U.S. patent application number 15/631121 was filed with the patent office on 2017-10-26 for alkylated polyetheramines as clay stabilizing agents.
The applicant listed for this patent is Huntsman Petrochemical LLC. Invention is credited to Matthew W. Forkner, Marek K. Pakulski.
Application Number | 20170306210 15/631121 |
Document ID | / |
Family ID | 50685099 |
Filed Date | 2017-10-26 |
United States Patent
Application |
20170306210 |
Kind Code |
A1 |
Pakulski; Marek K. ; et
al. |
October 26, 2017 |
Alkylated Polyetheramines as Clay Stabilizing Agents
Abstract
The present disclosure provides water-based well treatment
fluids for use in treating subterranean formations to prevent
swelling and/or migration of fines. The water-based well treatment
fluid contains an aqueous continuous phase, a clay stabilizing
agent consisting of an alkylated polyetheramine and a weighting
material. In addition to inhibiting swelling and/or migration, the
water-based well treatment fluids are thermally stable, are
toxicologically safe, and have exceptional handling properties.
Inventors: |
Pakulski; Marek K.; (The
Woodlands, TX) ; Forkner; Matthew W.; (Spring,
TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Huntsman Petrochemical LLC |
The Woodlands |
TX |
US |
|
|
Family ID: |
50685099 |
Appl. No.: |
15/631121 |
Filed: |
June 23, 2017 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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14421462 |
Feb 13, 2015 |
9719007 |
|
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PCT/US13/68261 |
Nov 4, 2013 |
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15631121 |
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61725204 |
Nov 12, 2012 |
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Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 21/00 20130101;
E21B 43/26 20130101; C09K 8/04 20130101; C09K 8/588 20130101; C09K
8/74 20130101; E21B 43/25 20130101; C09K 8/52 20130101; C09K 8/86
20130101; C09K 8/22 20130101; C09K 2208/22 20130101; C09K 2208/12
20130101; E21B 21/003 20130101; C09K 8/58 20130101; E21B 43/04
20130101; E21B 43/16 20130101; C09K 8/12 20130101; C09K 8/68
20130101; E21B 41/02 20130101; E21B 43/267 20130101; C07C 217/08
20130101 |
International
Class: |
C09K 8/12 20060101
C09K008/12; E21B 43/26 20060101 E21B043/26; E21B 43/25 20060101
E21B043/25; E21B 43/16 20060101 E21B043/16; C09K 8/588 20060101
C09K008/588; C07C 217/08 20060101 C07C217/08; E21B 21/00 20060101
E21B021/00; E21B 21/00 20060101 E21B021/00; E21B 41/02 20060101
E21B041/02; E21B 43/267 20060101 E21B043/267; E21B 43/04 20060101
E21B043/04 |
Claims
1. A water-based well treatment fluid comprising an aqueous
continuous phase, a clay stabilizing agent consisting of an
alkylated polyetheramine and a weighting material, wherein the
alkylated polyetheramine is a compound having a formula (I):
##STR00004## wherein: R is C.sub.2H.sub.4, R.sub.1 is a straight
chain or branched C.sub.1 to C.sub.6 alkyl group, and x is an
integer from 1 to 3.
2. The water-based well treatment fluid of claim 1, wherein the
aqueous continuous phase is selected from fresh water, sea water,
brine, a mixture of water and a water soluble organic compound and
mixtures thereof.
3. The water-based well treatment fluid of claim 1, wherein the
alkylated polyetheramine is a compound having formula (III) or a
compound having the formula (IV): ##STR00005##
4. The water-based well treatment fluid of claim 1, wherein the
amount of clay stabilizing agent present in the water-based well
treatment fluid ranges from about 0.05% to about 0.5% by volume of
the water-based well treatment fluid.
5. The water-based well treatment fluid of claim 1, wherein the
weighting material is barium sulfate, barite, hematite, iron oxide,
calcium carbonate, magnesium carbonate, an organic salt, an
inorganic salt or mixtures thereof.
6. The water-based well treatment fluid of claim 1, further
comprising one or more additives.
7. A process of making a water-based well treatment fluid
comprising admixing a clay stabilizing agent consisting of an
alkylated polyetheramine, a weighting material and optional
additives with an aqueous continuous phase, wherein the alkylated
polyetheramine is a compound having a formula (I): ##STR00006##
wherein: R is C.sub.2H.sub.4, R.sub.1 is a straight chain or
branched C.sub.1 to C.sub.6 alkyl group, and x is an integer from 1
to 3.
8. A water-based well treatment fluid made according to the process
of claim 7.
9. A method of inhibiting the swelling and/or migration of clay
subterranean materials encountered during the drilling of a
subterranean formation comprising circulating in the subterranean
formation a water-based well treatment fluid comprising an aqueous
continuous phase, a clay stabilizing agent consisting of an
alkylated polyetheramine and a weighting material, wherein the
alkylated polyetheramine is a compound having a formula (I):
##STR00007## wherein: R is C.sub.2H.sub.4, R.sub.1 is a straight
chain or branched C.sub.1 to C.sub.6 alkyl group, and x is an
integer from 1 to 3.
10. A method of extracting oil from an oil containing subterranean
formation comprising: providing through a first borehole, a
pressurized water-based well treatment fluid comprising an aqueous
continuous phase, a clay stabilizing agent consisting of an
alkylated polyetheramine and a weighting material, wherein the
alkylated polyetheramine is a compound having a formula (I):
##STR00008## wherein: R is C.sub.2H.sub.4, R.sub.1 is a straight
chain or branched C.sub.1 to C.sub.6 alkyl group, and x is an
integer from 1 to 3; and recovering oil from the subterranean
formation through a second borehole.
11. The method of claim 10, wherein the subterranean formation was
previously hydraulically fractured and oil was previously
extracted.
12. The water-based well treatment fluid of claim 1, wherein x is
an integer from 1 to 2.
13. The water-based well treatment fluid of claim 1, wherein the
weighting material is barium sulfate, barite, hematite, iron oxide,
magnesium carbonate, an organic salt, an inorganic salt or mixtures
thereof.
14. The water-based well treatment fluid of claim 1, wherein the
fluid further comprises at least one of gel breakers, penetration
rate enhancers, corrosion inhibitors, lost circulation fluids,
anti-bit balling agents, proppants, and sand for gravel packing.
Description
CROSS-REFERENCE TO RELATED APPLICATION
[0001] This application is a Continuation of application Ser. No.
14/421,462, filed Feb. 13, 2015, which is the U.S. National Phase
of International Application PCT/US13/68261, filed Nov. 4, 2013,
which designated the U.S., and which claims priority to U.S.
Provisional Application Ser. No. 61/725,204 filed Nov. 12, 2012.
The noted applications are incorporated herein by reference.
STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT
[0002] Not Applicable.
FIELD OF THE INVENTION
[0003] The present disclosure relates generally to well treatment
fluids and their use. More specifically, the present disclosure
relates to alkylated polyetheramines as clay stabilizing agents in
well treatment fluids and methods of using the same.
BACKGROUND OF THE INVENTION
[0004] The production of hydrocarbons from subterranean formations
is often effected by the presence of clays and other fines which
can migrate and plug off or restrict the flow of the hydrocarbon
product. The migration of fines in a subterranean formation is
often the result of clay swelling, salt dissolution, and/or the
disturbance of fines by the introduction of fluids that are foreign
to the formation. Typically, such foreign fluids (e.g. drilling
fluid, fracturing fluid or stabilizing fluid) are introduced into
the formation for the purpose of completing and/or treating the
formation to stimulate production of hydrocarbons by, for example,
drilling, fracturing, acidizing, or stabilizing the well.
[0005] Attempts to diminish the damaging effects caused by
introduction of the foreign fluid and the swelling and migration of
the components of the formations has included the addition of one
or more various shale hydration inhibitors and/or stabilizing
agents into such foreign fluids. These work on the principle of the
substitution of a cationic species in the clay lattice for a sodium
ion. The cationic species is generally selected such that its
radius of hydration is less than that of the sodium ion. It is
believed that the molecules of the shale hydration inhibitors and
stabilizing agents compete with molecules of water for reactive
sites. Thus, the possibility of swelling and migration is minimized
upon their contact with the formation. As a result, the probability
of disintegration of formation is diminished and swelling is
inhibited.
[0006] Potassium chloride has been widely used as a shale
inhibitor/clay stabilizer. In stimulation methods, potassium
chloride has often been used as a preflush and/or added to aqueous
stimulation methods in order to convert the clay to a less
swellable form. While such salts diminish the reduction of
formation permeability, they are often detrimental to the
performance of other constituents of the foreign fluid. For
example, high concentration of such salts is typically required for
stabilization of clay (typically 6%). Such salts further produce
high chloride levels which are environmentally unacceptable. Other
known shale hydration inhibitors/clay stabilizing agents, which
have been used include, for example:
[0007] WO 98/55733, which discloses the use of at least one organic
amine selected from a primary diamine with a chain length of less
than 8 carbon atoms and a primary alkyl amine with a chain length
of less than 4 carbon atoms:
[0008] WO 05/058986, which teaches the use of an amine salt of an
imide of a maleic anhydride polymer;
[0009] WO 06/013595, which discloses adducts of carboxymethyl
cellulose and an organic amine as solid shale inhibitors;
[0010] WO 06/013597, which teaches the use of 0.2-5% by wt. of
1,2-diaminocyclohexane to inhibit the swelling of clay;
[0011] WO 06/136031, which teaches the use of amine salts having
different molecular weights so as to be able to transport into
micropore, mesospore and macrospores in the formation and effect
cationic exchange therein;
[0012] WO 10/040223, which discloses the use of bis-surfactant
diamine compounds to reduce clay swelling while drilling is carried
out;
[0013] U.S. Pat. No. 4,719,021, which teaches incorporating a
polyvalent metal/guanidine complex into a drilling fluid to
stabilize colloidal clay;
[0014] U.S. Pat. No. 4,988,450, which discloses polymers of vinyl
acetate combined with potassium salts as an additive for aqueous
mud for improving wellbore stability;
[0015] U.S. Pat. No. 6,706,667, which discloses a shale-stabilizing
additive for water-based drilling fluids including a polymer based
on an olefinically unsaturated hydrocarbon with alkylene oxide
based side chains;
[0016] U.S. Pat. Nos. 6,831,043 and 6,857,485, which teach the use
of polyether amines as shale hydration inhibition agents;
[0017] U.S. Pat. No. 7,192,907, which discloses quaternary
compounds as shale encapsulating agents to at least partially
inhibit swelling and aid in the action of conventional shale
inhibitors;
[0018] U.S. Pat. No. 7,514,392, which teaches the use of
bis-cyclohexylamine derivatives as shale hydration inhibitors;
[0019] U.S. Pat. No. 7,939,473, which discloses monoquaternary
hydroxyalkylalkylamines or poly(trihydroxyalklyalkylquaternary
amines) as additives for reducing the swelling of clay in
wells;
[0020] U.S. Pat. No. 8,026,198, which teaches the use of
propylamine derivatives, hydrogenated poly (propyleneimine)
dendrimers and polyamine twin dendrimers as shale hydration
inhibitors;
[0021] U.S. Pat. No. 8,220,565, which teaches the use of a guanidyl
copolymer to stabilize a subterranean formation; and
[0022] U.S. Pat. No. 8,252,728, which discloses polymers containing
hydroxylated structural units which are useful for inhibiting
swelling of clays.
[0023] There is a continuing need for the development of shale
hydration inhibitors/clay stabilizing agents which are
substantially odor free, pose little threat to the environment by
eliminating substantially all chlorides, and are as at least as
effective as the most effective prior art hydration
inhibitor/stabilizing agents.
SUMMARY OF THE INVENTION
[0024] The present disclosure provides a water-based well treatment
fluid which is used in downhole fluid introduced into a
subterranean formation containing clay subterranean materials that
have a tendency to exhibit swelling and/or migration upon exposure
to water. The well treatment fluid contains an aqueous continuous
phase, a clay stabilizing agent consisting of an alkylated
polyetheramine and a weighting material.
[0025] In another aspect, the present disclosure provides a method
of inhibiting swelling and/or migration of clay subterranean
materials encountered during the drilling of a subterranean
formation. The method includes circulating in the subterranean
formation a water-based well treatment fluid containing an aqueous
continuous phase, a clay stabilizing agent consisting of an
alkylated polyetheramine and a weighting material.
DETAILED DESCRIPTION OF THE INVENTION
[0026] As used herein, the term "comprising" and derivatives
thereof are not intended to exclude the presence of any additional
component, step or procedure, whether or not the same is disclosed
herein. In order to avoid any doubt, all compositions claimed
herein through use of the term "comprising" may include any
additional additive or compound, unless stated to the contrary. In
contrast, the term, "consisting essentially of" if appearing
herein, excludes from the scope of any succeeding recitation any
other component, step or procedure, excepting those that are not
essential to operability and the term "consisting of", if used,
excludes any component, step or procedure not specifically
delineated or listed. The term "or", unless stated otherwise,
refers to the listed members individually as well as in any
combination.
[0027] The articles "a" and "an" are used herein to refer to one or
more than one (i.e. to at least one) of the grammatical object of
the article. By way of example, "an alkylated polyetheramine" means
one alkylated polyetheramine or more than one alkylated
polyetheramine.
[0028] The phrases "in one embodiment", "according to one
embodiment" and the like generally mean the particular feature,
structure, or characteristic following the phrase is included in at
least one embodiment of the present invention, and may be included
in more than one embodiment of the present invention. Importantly,
such phases do not necessarily refer to the same embodiment.
[0029] If the specification states a component or feature "may",
"can", "could", or "might" be included or have a characteristic,
that particular component or feature is not required to be included
or have the characteristic.
[0030] The phrase "subterranean formation" encompasses both areas
below exposed earth and areas below earth covered by water, such as
an ocean or fresh water. The term "clay subterranean materials"
includes sand and/or clays which swell, disperse, disintegrate or
otherwise become disrupted, thereby demonstrating an increase in
bulk volume, in the presence of foreign aqueous well treatment
fluids, such as drilling fluids, stimulation fluids, gravel packing
fluids, etc. The term also includes those sand and/or clays which
disperse, disintegrate or otherwise become disrupted without actual
swelling. For example, clays which, in the presence of foreign
aqueous well treatment fluids, expand and may be disrupted by
becoming unconsolidated, thereby producing particles that migrate
into a borehole shall also be included by the term.
[0031] The clay stabilizing agent consisting of an alkylated
polyetheramine as defined herein can be used as a total potassium
chloride substitute when potassium chloride is used as a clay
stabilizing agent. In addition, the clay stabilizing agent
consisting of an alkylated polyetheramine can be used in
water-based well treatment fluids and methods where potassium
chloride or other inorganic salts have not been traditionally used.
In some embodiments, the clay stabilizing agent consists
essentially of an alkylated polyetheramine and can be used in
water-based well treatment fluids in conjunction with potassium
chloride. When combined with an aqueous continuous phase and a
weighting material to render a water-based well treatment fluid,
the clay stabilizing agent consisting of an alkylated
polyetheramine is capable of reducing or substantially eliminating
damage to a subterranean formation caused by swellable and/or
migrating clay subterranean materials. The presence of the clay
stabilizing agent consisting of an alkylated polyetheramine
eliminates or reduces the tendency of the clay subterranean
materials to swell and/or disintegrate/migrate upon contact with
the water-based well treatment fluid.
[0032] Such inhibition and/or migration may be temporary or
substantially permanent depending on the quantity of water-based
well treatment fluid used to treat the subterranean formation.
Thus, another advantage of using the disclosed clay stabilizing
agent consisting of an alkylated polyetheramine is evidenced by its
ability to provide permanent clay stabilization. Temporary clay
stabilizers are materials that protect the subterranean formation
only during treatment of the formation with the water-based well
treatment fluid. Migration of natural fluids over the subterranean
formation over time displaces foreign cations, thereby reverting
the clay back to its natural swelling form. In contrast, permanent
clay stabilizers minimize such swelling when the clays are exposed
to natural fluids over time without the need of continued addition
of the water-based well treatment fluid.
[0033] In addition to inhibiting swelling and/or migration, the
clay stabilizing agents consisting of an alkylated polyetheramine
disclosed herein also achieve other benefits. For instance, the
clay stabilizing agents consisting of an alkylated polyetheramine
are thermally stable, are toxicologically safer, and have better
handling properties. Therefore, the clay stabilizing agents
consisting of an alkylated polyetheramine may be broadly utilized
in land based drilling operations as well as offshore drilling
operations.
[0034] Thus, according to one embodiment, a water-based well
treatment fluid is provided comprising an aqueous continuous phase,
a clay stabilizing agent consisting of an alkylated polyetheramine
and a weighting material.
[0035] The water-based well treatment fluid may be any fluid
capable of delivering the clay stabilizing agent consisting of an
alkylated polyetheramine into a subterranean formation. Thus, in
one embodiment, the water-based well treatment fluid is a drilling
fluid, a drill-in-fluid, a stimulation fluid, a fracturing fluid,
an acidizing fluid, a remedial fluid, a well reworking fluid or a
gravel pack fluid.
[0036] According to another embodiment, the aqueous continuous
phase is any water based fluid phase that is compatible with the
formulation of a well treatment fluid and is also compatible with
the clay stabilizing agents disclosed herein. In one embodiment,
the aqueous continuous phase is selected from fresh water, sea
water, brine, a mixture of water and a water soluble organic
compound and mixtures thereof. The amount of the aqueous continuous
phase should be sufficient to form a water-based well treatment
fluid. In one embodiment, the amount of aqueous continuous phase
may range from nearly 100% of the water-based well treatment fluid
by volume to less than 30% of the water-based well treatment fluid
by volume. In another embodiment, the amount of the aqueous based
continuous phase is from about 95% by volume to about 30% by volume
of the water-based well treatment fluid. In still another
embodiment, the amount of the aqueous based continuous phase is
from about 90% by volume to about 40% by volume of the water-based
well treatment fluid.
[0037] As discussed above, the water-based well treatment fluid
also includes a clay stabilizing agent consisting of an alkylated
polyetheramine. In one embodiment, the alkylated polyetheramine is
a compound having the formula (I):
##STR00001##
wherein R is C.sub.2H.sub.4 or CH(CH.sub.3)CH.sub.2, R.sub.1 is a
straight chain or branched C.sub.1 to C.sub.6 alkyl group, and x is
an integer from 1 to 3. In one embodiment, R is C.sub.2H.sub.4, and
R.sub.1 is a methyl group, ethyl group, n iso-propyl group,
n-propyl group, n-iso-butyl or n-butyl group. According to another
embodiment, R is C.sub.2H.sub.4, and R.sub.1 is an ethyl group, n
iso-propyl group or n-propyl group. In one illustrative embodiment
of the present disclosure, the clay stabilizing agent is a compound
having the formula (II) or a compound having the formula (III) or a
compound having the formula (IV):
##STR00002##
In another illustrative embodiment, of the present disclosure, the
clay stabilizing agent is a compound having the formula (II) or a
compound having the formula (IV):
##STR00003##
[0038] Generally, the clay stabilizing agent is present in the
water-based well treatment fluid in an amount sufficient to reduce
either or both of surface hydration based swelling and/or osmotic
based swelling of clay subterranean materials. The exact amount of
the clay stabilizing agent present in a particular water-based well
treatment fluid may be determined by a trial and error method of
testing the combination of water-based well treatment fluid and
clay formation encountered. In one embodiment, the amount of clay
stabilizing agent of the present disclosure used in the water-based
well treatment fluids ranges from about 1 to about 20 pounds per
barrel (lbs/bbl or ppb) of water-based well treatment fluid. In
another embodiment, the amount of clay stabilizing agent present in
the water-based well treatment fluid ranges from about 2 to about
18 ppb of water-based well treatment fluid. In still another
embodiment, the amount of clay stabilizing agent present in the
water-based well treatment fluid ranges from about 0.05% to about
0.5% by volume of the water-based well treatment fluid.
[0039] The water-based well treatment fluid also contains a
weighting material. The weighting material increases the density of
the fluid in order to prevent kick-backs and blow-outs. Suitable
weighting materials include any type of weighting material that is
in solid form, particulate form, suspended in solution, or
dissolved in the aqueous continuous phase. In one embodiment, the
weighting material is barium sulfate, barite, hematite, iron oxide,
calcium carbonate, magnesium carbonate, an organic salt, an
inorganic salt or mixtures thereof. The amount of weighting
material present in the water-based well treatment fluid is an
amount effective to prevent kick-backs and blow-outs, which amount
changes according to the nature of the formation under treatment
operations. In one particular embodiment, the weighting material is
included in the water-based well treatment fluid at a level of less
than 800 ppb, for example, from about 5 ppb to about 750 ppb or
from about 10 ppb to about 700 ppb of water-based well treatment
fluid.
[0040] In another embodiment, the water-based well treatment fluid
optionally contains one or more conventional additives. Examples of
such additives include, but are not limited to, gelling materials,
thinners, fluid loss control agents, encapsulating agents,
bactericides, gel breakers, foaming agents, stabilizers,
lubricants, penetration rate enhancers, defoamers, corrosion
inhibitors, lost circulation fluids, anti-bit balling agents,
neutralizing agents, pH buffering agents, surfactants, proppants,
and sand for gravel packing.
[0041] Examples of gelling materials include, but are not limited
to, bentonite, sepiolite clay, attapulgite clay, anionic
high-molecular weight polymers and biopolymers.
[0042] Examples of thinners include, but are not limited to,
lignosulfates, modified lignosulfates, polyphosphates, tannins, and
low molecular weight polyacrylates.
[0043] Examples of fluid loss control agents include, but are not
limited to, synthetic organic polymers, biopolymers and mixtures
thereof, modified lignite polymers, modified starches and modified
celluloses.
[0044] Examples of encapsulating agents include, but are not
limited to, synthetic materials, organic materials, inorganic
materials, biopolymers or mixtures thereof. The encapsulating agent
may be anionic, cationic or non-ionic in nature.
[0045] The clay stabilizing agent of the present disclosure and
weighting material and optional additives may be admixed with the
aqueous continuous phase to form the water-based well treatment
fluid. Thus, in another embodiment, there is provided a process of
making a water-based well treatment fluid comprising admixing a
clay stabilizing agent consisting of an alkylated polyetheramine, a
weighting material and optional additives with an aqueous
continuous phase.
[0046] In another embodiment, there is provided a method of
inhibiting the swelling and/or migration of clay subterranean
materials encountered during the drilling of a subterranean
formation. The method includes circulating in the subterranean
formation a water-based well treatment fluid containing an aqueous
continuous phase, a clay stabilizing agent consisting of an
alkylated polyetheramine and a weighting material. In still another
embodiment, there is provided a method for stabilizing a
subterranean formation including the steps of contacting the
subterranean formation with the water-based well treatment fluid of
the present disclosure. Contacting the subterranean formation may
be accomplished, for example, by providing the water-based well
treatment fluid disclosed herein to the subterranean formation
before, during or after hydraulic fracturing or drilling.
[0047] Clay subterranean materials which may be effectively treated
with the water-based well treatment fluid may be of varying shapes,
such as minute, plate-like, tube-like and/or fiber-like particles
having an extremely large surface area. Examples include clay
minerals of the montmorillonite (smectite) group such as
montmorillonite, saponite, nontronite, hectorite and sauconite, the
kaolin group such as kaolinite, nacrite, dickite, and halloysite,
the hydrousmica group such as hydrobiotite, gluaconite, illite and
bramallite, the chlorite group such as chlorite and chamosite, clay
minerals not belonging to the above group such as vermiculite,
attapulgite and sepiolite and mixed-layer varieties of such clay
minerals and groups. Other mineral components may be further
associated with the clay.
[0048] In another embodiment, the materials and method of
inhibiting swelling and/or migration of clay subterranean materials
and stabilizing the subterranean formation can be provided as a kit
that includes a sufficient amount of the clay stabilizing agent,
weighting material and optional additives for on-site admixture
with the aqueous continuous phase.
[0049] The result of stabilization of the subterranean formation
with the water-based well treatment fluid described herein is that
clay subterranean material particulates loosened from the
subterranean formation by the process of removing a hydrocarbon
product have reduced swell, have reduced subterranean migration, do
not reduce the flow of the hydrocarbon product, and/or do not
contaminate the hydrocarbon product. Without the water-based well
treatment fluid, the clay subterranean materials can swell and/or
migrate to inhibit or contaminate the hydrocarbon production. The
stabilization effect can be measured by comparing wells with and
without the water-based well treatment fluid or comparing the flow
rate of fluids (e.g. oil, water or natural gas) through samples
from the subterranean formation with and without the water-based
well treatment fluid.
[0050] Subterranean formations can be stabilized by contacting them
with the water-based well treatment fluid. In one embodiment, clay
subterranean materials swelling and/or fines migration can be
reduced by contacting the subterranean formation with a water-based
well treatment fluid comprising an aqueous continuous phase, a clay
stabilizing agent consisting of an alkylated polyetheramine, a
weighting material and optional additives.
[0051] In another embodiment, a previously hydraulically fractured
subterranean formation can be restabilized by contacting the
hydraulically fractured subterranean formation with a water-based
well treatment fluid comprising an aqueous continuous phase, a clay
stabilizing agent consisting of an alkylated polyetheramine, a
weighting material and optional additives. The hydraulically
fractured subterranean formation can be a hydraulically fractured
subterranean formation, for example, that from which hydrocarbons
have been extracted. Preferably, the hydraulically fractured
subterranean formation is a formation having a mineral content that
is predominantly clay, shale, sand, and/or a mixture thereof.
[0052] In still another embodiment, the water-based well treatment
fluid can be used in a method of flushing a bore hole during
drilling. The method includes applying the water-based well
treatment fluid to a drill head during drilling of a subterranean
formation.
[0053] In yet another embodiment, there is provided a method of
extracting oil from an oil containing subterranean formation by
providing through a first borehole, a pressurized water-based well
treatment fluid of the present disclosure and recovering oil from
the subterranean formation through a second borehole. Preferably,
the subterranean formation was previously hydraulically fractured
and oil was previously extracted.
EXAMPLES
[0054] The following examples are provided to illustrate the
invention, but are intended not to limit the scope thereof.
Example 1
[0055] Capillary Suction Time (CST) tests were measured as a
determination of the relative flow capacity of a slurry of ground
formation rock used to form an artificial core. Wyoming bentonite
clay was ground and 5% by weight of the ground clay was added to
95% by weight of silica flour to form a core sample. 4 grams of the
core sample was then placed in 40 ml of a test fluid (the test
fluid comprising the clay stabilizing agent and water) and stirred
on a magnetic stirrer for at least 30 minutes. 5 ml of this slurry
was then placed into a metal funnel containing filter paper of the
CST instrument and the time needed for the slurry to travel down a
certain distance was recorded.
[0056] Here, the data obtained from the CST test is reported as a %
Change obtained from the equation:
((CST.sub.sample/CST.sub.blank)-1).times.100=______% Change
where CST.sub.blank is the CST time for the test fluid (a 5% by
weight of KCl dissolved in water) to flow the required distance
without a core sample present. Four clay stabilizing agents were
tested: Example 1=2-propanamine,
NN'-[1,2-ethanediylbis(oxy-2,1-ethanediyl)]bis- (Structure II);
Example 2=ethanamine,
NN'-[1,2-ethanediylbis(oxy-2,1-ethanediyl)]bis-, (Structure IV);
Comparative Example 3 JEFFAMINE.RTM. D-230 polyetheramine
(Structure I R.dbd.CH(CH.sub.3)CH.sub.2, R.sup.1=H available from
Huntsman Petrochemical LLC) and Comparative Example
4=JEFFAMINE.RTM. SD-231 polyetheramine (Structure 1
R.dbd.CH(CH.sub.3)CH.sub.2, R.sup.1=i-C.sub.3H.sub.7 available from
Huntsman Petrochemical LLC). In some of the test fluids, the clay
stabilizing was first neutralized by contacting 20 g of the clay
stabilizing agent with either 0.5, 0.6 or 2 moles of glacial acetic
acid or concentrated HCl (37%). They are reported below as neat
amine or salt concentration:
TABLE-US-00001 TABLE 1 Concentration 30 Minute Clay Stabilizing (%
by wt. Contact % Agent in water) Time (sec) Change None (100%
Water) 0 237 -- KCl (Blank) 5 17.6 -- Example 1 0.1 24 36.4 Neat
Amine Example 1 0.25 21.2 20.5 Neat Amine Example 1 0.5 23.3 32.4
Neat Amine Example 2 0.1 16.6 -5.7 Neat Amine Example 2 0.25 16.9
-4.0 Neat Amine Example 2 0.5 22.1 25.6 Neat Amine Comparative
Example 3 0.1 22.6 28.4 Neat Amine Comparative Example 3 0.25 18.5
5.1 Neat Amine Comparative Example 3 0.5 21.6 22.7 Neat Amine
Example 1 0.1 17.5 -0.6 0.5 mol acetate Example 1 0.25 18.6 5.7 0.5
mol acetate Example 1 0.5 18 2.3 0.5 mol acetate Example 2 0.1 17.3
-1.7 0.5 mol acetate Example 2 0.25 16.6 -5.7 0.5 mol acetate
Example 2 0.5 19.2 9.1 0.5 mol acetate Comparative Example 3 0.1 21
19.3 0.5 mol acetate Comparative Example 3 0.25 18.5 5.1 0.5 mol
acetate Comparative Example 3 0.5 20 13.6 0.5 mol acetate
Comparative Example 4 0.1 24.2 37.5 0.5 mol acetate Comparative
Example 4 0.25 21 22.7 0.5 mol acetate Comparative Example 4 0.5
22.6 28.4 0.5 mol acetate Example 1 0.1 17.7 0.6 0.6 mol HCl
Example 1 0.25 17.6 0 0.6 mol HCl Example 1 0.5 17.8 1.1 0.6 mol
HCl Example 2 0.1 17.3 -1.7 0.6 mol HCl Example 2 0.25 16.5 -6.3
0.6 mol HCl Example 2 0.5 16.5 -6.3 0.6 mol HCl Comparative Example
3 0.1 21.9 24.4 0.6 mol HCl Comparative Example 3 0.25 18.8 6.8 0.6
mol HCl Comparative Example 3 0.5 18 2.3 0.6 mol HCl Example 1 0.1
19.3 9.7 2 mol acetate pH = 6.25 Example 1 0.25 19.3 9.7 2 mol
acetate pH = 6.25 Example 1 0.5 18.3 4 2 mol acetate pH = 6.25
Comparative Example 3 0.1 19.8 12.5 2 mol acetate pH = 6.55
Comparative Example 3 0.25 16.4 -6.8 2 mol acetate pH = 6.55
Comparative Example 3 0.5 17 -3.4 2 mol acetate pH = 6.55
[0057] Notice the results interpretation. In the CST tests, best
clay control chemicals cause less Bentonite swelling; thus, the
test solution flows faster through the cup and lower flow times are
recorded. Lower numbers (time and % change) indicate better clay
control. Negative percent change numbers are obtained when the test
solution flows faster than 5% KCl reference solution. Results for
tested chemicals (Examples 1 and 2) are generally significant
better than results for comparative chemicals (Comparative Examples
3 and 4). Line one in the table illustrates the swelling effect in
non-inhibited solution.
[0058] Although making and using various embodiments of the present
invention have been described in detail above, it should be
appreciated that the present invention provides many applicable
inventive concepts that can be embodied in a wide variety of
specific contexts. The specific embodiments discussed herein are
merely illustrative of specific ways to make and use the invention,
and do not delimit the scope of the invention.
* * * * *