminants
from at
least a portion of the subterranean formation to form a cleaned portion of the
formation;
providing a consolidation agent; placing the consolidation agent on at least a
portion of
the cleaned portion of the formation; and
allowing the consolidation agent to adhere to at least a plurality of
unconsolidated
particulates in the cleaned portion of the formation.
In accordance with another aspect of the present invention, there is provided
a method
comprising:
providing a clean-up fluid comprising an aqueous base fluid and a peroxide-
generating
compound selected from the group consisting of: a sodium percarbonate, a
sodium carbonate
peroxyhydrate, a dichromate, a permanganate, a peroxydisulfate, a potassium
diperphosphate, an
ammonium salt of dipersulfuric acid, an alkali metal salt of dipersulfuric
acid, an alkali
percarbonate, an alkaline earth percarbonate, an alkali perchlorate, an
alkaline earth perchlorate,
and combinations thereof;
placing the clean-up fluid in a subterranean formation;
allowing the clean-up fluid to penetrate a portion of the subterranean
formation; and
allowing the clean-up fluid to remove contaminants from the portion of the
subterranean
formation to form a cleaned portion of the subterranean formation, wherein the
cleaned portion
of the formation comprises at least a plurality of cleaned flow paths.
The present invention relates to enhancing the production of hydrocarbons from
a
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subterranean formation. More particularly, the invention relates to formation
conditioning fluids comprising peroxide generating compounds and their methods
of use
relative to enhancing the placement and performance of consolidating agents in
subterranean
formations.
Of the many advantages of the formation conditioning fluids of the present
invention,
many of which are not discussed or eluded to herein, is that through their
use, the rock
surfaces within the formation are in a wetted state that is amenable to
allowing the
resin or tackifier to stick to its surface in a subsequent consolidation
treatment.
The formation conditioning fluids of the present invention are very efficient
at removing
to contaminants from the rock surfaces. When compared to standard solvent
pre-treatment
techniques, the efficiency improvement is marked, especially with respect to
the removal or
reduction in the presence of oil as well as other contaminants such as
unbroken bits of
fracturing gel or organic deposits that are not soluble in standard solvents.
Additionally, as an
added benefit, the formation conditioning fluids of the present invention
allow for
some stimulation effect in that they remove contaminants from pore throats to
clear
flow paths for hydrocarbon production. Another benefit is that these formation
conditioning
fluids are less expensive than solvent pre-treatments, and do not present the
same sort of
toxicity or handling concerns. Perhaps a key advantage is the amenability to
these
formation conditioning fluids to being foamed; conventional solvent
pretreatment fluids are
not amenable to foaming because of the inherent incompatibility of the foaming
agent
and the solvent. This allows the fluids to be used over long intervals within
a well bore in the
formation. Additionally, foaming the fluids can be viewed as extending the
fluids so that a
relatively small volume of fluid can have a large bottom hole volume making it
possible to
contact larger reservoir sections with smaller treatments. Foamed embodiments
of the
fluids of the present invention also may act as diverting agents to help
provide more
uniform matrix placement of the chemicals into the reservoir over long
intervals, which
may overcome the effects of variable permeabilities.
The clean-up fluids of the present invention comprise an aqueous base fluid
and
a peroxide-generating compound. Optionally, the clean-up fluids may comprise a
foaming agent and a gas. Additional components also may be included as
described below.
In the methods of the present invention, it is believed that the peroxide
generating
compounds react to generate heat, oxygen, and other compounds such as water
that may be
used to clean the sand surfaces in the formation and remove contaminants that
may
otherwise clog flow paths in the rock matrix or coat on the surfaces of the
sand particulates.
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For example, the decomposition of the hydrogen peroxide into oxygen and water
generates a considerable amount of heat (i.e., approximately 23 Kcal/gm-mole
of
H202), and liberates oxygen that may react further with any oil residue or
debris present in
the subterranean formation to generate carbon dioxide and additional amounts
heat
and water. Depending on the concentration of the hydrogen peroxide, the water
generated
by the two reactions, along with the water already present in the formation
conditioning
fluid, may generate steam and/or hot water that itself may reduce the
viscosity of the
adjacent hydrocarbons. The viscosity of the adjacent hydrocarbons may also be
reduced by
the miscible solution of carbon dioxide generated by the reaction of oxygen
with
hydrocarbons in the formation, into hydrocarbons in the cooler regions of the
reservoir. The
heat generated by the various reactions may also facilitate the release of
hydrocarbons from
the formation.
Optionally, the clean-up fluids may be foamed with a foaming agent and a gas.
In
such embodiments, the clean-up fluids also comprise a gas and a foaming agent.
While
various gases can be utilized for foaming the treatment fluids of this
invention, nitrogen,
carbon dioxide, and mixtures thereof are preferred. In examples of such
embodiments, the gas
may be present in a treatment fluid in an amount in the range of from about 5%
to about 95%
by volume of the treatment fluid, and more preferably in the range of from
about 20% to
about 80%. The amount of gas to incorporate into the fluid may be affected by
factors
including the viscosity of the fluid and wellhead pressures involved in a
particular
application. Examples of preferred foaming agents that can be utilized to foam
and stabilize
the fluids of this invention include, but are not limited to,
alkylamidobetaines such as
cocoamidopropyl betaine, alpha-olefin sulfonate, trimethyltallowammonium
chloride, cs to
C22 alkylethoxylate sulfate, trimethylcocoammonium chloride, any derivative of
any of the
foregoing, and any combination of the foregoing. Cocoamidopropyl betaine is
especially
preferred. Other suitable surfactants available from Halliburton Energy
Services include, but
are not limited to: "19NTM," "G-Sperse Dispersant," "Morflo III.RTM"
surfactant,
"Hyflo® IV M" surfactant, "Pen-88MTM" surfactant, "HC2TM Agent," "Pen-88
HTTM" surfactant, "SEM-71m" emulsifier, "Howco-Suds" foaming agent, "Howco
Sticks" surfactant, "A-SperseTm" dispersing aid for acid additives, "SSO-21E"
surfactant,
and "SSO-21MWTm" surfactant. 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. The foaming agent is generally present in fluid of the
present invention in an
amount in the range of from about 0.1% to about 5% w/v, more preferably in the
amount of
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from about 0.2% to about 1% w/v, and most preferably about 0.5%.
The peroxide-generating compounds suitable for use in the present invention
may include any peroxide or peroxide-generating compound. One suitable
peroxide -
generating compound is hydrogen peroxide. Another is sodium percarbonate (or
sodium carbonate peroxyhydrate), a granular product used as an alternative to
perborate
bleaches in household detergents that, when dissolved into water, releases
H202 and
soda ash (sodium carbonate). The pH of the resulting solution is typically
alkaline, which
activates the H202. Additional suitable peroxide-generating compounds include,
but are not
limited to, pentanedione peroxide, calcium peroxide, dichromates,
permanganates,
to peroxydisulfates, sodium perborate, sodium carbonate peroxide, hydrogen
peroxide,
tertiarybutylhydroperoxide, potassium diperphosphate, and ammonium and alkali
metal
salts of dipersulfuric acid, alkali and alkaline earth percarbonates and
persulfates and
perchlorates. Specific examples include, but are not limited to, ammonium and
alkali and
alkaline earth persulfates such as ammonium, sodium and potassium persulfate.
Additional examples include, but are not limited to, cumene hydrop ero xi de ,
t-butyl cumyl peroxide, di-t-butyl peroxide, di-(2-t-
butylperoxyisopropyl)benzene, 2,5-dimethy1-2,5-di(t-butylperoxy)hexane,
di-isopropylbenzene monohydroperoxide, di-cumylperoxide, 2,2-di-(t-butyl
peroxy) butane,
t-amyl hydroperoxide, benzoyl peroxide, any derivative of any of the
foregoing, and any
combination of the foregoing. Any combination of these suitable peroxide-
generating
compounds is suitable as well. Other suitable peroxide-generating compounds
will be
apparent to one skilled in the art, with the benefit of this disclosure.
Typically, the peroxide-generating compound is present in the treatment fluids
of the
present invention in an amount in the range of from about 0.1% to about 10%
w/v. In
particular embodiments, the peroxide-generating compound may be present in the
treatment
fluids in an amount in the range of from about 1% to about 5% w/v.
As mentioned above, peroxide-generating compounds may have a propensity
to prematurely decompose spontaneously or react in the well bore environment.
These
reactions may be affected by many factors, including, inter alia, temperature,
pH,
concentration, and the presence of potential catalysts. For example, the
decomposition of the
peroxide-generating compound may be hastened by raising the temperature,
adjusting the pH
to 7.0 or greater, or introducing decomposition catalysts, such as salts of
iron, nickel,
cobalt, or certain other metals. Generally, the rate of decomposition
increases approximately
2.2 times for each approximate 10 C rise in temperature in the range from
about 20 C to
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about 100 C, and about 1.5 times for each 10 F rise from 68 F to 212 F.
Generally,
decreasing temperatures have little effect on hydrogen peroxide until they
drop substantially
below 0 C. Crystals do not begin to appear in 35% and 50% solutions of
hydrogen
peroxide until about -33 C. (-27.4 F.) and - 52.2 C. (-62 F.), respectively.
Particular embodiments of the present invention may employ one or more
mechanical
means to minimize the decomposition of the peroxide-generating compound until
the
compound is down hole. Generally, the holding tanks, pumps, and the like used
to handle the
peroxide-generating compound prior to its injection into the subterranean
formation
are constructed out of passivated, corrosion-resistant materials, such as
stainless steel,
to specifically selected to minimize the decomposition of the hydrogen
peroxide. Particular
embodiments of the present invention may also mechanically isolate the
peroxide-generating
compound from the well bore environment itself until the compound reaches a
desired
location in the subterranean formation. In particular embodiments, this
entails injecting the
peroxide-generating compound into the formation using coiled tubing
constructed from a
material selected for its compatibility both with the corrosive demands of the
peroxide-generating compound and with the physical demands placed on coiled
tubing. Such
compatible coiled tubing materials include, but are not limited to, QT 16Cr
alloys, such as
QT 16Cr30 and QT 16Cr80, available under the tradename "NITRONIC® 30,"
from
Quality Tubing, Inc., of Houston, Tex. Other particular embodiments may employ
other corrosion-resistant tubing, such as pure aluminum tubing, Type 304
stainless steel
tubing, plastic-lined steel tubing, or tubing lined with crosslinked
polyethylene (PEX),
polyethylene, or some other peroxide-inert material.
Either alone or in combination with mechanical means, particular
embodiments of the present invention may also use chemical means to minimize
the
decomposition of the peroxide-generating compound until the peroxide-
generating compound
reaches the desired location in the subterranean formation. Generally, these
embodiments use
a moderator to delay the decomposition of the peroxide-generating compound and
may
further use an initiator to catalyze the reaction once the peroxide-generating
compound is in
place in the formation.
Several methods are available for determining whether the minerals present in
the formation are sufficient to initiate the reaction of the peroxide-
generating
compound. Generally, a sample of the formation is exposed to the
peroxide-generating compound. If the peroxide-generating compound is too
reactive with
the formation, a moderator may be added. Moderator is added until the about
95% of the
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peroxide-generating compound remains unconsumed after a 24-hour period. In
some
embodiments, this level of moderator may then be scaled up by up by about 20%
to ensure an
adequate amount of moderator is present to prevent the premature decomposition
of the
peroxide-generating compound. With the benefit of this disclosure, one skilled
in the art
should be able to determine the proper amount of moderator for use in chosen
formation. In
some embodiments of the present invention, a moderator or moderators are
included in
concentrations of from about 10 mg of moderator per liter of hydrogen peroxide
solution to about 500 mg of moderator per liter of hydrogen peroxide solution;
however, when it is desired to all but completely stop the reaction, moderator
may be
to included in concentrations of multiple grams of moderator per liter of
hydrogen
peroxide solution, for example, some embodiments may use 2 grams of moderator
per liter
of hydrogen peroxide solution. In other embodiments of the present invention,
a moderator or
moderators are included in concentrations of from about 25 mg of moderator per
liter of
hydrogen peroxide solution to about 250 mg of moderator per liter of hydrogen
peroxide
solution.
Optionally, the clean-up fluids of the present invention may comprise
surfactants,
mutual solvents, oxidants, chelating agents, any derivative of any of the
foregoing, acids
(both inorganic and organic), any derivative of any of the foregoing, and any
combination
of the foregoing.
Surfactants that are suitable for use in the clean-up fluids of the present
invention
include, but are not limited to, non-ionic ethoxylated surfactants. Those that
are
especially suitable have about 3 to about 12 moles of ethylene oxide, such as
nonylphenol ethoxylates comprising from about 4 moles to about 10.5 moles of
ethylene
oxide. A commercially available example of a suitable surfactant is "BEROL
226 SA,"
available from Akzo Nobel in various locations. A commercially available
product that is
suitable that provides both carbonate peroxyhdrate and ethoxylated surfactant
is
"OXICLEAN " available from Church & Dwight, Inc. If used, the surfactant may
be
included in an amount of from about 0.1% to about 4% w/v.
Examples of suitable mutual solvents include, but are not limited to, ethylene
glycol monobutyl ether, 1-methoxy-2-propanol, dipropylene glycol methyl ether,
dipropylene
glycol dimethyl ether, diethyleneglycol methyl ether, ethyleneglycol butyl
ether, and
diethyleneglycol butyl ether, propyleneglycolmonobutylether, water, methanol,
isopropyl alcohol, alcohol ethers, aromatic solvents, other hydrocarbons,
mineral oils,
paraffins, any derivative of any of the foregoing, and any combination of the
foregoing.
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Additional suitable mutual solvents include, but are not limited to,
"MUSOL.RTM". Mutual Solvent, "MUSOL® A" Mutual Solvent, and
"MUSOL® E" Mutual Solvent, all available from Halliburton Energy Services
in
Duncan, Oklahoma. Other suitable solvents may also be used. If used, the
mutual solvent
may be included in an amount of from about 0.1% to about 10% w/v. Examples of
suitable
oxidants include, but are not limited to, alkali hypohalites and alkaline
earth hypohalites
such as sodium or calcium hypohalites, any derivative of any of the foregoing,
and any
combination of the foregoing. A specific example includes sodium hypochlorite.
If
used, the oxidant may be included in an amount of from about 0.1% to about 10%
w/v.
to Examples of suitable chelating agents include, but are not limited to,
ethylene
diamine tetraacetic acid, nitrilotriacetic acid, hydroxyl-
ethylethylenediaminetriacetic acid,
diethylenetriaminepentaacetic acid, propylenediaminetetraacetic acid,
ethylenediaminedi(o-
hydroxyphenylacetic) acid, a sodium or potassium salt of any of the foregoing,
dicarboxymethyl glutamic acid tetrasodium salt, any derivative of any of the
foregoing, and
any combination of the foregoing. If used, the chelating agent may be included
in an amount
of from about 0.1% to about 10% w/v.
In alternative embodiments, if it is desirable to increase the viscosity of
the
formation conditioning fluid, a viscoelastic surfactant may be included.
Suitable viscoelastic
surfactants that may be suitable include, but are not limited to, methyl ester
sulfonates, sulfosuccinates, taurates, amine oxides, ethoxylated amines,
alkoxylated fatty
acids, alkoxylated alcohols, lauryl alcohol ethoxylate, ethoxylated nonyl
phenol, ethoxylated
fatty amines, cocoalkylamine ethoxylate, betaines, modified betaines,
alkylamidobetaines,
cocoamidopropyl betaine, quaternary ammonium compounds,
trimethyltallowammonium chloride, trimethylcocoaammonium chloride, an
ammonium salt of an alkyl ether sulfate, a cocoamidopropyl dimethylamine
oxide, cocoamidopropyl hydroxysultaine, tallow dihydroxyethyl betaine, any
derivative of any of the foregoing, and any combination of the foregoing.
In one embodiment, the present invention provides a method comprising:
providing a
clean-up fluid comprising a peroxide-generating compound and an aqueous base
fluid;
placing the clean-up fluid in a subterranean formation; removing contaminants
from at
least a portion of the subterranean formation to form a cleaned portion of the
formation; providing a consolidation agent; placing the consolidation agent on
at least
a portion of the cleaned portion of the formation; and allowing the
consolidation agent to
adhere to at least a plurality of unconsolidated particulates in the cleaned
portion of the
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formation. The term "cleaned" as used herein does not imply any particular
degree of
contaminant removal in that portion of the formation.
Suitable consolidation agents include resins and tackifiers. In some
embodiments,
these consolidation agents may be used in the form of an emulsion. In such
embodiments, the
emulsion may comprise an aqueous base fluid and a suitable surfactant.
Resins suitable for use in the consolidation fluids of the present invention
include all
resins known in the art that are capable of forming a hardened, consolidated
mass. Many
such resins are commonly used in subterranean consolidation operations, and
some
suitable resins include two component epoxy based resins, novolak resins,
polyepoxide resins,
to phenol-aldehyde resins, urea-aldehyde resins, urethane resins, phenolic
resins, furan resins,
furan/furfuryl alcohol resins, phenolic/latex resins, phenol formaldehyde
resins, polyester
resins and hybrids and copolymers thereof, polyurethane resins and hybrids and
copolymers
thereof, acrylate resins, and mixtures thereof. Some suitable resins, such as
epoxy resins, may
be cured with an internal catalyst or activator so that when pumped down hole,
they may be
cured using only time and temperature. Other suitable resins, such as furan
resins generally
require a time delayed catalyst or an external catalyst to help activate the
polymerization of
the resins if the cure temperature is low (i.e., less than 250 F), but will
cure under the
effect of time and temperature if the formation temperature is above about 250
F,
preferably above about 300 F. It is within the ability of one skilled in the
art, with the benefit
of this disclosure, to select a suitable resin for use in embodiments of the
present invention
and to determine whether a catalyst is required to trigger curing.
Selection of a suitable resin may be affected by the temperature of the
subterranean
formation to which the fluid will be introduced. By way of example, for
subterranean formations having a bottom hole static temperature ("BHST")
ranging from
about 60 F to about 250 F, two-component epoxy-based resins comprising a
hardenable resin component and a hardening agent component containing specific
hardening agents may be preferred. For subterranean formations having a BHST
ranging from about 300 F to about 600 F, a furan-based resin may be preferred.
For
subterranean formations having a BHST ranging from about 200 F to about 400 F,
either
a phenolic-based resin or a one-component HT epoxy-based resin may be
suitable. For
subterranean formations having a BHST of at least about 175 F, a phenol/phenol
formaldehyde/furfuryl alcohol resin may also be suitable.
Any solvent that is compatible with the chosen resin and achieves the desired
viscosity effect is suitable for use in the present invention. Some preferred
solvents are those
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having high flash points (e.g., about 125 F) because of, among other things,
environmental
and safety concerns; such solvents include butyl lactate, butylglycidyl ether,
dipropylene
glycol methyl ether, dipropylene glycol dimethyl ether, dimethyl formamide,
diethyleneglycol methyl ether, ethyleneglycol butyl ether, diethyleneglycol
butyl ether,
propylene carbonate, butyl alcohol, d'limonene, fatty acid methyl esters, and
any
derivative of any of the foregoing, and any combination of the foregoing.
Other preferred
solvents include aqueous dissolvable solvents such as, methanol, isopropanol,
butanol,
glycol ether solvents, and any derivative of any of the foregoing, and any
combination of the
foregoing. Suitable glycol ether solvents include, but are not limited to,
diethylene glycol
to methyl ether, dipropylene glycol methyl ether, 2-butoxy ethanol, ethers
of a C2 to C6 dihydric
alkanol containing at least one CI to C6 alkyl group, mono ethers of dihydric
alkanols,
methoxypropanol, butoxyethanol, hexoxyethanol, and isomers thereof. Selection
of an
appropriate solvent is dependent on the resin chosen and is within the ability
of one
skilled in the art with the benefit of this disclosure.
In some embodiments, compositions suitable for use as tackifying agents in the
present invention may comprise any compound that, when in liquid form or in a
solvent
solution, will form a tacky, non-hardening coating upon a particulate.
Tackifying agents
suitable for use in the present invention include non-aqueous tackifying
agents;
aqueous tackifying agents; silyl-modified polyamides, and reaction products of
an amine
and a phosphate ester. In addition to encouraging particulates to form
aggregates, the use of
a tackifying agent may reduce particulate flow back once the particulates are
placed
into a subterranean formation. The tackifying agents are preferably coated on
the
particulates in an amount ranging from about 0.1% to about 5% by weight of the
uncoated
particulates, preferably ranging from about 0.5 % to about 2.5 % by weight of
the uncoated
particulates.
One type of tackifying agent suitable for use in the present invention is a
non-aqueous
tackifying agent. A particularly preferred group of tackifying agents comprise
polyamides
that are liquids or in solution at the temperature of the subterranean
formation such that they
are, by themselves, non-hardening when introduced into the subterranean
formation. A
particularly preferred product is a condensation reaction product comprised of
commercially
available polyacids and a polyamine. Such commercial products include
compounds such as
mixtures of C36 dibasic acids containing some trimer and higher oligomers and
also
small amounts of monomer acids that are reacted with polyamines. Other
polyacids
include trimer acids, synthetic acids produced from fatty acids, maleic
anhydride, acrylic
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acid, and the like. Such acid compounds are commercially available from
companies such as
Witco Corporation, Union Camp, Chemtall, and Emery Industries. The reaction
products are
available from, for example, Champion Technologies, Inc. and Witco
Corporation.
Additional compounds which may be used as non-aqueous tackifying compounds
include
liquids and solutions of, for example, polyesters, polycarbonates and
polycarbamates, natural
resins such as shellac and the like. Other suitable non-aqueous tackifying
agents are described
in U.S. Patent Number 5,853,048 issued to Weaver, et al. and U.S. Patent
Number
5,833,000 issued to Weaver, et al., the relevant disclosures of which are
herein
incorporated by reference.
Non-aqueous tackifying agents suitable for use in the present invention may be
either used such that they form non-hardening coating or they may be combined
with a
multifunctional material capable of reacting with the non-aqueous tackifying
agent to form a
hardened coating. A "hardened coating" as used herein means that the reaction
of the
tackifying compound with the multifunctional material will result in a
substantially
non-flowable reaction product that exhibits a higher compressive strength in a
consolidated agglomerate than the tackifying compound alone with the
particulates. In this
instance, the non-aqueous tackifying agent may function similarly to a
hardenable resin.
Multifunctional materials suitable for use in the present invention include,
but are not
limited to, aldehydes such as formaldehyde, dialdehydes such as
glutaraldehyde,
hemiacetals or aldehyde releasing compounds, diacid halides, dihalides such as
dichlorides and dibromides, polyacid anhydrides such as citric acid, epoxides,
furfuraldehyde, glutaraldehyde or aldehyde condensates and the like, and any
derivative of any of the foregoing, and any combination of the foregoing. In
some
embodiments of the present invention, the multifunctional material may be
mixed
with the tackifying compound in an amount of from about 0.01 to about 50
percent by
weight of the tackifying compound to effect formation of the reaction product.
In some
preferable embodiments, the compound is present in an amount of from about 0.5
to
about 1 percent by weight of the tackifying compound. Suitable multifunctional
materials
are described in U.S. Patent Number 5,839,510 issued to Weaver, et al., the
relevant
disclosure of which is herein incorporated by reference. Other suitable
tackifying agents
are described in U.S. Patent Number 5,853,048 issued to Weaver, et al., the
relevant
disclosure of which is herein incorporated by reference.
Solvents suitable for use with the non-aqueous tackifying agents of the
present
invention include any solvent that is compatible with the non-aqueous
tackifying agent and
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achieves the desired viscosity effect. The solvents that can be used in the
present invention
preferably include those having high flash points (most preferably above about
125 F). Examples of solvents suitable for use in the present invention
include, but are not
limited to, butylglycidyl ether, dipropylene glycol methyl ether, butyl bottom
alcohol,
dipropylene glycol dimethyl ether, diethyleneglycol methyl ether,
ethyleneglycol butyl
ether, methanol, butyl alcohol, isopropyl alcohol, diethyleneglycol butyl
ether,
propylene carbonate, d'limonene, 2- butoxy ethanol, butyl acetate, furfuryl
acetate,
butyl lactate, dimethyl sulfoxide, dimethyl formamide, fatty acid methyl
esters, and
any derivative of any of the foregoing, and any combination of the foregoing.
It is
to within the ability of one skilled in the art, with the benefit of this
disclosure, to determine
whether a solvent is needed to achieve a viscosity suitable to the
subterranean conditions and,
if so, how much.
Aqueous tackifying agents suitable for use in the present invention are not
significantly tacky when placed onto a particulate, but are capable of being
"activated" (that
is destabilized, coalesced and/or reacted) to transform the compound into a
sticky,
tackifying compound at a desirable time. Such activation may occur before,
during, or after
the aqueous tackifying agent is placed in the subterranean formation. In some
embodiments, a
pre-treatment may be first contacted with the surface of a particulate to
prepare it to be coated
with an aqueous tackifying agent. Suitable aqueous tackifying agents are
generally
charged polymers that comprise compounds that, when in an aqueous solvent or
solution,
will form a non-hardening coating (by itself or with an activator) and, when
placed on a
particulate, will increase the continuous critical resuspension velocity of
the particulate
when contacted by a stream of water. The aqueous tackifying agent may enhance
the
grain-to-grain contact between the individual particulates within the
formation (be they
proppant particulates, formation fines, or other particulates), helping bring
about the
consolidation of the particulates into a cohesive, flexible, and permeable
mass.
Suitable aqueous tackifying agents include any polymer that can bind,
coagulate, or
flocculate a particulate. Also, polymers that function as pressure sensitive
adhesives
may be suitable. Examples of aqueous tackifying agents suitable for use in the
present
invention include, but are not limited to: acrylic acid polymers; acrylic acid
ester
polymers; acrylic acid derivative polymers; acrylic acid homopolymers; acrylic
acid ester
homopolymers (such as poly(methyl acrylate), poly (butyl acrylate), and poly(2-
ethylhexyl
acrylate)); acrylic acid ester co-polymers; methacrylic acid derivative
polymers; methacrylic
acid homopolymers; methacrylic acid ester homopolymers (such as poly(methyl
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methacrylate), poly (butyl methacrylate), and poly(2-ethylhexyl
methacrylate));
acrylamido-methyl-propane sulfonate polymers; acrylamido-methyl-propane
sulfonate
derivative polymers; acrylamido-methylpropane sulfonate co-polymers; and
acrylic
acid/acrylamido-methyl-propane sulfonate copolymers, any derivative of any of
the
foregoing, and any combination of the foregoing. The term "derivative" as used
herein
refers to any compound that is made from one of the listed compounds, for
example,
by replacing one atom in the base compound with another atom or group of
atoms.
Methods of determining suitable aqueous tackifying agents and additional
disclosure
on aqueous tackifying agents can be found in Published U.S. Patent Application
to Number 2005-0277554 and Published U.S. Patent Application Number 2005-
0274517,
the relevant disclosures of which are hereby incorporated by reference.
Some suitable aqueous tackifying agents are described in U.S. Patent No.
5,249,627
by Harms, et al., the relevant disclosure of which is incorporated by
reference. Harms
discloses aqueous tackifying agents that comprise at least one member selected
from the
group consisting of benzyl coco di-(hydroxyethyl) quaternary amine, p-T-amyl-
phenol
condensed with formaldehyde, and a copolymer comprising from about 80% to
about 100% c 1-30 alkylmethacrylate monomers and from about 0% to about 20%
hydrophilic monomers. In some embodiments, the aqueous tackifying agent may
comprise a copolymer that comprises from about 90% to about 99.5% 2-
ethylhexylacrylate
and from about 0.5% to about 10% acrylic acid. Suitable hydrophilic monomers
may be any
monomer that will provide polar oxygen-containing or nitrogen-containing
groups. Suitable
hydrophillic monomers include dialkyl amino alkyl (meth)acrylates and their
quaternary
addition and acid salts, acrylamide, N-(dialkyl amino alkyl) acrylamide,
methacrylamides and
their quaternary addition and acid salts, hydroxy alkyl (meth)acrylates,
unsaturated
carboxylic acids such as methacrylic acid or preferably acrylic acid,
hydroxyethyl acrylate,
acrylamide, and the like. These copolymers can be made by any suitable
emulsion
polymerization technique. Methods of producing these copolymers are disclosed,
for example,
in U.S. Patent No. 4,670,501, the relevant disclosure of which is incorporated
herein by
reference.
[[[Silyl-Modified Polyamide Tackifying Agents.]]]
Silyl-modified polyamide compounds suitable for use as a tackifying agent in
the methods of the present invention may be described as substantially self-
hardening
compositions that are capable of at least partially adhering to particulates
in the unhardened
state, and that are further capable of self-hardening themselves to a
substantially
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non-tacky state to which individual particulates such as formation fines will
not
adhere to, for example, in formation or proppant pack pore throats. Such silyl-
modified
polyamides may be based, for example, on the reaction product of a silating
compound
with a polyamide or a mixture of polyamides. The polyamide or mixture of
polyamides may be one or more polyamide intermediate compounds obtained, for
example, from the reaction of a polyacid (e.g., diacid or higher) with a
polyamine (e.g.,
diamine or higher) to form a polyamide polymer with the elimination of water.
Other
suitable silyl-modified polyamides and methods of making such compounds are
described
in U.S. Patent Number 6,439,309 issued to Matherly, et al., the relevant
disclosure of
to which is herein incorporated by reference.
Yet another tackifying agent suitable for use in the present invention is a
reaction
product of an amine and a phosphate ester such as those describes in U.S.
Patent No.
7,392,847 issued to Gatlin et al., the relevant disclosure of which is herein
incorporated by
reference. The ratio of amine to phosphate ester combined to create the
reaction
product tackifying agent is preferably from about 1:1 to about 5:1, more
preferably from
about 2:1 to about 3:1. In some embodiments it may be desirable to combine the
amine and
phosphate ester in the presence of a solvent, such as methanol.
To create these amine/phosphate ester tackifying agents, suitable amines
include,
without limitation, any amine that is capable of reacting with a suitable
phosphate ester to
form a composition that forms a deformable coating on a metal-oxide-containing
surface.
Exemplary examples of such amines include, without limitation, any amine of
the
general formula R1,R2NH or mixtures or combinations thereof, where R1 and R2
are
independently a hydrogen atom or a carbyl group having between about between
about 1
and 40 carbon atoms and the required hydrogen atoms to satisfy the valence and
where
one or more of the carbon atoms can be replaced by one or more hetero atoms
selected from
the group consisting of boron, nitrogen, oxygen, phosphorus, sulfur or mixture
or
combinations thereof and where one or more of the hydrogen atoms can be
replaced by one
or more single valence atoms selected from the group consisting of fluorine,
chlorine,
bromine, iodine or mixtures or combinations thereof. Exemplary examples of
amines
suitable for use in this invention include, without limitation, aniline and
alkyl anilines or
mixtures of alkyl anilines, pyridines and alkyl pyridines or mixtures of alkyl
pyridines,
pyrrole and alkyl pyrroles or mixtures of alkyl pyrroles, piperidine and alkyl
piperidines or
mixtures of alkyl piperidines, pyrrolidine and alkyl pyrrolidines or mixtures
of alkyl
pyrrolidines, indole and alkyl indoles or mixture of alkyl indoles, imidazole
and alkyl
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imidazole or mixtures of alkyl imidazole, quinoline and alkyl quinoline or
mixture of
alkyl quinoline, isoquinoline and alkyl isoquinoline or mixture of alkyl
isoquinoline,
pyrazine and alkyl pyrazine or mixture of alkyl pyrazine, quinoxaline and
alkyl
quinoxaline or mixture of alkyl quinoxaline, acridine and alkyl acridine or
mixture of alkyl
acridine, pyrimidine and alkyl pyrimidine or mixture of alkyl pyrimidine,
quinazoline and
alkyl quinazoline or mixture of alkyl quinazoline, or any derivative of any of
the foregoing,
and any combination of the foregoing..
For the phosphate ester component of the amine/phosphate ester tackifying
agents, suitable phosphate esters include, without limitation, any phosphate
ester that is
to capable of reacting with a suitable amine to form a composition that
forms a
deformable coating on a metal-oxide containing surface or partially or
completely coats
particulate materials. Exemplary examples of such phosphate esters include,
without
limitation, any phosphate esters of the general formula P(0)(0R3)(0R4)(0R5) or
mixture or
combinations thereof, where R3, R4, and OR5 are independently a hydrogen atom
or a
carbyl group having between about between about 1 and 40 carbon atoms and the
required
hydrogen atoms to satisfy the valence and where one or more of the carbon
atoms can be
replaced by one or more hetero atoms selected from the group consisting of
boron, nitrogen,
oxygen, phosphorus, sulfur or mixture or combinations thereof and where one or
more
of the hydrogen atoms can be replaced by one or more single valence atoms
selected
from the group consisting of fluorine, chlorine, bromine, iodine or mixtures
or
combinations thereof. Exemplary examples of phosphate esters include, without
limitation,
phosphate ester of alkanols having the general formula P(0)(OH)õ(0R6)y where
x+y=3
and are independently a hydrogen atom or a carbyl group having between about
between
about 1 and 40 carbon atoms and the required hydrogen atoms to satisfy the
valence and
where one or more of the carbon atoms can be replaced by one or more hetero
atoms selected
from the group consisting of boron, nitrogen, oxygen, phosphorus, sulfur or
mixture or
combinations thereof and where one or more of the hydrogen atoms can be
replaced by
one or more single valence atoms selected from the group consisting of
fluorine,
chlorine, bromine, iodine or mixtures or combinations thereof such as ethoxy
phosphate, propoxyl phosphate or higher alkoxy phosphates or mixtures or
combinations
thereof. Other exemplary examples of phosphate esters include, without
limitation, phosphate
esters of alkanol amines having the general formula MR7OP(0)(OH)213 where R7
is a
carbonyl group having between about between about 1 and 40 carbon atoms and
the required
hydrogen atoms to satisfy the valence and where one or more of the carbon
atoms can be
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replaced by one or more hetero atoms selected from the group consisting of
boron,
nitrogen, oxygen, phosphorus, sulfur or mixture or combinations thereof and
where one or
more of the hydrogen atoms can be replaced by one or more single valence atoms
selected
from the group consisting of fluorine, chlorine, bromine, iodine or mixtures
or
combinations thereof group including the tri-phosphate ester of tri-ethanol
amine or mixtures
or combinations thereof. Other exemplary examples of phosphate esters include,
without
limitation, phosphate esters of hydroxylated aromatics such as phosphate
esters of alkylated
phenols such as Nonylphenyl phosphate ester or phenolic phosphate esters.
Other
exemplary examples of phosphate esters include, without limitation, phosphate
esters
to of diols and polyols such as phosphate esters of ethylene glycol,
propylene glycol, or
higher glycolic structures. Other exemplary phosphate esters include any
phosphate ester than
can react with an amine and coated on to a substrate forms a deformable
coating enhancing
the aggregating potential of the substrate.
Multifunctional materials suitable for use in the present invention include,
but are not
limited to, aldehydes, dialdehydes such as glutaraldehyde, hemiacetals or
aldehyde releasing
compounds, diacid halides, dihalides such as dichlorides and dibromides,
polyacid
anhydrides such as citric acid, epoxides, furfuraldehyde, glutaraldehyde,
aldehyde
condensates, and silyl-modified polyamide compounds and the like, and
combinations thereof.
Suitable silylmodified polyamide compounds that may be used in the present
invention are
those that are substantially self-hardening compositions capable of at least
partially adhering
to particulates in the unhardened state, and that are further capable of self-
hardening
themselves to a substantially non-tacky state to which individual particulates
such as
formation fines will not adhere to, for example, in formation or proppant pack
pore throats.
Such silyl-modified polyamides may be based, for example, on the reaction
product of
a silating compound with a polyamide or a mixture of polyamides. The polyamide
or
mixture of polyamides may be one or more polyamide intermediate compounds
obtained, for
example, from the reaction of a polyacid (e.g., diacid or higher) with a
polyamine (e.g.,
diamine or higher) to form a polyamide polymer with the elimination of water.
In some embodiments of the present invention, the multifunctional material
may be mixed with a tackifying compound in an amount of from about 0.01% to
about 50%
by weight of the tackifying compound to effect formation of the reaction
product. In other
embodiments, the compound is present in an amount of from about 0.5% to about
1% by
weight of the tackifying compound. Suitable multifunctional materials are
described in U.S.
Pat. No. 5,839,510 issued to Weaver, et al., the relevant disclosure of which
is herein
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incorporated by reference.
In embodiments where the consolidating agent is used in an emulsion form, the
consolidating agent emulsions of the present invention comprise an aqueous
fluid, a
surfactant, and a consolidating agent. These consolidating agent emulsions
have water
external phases and oil internal phases. Suitable consolidating agents for the
emulsion
embodiments comprise all of the consolidating agents listed above. The
consolidating agent
may be present in an amount in the range from about 0.1% to about 10% by
weight of
the composition. The surfactant is preferably present in the consolidating
agent emulsion in
an amount in the range from about 0.1% to 10% by weight of the composition.
The balance
of the fluid is the aqueous base fluid (e.g., 40% to 97% by weight of the
consolidating
agent emulsion composition). Suitable emulsions are described in U.S. Patent
Publication
No. 20070187097, the disclosure of which is hereby incorporated by reference.
Suitable aqueous fluids that may be used in the consolidating agent emulsions
embodiments of the present invention include fresh water, salt water, brine,
seawater, or any
other aqueous fluid that, preferably, does not adversely react with the other
components used
in accordance with this invention or with the subterranean formation. One
should note,
however, that if long-term stability of the emulsion is desired, the preferred
aqueous fluid is
one that is substantially free of salts. It is within the ability of one
skilled in the art with the
benefit of this disclosure to determine if and how much salt may be tolerated
in the
consolidating agent emulsions of the present invention before it becomes
problematic
for the stability of the emulsion. Surfactants that may be suitable in the
emulsion
embodiments are those that are capable of emulsifying an oil-based component
in a
water-based component so that the emulsion has a water external phase and an
oil
internal phase. A preferred surfactant is an amine surfactant. Such preferred
amine
surfactants include, but are not limited to, amine ethoxylates and amine
ethoxylated
quaternary salts such as tallow diamine and tallow triamine exthoxylates and
quaternary
salts. Examples of suitable surfactants are ethoxylated C12-C22 diamine,
ethoxylated
C12-C22 triamine, ethoxylated C12-C22 tetraamine, ethoxylated Ci2-C22 diamine
methylchloride
quat, ethoxylated C12-C22 triamine methylchloride quat, ethoxylated C12-C22
tetraamine
methylchloride quat, ethoxylated C12-C22 diamine reacted with sodium
chloroacetate,
ethoxylated C12-C22 triamine reacted with sodium chloroacetate, ethoxylated
C12-C22
tetraamine reacted with sodium chloroacetate, ethoxylated C12-C22 diamine
acetate salt,
ethoxylated C12-C22 diamine hydrochloric acid salt, ethoxylated C12-C22
diamine glycolic acid
salt, ethoxylated C12- C22 diamine DDBSA salt, ethoxylated C12-C22 triamine
acetate salt,
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ethoxylated C12-C22 triamine hydrochloric acid salt, ethoxylated C12-C22
triamine glycolic
acid salt, ethoxylated C12-C22 triamine DDBSA salt, ethoxylated C12-C22
tetraamine
acetate salt, ethoxylated C12-C22 tetraamine hydrochloric acid salt,
ethoxylated C12-C22
tetraamine glycolic acid salt, ethoxylated C12-C22 tetraamine DDBSA salt,
pentamethylated
C12-C22 diamine quat, heptamethylated C12-C22 diamine quat, nonamethylated C12-
C22
diamine quat, and combinations thereof.
In some embodiments of the present invention the amine surfactant may have the
general formula: wherein R is a C12-C22 aliphatic hydrocarbon; R is
independently
selected from hydrogen or CI to C3 alkyl group; A is NH or 0, and x+y has a
value greater
to than or equal to one but also less than or equal to three. Preferably
the R group is a
non-cyclic aliphatic. In some embodiments, the R group contains at least one
degree of
unsaturation that is to say at least one carbon-carbon double bond. In other
embodiments the
R group may be a commercially recognized mixture of aliphatic hydrocarbons
such as soya,
which is a mixture of C14 to C20 hydrocarbons, or tallow which is a mixture of
C16 to C20
aliphatic hydrocarbons, or tall oil which is a mixture of C14 to cts aliphatic
hydrocarbons. In
other embodiments, one in which the A group is NH, the value of x+y is
preferably two with
x having a preferred value of one. In other embodiments in which the A group
is 0, the
preferred value of x+y is two with the value of x being preferably one. One
example of a
commercially available amine surfactant is TER 2168 Series available from
Champion
Chemicals located in Fresno, Tex. Other commercially available examples
include Ethomeen
T/12 a diethoxylated tallow amine; Ethomeen S/12 a diethoxylated soya amine;
Duomeen
0 a N-oley1-1,3-diaminopropane, Duomeen T a N-tallow-1,3- diaminopropane, all
of which are available from Akzo Nobel.
In other embodiments, the surfactant is a tertiary alkyl amine ethoxylate (a
cationic
surfactant). 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.
In other embodiments, the surfactant is a combination of 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 30 to about 45% by weight
of the
surfactant mixture and from about 55 to about 70% by weight of the surfactant
mixture, respectively. 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
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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 yet other embodiments, the surfactant is a nonionic surfactant. Such
preferred
nonionic surfactants include, but are not limited to, alcohol oxylalkylates,
alkyl phenol
oxylalkylates, nonionic esters such as sorbitan esters and alkoxylates of
sorbitan
esters. Examples of suitable surfactants include but are not limited to,
castor oil alkoxylates,
fatty acid alkoxylates, lauryl alcohol alkoxylates, nonylphenol alkoxylates,
octylphenol
to alkoxylates, tridecyl alcohol alkoxylates, such as POE-10 nonylphenol
ethoxylate, POE-100
nonylphenol ethoxylate, POE-12 nonylphenol ethoxylate, POE-12 octylphenol
ethoxylate,
POE-12 tridecyl alcohol ethoxylate, POE-14 nonylphenol ethoxylate, POE-15
nonylphenol
ethoxylate, POE-18 tridecyl alcohol ethoxylate, POE-20 nonylphenol ethoxylate,
POE-20
oleyl alcohol ethoxylate, POE-20 stearic acid ethoxylate, POE-3 tridecyl
alcohol
ethoxylate, POE-30 nonylphenol ethoxylate, POE-30 octylphenol ethoxylate,
POE-34 nonylphenol ethoxylate, POE-4 nonylphenol ethoxylate, POE-40 castor oil
ethoxylate, POE-40 nonylphenol ethoxylate, POE-40 octylphenol ethoxylate, POE-
50
nonylphenol ethoxylate, POE-50 tridecyl alcohol ethoxylate, POE-6 nonylphenol
ethoxylate, POE-6 tridecyl alcohol ethoxylate, POE-8 nonylphenol ethoxylate,
POE-9
octylphenol ethoxylate, mannide monooleate, sorbitan isostearate, sorbitan
laurate, sorbitan
monoisostearate, sorbitan monolaurate, sorbitan monooleate, sorbitan
monopalmitate,
sorbitan monostearate, sorbitan oleate, sorbitan palmitate, sorbitan
sesquioleate, sorbitan
stearate, sorbitan trioleate, sorbitan tristearate, POE-20 sorbitan
monoisostearate
ethoxylate, POE-20 sorbitan monolaurate ethoxylate, POE-20 sorbitan monooleate
ethoxylate,
POE-20 sorbitan monopalmitate ethoxylate, POE-20 sorbitan monostearate
ethoxylate,
POE-20 sorbitan trioleate ethoxylate, POE-20 sorbitan tristearate ethoxylate,
POE-30
sorbitan tetraoleate ethoxylate, POE-40 sorbitan tetraoleate ethoxylate, POE-6
sorbitan
hexastearate ethoxylate, POE-6 sorbitan monstearate ethoxylate, POE-6 sorbitan
tetraoleate
ethoxylate, and/or POE-60 sorbitan tetrastearate ethoxylate. Preferred
nonionic surfactants
include alcohol oxyalkyalates such as POE-23 lauryl alcohol and alkyl phenol
ethoxylates such as POE (20) nonyl phenyl ether. Other applicable nonionic
surfactants are
esters such as sorbitan monooleate.
While cationic, amphoteric, and nonionic surfactants are preferred, any
suitable
emulsifying surfactant can be used. Good surfactants for emulsification
typically need to be
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either ionic to give charge stabilization or have long groups for steric
stability in water. This
would include other cationic surfactants and even anionic surfactants.
Examples include, but
are not limited to, hexahydro-1,3,5-tris(2-hydroxyethyl)triazine, alkyl ether
phosphate,
ammonium lauryl sulfate, ammonium nonylphenol ethoxylate sulfate, branched
is amine dodecylbenzene sulfonate, branched sodium dodecylbenzene
sulfonate,
dodecylbenzene sulfonic acid, branched dodecylbenzene sulfonic acid, fatty
acid
sulfonate potassium salt, phosphate esters, POE-1 ammonium lauryl ether
sulfate, POE-1
sodium lauryl ether sulfate, POE-10 nonylphenol ethoxylate phosphate ester,
POE-12
ammonium lauryl ether sulfate, POE-12 linear phosphate ester, POE-12 sodium
lauryl ether
to sulfate, POE-12 tridecyl alcohol phosphate ester, POE-2 ammonium lauryl
ether sulfate,
POE-2 sodium lauryl ether sulfate, POE-3 ammonium lauryl ether sulfate, POE-3
disodium
alkyl ether sulfosuccinate, POE-3 linear phosphate ester, POE-3 sodium lauryl
ether sulfate,
POE-3 sodium octylphenol ethoxylate sulfate, POE-3 sodium tridecyl ether
sulfate, POE-3
tridecyl alcohol phosphate ester, POE-30 ammonium lauryl ether sulfate, POE-30
sodium
lauryl ether sulfate, POE-4 ammonium lauryl ether sulfate, POE-4 ammonium
nonylphenol ethoxylate sulfate, POE-4 nonyl phenol ether sulfate, POE-4
nonylphenol ethoxylate phosphate ester, POE-4 sodium lauryl ether sulfate, POE-
4 sodium
nonylphenol ethoxylate sulfate, POE-4 sodium tridecyl ether sulfate, POE-50
sodium lauryl
ether sulfate, POE-6 disodium alkyl ether sulfosuccinate, POE-6 nonylphenol
ethoxylate
phosphate ester, POE-6 tridecyl alcohol phosphate ester, POE-7 linear
phosphate ester,
POE-8 nonylphenol ethoxylate phosphate ester, potassium dodecylbenzene
sulfonate, sodium
2-ethyl hexyl sulfate, sodium alkyl ether sulfate, sodium alkyl sulfate,
sodium alpha olefin
sulfonate, sodium decyl sulfate, sodium dodecylbenzene sulfonate, sodium
lauryl sulfate,
sodium lauryl sulfoacetate, sodium nonylphenol ethoxylate sulfate, and/or
sodium octyl
sulfate.
The clean-up fluids of the present invention may also be used in other methods
that
are useful for subterranean applications.
In one embodiment, a method of the present invention may comprise providing a
clean-up fluid comprising a peroxide-generating compound and an aqueous base
fluid;
placing the clean-up fluid in a subterranean formation; allowing the clean-up
fluid to
penetrate a portion of the subterranean formation (such as an interval of the
formation,
an interval comprising proppant or gravel, an interval of a propped fracture
comprising a
proppant pack, a section of a well bore comprising a sand control screen with
or without a
gravel pack, a portion of a well bore comprising a slotted or perforated
liner, or a
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portion of a well bore comprising an expandable screen); and allowing the
clean-up fluid to
remove contaminants from the portion of the subterranean formation to form a
cleaned
portion of the subterranean formation. The cleaned portion of the formation
may comprise
"cleaned flow paths," which are flow paths in which contaminants have been
removed
from those flow paths to enable hydrocarbons to flow through them. These flow
paths
may be production or injection flow paths.
In one embodiment, the present invention provides a method that comprises:
providing a clean-up fluid comprising a peroxide-generating compound and an
aqueous
base fluid; providing proppant, formation sand, fines, drill cuttings, or any
solids that
comprise contaminants (collectively referred to herein as "contaminated well
solids");
contacting the contaminated well solids with the clean-up fluid; separating
the contaminants
from the well solids; and disposing of the solids.
In one embodiment, a clean-up fluid of the present invention may be injected
into a well bore before a squeeze method. This method of pressure squeezing a
cementitious composition into cracks and perforations is known in the art as a
squeeze
cementing procedure. In various embodiments, the cementitious compositions of
the present
teachings can be used in any commonly acceptable method of squeeze cementing.
Examples
of such methods can include: a "Bradenhead squeeze method," a "Spotting
squeeze
method" and a "Bullhead squeeze method." Common to all such methods is the
introduction
of a cementitious composition into the perforations in the casing, liner, or
primary cementing
structure under pressure. The procedure can be facilitated with various packer
devices
126 commonly used in the art of remedial cementing operations. For example,
such
packer devices 126can be commercially available from Baker Hughes, and
Halliburton,
both of Houston, Tex., United States and World Oil Tools, Inc., of Calgary,
Canada. Another
embodiment of the present invention provides a method comprising: introducing
a
peroxide-generating compound into a desired location in a subterranean
formation,
wherein the peroxide-generating compound further comprises a chemical
moderator
that acts to inhibit the reaction of the hydrogen peroxide within the
subterranean
formation; and later, allowing the peroxide-generating compound to generate
peroxide
in the desired location in the subterranean formation to remove contaminants
therefrom.
To facilitate a better understanding of the present invention, the following
examples
of certain aspects of some embodiments are given. In no way should the
following examples
be read to limit, or define, the entire scope of the invention.
Examples
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Below is a discussion of representative tests.
A first test was used to determine the loss-on-ignition ("LOI") value of
plain,
uncoated 20/40 mesh Brady sand to provide the basis value of organic material
that may exist
on the sand.
In a second test, heavy crude oil in the amount of 3 cc was dry coated on 100
grams
of 20/40 mesh sand. The coated sand was then mixed in 100 cc of tap water and
decanted. This step was repeated again one more time. LOI value was determined
for
this crude-oil coated sand.
In a third test, heavy crude oil in the amount of 3 cc was dry coated on 100
grams of
to 20/40 mesh Brady sand. The coated sand was then mixed in 100 cc of clean-
up
solution containing 5% w/v "OXICLEAN" for 1 minute and decanted. This step was
repeated again one more time. LOI value was determined for this cleaned sand.
Table 1 below shows a summary of the LOI results of Tests 1 through 3
described
above.
Table 1
Test No. Test Description LOI%
1 Plain 20/40 Brady sand - control sample 0.03
2 3% v/w heavy crude oil dry coated on 20/40 2.81
Brady sand - stirred in tap water (2 times)
5 3% (v/w) heavy crude oil dry coated on 20/40 0.15
Brady sand - stir in clean-up solution
containing 5% w/v of "OXICLEAN" (2 times)
The purpose of the next two steps is to demonstrate the effectiveness of using
a
clean-up fluid of the present invention to enhance the coating of a
consolidation agent on to
proppant (e.g., as part of a remedial proppant treatment in controlling
proppant flowback).
Without effective contaminant removal, it is believed that the consolidation
strength
resulting from resin strength is decreased.
In this test, 190 grams of 20/40 mesh Brady sand was packed in a brass flow
cell.
The sand pack was saturated with 100 cc of a light crude oil (>2 pore volumes
of sand pack),
and heated to 150 F and held at the temperature for approximately 2 hours. A
volume of
150 mL of a clean-up fluid of the invention was prepared from 3% KC1
containing 5%w/v
of "OXICLEAN" was injected and flushed through the sand pack with a peristatic
pump at a
flow rate of 20mL/min. Next, a foam of 100 mL of 3% KC1 brine containing 0 5%
19N
surfactant and 0.5% "HC-2" foaming agent (both available from Halliburton
Energy
Services, in Duncan, OK) was flushed through the sand pack at 50 ml/min. Next,
a foam of
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100 mL of a curable, water-based resin emulsion containing 0.5% "HC-2" foaming
agent
was flushed through the sand pack at 50 mL/min. After the resin treatment, a
volume of
50mL of diesel was used to flush the line and flushed through the sand treated
sand pack.
The packed flow cell was then capped at both ends and allowed to cure at 150 F
for 3 days.
After curing, the consolidated sand pack was extruded from the flow cell and
cut into core
sizes for unconfined compressive strength (UCS) and tensile strength
measurements. The
results were: UCS = 845 psi, Tensile = 210 psi.
In another test, 190 grams of 20/40-mesh bauxite proppant was packed in a
brass
flow cell. The pack was saturated with 100 cc of a heavy crude oil (>2 pore
volumes of the
to pack) and heated to 150 F and remained at this temperature for 2 hours.
A volume of 150
mL of a clean-up fluid of the invention was prepared from 3% KC1 containing
5%w/v of
"OXICLEAN" was injected and flushed through the pack with a peristatic pump at
a flow
rate of 20mL/min. Next, a foam of 100 mL of 3% KC1 brine containing 0.5% "19N"
surfactant and 0.5% "HC-2" foaming agent (both available from Halliburton
Energy
Services, in Duncan, OK) was flushed through the pack at 50 ml/min. Next, a
foam of 100
mL of a curable, water-based resin emulsion containing 0.5% "HC-2" foaming
agent was
flushed through the sand pack at 50 mL/min. After the resin treatment, a
volume of 50mL of
diesel was used to flush the line and flushed through the sand treated sand
pack. The packed
flow cell was then capped at both ends and allowed to cure at 150 F for 3
days. After curing,
the consolidated sand pack was extruded from the flow cell and cut into core
sizes for
unconfined compressive strength (UCS) and tensile strength measurements. The
results were:
UCS = 615 psi, Tensile = 240 psi.
To examine the effect of using an aqueous-based formation condition fluid in
removing hydrocarbons to prepare a proppant pack, the following was performed.
A
water based formation condition fluid of the present invention was used in
place of a
mutual solvent. This formation condition fluid was prepared in brine solution
and applied as
part of the first preflush to remove contaminants such as oil residue, frac-
gel remnant, or any
debris material that needed to be removed from the proppant pack before the
subsequent preflush fluid to precondition the proppant surface for enhancing
the wetting
of WBR. The treatment procedure included the following steps:
Preparing 20/40-mesh Brady sand in flow cell;
Saturating proppant pack with diesel or crude oil and heating to temperature
with heat tape and thermocouple, maintaining temperature during treatment;
Treating Preflush 1 by injecting two or three pore volumes of a water based
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cleanup solution;
Treating Preflush 2 by injecting a foam prepared from two pore volumes of
3%-KC1 brine containing 0.5% (v/v) cationic surfactant and 0.5% (v/v) foaming
agent;
Treating consolidation fluid by injecting a foam prepared from two pore
volumes of
WBR Formulation C solution containing 0.5% (v/v) foaming agent;
Treating post-flush by injecting one pore volume of diesel; and [0072] Curing
at
designed temperature and duration.
After curing, cores were obtained from the consolidated proppant packs for
measurements of UCS and tensile strength. The results of this test series
(Table 2) show that
to water-based cleanup solution effectively removed hydrocarbon, such as
diesel, light and
heavy crudes, with similar performance compared to that of the mutual solvent.
The use
of foamed WBR treatment fluid and diesel post-flush greatly enhances the
consolidation
performance of WBR-treated proppant packs.
Table 2
Test Proppant Pretreatment Treatment Volume of
Cure Cure UCS, Tensile,
No. Type Fluid
Temperature, Formation Temp., Time, psi psi
'I' Condition 'I' hr
Fluid
1 20/40 Diesel 150 3 230 20 610
55
mesh,
Brady
2 20/40 Diesel 150 3 230 20 435
105
mesh,
Brady
3 20/40 Diesel 200 None 200 20 435
130
mesh,
Brady
4 20/40 Diesel 200 2 200 20 895
275
mesh,
Brady
5 20/40 Light Crude 150 3 150 72 845
210
mesh,
Brady
6 20/40 Heavy Crude 250 3 250 72 645
240
mesh,
bauxite
For this test, a hydraulic fracturing treatment was simulated with the mixing
and packing of proppant with crosslinked frac fluid in the flow cell, allowing
the
crosslinked fluid to break, removing the broken gel from the pack, and then
treating the
proppant pack with PropStop ABC system. Procedure. First, 16/20 Carbolite was
packed in a
45# Hybor H crosslinked fluid in brass cell. Then the crosslinked fracturing
fluid was
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broken after 3-hour shut-in period at 250 F. Then a treatment was performed
where a
preflush 1 of 3% KC1 containing 3% "FDP-S929-09" (available from Halliburton
Energy
Services, Inc.) to clean up the broken gel, and then a preflush 2 was used
that contained a
Foamed brine including 19N. Then a resin treatment was applied using a "Foamed
FDP-S867" (available from Halliburton Energy Services) resin mixture. A
postflush of
diesel was then used. Then the pack was allowed to cure at 250 F for 20 hours.
The results
showed a regained permeability of about 90% and a UCS of 420 psi and a tensile
strength
of 145 psi.
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.
While compositions and methods are described in terms of
"comprising," "containing," or "including" various components or steps, the
compositions
and methods can also "consist essentially of or "consist of the various
components and
steps. All numbers and ranges disclosed above may vary by some amount.
Whenever a
numerical range with a lower limit and an upper limit is disclosed, any number
and any
included range falling within the range is specifically disclosed. In
particular, every range
of values (of the form, "from about a to about b," or, equivalently, "from
approximately
a to b," or, equivalently, "from approximately a-b") disclosed herein is to be
understood
to set forth every number and range encompassed within the broader range of
values.
Also, the terms in the claims have their plain, ordinary meaning unless
otherwise
explicitly and clearly defined by the patentee. Moreover, the indefinite
articles "a" or
"an", as used in the claims, are defined herein to mean one or more than one
of the
element that it introduces.
