Note: Descriptions are shown in the official language in which they were submitted.
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COMPOSITIONS AND METHODS FOR CONTROLLING
UNCONSOLIDATED PARTICULATES
BACKGROUND
The present invention relates to the stabilization of subterranean formations.
More particularly, the present invention relates to improved methods for
stabilizing
unconsolidated or weakly consolidated zones of a subterranean formation.
Hydrocarbon wells are often located in subterranean zones that contain
unconsolidated particulates that may migrate out of the subterranean formation
with the oil,
gas, water, and/or other fluids produced by the wells. The presence of
particulates, such as
formation sand, in produced fluids is undesirable in that the particulates may
abrade pumping
and other producing equipment and reduce the fluid production capabilities of
the producing
zones. Unconsolidated subterranean zones include those that contain loose
particulates and
those wherein the bonded particulates have insufficient bond strength to
withstand the forces
produced by the production of fluids through the zones.
One method of controlling particulates in such unconsolidated subterranean
zones has been to produce fluids from the formations at low flow rates,
whereby the near well
stability of sand bridges and the like may be substantially preserved.
However, the collapse
of such sand bridges may occur due to unintentionally high production rates
and/or pressure
cycling as may occur from repeated shut-ins and start ups of a well. The
frequency of
pressure cycling is very critical to the longevity of the near well formation,
especially during
the depletion stage of the well when the pore pressure of the formation has
already been
significantly reduced.
Another method of controlling particulates in unconsolidated subterranean
zones is gravel packing. Gravel packing involves placing a filtration bed
containing gravel
near the well bore in order to present a physical barrier to the transport of
unconsolidated
formation fines with the production of hydrocarbons. Typically, gravel packing
operations
involve the pumping and placement of a quantity of a desired particulate into
an area adjacent
to a well bore in an unconsolidated or weakly consolidated formation. Such
packs may be
time consuming and expensive to install. Weakly consolidated formations also
have been
treated by creating fractures in the formations and depositing proppant in the
fractures
wherein the proppant is consolidated within the fractures into hard, permeable
masses using a
resrn or taclcifying composrtron to redrnce the rrrigrati~n of sand. gn some
situations tlae
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processes of fracturing and gravel packing are combined into a single
treatment to provide a
stimulated production and an annular gravel pack to prevent formation sand
production.
Such treatments are often referred to as "frac pack" operations.
Another method used to control particulates in unconsolidated formations
involves consolidating unconsolidated subterranean producing zones into hard
permeable
masses by applying a resin followed by a spacer fluid and then a catalyst.
Such methods may
be problematic when, for example, an insufficient amount of spacer fluid is
used between the
application of the resin and the application of the external catalyst. In that
case, the resin may
come into contact with the external catalyst in the well bore itself rather
than in the
unconsolidated subterranean producing zone. When resin is contacted with an
external
catalyst an exothermic reaction occurs that may result in rapid
polymerization, potentially
damaging the formation by plugging the pore channels, halting pumping when the
well bore
is plugged with solid material, or resulting in a down hole explosion as a
result of the heat of
polymerization. Also, using resins to consolidate unconsolidated zones may not
be practical
due, at least in part, to the high cost of most suitable resins.
Thus, there is a need for improved methods of stabilizing and stimulating
fluid production from unconsolidated or weakly consolidated zones of
subterranean
formations while preventing the undesired migration of formation particulates
with fluids
produced therefrom.
SUMMARY OF THE INVENTION
The present invention relates to the stabilization of subterranean formations.
More particularly, the present invention relates to improved methods for
stabilizing
unconsolidated or weakly consolidated zones of a subterranean formation.
One embodiment of the present invention provides a method of stabilizing
an unconsolidated or weakly consolidated subterranean formation comprising the
steps of
placing a getable liquid composition into the subterranean formation; and,
allowing the
getable liquid composition to convert into a gelled substance that at least
partially stabilizes
unconsolidated or weakly consolidated particles within the subterranean
formation.
Another embodiment of the present invention provides a method of
stimulating production from an unconsolidated or weakly consolidated
subterranean
formation penetrated by a well bore comprising the steps of placing a getable
liquid
co°n~osition into ghe subtergaraean ~'~~ation; allowing the getable
liquid c~mp~siti~n t~ f~rm
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a gelled substance; creating at least one fracture in the subterranean
formation that extends
through the gelled substance, and into a zone of the subterranean formation;
and depositing
proppant into the fracture.
Another embodiment of the present invention provides a method of
stimulating production from an unconsolidated or weakly consolidated
subterranean
formation penetrated by a well bore comprising the steps of placing a getable
liquid
composition into the subterranean formation, wherein the getable liquid
composition
comprises a polyepoxide resin, a diluent, a flexibilizer additive, and a resin
curing agent;
allowing the getable liquid composition to form a gelled substance; creating
at least one
fracture in the subterranean formation extending through the gelled substance
and into a zone
of the subterranean formation; and depositing proppant into the fracture.
Other and further features and advantages of the present invention will be
readily apparent to those skilled in the art upon a reading of the description
of preferred
embodiments that follows.
DESCRIPTION OF PREFERRED EMBODIMENTS
The present invention relates to the stabilization of subterranean formations.
More particularly, the present invention relates to improved methods for
stabilizing
unconsolidated or weakly consolidated zones of a subterranean formation.
Certain embodiments of the present invention comprise placing a getable
liquid composition into a subterranean formation, and allowing the getable
liquid
composition to convert into a gelled substance that stabilizes unconsolidated
or weakly
consolidated particles within the subterranean formation.
The getable liquid composition may be any getable liquid composition
capable of converting into a gelled substance capable of substantially
plugging the
permeability of the formation while allowing the formation to remain flexible.
That is, the
gelled substance should negatively impact the ability of the formation to
produce desirable
fluids such as hydrocarbons. As referred to herein, the term "flexible" refers
to a state
wherein the treated formation is relatively malleable and elastic and able to
withstand
substantial pressure cycling without substantial breakdown of the formation.
Thus, the
resultant gelled substance should be a semi-solid, immovable, gel-like
substance, which,
among other things, stabilizes the treated portion of the formation while
allowing the
formation to absorb the stresses created duY~ing pressure cycling. As a
result, the gelled
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substance may aid in preventing breakdown of the formation both by stabilizing
and by
adding flexibility to the formation sands. Examples of suitable gelable liquid
compositions
include, but are not limited to, resin compositions that cure to form flexible
gels, gelable
aqueous silicate compositions, crosslinkable aqueous polymer compositions, and
polymerizable organic monomer compositions.
Certain embodiments of the getable liquid compositions of the present
invention comprise curable resin compositions. Curable resin compositions are
well known
to those skilled in the art and have been used to consolidate portions of
unconsolidated
formations and to consolidate proppant materials into hard, permeable masses.
While the
curable resin compositions used in accordance with the present invention may
be similar to
those previously used to consolidate sand and proppant into hard, permeable
masses, they are
distinct in that resins suitable for use with the present invention do not
cure into hard,
permeable masses; rather they cure into flexible, gelled substances That is,
suitable curable
resin compositions form resilient gelled substances between the particulates
of the treated
zone of the unconsolidated formation and thereby allow that portion of the
formation to
remain flexible and to resist breakdown. It is not necessary or desirable for
the cured resin
composition to solidify and harden to provide high consolidation strength to
the treated
portion of the formation. On the contrary, upon being cured, the curable resin
compositions
useful in accordance with this invention form semi-solid, immovable, gelled
substances.
Generally, the curable resin compositions useful in accordance with this
invention comprise a curable resin, a diluent, and a resin curing agent. When
certain resin
curing agents, such as polyamides, are used in the curable resin compositions,
the
compositions form the semi-solid, immovable, gelled substances described
above. Where the
resin curing agent used may cause the organic resin compositions to form hard,
brittle
material rather than a desired gelled substance, the curable resin
compositions may further
comprise one or more "flexibilizer additives" (described in more detail below)
to provide
flexibility to the cured compositions.
Examples of curable resins that can be used in the curable resin
compositions of the present invention include, but are not limited to, organic
resins such as
polyepoxide resins (e.g., bisphenol A-epichlorihydrin resins), polyester
resins, urea-aldehyde
resins, furan resins, urethane resins, and mixtures thereof. Of these,
polyepoxide resins are
preferred.
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Any diluent that is compatible with the curable resin and achieves the
desired viscosity effect is suitable for use in the present invention.
Examples of diluents that
may be used in the curable resin compositions of the present invention
include, but are not
limited to, phenols; formaldehydes; furfuryl alcohols; furfurals; alcohols;
ethers such as butyl
glycidyl ether and cresyl glycidyl etherphenyl glycidyl ether; and mixtures
thereof. In some
embodiments of the present invention, the diluent comprises butyl lactate. The
diluent may
be used to reduce the viscosity of the curable resin composition to from about
3 to about
3,000 centipoises ("cP") at 80°F. Among other things, the diluent acts
to provide flexibility
to the cured composition. The diluent may be included in the curable resin
composition in an
amount sufficient to provide the desired viscosity effect. Generally, the
diluent used is
included in the curable resin composition in amount in the range of from about
5% to about
75% by weight of the curable resin.
Generally, any resin curing agent that may be used to cure an organic resin
is suitable for use in the present invention. When the resin curing agent
chosen is an amide
or a polyamide, generally no flexibilizer additive will be required because,
inter alia, such
curing agents cause the curable resin composition to convert into a semi-
solid, immovable,
gelled substance. Other suitable resin curing agents (such as an amine, a
polyamine,
methylene dianiline, and other curing agents known in the art) will tend to
cure into a hard,
brittle material and will thus benefit from the addition of a flexibilizer
additive. Generally,
the resin curing agent used is included in the curable resin composition,
whether a flexibilizer
additive is included or not, in an amount in the range of from about 5% to
about 75% by
weight of the curable resin. In some embodiments of the present invention, the
resin curing
agent used is included in the curable resin composition in an amount in the
range of from
about 20% to about 75% by weight of the curable resin.
As noted above, flexibilizer additives may be used, inter alia, to provide
flexibility to the gelled substances formed from the curable resin
compositions. Flexibilizer
additives should be used where the resin curing agent chosen would cause the
organic resin
composition to cure into a hard and brittle material - not the desired gelled
substances
described herein. For example, flexibilizer additives may be used where the
resin curing
agent chosen is not an amide or polyamide. Examples of suitable flexibilizer
additives
include, but are not limited to, an organic ester, an oxygenated organic
solvent, an aromatic
solvent, and c~a~hanatgO~aS thereof. Of these, ethers, such as dibutyl
phthalate, are preferred.
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Where used, the flexibilizer additive may be included in the curable resin
composition in an
amount in the range of from about 5% to about 80% by weight of the curable
resin. In some
embodiments of the present invention, the flexibilizer additive may be
included in the curable
resin composition in an amount in the range of from about 20% to about 45% by
weight of
the curable resin.
In other embodiments, the gelable liquid compositions of the present
invention may comprise a gelable aqueous silicate composition. Generally, the
getable
aqueous silicate compositions that are useful in accordance with the present
invention
generally comprise an aqueous alkali metal silicate solution and a temperature
activated
catalyst for gelling the aqueous alkali metal silicate solution.
The aqueous alkali metal silicate solution component of the getable aqueous
silicate compositions generally comprises an aqueous liquid and an alkali
metal silicate. The
aqueous liquid component of the aqueous alkali metal silicate solution
generally may be fresh
water, salt water (e.g., water containing one or more salts dissolved
therein), brine (e.g.,
saturated salt water), seawater, or any other aqueous liquid that does not
adversely react with
the other components used in accordance with this invention or with the
subterranean
formation. Examples of suitable alkali metal silicates include, but are not
limited to, one or
more of sodium silicate, potassium silicate, lithium silicate, rubidium
silicate, or cesium
silicate. Of these, sodium silicate is preferred. While sodium silicate exists
in many forms,
the sodium silicate used in the aqueous alkali metal silicate solution
preferably has a Na20-
to-Si02 weight ratio in the range of from about 1:2 to about 1:4. Most
preferably, the sodium
silicate used has a Na20-to-Si02 weight ratio in the range of about 1:3.2.
Generally, the
alkali metal silicate is present in the aqueous alkali metal silicate solution
component in an
amount in the range of from about 0.1% to about 10% by weight of the aqueous
alkali metal
silicate solution component.
The temperature activated catalyst component of the getable aqueous
silicate compositions is used, inter alia, to convert the getable aqueous
silicate compositions
into the desired semi-solid, immovable, gelled substance described above.
Selection of a
temperature activated catalyst is related, at least in part, to the
temperature of the
subterranean formation to which the getable aqueous silicate composition will
be introduced.
The temperature activated catalysts which can be used in the getable aqueous
silicate
compositions of the present invention include, but are not limited to,
~~nmonium sulfate,
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which is most suitable in the range of from about 60°F to about
240°F; sodium acid
pyrophosphate, which is most suitable in the range of from about 60°F
to about 240°F; citric
acid which is most suitable in the range of from about 60°F to about
120°F; and ethyl acetate
which is most suitable in the range of from about 60°F to about
120°F. Generally, the
temperature activated catalyst is present in the getable aqueous silicate
composition in the
range of from about 0.1% to about 5% by weight of the getable aqueous silicate
composition.
In other embodiments, the getable liquid compositions of the present
invention comprises crosslinkable aqueous polymer compositions. Generally,
suitable
crosslinkable aqueous polymer compositions comprise an aqueous solvent, a
crosslinkable
polymer, and a crosslinking agent.
The aqueous solvent may be any aqueous solvent in which the crosslinkable
composition and the crosslinking agent may be dissolved, mixed, suspended, or
dispersed
therein to facilitate gel formation. For example, the aqueous solvent used may
be fresh water,
salt water, brine, seawater, or any other aqueous liquid that does not
adversely react with the
other components used in accordance with this invention or with the
subterranean formation.
Examples of crosslinkable polymers that can be used in the crosslinkable
aqueous polymer compositions include, but are not limited to, carboxylate-
containing
polymers and acrylamide-containing polymers. Preferred acrylamide-containing
polymers
include polyacrylamide, partially hydrolyzed polyacrylamide, copolymers of
acrylamide and
acrylate, and carboxylate-containing terpolymers and tetrapolymers of
acrylate. Additional
examples of suitable crosslinkable polymers include hydratable polymers
comprising
polysaccharides and derivatives thereof and that contain one or more of the
monosaccharide
units galactose, mannose, glucoside, glucose, xylose, arabinose, fructose,
glucuronic acid, or
pyranosyl sulfate. Suitable natural hydratable polymers include, but are not
limited to, guar
gum, locust bean gum, tara, konjak, tamarind, starch, cellulose, karaya,
xanthan, tragacanth,
and carrageenan, and derivatives of all of the above. Suitable hydratable
synthetic polymers
and copolymers that may be used in the crosslinkable aqueous polymer
compositions include,
but are not limited to, polyacrylates, polymethacrylates, polyacrylamides,
malefic anhydride,
methylvinyl ether polymers, polyvinyl alcohols, and polyvinylpyrrolidone. The
crosslinkable
polymer used should be included in the crosslinkable aqueous polymer
composition in an
amount sufficient to form the desired gelled substance in the subterranean
formation. In
some embodiments of the present invention, the crosslinka~ble polymer is
included in the
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crosslinkable aqueous polymer composition in an amount in the range of from
about 1 % to
about 30% by weight of the aqueous solvent. In another embodiment of the
present
invention, the crosslinkable polymer is included in the crosslinkable aqueous
polymer
composition in an amount in the range of from about 1 % to about 20% by weight
of the
aqueous solvent.
The crosslinkable aqueous polymer compositions of the present invention
further comprise a crosslinking agent for crosslinking the crosslinkable
polymers to form the
desired gelled substance. In some embodiments, the crosslinking agent is a
molecule or
complex containing a reactive transition metal cation. A most preferred
crosslinking agent
comprises trivalent chromium cations complexed or bonded to anions, atomic
oxygen, or
water. Examples of suitable crosslinking agents include, but are not limited
to, compounds or
complexes containing chromic acetate and/or chromic chloride. Other suitable
transition
metal cations include chromium VI within a redox system, aluminum III, iron
II, iron III, and
zirconium N.
The crosslinking agent should be present in the crosslinkable aqueous
polymer compositions of the present invention in an amount sufficient to
provide, inter alia,
the desired degree of crosslinking. In some embodiments of the present
invention, the
crosslinking agent is present in the crosslinkable aqueous polymer
compositions of the
present invention in an amount in the range of from 0.01% to about 5% by
weight of the
crosslinkable aqueous polymer composition. The exact type and amount of
crosslinking
agent or agents used depends upon the specific crosslinkable polymer to be
crosslinked,
formation temperature conditions, and other factors known to those individuals
skilled in the
art.
Optionally, the crosslinkable aqueous polymer compositions may further
comprise a crosslinking delaying agent, such as a polysaccharide crosslinking
delaying agents
derived from guar, guar derivatives, or cellulose derivatives. The
crosslinking delaying agent
may be included in the crosslinkable aqueous polymer compositions, inter alia,
to delay
crosslinking of the crosslinkable aqueous polymer compositions until desired.
One of
ordinary skill in the art, with the benefit of this disclosure, will know the
appropriate amount
of the crosslinking delaying agent to include in the crosslinkable aqueous
polymer
compositions for a desired application.
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In other embodiments, the gelled liquid compositions of the present
invention comprise polymerizable organic monomer compositions. Generally,
suitable
polymerizable organic monomer compositions comprise an aqueous-base fluid, a
water-
soluble polymerizable organic monomer, an oxygen scavenger, and a primary
initiator.
The aqueous-base fluid component of the polymerizable organic monomer
composition generally may be fresh water, salt water, brine, seawater, or any
other aqueous
liquid that does not adversely react with the other components used in
accordance with this
invention or with the subterranean formation.
A variety of monomers are suitable for use as the water-soluble
polymerizable organic monomers in the present invention. Examples of suitable
monomers
include, but are not limited to, acrylic acid, methacrylic acid, acrylamide,
methacrylamide, 2-
methacrylamido-2-methylpropane sulfonic acid, 2-dimethylacrylamide, vinyl
sulfonic acid,
N,N-dimethylaminoethylmethacrylate, 2-triethylammoniumethylmethacrylate
chloride, N,N-
dimethyl-aminopropylmethacryl-amide, methacrylamidepropyltriethylammonium
chloride,
N-vinyl pyrrolidone, vinyl-phosphoric acid, and methacryloyloxyethyl
trimethylammonium
sulfate, and mixtures thereof. Preferably, the water-soluble polymerizable
organic monomer
should be self crosslinking. Examples of suitable monomers which are self
crosslinking
include, but are not limited to, hydroxyethylacrylate, hydroxymethylacrylate,
hydroxyethylmethacrylate, N-hydroxymethylacrylamide, N-hydroxymethyl-
methacrylamide,
polyethylene glycol acrylate, polyethylene glycol methacrylate, polypropylene
gylcol
acrylate, polypropylene glycol methacrylate, and mixtures thereof. Of these,
hydroxyethylacrylate is preferred. An example of a particularly preferable
monomer is
hydroxyethylcellulose-vinyl phosphoric acid.
The water-soluble polymerizable organic monomer (or monomers where a
mixture thereof is used) should be included in the polymerizable organic
monomer
composition in an amount sufficient to form the desired gelled substance after
placement of
the polymerizable organic monomer composition into the subterranean formation.
In some
embodiments of the present invention, the water-soluble polymerizable organic
monomers)
are included in the polymerizable organic monomer composition in an amount in
the range of
from about 1 % to about 30% by weight of the aqueous-base fluid. In another
embodiment of
the present invention, the water-soluble polymerizable organic monomers) are
included in
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the polymerizable organic monomer composition in an amount in the range of
from about 1%
to about 20% by weight of the aqueous-base fluid.
The presence of oxygen in the polymerizable organic monomer
composition may inhibit the polymerization process of the water-soluble
polymerizable
organic monomer or monomers. Therefore, an oxygen scavenger, such as stannous
chloride,
may be included in the polymerizable monomer composition. In order to improve
the
solubility of stannous chloride so that it may be readily combined with the
polymerizable
organic monomer composition on the fly, the stannous chloride may be pre-
dissolved in a
hydrochloric acid solution. For example, the stannous chloride may be
dissolved in a 0.1%
by weight aqueous hydrochloric acid solution in an amount of about 10% by
weight of the
resulting solution. The resulting stannous chloride-hydrochloric acid solution
may be
included in the polymerizable organic monomer composition in an amount in the
range of
from about 0.1% to about 10% by weight of the polymerizable organic monomer
composition. Generally, the stannous chloride may be included in the
polymerizable organic
monomer composition of the present invention in an amount in the range of from
about
0.005% to about 0.1% by weight of the polymerizable organic monomer
composition.
The primary initiator is used, inter alia, to initiate polymerization of the
water-soluble polymerizable organic monomers) used in the present invention.
Any
compound or compounds which form free radicals in aqueous solution may be used
as the
primary initiator. The free radicals act, inter alia, to initiate
polymerization of the water-
soluble polymerizable organic monomers) present in the polymerizable organic
monomer
composition. Compounds suitable for use as the primary initiator include, but
are not limited
to, alkali metal persulfates; peroxides; oxidation-reduction systems employing
reducing
agents, such as sulfites in combination with oxidizers; and azo polymerization
initiators.
Preferred azo polymerization initiators include 2,2'-azobis(2-imidazole-2-
hydroxyethyl)
propane, 2,2'-azobis(2-aminopropane), 4,4'-azobis(4-cyanovaleric acid), and
2,2'-azobis(2-
methyl-N-(2-hydroxyethyl) propionamide. Generally, the primary initiator
should be present
in the polymerizable organic monomer composition in an amount sufficient to
initiate
polymerization of the water-soluble polymerizable organic monomer(s). In
certain
embodiments of the present invention, the primary initiator is present in the
polymerizable
organic monomer composition in an amount in the range of from about 0.1% to
about 5% by
weight of the water-soluble polymerizable organic monomer(s).
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Optionally, the polymerizable organic monomer compositions further may
comprise a secondary initiator. A secondary initiator may be used, for
example, where the
immature aqueous gel is placed into a subterranean formation that is
relatively cool as
compared to the surface mixing, such as when placed below the mud line in
offshore
operations. The secondary initiator may be any suitable water-soluble compound
or
compounds that may react with the primary initiator to provide free radicals
at a lower
temperature. An example of a suitable secondary initiator is triethanolamine.
In some
embodiments of the present invention, the secondary initiator is present in
the polymerizable
organic monomer composition in an amount in the range of from about 0.1% to
about 5% by
weight of the water-soluble polymerizable organic monomer(s).
Optionally, the polymerizable organic monomer compositions of the
present invention further may comprise a crosslinking agent for crosslinking
the
polymerizable organic monomer compositions in the desired gelled substance. In
some
embodiments, the crosslinking agent is a molecule or complex containing a
reactive transition
metal cation. A most preferred crosslinking agent comprises trivalent chromium
cations
complexed or bonded to anions, atomic oxygen, or water. Examples of suitable
crosslinking
agents include, but are not limited to, compounds or complexes containing
chromic acetate
and/or chromic chloride. Other suitable transition metal cations include
chromium VI within
a redox system, aluminum III, iron II, iron III, and zirconium IV. Generally,
the crosslinking
agent may be present in polymerizable organic monomer compositions in an
amount in the
range of from 0.01% to about 5% by weight of the polymerizable organic monomer
composition.
In certain embodiments of the present invention, an optional pre-flush fluid
may be placed into the subterranean formation prior to the placement of the
getable liquid
compositions into the subterranean formation. The pre-flush fluid acts, inter
alia, to prepare
the subterranean formation for the later placement of the getable liquid
composition.
Generally, the volume of the pre-flush fluid placed into the formation is
between 0.1 to 50
times the volume of the getable liquid composition.
The pre-flush fluid may be any fluid that does not adversely react with the
other components used in accordance with this invention or with the
subterranean formation.
For example, the pre-flush fluid may be an aqueous-based fluid or a
hydrocarbon-based fluid.
In certain embodiments of the present invention, the pre-flush fluid may
comprise an aqueous
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liquid and a surfactant. The aqueous-liquid component may be fresh water, salt
water, brine,
or seawater, or any other aqueous-based liquid that does not adversely react
with the other
components used in accordance with this invention or with the subterranean
formation. Any
surfactant compatible with the later-used getable liquid composition and
capable of aiding the
getable liquid composition in flowing to the contact points between adjacent
particulates in
the formation may be used in the present invention. Such surfactants include,
but are not
limited to, ethoxylated nonyl phenol phosphate esters, mixtures of one or more
cationic
surfactants, one or more non-ionic surfactants, and an alkyl phosphonate
surfactant. Suitable
mixtures of one or more cationic and nonionic surfactants are described in
U.S. Patent No.
6,311,773 issued to Todd et al. on November 6, 2001, the disclosure of which
is incorporated
herein by reference. A C~ - C22 alkyl phosphonate surfactant is preferred. The
surfactant or
surfactants used are included in the pre-flush fluid in an amount sufficient
to prepare the
subterranean formation to receive a treatment of an immature aqueous gel. In
some
embodiments of the present invention, the surfactant is present in the pre-
flush fluid in an
amount in the range of from about 0.1% to about 3% by weight of the aqueous
liquid.
In certain embodiments of the present invention, after the placement of the
getable liquid composition into the subterranean formation, an optional after-
flush fluid may
be placed into the subterranean formation, inter alia, to restore the
permeability of the treated
portion of the subterranean formation. The after-flush fluid is preferably
placed into the
subterranean formation while the getable liquid composition is still in a
flowing state.
Among other things, the after-flush fluid acts to displace at least a portion
of the getable
liquid composition from the pore channels of the subterranean formation and to
force the
displaced portion of the getable liquid composition further into the
subterranean formation
where it may have negligible impact on subsequent hydrocarbon production.
Generally, the
after-flush fluid may be any fluid that does not adversely react with the
other components
used in accordance with this invention or with the subterranean formation. The
after-flush
may be an aqueous-based brine or a hydrocarbon fluid, such as kerosene,
diesel, or crude oil.
The after-flush fluid may be placed into the formation at a matrix flow rate
such that a
sufficient portion of the getable liquid composition may be displaced from the
pore channels
to restore the formation to a desired permeability. However, a substantial
amount of the
getable liquid composition should not be displaced therein. For example,
sufficient amounts
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of the gelable liquid composition should remain in the treated zone to provide
effective
stabilization of the unconsolidated zones therein.
Generally, the volume of after-flush fluid placed in the subterranean
formation ranges from about 0.1 to about 50 times the volume of the gelable
liquid
composition. In some embodiments of the present invention, the volume of after-
flush fluid
placed in the subterranean formation ranges from about 2 to about 5 times the
volume of the
gelable liquid composition.
In another embodiment of the present invention, no after-flush fluid is
placed into the subterranean formation after placement of the immature aqueous
gel into the
subterranean formation. Whether to omit an after-flush fluid is based, in
part, on the initial
permeability of the subterranean formation. For example, it may be desirable
to not use an
after-flush where the initial permeability of the formation is less than about
10 mini-darcies
("mD") for gas wells, or less than about 50 mD for oil wells. Where no after-
flush is used,
the permeability of the subterranean formation is significantly reduced
because the gelable
liquid composition remains in the pore spaces therein and converts into a
gelled substance.
While there is a significant reduction in the permeability, the unconsolidated
zones of the
formation may be stabilized due, inter alia, to the gelled substance remaining
in the pore
spaces of the formation.
In some embodiments of the present invention, after the gelable liquid
composition is allowed to form a gelled substance, one or more fractures may
be created in
the subterranean formation extending through the gelled substance and into
untreated zones
of the subterranean formation. In certain embodiments, the fracture or
fractures are created
after the after-flush fluid is placed into the subterranean formation. The
fracture or fractures
may be created by pumping a viscous fracturing fluid comprising a proppant
into the
subterranean formation at a rate and pressure sufficient to create one or more
fractures
therein. The continued pumping of the fracturing fluid extends the fractures
into the
subterranean formation and carnes the proppant into the fracture or fractures
formed. Upon
reduction of the flow of the fracturing fluid and the pressure exerted on the
subterranean
formation, the proppant is deposited in the fracture or fractures. The
fracture or fractures
may be prevented from closing by the presence of the proppant therein.
The fracturing fluids that may be used in accordance with the present
invention incnude any fracturing fluid that is suitable for use in
subterranean operations, such
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as gelled water-based fluids, hydrocarbon-based fluids, foams, and emulsions.
In one
embodiment of the present invention, the fracturing fluid used to create the
one or more
fractures may be a viscoelastic surfactant fluid comprising worm-like
micelles. In another
embodiment of the present invention, the fracturing fluid may be a gelled
fracturing fluid that
comprises water (e.g., fresh water, salt water, brine, or sea water) and a
gelling agent for
increasing the viscosity of the fracturing fluid. The increased viscosity
reduces fluid loss and
allows the fracturing fluid to transport significant concentrations of
proppant into the created
fractures. The selection of an appropriate fracturing fluid is within the
ability of one of
ordinary skill in the art.
As mentioned, the proppant deposited in the one or more fractures formed
in a subterranean formation functions to prevent the fractures from closing
due to overburden
pressures, whereby produced fluids can flow through the fractures. Proppant
used in
accordance with the present invention are generally particulate materials of a
size such that
formation particulates that may migrate with produced fluids are prevented
from being
produced from the subterranean formation, e.g., the proppant may filter out
migrating sand.
A wide variety of particulate materials may be used as proppant in accordance
with the
present invention, including, but not limited to, sand; bauxite; ceramic
materials; glass
materials; polymer materials; "TEFLON"~" materials; ground or crushed nut
shells; ground or
crushed seed shells; ground or crushed fruit pits; processed wood; composite
particulates
prepared from a binder with filler particulate including silica, alumina,
fumed carbon, carbon
black, graphite, mica, titanium dioxide, meta-silicate, calcium silicate,
kaolin, talc, zirconia,
boron, fly ash, hollow glass microspheres, and solid glass; or mixtures
thereof. The proppant
used may have a particle size in the range of from about 2 to about 400 mesh,
U. S. Sieve
Series. Preferably, the proppant is graded sand having a particle size in the
range of from
about 10 to about 70 mesh, U.S. Sieve Series. Preferred sand particle size
distribution ranges
are one or more of 10-20 mesh, 20-40 mesh, 40-60 mesh or 50-70 mesh, depending
on the
particle size and distribution of the formation particulates to be screened
out by the proppant.
The proppant used in accordance with the present invention may be coated
with a hardenable resin composition. In some embodiments, the hardenable resin
composition is preferably comprised of a hardenable resin, a diluent, and a
silane coupling
agent. Generally, the hardenable resin composition should harden after being
introduced into
fracture or fractures that are formed. The hardening may be caused by heat
from the
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formation or by inclusion of a delayed internal hardening agent in the
hardenable resin
composition. It is within the ability of one of ordinary skill in the art to
determine, with the
benefit of this disclosure, the appropriate hardenable resin composition for a
particular
application.
The proppant may be coated with the hardenable resin composition by any
suitable technique; such as by batch mixing methods as the hardenable resin
composition is
metered directly into the proppant slurry or by coating the hardenable resin
composition
directly onto the dry proppant through use of auger action. In some
embodiments, the
fracturing fluid containing proppant coated with the hardenable resin
composition may be
prepared in a substantially continuous, on the fly, manner.
After proppant coated with the hardenable resin composition has been
deposited within the subterranean formation, the hardenable resin composition
may be caused
to harden as described above, whereby the proppant is consolidated into a hard
permeable
mass in the fracture or fractures. The hard, permeable mass functions to
prevent the
production of formation particulates that may migrate with produced fluids
According to the methods of the present invention, after placement of the
getable liquid composition (or the after-flush fluid where used), the
subterranean formation
may be shut in for a period of time to allow the getable liquid composition
present in the
subterranean formation to form the desired gelled substance therein, inter
alia, to stabilize
unconsolidated zones of the subterranean formation. The necessary period of
time is
dependent, among other things, on the composition of the getable liquid
composition used
and the temperature of the formation. Generally, the chosen period of time
will be between
about 0.5 hours and about 72 hours, or longer. In certain embodiments, the
fracturing
treatment, discussed above, may be performed after the shut in period so that
the fractures
may be created through the gelled substance. Determining the proper period of
time to shut
in the formation is within the ability of one skilled in the art with the
benefit of this
disclosure.
To facilitate a better understanding of the present invention, the following
examples of preferred embodiments are given. In no way should the following
examples be
read to limit, or to define the scope of the invention.
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EXAMPLE 1
Tests were conducted using various treatment fluids and a simulated
unconsolidated sand core. Brazos River sand was used to simulate a high
permeability,
unconsolidated formation material. An unconsolidated sand core was prepared by
using a f-
inch ID Teflon sleeve. A stainless steel, 80-mesh wire screen was first
installed at the bottom
of the sleeve before packing 1-inch height of 40/60-mesh Ottawa sand at the
bottom of the
sleeve, 2.5-inch height of Brazos River sand in the middle, and 1-inch height
of 40/60-mesh
Ottawa sand at the top of the sleeve.
Treatment fluids were prepared using various concentrations of
"PermSeal~" sealant, which comprises a water-soluble polymerizable organic
monomer of
the present invention and is commercially available from Halliburton Energy
Services,
Duncan, Oklahoma. The water-soluble polymerizable monomer present in PermSeal~
sealant
is hydroxyethylacrylate. The concentrations of the water-soluble
polyrnerizable organic
monomer present in the treatment fluids range from about 5% to about 20% by
volume of the
treatment fluid.
The following procedure was used for this series of tests. For each test, the
unconsolidated sand core was first pre-flushed and saturated with 2 pore
volumes of 2% KCl
brine containing 0.25% cationic surfactant at a flow rate of 1 mL/min.
Following the pre-
flush, a treatment fluid was injected into the core at a flow rate of 1
mL/min. After injection
of the treatment fluid into the treated core, an after-flush fluid was
injected into the treated
core. Next, the treated core was placed inside an oven at 175°F for 20
hours to allow the
monomer to fully polymerize. This polymerization time simulated the shut-in
time of a well
after being treated with a getable liquid composition. After the
polymerization time,
kerosene was injected into the treated core to determine the retained
permeability of the
treated core. The treated core was then removed from the Teflon sleeve for
observation. The
above procedwe was repeated for a second series of tests where no after-flush
fluid was
injected into the treated core before the treated core was placed inside the
oven. The results
of these tests are provided below in Table 1.
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TABLE 1
Treatment Retained Appearance of Treated
Volume % After-flushPermeability
Fluid Core after
Monomer Volume Volume of Treated Polymerization Time
Core %
20 4 pore 0 plugged rubbery and pliable
volumes
20 p 94% rubbery and pliable
o vohunes
~e
2 pore 0 , plugged rubbery and pliable
volumes
10 p l 86% rubbery and less
pliable
o ames
~e vo
2 pore 0 plugged formed
slightly pliable
volumes ,
l l 100% formed
slightly pliable
vo vo ,
ume ames
This example indicates, inter alia, that a gelable liquid composition of the
present invention may completely plug the permeability of an unconsolidated
sand core and
introduction of an after-flush fluid after the gelable liquid composition
should restore
permeability to such unconsolidated sand core.
EXAMPLE 2
Brazos River sand with mesh sizes smaller than 200 mesh was used to
simulate formation fines. A transparent acrylic tube (8 inches long and 1 inch
inside
diameter) was used for ease of observation during flow test. A unconsolidated
sand core was
created in the tube by placing a mixture of Brazos River sand (9 grams) and
20/40-mesh
Ottawa sand (6 grams) between 100 grams of 20/40-mesh Ottawa sand on top and
20 grams
of 40/60-mesh Ottawa sand at the bottom.
Treatment fluids were prepared using various concentrations of
"PermSeal~" sealant, wherein the PermSeal~ sealant comprises a water-soluble
polymerizable organic monomer. The concentrations of the water-soluble
polymerizable
organic monomer present in the treatment fluids ranges from about 5% to about
10% by
volume of the treatment fluid.
The following procedure was used for this series of tests. For test 1, an
unconsolidated sand core constructed as described above was first pre-flushed
from top down
and saturated with 120 mL of kerosene at a flow rate ~f 10 mL/min. Following
the kerosene
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pre-flush, a treatment fluid comprising PermSeal~ was injected into the core
at a flow rate of
mL/min. After injection of the treatment fluid, an after-flush of kerosene was
injected into
the treated core. Next, the treated core was let sit at room temperature for
20 hours to allow
the monomer to fully gel. After the gel time, kerosene was again injected into
the treated
core, this time in the reverse direction at increasing increment flow rates,
starting from 10
mL/min, to simulate the effect of production flow rates and to help determine
if the treatment
fluid has stabilized the Brazos River sand fines and caused them to remain
intact without
migrating and producing out along with the production fluid. It was found that
Brazos River
sand remained in place without producing out of the sand pack, even at
production rate of 80
mL/min.
For test 2, an unconsolidated sand core constructed as described above was
first pre-flushed from top down and saturated with 120 mL of 2% KCl brine
containing
0.25% cationic surfactant at a flow rate of 2 mL/min. Following the brine pre-
flush, a
treatment fluid of PermSeal~ was injected into the core at a flow rate of 2
mL/min. After
injection of the treatment fluid, an after-flush of 2% KCl brine was injected
into the treated
core. Next, the treated core was let sit at room temperature for 20 hours to
allow the
monomer to fully gel. After the gel time, kerosene was injected into the
treated core in the
reverse direction at increasing increment flow rates, starting from 10 mL/min,
to simulate the
effect of production flow rates and to help determine if the treatment fluid
has stabilized the
Brazos River sand fines and caused them to remain intact without migrating and
producing
out along with the production fluid. Similar to the results obtained in test
1, it was found that
Brazos River sand remained in place without producing out of the sand pack,
even at a
production rate as high as 80 mL/min.
Thus, this example displays the ability of the gelled substances of the
present invention to stabilize unconsolidated formation sand and to prevent
formation fines
from migrating or producing with production fluids.
Therefore, the present invention is well adapted to carry out the objects and
attain the ends and advantages mentioned as well as those that are inherent
therein. While
numerous changes may be made by those skilled in the art, such changes are
encompassed
within the spirit and scope of this invention as defined by the appended
claims.
