Note: Descriptions are shown in the official language in which they were submitted.
CA 02906165 2015-09-11
WO 2014/153102 PCT/US2014/029079
METHODS AND COMPOSITIONS FOR USE IN OIL AND/OR GAS WELLS
Field of Invention
Methods and compositions comprising an emulsion or a microemulsion for use in
various aspects of a life cycle of an oil and/or gas well are provided.
Background of Invention
For many years, petroleum has been recovered from subterranean reservoirs
through the use of drilled wells and production equipment. Oil and natural gas
are found
in, and produced from, porous and permeable subterranean formations, or
reservoirs. The
porosity and permeability of the formation determine its ability to store
hydrocarbons,
and the facility with which the hydrocarbons can be extracted from the
formation.
Generally, the life cycle of an oil and/or gas well includes drilling to form
a wellbore,
casing, cementing, stimulation, and enhanced or improved oil recovery.
is Various aspects of the life cycle of an oil and/or gas well are designed
to facilitate
the extraction of oil and/or gas from the reservoir via the wellbore. A wide
variety of
fluids is utilized during the life cycle of an oil and/or gas well and are
well known. In
order to improve extraction of oil and/or gas, additives have been
incorporated into
various fluids utilized during the life cycle of an oil and/or gas well. The
incorporation of
additives into fluids utilized during the life cycle of an oil and/or gas well
can increase
crude oil or formation gas, for example, by reducing capillary pressure and/or
minimizing capillary end effects. For example, drilling fluids are utilized to
carry
cuttings and other particulates from beneath the drill bit to the surface and
can function
to reduce friction between the drill bit and the sides of the wellbore while
maintaining
the stability of uncased sections of the borehole. In addition, the drilling
fluid and the
subsequent cementing and perforating fluids can be formulated to prevent
imbibition
and/or unwanted influxes of some formation fluids. As another example,
fracturing and
acidizing are a commonly used techniques to stimulate the production of oil
and/or gas
from reservoirs, wherein a stimulation fluid is injected into the wellbore and
the
formation (reservoir). In a typical matrix acidizing or fracturing treatment,
from 1 barrel
per foot to several million gallons of stimulation fluid are pumped into a
reservoir (e.g.,
via the wellbore). The stimulation fluid can comprise additives to aid in the
stimulation
process, for example, proppants, scale inhibitors, friction reducers,
biocides, gases such
- 1 -
CA 02906165 2015-09-11
WO 2014/153102 PCT/US2014/029079
as carbon dioxide and nitrogen, acids, slow release acids, corrosion
inhibitors, buffers,
viscosifiers, clay swelling inhibitors, oxygen scavengers, and surfactants.
Later in the life
of the well additional fluids and gases may be injected into the well to
remediate
damage, maintain pressure or contact and recover further oil.
When selecting or using a fluid to be utilized during the life cycle of an oil
and/or
gas well, it is important for the fluid to comprise the right combination of
additives and
components to achieve the necessary characteristics of the specific end-use
application.
A primary goal amongst all aspects of the life cycle of a well is to optimize
recovery of
oil and/or gas from the reservoir. However, in part because the fluids
utilized during the
life cycle of an oil and/or gas well are often utilized to perform a number of
tasks
simultaneously, achieving necessary to optimal characteristics is not always
easy.
Accordingly, it would be desirable if a wide variety of additives were
available
which could be selected to achieve the necessary characteristics and/or could
be easily
adapted. Furthermore, it is desirable that the additives provide multiple
benefits and are
is useful across multiple portions of the life cycle of the well. For
example, a challenge
often encountered is fluid recovery following injection of fracturing fluids
or other fluids
into the wellbore. Often, large quantities of injected fluids are trapped in
the formation,
for example, in the area surrounding the fracture and within the fracture
itself. It is
theorized that the trapping of the fluid is due to interfacial tension between
water and
reservoir rock and/or capillary end effects in and around the vicinity of the
face of the
fractured rock. The presence of trapped fluids generally has a negative effect
on the
productivity of the well. While several approaches have been used to overcome
this
problem, for example, incorporation of co-solvents and/or surfactants (i.e.,
low surface
tension fluids) , there is still the need for improved additives, as well as a
greater
understanding as to how to select the additives to maximize the productivity
of the well.
The use of microemulsions has also been employed, however, selection of an
appropriate
microemulsion for a particular application remains challenging, as well as
there is a
continued need for emulsions with enhanced abilities.
Accordingly, although a number of additives are known in the art, there is a
continued need for more effective additives for increasing production of oil
and/or gas.
Summary of Invention
- 2 -
CA 02906165 2015-09-11
WO 2014/153102 PCT/US2014/029079
Methods and compositions comprising an emulsion or a microemulsion for use in
various aspects of the life-cycle of an oil and/or gas well are provided.
In some embodiments, a method of treating an oil and/or gas well having a
wellbore is provided comprising injecting a fluid comprising an emulsion or
microemulsion into the wellbore, wherein the emulsion or microemulsion
comprises an
aqueous phase; a surfactant; and a solvent, wherein the solvent comprises an
amine of
the formula NR1R2R3, wherein each of R1, R2, and R3 are the same or different
and are
alkyl, provide at least one of R1, R2, and R3 is methyl or ethyl, or
optionally, wherein any
two of R1, R2, and R3 are joined together to form a ring; and wherein the pH
of the fluid
is about neutral or greater.
In some embodiments, a method of treating an oil and/or gas well having a
wellbore is provided comprising injecting a fluid comprising an emulsion or
microemulsion into the wellbore, wherein the emulsion or microemulsion
comprises an
aqueous phase; a surfactant; and a solvent, wherein the solvent comprises an
amide of
the formula (C=0R4)R5R6, wherein each of R4, R5, and R6 are the same or
different and
are hydrogen or alkyl, or optionally, R5 and R6 are joined together to form a
ring.
In some embodiments, a method of treating an oil and/or gas well having a
wellbore is provided comprising injecting a fluid comprising an emulsion or
microemulsion into the wellborc, wherein the emulsion or microcmulsion
comprises
water; an alcohol; a solvent comprising a terpene; and a surfactant, wherein
the
surfactant has a structure as in Formula I:
R8
R7 R9
0 Rlo
m
R11
(1),
wherein each of R7, R8, R9, R1 , and R11 are the same or different and are
selected
from the group consisting of hydrogen, optionally substituted alkyl, and
¨CH=CHAr,
provided at least one of R7, R8, R9, RI , and R11 is ¨CH=CHAr; Ar is an aryl
group;
R12 is hydrogen or alkyl; n is 1-100; and each m is independently 1 or 2.
- 3 -
CA 02906165 2015-09-11
WO 2014/153102 PCT/US2014/029079
In some embodiments, a method of treating an oil and/or gas well having a
wellbore is provided comprising injecting a fluid comprising an emulsion or
microemulsion into the wellbore, wherein the emulsion or microemulsion
comprise
water; an alcohol; a solvent comprising a terpene; and a surfactant, wherein
the
surfactant has a structure as in Formula II:
R8
R7 R9
SO
X R1 O
1 'm
R11
(II),
wherein each of R7, R8, R9, R19, and are the same or different and are
selected from
the group consisting of hydrogen, optionally substituted alkyl, and ¨CH=CHAr,
provided
at least one of R7, R8, R9, R10, and is ¨CH=CHAr; Ar is an aryl group; Y is
an
anionic group; Xis a cationic group; n is 1-100; and each m is independently 1
or 2.
In some embodiments, a method of treating an oil and/or gas well having a
wellbore is provided comprising injecting a fluid comprising an emulsion or
microemulsion into the wellbore, wherein the emulsion or microemulsion
comprises
water; an alcohol; a solvent comprising a terpene; and a surfactant, wherein
the
surfactant has a structure as in Formula III:
R8
R7 R9
Z
0 R1
R11
(III),
wherein each of R7, R8, R9, R10, and R11 are the same or different and are
selected from
the group consisting of hydrogen, optionally substituted alkyl, and ¨CH=CHAr,
provided
at least one of R7, R8, R9, R1 , and R" is ¨CH=CHAr; Ar is an aryl group; Z+
is a cationic
group; n is 1-100; and each m is independently 1 or 2.
- 4 -
CA 02906165 2015-09-11
WO 2014/153102 PCT/US2014/029079
In some embodiments, a method of treating an oil and/or gas well having a
wellbore is provided comprising injecting a solution into the wellbore,
wherein the
solution comprising a fluid selected from the group consisting of a mud
displacement
fluid, a cementing fluid, a perforating fluid, a kill fluid, and EOR/IOR
fluid, a stored
fluid, or a stimulation fluid utilized in offshore wells or during fracture
packing, and an
emulsion or microemulsion, wherein the emulsion or the microemulsion comprises
between about 1 wt% and 95 wt% water; between about 1 wt% and 99 wt% solvent;
between about 0 wt% and about 50 wt% alcohol; between about 1 wt% and 90 wt%
surfactant; between about 0 wt% and about 70 wt% freezing point depression
agent; and
between about 0 wt% and about 70 wt% other additives.
In some embodiments, a composition for use in an oil and/or gas well having a
wellbore is provided comprising a fluid and an emulsion or microemulsion,
wherein the
emulsion or the microemulsion comprises water; an alcohol; a solvent
comprising a
terpene; and a surfactant in an amount between about 9 wt% and about 11 wt%
versus
the total emulsion, wherein the surfactant has a structure as in Formula I:
R8
R7 R9
R120
0 R10
R11
(I),
wherein each of R7, R8, R9, R19, and R11 are the same or different and are
selected from
the group consisting of hydrogen, optionally substituted alkyl, and ¨CH=CHAr,
provided
at least one of R7, R8, R9, R1 , and RH is ¨CH=CHAr; Ar is an aryl group; R12
is
hydrogen or alkyl; n is 1-100; and each m is independently 1 or 2.
In some embodiments, a composition for use in an oil and/or gas well having a
wellbore is provided comprising a fluid and an emulsion or microemulsion,
wherein the
emulsion or the microemulsion comprises water; an alcohol; a solvent
comprising a
terpene; and a surfactant in an amount between about 9 wt% and about 11 wt%
versus
the total emulsion, wherein the surfactant has a structure as in Formula II:
- 5 -
CA 02906165 2015-09-11
WO 2014/153102 PCT/US2014/029079
R8
R7 R9
0 Oil R10
R11
(TO,
wherein each of R7, R8, R9, R10, and R11 are the same or different and are
selected from
the group consisting of hydrogen, optionally substituted alkyl, and ¨CH=CHAr,
provided
at least one of R7, R8, R9, R10, and R11 is ¨CH=CHAr; Ar is an aryl group; Y-
is an
anionic group; Xis a cationic group; n is 1-100; and each m is independently 1
or 2.
In some embodiments, a composition for use in an oil and/or gas well having a
wellbore is provided comprising a fluid and an emulsion or microemulsion,
wherein the
emulsion or the microemulsion comprises water; an alcohol; a solvent
comprising a
terpene; and a surfactant in an amount between about 9 wt% and about 11 wt%
versus
the total emulsion, wherein the surfactant has a structure as in Formula III:
R8
R7 R9
0
1101
Z
0 R1
R11
(III),
wherein each of R7, R8, R9, R10, and R11 are the same or different and are
selected from
the group consisting of hydrogen, optionally substituted alkyl, and ¨CH=CHAr,
provided
at least one of R7, R8, R9, R10, and is ¨CH=CHAr; Ar is an aryl group; Z1
is a
cationic group; n is 1-100; and each m is independently 1 or 2.
Other aspects, embodiments, and features of the methods and compositions will
become apparent from the following detailed description when considered in
conjunction
with the accompanying drawings. All patent applications and patents
incorporated herein
by reference are incorporated by reference in their entirety. In case of
conflict, the
present specification, including definitions, will control.
- 6 -
CA 02906165 2015-09-11
WO 2014/153102 PCT/US2014/029079
Brief Description of the Drawings
The accompanying drawings are not intended to be drawn to scale. For purposes
of clarity, not every component may be labeled in every drawing. In the
drawings:
Figure 1 shows an exemplary plot for determining the phase inversion
temperature of a microemulsion, according to some embodiments.
Detailed Description
Methods and compositions comprising an emulsion or a microemulsion for use in
various aspects of the life cycle of an oil and/or gas well are provided. An
emulsion or a
microemulsion may comprise water, a solvent, a surfactant, a co-surfactant
(e.g., an
alcohol), and optionally other components (e.g., a clay stabilizer, a freezing
point
depression agent, an acid, a salt, etc.). In some embodiments, the solvent
comprises more
than one type of solvent (e.g., a first type of solvent and a second type of
solvent). In
some embodiments, the methods and compositions relate to various aspects of
the life
is cycle of an oil and/or gas well (e.g., drilling, mud displacement,
casing, cementing,
perforating, stimulation, kill fluids, enhanced oil recovery/improved oil
recovery, etc.).
In some embodiments, an emulsion or a microemulsion is added to a fluid
utilized in the
life cycle of well thereby increasing hydrocarbon (e.g., liquid or gaseous)
production of
the well, improving recovery of the fluid and/or other fluids, and/or
preventing or
minimizing damage to the well caused by exposure to the fluid (e.g., from
imbibition).
Additional details regarding the emulsion or microemulsions, as well as the
applications of the emulsions or microemulsions, are described herein. For
example, the
emulsions and microemulsions described in the Section A may be utilized in any
a wide
variety of application in the life cycle of the well, as described in Section
B.
I. Emulsions and Microemulsions
In some embodiments, emulsions or microemulsion are provided. The terms
should be understood to include emulsions or microemulsions that have a water
continuous phase, or that have an oil continuous phase, or microemulsions that
are
bicontinuous or multiple continuous phases of water and oil.
As used herein, the term emulsion is given its ordinary meaning in the art and
refers to dispersions of one immiscible liquid in another, in the form of
droplets, with
- 7 -
CA 02906165 2015-09-11
WO 2014/153102 PCT/US2014/029079
diameters approximately in the range of 100-1,000 nanometers. Emulsions may be
thermodynamically unstable and/or require high shear forces to induce their
formation.
As used herein, the term microemulsion is given its ordinary meaning in the
art
and refers to dispersions of one immiscible liquid in another, in the form of
droplets,
with diameters approximately in the range of about between about 1 and about
1000 nm,
or between 10 and about 1000 nanometers, or between about 10 and about 500 nm,
or
between about 10 and about 300 nm, or between about 10 and about 100 nm.
Microemulsions are clear or transparent because they contain particles smaller
than the
wavelength of visible light. In addition, microemulsions are homogeneous
thermodynamically stable single phases, and form spontaneously, and thus,
differ
markedly from thermodynamically unstable emulsions, which generally depend
upon
intense mixing energy for their formation. Microemulsions may be characterized
by a
variety of advantageous properties including, by not limited to, (i) clarity,
(ii) very small
particle size, (iii) ultra-low interfacial tensions, (iv) the ability to
combine properties of
water and oil in a single homogeneous fluid, (v) shelf life stability, and
(vi) ease of
preparation.
In some embodiments, the microemulsions described herein are stabilized
microemulsions that are formed by the combination of a solvent-surfactant
blend with an
appropriate oil-based or water-based carrier fluid. Generally, the
microemulsion forms
upon simple mixing of the components without the need for high shearing
generally
required in the formation of ordinary emulsions. In some embodiments, the
microemulsion is a thermodynamically stable system, and the droplets remain
finely
dispersed over time. In some cases, the average droplet size ranges from about
10 nm to
about 300 nm.
It should be understood, that while much of the description herein focuses on
microemulsions, this is by no means limiting, and emulsions may be employed
where
appropriate.
In some embodiments, the emulsion or microemulsion is a single emulsion or
microemulsion. For example, the emulsion or microemulsion comprises a single
layer of
a surfactant. In other embodiments, the emulsion or microemulsion may be a
double or
multilamellar emulsion or microemulsion. For example, the emulsion or
microemulsion
comprises two or more layers of a surfactant. In some embodiments, the
emulsion or
microemulsion comprises a single layer of surfactant surrounding a core (e.g.,
one or
- 8 -
CA 02906165 2015-09-11
WO 2014/153102 PCT/US2014/029079
more of water, oil, solvent, and/or other additives) or a multiple layers of
surfactant (e.g.,
two or more concentric layers surrounding the core). In certain embodiments,
the
emulsion or microemulsion comprises two or more immiscible cores (e.g., one or
more
of water, oil, solvent, and/or other additives which have equal or about equal
affinities
for the surfactant).
In some embodiments, a microemulsion comprises water, a solvent, and a
surfactant. In some embodiments, the microemulsion further comprises
additional
components, for example, a freezing point depression agent. Details of each of
the
components of the microemulsions are described in detail herein. In some
embodiments,
the components of the microemulsions are selected so as to reduce or eliminate
the
hazards of the microemulsion to the environment and/or the subterranean
reservoirs.
In some embodiments, the emulsion or microemulsion comprise between about 1
wt% and 95 wt% water, between about 1 wt% and 99 wt% solvent, between about 0
wt%
and about 50 wt% alcohol, between about 1 wt% and 90 wt% surfactant, and
between
.. about 0 wt% and about 70 wt% freezing point depression agent, and between
about 0
wt% and about 70 wt% other additives, versus the total microemulsion
composition. In
some embodiments, the emulsion or microemulsion comprise between about 1 wt%
and
60 wt% water, between about 1 wt% and 30 wt% solvent, between about 1 wt% and
about 50 wt% alcohol, between about 5 wt% and 65 wt% surfactant, and between
about
0 wt% and about 25 wt% freezing point depression agent, and between about 0
wt% and
about 30 wt% other additives, versus the total microemulsion composition. In
some
embodiments, for the formulation above, the water is present in an amount
between
about 10 wt% and about 55 wt%, or between about 15 wt% and about 45 wt%. In
some
embodiments, for the formulation above the solvent is present in an amount
between
about 2 wt% and about 25 wt%, or between about 5 wt% and about 25 wt%. In some
embodiments, the solvent comprises a terpene. In some embodiments, for the
formulations above, the alcohol is present in an amount between about 5 wt%
and about
40 wt%, or between about 5 wt% and 35 wt%. In some embodiments, the alcohol
comprises isopropanol. In some embodiments, for the formulations above, the
surfactant
is present in an amount between about 5 wt% and 60 wt%, or between about 10
wt% and
55 wt%. In some embodiments, for the formulations above, the freezing point
depression
agent is present in an amount between about 1 wt% and about 25 wt%, or between
about
1 wt% and about 20 wt%, or between about 3 wt% and about 20 wt%. In some
- 9 -
CA 02906165 2015-09-11
WO 2014/153102 PCT/US2014/029079
embodiments, for the formulations above, the other additives are present in an
amount
between about 1 wt% and about 30 wt%, or between about 1 wt% and about 25 wt%,
or
between about 1 wt% and about 20 wt%. In some embodiments, the other additives
comprise one or more salts and/or one or more acids.
In some embodiments, a microemulsion composition comprises between about 5
wt% to about 60 wt% water, from about 2 wt% to about 50 wt% solvent, from
about 5
wt% to about 60 wt% of a first type of a solubilizing surfactant, from about 2
wt% to
about 50 wt% of alcohol, from about 0.5 to 30 wt% of a freezing point
depression agent,
from about 0.5 wt% to about 30 wt% of a second type of surfactant, from about
0 wt% to
about 70 wt% of other additives (e.g., acid), and from about 0.5 wt% to about
30% of
mutual solvent, which is miscible together with the water and the solvent. In
some
embodiments, the solvent is a substance with a significant hydrophobic
character with
linear, branched, cyclic, bicyclic, saturated or unsaturated structure,
including but not
limited to terpenes, terpineols, terpene alcohols, aldehydes, ketones, esters,
amines, and
amides. Non-limiting examples of suitable mutual solvents include
ethyleneglycolmonobutyl ether (EGMBE), dipropylene glycol monomethyl ether,
short
chain alcohols (e.g., isopropanol), tetrahydrofuran, dioxane,
dimethylformamide, and
dimethylsulfoxide. Freezing point depressions agents are described in more
detail herein,
and include, but are not limited to, alkali metal or earth alkali metal salts,
preferably
chlorides, urea, alcohols (e.g., glycols such as propylene glycol and
triethylene glycol).
In some embodiments, the solubilizing surfactant is a molecule capable of
forming a
colloidal solution of the said solvent in predominantly aqueous media.
Generally,
surfactants are amphiphilic molecules that adsorb at interfaces to lower
surface energy
and can be used to form microemulsions in which they stabilize a mixture of
polar and
non-polar solvent. Non-limiting examples of suitable surfactants include
nonionic
surfactants with linear or branched structure, including, but not limited to,
ethoxylated
fatty alcohols, ethoxylated castor oils, and alkyl glucosides with a
hydrocarbon chain of
at least 8 carbon atoms and mole % of ethoxylation of 5 or more. Additional
surfactants
are described herein. Non-limiting examples of second types of surfactants
include
adsorption modifiers, foamers, surface tension lowering enhancers, and
emulsion
breaking additives. Specific examples of such surfactants include cationic
surfactants
with a medium chain length, linear or branched anionic surfactants, amine
oxides,
amphoteric surfactants, silicone based surfactants, alkoxylated novolac resins
(e.g.
- 10-
CA 02906165 2015-09-11
WO 2014/153102 PCT/US2014/029079
alkoxylated phenolic resins), alkoxylated polyimines, alkoxylated polyamines,
and
fluorosurfactants.
In some embodiments, the emulsion or microemulsion is as described in U.S.
Patent Number 7,380,606 and entitled "Composition and Process for Well
Cleaning,"
herein incorporated by reference.
I-A. Solvents
The microemulsion generally comprises a solvent. The solvent, or a combination
of solvents, may be present in the microemulsion in any suitable amount. In
some
embodiments, the total amount of solvent present in the microemulsion is
between about
1 wt% and about 99 wt%, or between about 2 wt% and about 90 wt %, or between
about
1 wt% and about 60 wt%, or between about 2 wt% and about 60 wt%, or between
about
1 and about 50 wt%, or between about 1 and about 30 wt%, or between about 5
wt% and
about 40 wt%, or between about 5 wt% and about 30 wt%, or between about 2 wt%
and
about 25 wt%, or between about 5 wt% and about 25 wt%, or between about 60 wt%
and
about 95 wt%, or between about 70 wt% or about 95 wt%, or between about 75 wt%
and
about 90 wt%, or between about 80 wt% and about 95 wt%, versus the total
microemulsion composition.
Those of ordinary skill in the art will appreciate that microemulsions
comprising
more than two types of solvents may be utilized in the methods, compositions,
and
systems described herein. For example, the microemulsion may comprise more
than one
or two types of solvent, for example, three, four, five, six, or more, types
of solvents. In
some embodiments, the microemulsion comprises a first type of solvent and a
second
type of solvent. The first type of solvent to the second type of solvent ratio
in a
microemulsion may be present in any suitable ratio. In some embodiments, the
ratio of
the first type of solvent to the second type of solvent by weight is between
about 4:1 and
1:4, or between 2:1 and 1:2, or about 1:1.
I-Al. Hydrocarbon solvents
In some embodiments, the solvent is an unsubstituted cyclic or acyclic,
branched
or unbranched alkane having 6-12 carbon atoms. In some embodiments, the cyclic
or
acyclic, branched or unbranched alkane has 6-10 carbon atoms. Non-limiting
examples
of unsubstituted acyclic unbranched alkanes having 6-12 carbon atoms include
hexane,
- 11 -
CA 02906165 2015-09-11
WO 2014/153102 PCT/US2014/029079
heptane, octane, nonane, decane, undecane, and dodecane. Non-limiting examples
of
unsubstituted acyclic branched alkanes having 6-12 carbon atoms include
isomers of
methylpentane (e.g., 2-methylpentane, 3-methylpentane), isomers of
dimethylbutane
(e.g., 2,2-dimethylbutane, 2,3-dimethylbutane), isomers of methylhexane (e.g.,
2-
methylhexane, 3-methylhexane), isomers of ethylpentane (e.g., 3-ethylpentane),
isomers
of dimethylpentane (e.g., 2,2,-dimethylpentane, 2,3-dimethylpentane, 2,4-
dimethylpentane, 3,3-dimethylpentane), isomers of trimethylbutane (e.g., 2,2,3-
trimethylbutane), isomers of methylheptane (e.g., 2-methylheptane, 3-
methylheptane, 4-
methylheptane), isomers of dimethylhexane (e.g., 2,2-dimethylhexane, 2,3-
dimethylhexane, 2,4-dimethylhexane, 2,5-dimethylhexane, 3,3-dimethylhexane,
3,4-
dimethylhexane), isomers of ethylhexane (e.g., 3-ethylhexane), isomers of
trimethylpentane (e.g., 2,2,3-trimethylpentane, 2,2,4-trimethylpentane, 2,3,3-
trimethylpentane, 2,3,4-trimethylpentane), and isomers of ethylmethylpentane
(e.g., 3-
ethy1-2-methylpentane, 3-ethy1-3-methylpentane). Non-limiting examples of
unsubstituted cyclic branched or unbranched alkanes having 6-12 carbon atoms,
include
cyclohexane, methylcyclopentane, ethylcyclobutane, propylcyclopropane,
isopropylcyclopropane, dimethylcyclobutane, cycloheptane, methylcyclohexane,
dimethylcyclopentane, ethylcyclopentane, trimethylcyclobutane, cyclooctane,
methylcycloheptane, dimethylcyclohexane, ethylcyclohexane, cyclononane,
methylcyclooctane, dimethylcycloheptane, ethylcycloheptane,
trimethylcyclohexane,
ethylmethylcyclohexane, propylcyclohexane, and cyclodecane. In a particular
embodiment, the unsubstituted cyclic or acyclic, branched or unbranched alkane
having
6-12 carbon is selected from the group consisting of heptane, octane, nonane,
decane,
2,2,4-trimethylpentane (isooctane), and propylcyclohexane.
In some embodiments, the solvent is an unsubstituted acyclic branched or
unbranched alkene having one or two double bonds and 6-12 carbon atoms. In
some
embodiments, the solvent is an unsubstituted acyclic branched or unbranched
alkene
having one or two double bonds and 6-10 carbon atoms. Non-limiting examples of
unsubstituted acyclic unbranched alkenes having one or two double bonds and 6-
12
carbon atoms include isomers of hexene (e.g., 1-hexene, 2-hexene), isomers of
hexadiene
(e.g., 1,3-hexadiene, 1,4-hexadiene), isomers of heptene (e.g., 1-heptene, 2-
heptene, 3-
heptene), isomers of heptadiene (e.g., 1,5-heptadiene, 1-6, heptadiene),
isomers of octene
(e.g., 1-octene, 2-octene, 3-octene), isomers of octadiene (e.g., 1,7-
octadiene), isomers of
- 12 -
CA 02906165 2015-09-11
WO 2014/153102
PCT/US2014/029079
nonene, isomers of nonadiene, isomers of decene, isomers of decadiene, isomers
of
undecene, isomers of undecadiene, isomers of dodecene, and isomers of
dodecadiene. In
some embodiments, the acyclic unbranched alkene having one or two double bonds
and
6-12 carbon atoms is an alpha-olefin (e.g., 1-hexene, 1-heptene, 1-oetene, 1-
nonene, 1-
decene, 1-undecene, 1-dodeeene). Non-limiting examples unsubstituted acyclic
branched
alkenes include isomers of methylpentene, isomers of dimethylpentene, isomers
of
ethylpentene, isomers of methylethylpentene, isomers of propylpentene, isomers
of
methylhexene, isomers of ethylhexene, isomers of dimethylhexene, isomers of
methylethylhexene, isomers of methylheptene, isomers of ethytheptene, isomers
of
dimethylhexptene, and isomers of methyl ethylheptene. In a particular
embodiment, the
unsubstituted acyclic unbranched alkene having one or two double bonds and 6-
12
carbon atoms is selected from the group consisting of 1-octene and 1,7-
octadiene.
In some embodiments, the solvent is a cyclic or acyclic, branched or
unbranched
alkane having 9-12 carbon atoms and substituted with only an ¨OH group. Non-
limiting
examples of cyclic or acyclic, branched or unbranched alkanes having 9-12
carbon atoms
and substituted with only an ¨OH group include isomers of nonanol, isomers of
decanol,
isomers of undecanol, and isomers of dodecanol. In a particular embodiment,
the cyclic
or acyclic, branched or unbranched alkane having 9-12 carbon atoms and
substituted
with only an ¨OH group is selected from the group consisting of 1-nonanol and
1-
decanol.
In some embodiments, the solvent is a branched or unbranched dialkylether
compound having the formula C,,H2õ+10CmH2m+1 wherein n + m is between 6 and
16. In
some cases, n + m is between 6 and 12, or between 6 and 10, or between 6 and
8. Non-
limiting examples of branched or unbranched dialkylether compounds having the
formula CiiH2t,{10CmH2m { I include isomers of C3H70C3H7, isomers of
C4H90C3H75
isomers of C5H110C3H7, isomers of C6H130C3H7, isomers of C4H90C4H9, isomers of
C4H90C5H11, isomers of C4H90061113, isomers of C5H110C6H13, and isomers of
C6H130C6H13. In a particular embodiment, the branched or unbranched
dialklyether is an
isomer C6H110C6H1l (e.g., dihexylether).
In some embodiments, the solvent is an aromatic solvent having a boiling point
between about 300-400 F. Non-limiting examples of aromatic solvents having a
boiling
point between about 300-400 F include butylbenzene, hexylbenzene, mesitylene,
light
aromatic naphtha, and heavy aromatic naphtha.
- 13 -
CA 02906165 2015-09-11
WO 2014/153102 PCT/US2014/029079
In some embodiments, the solvent is a bicyclic hydrocarbon solvent with
varying
degrees of unsaturation including fused, bridgehead, and spirocyclic
compounds. Non-
limiting examples of bicyclic solvents include isomers of decalin,
tetrahydronapthalene,
norbomane, norbomene, bicyclo[4.2.0]octane, bicyclo[3.2.1]octane, and
spiro[5.5]dodecane.
In some embodiments, the solvent is a bicyclic hydrocarbon solvent with
varying
degrees of unsaturation and containing at least one 0, N, or S atom including
fused,
bridgehead, and spirocyclic compounds. Non-limiting examples include isomers
of 7
oxabicyclo[2.2.1]heptane, 4,7-epoxyisobenzofuran-1,3-dione, and 7
oxabicyclo[2.2.1]heptane-2,3-dicarboxylic acid, 2,3-dimethyl ester.
In some embodiments, the solvent is a cyclic or acyclic, branched or
unbranched
alkane having 8 carbon atoms and substituted with only an ¨OH group. Non-
limiting
examples of cyclic or acyclic, branched or unbranched alkanes having 8 carbon
atoms
and substituted with only an ¨OH group include isomers of octanol (e.g., 1-
octanol,
octanol, 3-octanol, 4-octanol), isomers of methyl heptanol, isomers of
ethylhexanol (e.g.,
2-ethyl-1-hexanol, 3-ethyl-1-hexanol, 4-ethyl-1-hexanol), isomers of
dimethylhexanol,
isomers of propylpentanol, isomers of methylethylpentanol, and isomers of
trimethylpentanol. In a particular embodiment, the cyclic or acyclic, branched
or
unbranched alkane having 8 carbon atoms and substituted with only an ¨OH group
is
.. selected from the group consisting of 1-octanol and 2-ethyl-1-hexanol.
I-A2. Amine and Amide Solvents
In some embodiments, the amine is of the formula NR1R2R3, wherein R1, R2, and
R3 are the same or different and are hydrogen or cyclic or acyclic, branched
or
.. unbranched alkyl (e.g., C1_16 alkyl), optionally substituted, or
optionally, any two of R1,
R2 and R3 are joined together to form a ring. In some embodiments, each of RI,
R2, and
R3 are the same or different and are hydrogen or cyclic or acyclic, branched
or
unbranched alkyl, or optionally, any two of R1, R2 and R3 are joined together
to form a
ring, provide at least one of R1, R2, and R3 is methyl or ethyl. In some
cases, Rl is cyclic
or acyclic, branched or unbranched Cl-C6 alkyl and R2 and R3 are the same or
different
and are hydrogen or cyclic or acyclic, branched or unbranched alkyl (e.g.,
C8_16 alkyl), or
optionally, R2 and R3 may be joined together to form a ring. In some cases, R1
is methyl
or ethyl and R2 and R3 are the same or different and are hydrogen or cyclic or
acyclic,
- 14 -
CA 02906165 2015-09-11
WO 2014/153102 PCT/US2014/029079
branched or unbranched alkyl (e.g., C8_16 alkyl), or optionally, R2 and R3 may
be joined
together to form a ring. In some cases, R1 is methyl and R2 and R3 are the
same or
different and are hydrogen or cyclic or acyclic, branched or unbranched alkyl
(e.g., C8-16
alkyl), or optionally, R2 and R3 may be joined together to form a ring. In
some cases, R1
.. and R2 are the same or different and are hydrogen or cyclic or acyclic,
branched or
unbranched C1-C6 alkyl and R3 is branched or unbranched alkyl (e.g., C8_16
alkyl). In
some cases, 121 and R2 are the same or different and are methyl or ethyl and
R3 is
hydrogen or cyclic or acyclic, branched or unbranched alkyl (e.g., C8_16
alkyl). In some
cases, R1 and R2 are methyl and R3 is hydrogen or cyclic or acyclic, branched
or
unbranched alkyl (e.g., C8_16 alkyl).
In some embodiments, the amine is of the formula NR1R2R3, wherein R1, R2, and
R3 are the same or different and are cyclic or acyclic, branched or unbranched
alkyl (e.g.,
C1_16 alkyl), optionally substituted, or optionally, any two of R1, R2 and R3
are joined
together to form a ring. In some embodiments, each of R1, R2, and R3 are the
same or
different and are cyclic or acyclic, branched or unbranched alkyl, or
optionally, any two
of R1, R2 and R3 are joined together to form a ring, provide at least one of
R1, R2, and R3
is methyl or ethyl. In some cases, R1 is cyclic or acyclic, branched or
unbranched Ci-C6
alkyl and R2 and R3 are the same or different and are cyclic or acyclic,
branched or
unbranched alkyl (e.g., C8_16 alkyl), or optionally, R2 and R3 may be joined
together to
form a ring. In some cases, R1 is methyl or ethyl and R, and R3 are the same
or different
and are cyclic or acyclic, branched or unbranched alkyl (e.g., C816 alkyl), or
optionally,
R2 and R3 may be joined together to form a ring. In some cases, R1 is methyl
and R2 and
R3 are the same or different and are cyclic or acyclic, branched or unbranched
alkyl (e.g.,
C8_16 alkyl), or optionally, R2 and R3 may be joined together to form a ring.
In some
cases, R1 and R2 are the same or different and are cyclic or acyclic, branched
or
unbranched C1-C6 alkyl and R3 is branched or unbranched alkyl (e.g., C8_16
alkyl). In
some cases, R1 and R2 are the same or different and are methyl or ethyl and R3
is cyclic
or acyclic, branched or unbranched alkyl (e.g., C8_16 alkyl). In some cases,
R1 and R2 are
methyl and R3 is cyclic or acyclic, branched or unbranched alkyl (e.g., C8_16
alkyl).
In some embodiments, the amine is of the formula NR1R2R3, wherein R1 is
methyl and R2 and R3 are the same or different and are hydrogen or cyclic or
acyclic,
branched or unbranched C8_16 alkyl, or optionally R2 and R3 are joined
together to form a
ring. Non-limiting examples of amines include isomers of N-methyl-octylamine,
isomers
- 15 -
CA 02906165 2015-09-11
WO 2014/153102 PCT/US2014/029079
of N-methyl-nonylamine, isomers of N-methyl-decylamine, isomers of N
methylundecylamine, isomers of N-methyldodecylamine, isomers of N methyl
teradecylamine, and isomers of N-methyl-hexadecylamine. In certain
embodiements, the
amine is selected from the group consisting of N methyldecylamine and N
methylhexadecylamine.
In some embodiments, the amine is of the formula NR1R2R3, wherein RI is
methyl and R2 and R3 are the same or different and are cyclic or acyclic,
branched or
unbranched C8_16 alkyl, or optionally R2 and R3 are joined together to form a
ring. In
some embodiments, the amine is of the formula NR1R2R3, wherein R1 is methyl
and R2
and R3 are the same or different and are cyclic or acyclic, branched or
unbranched C8_16
alkyl, or optionally R2 and R3 are joined together to form a ring. Non-
limiting examples
of amines include isomers of N-methyl-N-octyloctylamine, isomers of N-methyl-N-
nonylnonylamine, isomers of N-methyl-N-decyldecylamine, isomers of N-methyl-N-
undecylundecylamine, isomers of N-methyl-N-dodecyldodecylamine, isomers of N-
methyl-N-tetradecylteradecylamine, isomers of N-methyl-N-
hexadecylhdexadecylamine,
isomers of N-methyl-N-oetylnonylamine, isomers of N-methyl-N-octyldecylamine,
isomers of N-methyl-N-octyldodecylamine, isomers of N-methyl-N-
octylundecylamine,
isomers of N-methyl-N-oetyltetradecylamine, isomers of N-methyl-N-
octylhexadecylamine, N-methyl-N-nonyldecylamine, isomers of N-methyl-N-
nonyldodecylamine, isomers of N-methyl-N-nonyltetradecylamine, isomers of N-
methyl-N-nonylhexadecylamine, isomers of N-methyl-N-decyldodecylamine, isomers
of
N-methyl-N-decylundecylamine, isomers of N-methyl-N-decyldodecylamine, isomers
of
N-methyl-N-decyltetradecylamine, isomers of N-methyl-N-decylhexadecylamine,
isomers of N-methyl-N-dodecylundecylamine, isomers of N-methyl-N-
dodecyltetradecylamine, isomers of N-methyl-N-dodecylhexadecylamine, and
isomers of
N-methyl-N-tetradecylhexadecylamine. In certain embodiments, the amine is
selected
from the group consisting of N-methyl-N-octyloctylamine, isomers of N-methyl-N-
nonylnonylamine, isomers of N-methyl N-decyldecylamine, isomers of N-methyl-N-
undecylundecylamine, isomers of N-methyl-N-dodecyldodecylamine, isomers of N-
methyl-N-tetradecylteradecylamine, and isomers of N-methyl-N
hexadecylhdexadecylamine. In certain embodiments, the amine is selected from
the
group consisting of N-methyl-N-dodecyldodecylamine and isomers of N-methyl-N
hexadecylhexadecylamine. In certain embodiments, the amine is selected from
the group
- 16-
CA 02906165 2015-09-11
WO 2014/153102 PCT/US2014/029079
consisting of isomers of N-methyl-N-octylnonylamine, isomers of N-methyl-N-
octyldecylamine, isomers of N-methyl-N-octyldodecylamine, isomers of N-methyl-
N-
octylundecylamine, isomers of N-methyl-N-octyltetradecylamine, isomers of N-
methyl-
N-octylhexadecylamine, N-methyl-N-nonyldecylamine, isomers of N-methyl-N-
nonyldodecylamine, isomers of N-methyl-N-nonyltetradecylamine, isomers of N-
methyl-N-nonylhexadecylamine, isomers of N-methyl-N-decyldodecylamine, isomers
of
N-methyl-N-decylundecylamine, isomers of N-methyl-N-decyldodecylamine, isomers
of
N-methyl-N-decyltetradecylamine, isomers of N-methyl-N-decylhexadecylamine,
isomers of N-methyl-N-dodecylundecylamine, isomers of N-methyl-N-
.. dodecyltetradecyl amine, isomers of N-methyl-N-dodecylhexadecylamine, and
isomers of
N-methyl-N-tetradecylhexadecylamine. In certain embodiments, the cyclic or
acyclic,
branched or unbranched tri-substituted amines is selected from the group
consisting of
N-methyl-N-octyldodecylamine, N-methyl-N-octylhexadecylamine or N-methyl-N-
dodecylhexadecylamine.
is In certain embodiments, the amine is of the formula NR1R2R3, wherein R1
and R2
are methyl and R3 is cyclic or acyclic, branched or unbranched C8_16 alkyl.
Non-limiting
examples of amines include isomers of N,N-dimethylnonylamine, isomers of N,N-
dimethyldecylamine, isomers of N,N-dimethylundecylamine, isomers of N,N-
dimethyldodecylamine, isomers of N,N-dimethyltetradecylamine, and isomers of
N,N-
dimethylhexadecylamine. In certain embodiments, the amine is selected from the
group
consisting of N,N-dimethyldecyl amine, isomers of N,N-dodecylamine, and
isomers of
N,N-dimethylhexadecylamine.
In some embodiments, the amide is of the formula N(C=0R4)R5R6, wherein R4,
R5, and R6 are the same or different and are hydrogen or cyclic or acyclic,
branched or
unbranched alkyl (e.g., C1_16 alkyl), optionally substituted, or optionally,
R5 and R6 are
joined together to form a ring. In some embodiments, each of R4, Rs, and R6
are the same
or different and are hydrogen or cyclic or acyclic, branched or unbranched
alkyl (e.g., Ci
16 alkyl), optionally substituted, or optionally, R5 and R6 are joined
together to form a
ring, provided at least one of R4, R5, and R6 is methyl or ethyl. In some
cases, R4 is
hydrogen or cyclic or acyclic, branched or unbranched C1-C6 alkyl, optionally
substituted, and R5 and R6 are the same or different and are hydrogen or
cyclic or
acyclic, branched or unbranched alkyl (e.g., C8_16 alkyl), optionally
substituted, or
optionally, R5 and R6 may be joined together to form a ring. In some cases, R4
is
- 17 -
CA 02906165 2015-09-11
WO 2014/153102 PCT/US2014/029079
hydrogen, methyl, or ethyl and R5 and R6 are the same or different and are
hydrogen or
cyclic or acyclic, branched or unbranched alkyl (e.g., C8_16 alkyl),
optionally substituted,
or optionally, R5 and R6 may be joined together to form a ring. In some cases,
R4 is
hydrogen and R5 and R6 are the same or different and are cyclic or acyclic,
branched or
unbranched alkyl (e.g., C8_16 alkyl), optionally substituted, or optionally,
R5 and R6 may
be joined together to form a ring. In some cases, R4 and R5 are the same or
different and
are hydrogen or cyclic or acyclic, branched or unbranched C1-C6 alkyl,
optionally
substituted, and R6 is cyclic or acyclic, branched or unbranched alkyl (e.g.,
C8_16 alkyl),
optionally substituted. In some cases, R4 and R5 are the same or different and
are
.. hydrogen, methyl, or ethyl and R6 is cyclic or acyclic, branched or
unbranched alkyl
(e.g., C8_16 alkyl), optionally substituted. In some cases, R4 and R5 are
hydrogen and R6 is
cyclic or acyclic, branched or unbranched alkyl (e.g., C8_16 alkyl),
optionally substituted.
In some cases, R6 is hydrogen or cyclic or acyclic, branched or unbranched Ci-
C6 alkyl,
optionally substituted, and R4 and R5 are the same or different and are
hydrogen or cyclic
or acyclic, branched or unbranched alkyl (e.g., C8_16 alkyl), optionally
substituted, or
optionally. In some cases, R6 is hydrogen, methyl, or ethyl and R4 and R5 are
the same or
different and are hydrogen or cyclic or acyclic, branched or unbranched alkyl
(e.g., C8-16
alkyl). In some cases, R6 is hydrogen and R4 and R5 are the same or different
and are
cyclic or acyclic, branched or unbranched alkyl (e.g., C8_16 alkyl),
optionally substituted.
In some cases, R5 and R6 are the same or different and arc hydrogen or cyclic
or acyclic,
branched or unbranched Ci-C6 alkyl, optionally substituted, and R4 is cyclic
or acyclic,
branched or unbranched alkyl (e.g., C846 alkyl), optionally substituted. In
some cases, R5
and R6 are the same or different and are hydrogen, methyl, or ethyl and R4 is
cyclic or
acyclic, branched or unbranched alkyl (e.g., C8_16 alkyl), optionally
substituted. In some
.. cases, R5 and R6 are hydrogen and R4 is cyclic or acyclic, branched or
unbranched alkyl
(e.g., C8_16 alkyl), optionally substituted.
In some embodiments, the amide is of the formula N(C=0R4)R5R6, wherein R4,
R5, and R6 are the same or different and are cyclic or acyclic, branched or
unbranched
alkyl (e.g., Ci_16 alkyl), optionally substituted, or optionally, R5 and R6
are joined
.. together to form a ring. In some embodiments, each of R4, R5, and R6 are
the same or
different and are cyclic or acyclic, branched or unbranched alkyl (e.g., C1_16
alkyl),
optionally substituted, or optionally, R5 and R6 are joined together to form a
ring,
provided at least one of R4, R5, and R6 is methyl or ethyl. In some cases, R4
is cyclic or
- 18-
CA 02906165 2015-09-11
WO 2014/153102 PCT/US2014/029079
acyclic, branched or unbranched Ci-C6 alkyl, optionally substituted, and R5
and R6 are
the same or different and are hydrogen or cyclic or acyclic, branched or
unbranched alkyl
(e.g., C8_16 alkyl), optionally substituted, or optionally, R5 and R6 may be
joined together
to form a ring. In some cases, R4 is methyl or ethyl and Rs and R6 are the
same or
different and are cyclic or acyclic, branched or unbranched alkyl (e.g., C8_16
alkyl),
optionally substituted, or optionally, R5 and R6 may be joined together to
form a ring. In
some cases, R4 is and R5 and R6 are the same or different and are cyclic or
acyclic,
branched or unbranched alkyl (e.g., C8_16 alkyl), optionally substituted, or
optionally, R5
and R6 may be joined together to form a ring. In some cases, R4 is methyl and
R5 and R6
are the same or different and are cyclic or acyclic, branched or unbranched
alkyl (e.g.,
C8_16 alkyl), optionally substituted, or optionally, R5 and R6 may be joined
together to
form a ring. In some cases, R4 and R5 are the same or different and are methyl
or ethyl
and R6 is cyclic or acyclic, branched or unbranched alkyl (e.g., C8_16 alkyl),
optionally
substituted. In some cases, R4 and R5 are methyl and R6 is cyclic or acyclic,
branched or
is unbranched alkyl (e.g., C846 alkyl), optionally substituted. In some
cases, R6 is cyclic or
acyclic, branched or unbranched C1-C6 alkyl, optionally substituted, and R4
and R5 are
the same or different and are hydrogen or cyclic or acyclic, branched or
unbranched alkyl
(e.g., C8_16 alkyl), optionally substituted, or optionally. In some cases, R6
is methyl or
ethyl and R4 and R5 are the same or different and are hydrogen or cyclic or
acyclic,
branched or unbranched alkyl (e.g., C8_16 alkyl). In some cases, R6 is methyl
and R4 and
R5 are the same or different and are cyclic or acyclic, branched or unbranched
alkyl (e.g.,
C8_16 alkyl), optionally substituted. In some cases, R5 and R6 are the same or
different
and are cyclic or acyclic, branched or unbranched Ci-C6 alkyl, optionally
substituted, and
R4 is cyclic or acyclic, branched or unbranched alkyl (e.g., C8_16 alkyl),
optionally
substituted. In some cases, R5 and R6 are the same or different and are methyl
or ethyl
and R4 is cyclic or acyclic, branched or unbranched alkyl (e.g., C846 alkyl),
optionally
substituted. In some cases, R5 and R6 are methyl and R6 is cyclic or acyclic,
branched or
unbranched alkyl (e.g., C8_16 alkyl), optionally substituted.
In some embodiments, the amide is of the formula N(C=0R4)R5R6, wherein each
of R4, R5, and R6 are the same or different and are cyclic or acyclic,
branched or
unbranched C4_16 alkyl, optionally substituted, or optionally, R5 and R6 are
joined
together to form a ring. In some embodiments, the amide is of the formula
N(C=OR4)R5R6, wherein each of R4, R5, and R6 are the same or different and are
cyclic
- 19-
CA 02906165 2015-09-11
WO 2014/153102 PCT/US2014/029079
or acyclic, branched or unbranched C8_16 alkyl, optionally substituted, or
optionally, R5
and R6 are joined together to form a ring. In some embodiments, the amide is
of the
formula N(C=0R4)R5R6, wherein each of R4, R5, and R6 are the same or different
and are
selected from the group consisting of t-butyl and cyclic or acyclic, branched
or
unbranched C5_16 alkyl, optionally substituted, or optionally, R5 and R6 are
joined
together to form a ring. In some embodiments, R4, R5, and R6 are the same or
different
and are selected from the group consisting of t-butyl and cyclic or acyclic,
branched or
unbranched C8_16 alkyl, optionally substituted, or optionally, R5 and R6 are
joined
together to form a ring. Non-limiting examples amides include N,N-
dioctyloctamide,
N,N-dinonylnonamide, N,N-didecyldecamide, N,N-didodecyldodecamide, N,N-
diundecylundecamide, N,N-ditetradecyltetradecamide, N,N-
dihexadecylhexadecamide,
N,N-didecyloctamide, N,N-didodecyloctamide, N,N-dioctyldodecamide, N,N-
didecyldodecamide, N,N-dioctylhexadecamide, N,N-didecylhexadecamide, and N,N-
didodecylhexadecamide. In certain embodiments, the amide is selected from the
group
consisting of N,N-dioctyldodecamide and N,N-didodecyloctamide
In some embodiments, the amide is of the formula N(C=0R4)R5R6, wherein R6 is
hydrogen or Ci-C1 alkyl and R4 and R5 are the same or different and are cyclic
or
acyclic, branched or unbranched C4_16 alkyl, optionally substituted. In some
embodiments, R6 is selected from the group consisting of hydrogen, methyl,
ethyl,
propyl and isopropyl, and R4 and R5 are the same or different and are cyclic
or acyclic,
branched or unbranched C4_16 alkyl, optionally substituted. In certain
embodiments, R6 is
selected from the group consisting of hydrogen, methyl, ethyl, propyl and
isopropyl, and
R4 and R5 are the same or different and are cyclic or acyclic, branched or
unbranched C8_
16 alkyl, optionally substituted. In some cases, at least one of R4 and R5 is
substituted
with a hydroxy group. In some embodiments, R6 is selected from the group
consisting of
hydrogen, methyl, ethyl, propyl, and isopropyl, and R4 and R5 are the same or
different
and are selected from the group consisting of tert-butyl, cyclic or acyclic,
branched or
unbranched C5_16 alkyl, optionally substituted, and cyclic or acyclic,
branched or
unbranched Ci_16 alkyl substituted with an ¨OH group.
In some embodiments, the amide is of the formula N(C=OR4)R5R6, wherein R6 is
C1-C3 alkyl and R4 and R5 are the same or different and are cyclic or acyclic,
branched or
unbranched C4_16 alkyl, optionally substituted. In some embodiments, R6 is
selected from
the group consisting of methyl, ethyl, propyl and isopropyl, and R4 and R5 are
the same
-20-
CA 02906165 2015-09-11
WO 2014/153102 PCT/US2014/029079
or different and are cyclic or acyclic, branched or unbranched C4_16 alkyl,
optionally
substituted. In certain embodiments, R6 is selected from the group consisting
of methyl,
ethyl, propyl and isopropyl, and R4 and R5 are the same or different and are
cyclic or
acyclic, branched or unbranched C8_16 alkyl, optionally substituted. In some
cases, at
least one of R4 and R5 is substituted with a hydroxy group. In some
embodiments, R6 is
selected from the group consisting of methyl, ethyl, propyl, and isopropyl,
and R4 and R5
are the same or different and are selected from the group consisting of tert-
butyl, cyclic
or acyclic, branched or unbranched C5_16 alkyl, optionally substituted, and
cyclic or
acyclic, branched or unbranched Ci_16 alkyl substituted with an ¨OH group.
to Non-limiting examples of amides include N,N-di-tert-butylformamide, N,N-
dipentyl formami de, N,N-dihexylformamide, N,N-diheptyl form amide, N,N-
dioctylformamide, N,N-dinonylformamide, N,N-didecylformamide, N,N-
diundecylformamide, N,N-didodecylformamide, N,N-dihydroxymethylformamide, N,N-
di-tert-butylacetamide, N,N-dipentylacetamide, N,N-dihexylacetamide, N,N-
diheptylacetamide, N,N-dioctylacetamide, N,N-dinonylacetamide, N,N-
didecylacetamide, N,N-diundecylacetamide, N,N-didodecylacetamide, N,N-
dihydroxymethylacetamide, N,N-dimethylpropionamide, N,N-diethylpropionamide,
N,N-dipropylpropionamide, such as N,N-di-n-propylpropionamide or N,N-
diisopropylpropionamide, N,N-dibutylpropionamide, such as N,N-di-n-
butylpropionamide, N,N -di-scc-butylpropionamide, N,N-diisobutylpropionamidc
or
N,N-di-tert-butylpropionami de, N,N-dipentylpropionamide, N ,N -
dihexylpropionami de,
N,N-diheptylpropionamide, N,N-dioctylpropionamide, N,N-dinonylpropionamide,
N,N-
didecylpropionamide, N,N-diundecylpropionamide, N,N-didodecylpropionamide, N,N-
dimethyl-n-butyramide, N,N-diethyl-n-butyramide, N,N-dipropyl-n-butyramide,
such as
N,N-di-n-propyl-n-butyramide or N,N-diisopropyl-n-butyramide, N,N-dibutyl-n-
butyramide, such as N,N-di-n-butyl-n-butyramide, N,N-di-sec-butyl-n-
butyramide, N,N-
diisobutyl-n-butyramide, N,N-di-tert-butyl-n-butyramide, N,N-dipentyl-n-
butyramide,
N,N-dihexyl-n-butyramide, N,N-diheptyl-n-butyramide, N,N-dioctyl-n-butyramide,
N,N-dinonyl-n-butyramide, N,N-didecyl-n-butyramide, N,N-diundecyl-n-
butyramide,
N,N-didodecyl-n-butyramide, N,N-dipentylisobutyramide, N,N-
dihexylisobutyramide,
N,N-dihcptylisobutyramide, N,N -dioctylisobutyramidc, N,N-
dinonylisobutyramide,
N,N-didecylisobutyramide, N,N-diundecylisobutyramide, N,N -
didodecylisobutyramide,
N,N-pentylhexyl form amide, N,N-pentylhexylacetamide, N,N-
pentylhexylpropionamide,
-21-
CA 02906165 2015-09-11
WO 2014/153102 PCT/US2014/029079
N,N-pentylhexyl-n-butyramide, N,N-pentylhexylisobutyramide, N,N-
methylethylpropionamide, N,N-methyl-n-propylpropionamide, N,N-
methylisopropylpropionamide, N,N-methyl-n-butylpropionamide, N,N-methylethyl-n-
butyramide, N,N-methyl-n-butyramide, N,N-methylisopropyl-n-butyramide, N,N-
methyl-n-butyl-n-butyramide, N,N-methylethylisobutyramide, N,N-methyl-n-
propylisobutyramide, N,N-methylisopropylisobutyramide, and N,N-methyl-n-
butylisobutyramide. In certain embodiments, the amide is selected from the
group
consisting of N,N-dioctyldodecacetamide, N,N-methyl-N-
octylhexadecdidodecylacetamide, and N-methyl-N-
ihexadecyldodecylhexadecacetamide.
to In some embodiments, the amide is of the formula N(C=0R4)R5R6, wherein
R6 is
hydrogen or methyl and R4 and R5 are the same or different and are cyclic or
acyclic,
branched or unbranched C8_16 alkyl. Non-limiting amides include isomers of N
methyloctamide, isomers of N-methylnonamide, isomers of N-methyldecamide,
isomers
of N methylundecamide, isomers of N methyldodecamide, isomers of N
.. methylteradecamide, and isomers of N-methyl-hexadecamide. In certain
embodiments
the amides are slected from the group consisteing of N methyloctamide, N
methyldodecamide, and N methylhexadecamide.
In some embodiments, the amide is of the formula N(C=0R4)R5R6, wherein R6 is
methyl and R4 and R5 are the same or different and are cyclic or acyclic,
branched or
unbranched C8_16 alkyl. Non-limiting amides include isomers of N-methyl-N-
octyloctami de, isomers of N-methyl-N-nonylnonamide, isomers of N-methyl -N-
decyldecamide, isomers of N methyl-N undecylundecamide, isomers of N methyl-N-
dodecyldodecamide, isomers of N methyl N-tetradecylteradecamide, isomers of N-
methyl-N-hexadecylhdexadecamide, isomers of N-methyl-N-octylnonamide, isomers
of
N-methyl-N-octyldecamide, isomers of N-methyl-N-octyldodecamide, isomers of N-
methyl-N-octylundecamide, isomers of N-methyl-N-octyltetradecamide, isomers of
N-
methyl-N-octylhexadecamide, N-methyl-N-nonyldecamide, isomers of N-methyl-N-
nonyldodecamide, isomers of N-methyl-N-nonyltetradecamide, isomers of N-methyl-
N-
nonylhexadecamide, isomers of N-methyl-N-decyldodecamide, isomers of N methyl-
N-
decylundecamide, isomers of N-methyl-N-decyldodecamide, isomers of N-methyl-N-
decyltetradecamide, isomers of N-methyl-N-decylhexadecamide, isomers of N
methyl-
N-dodecylundecamide, isomers of N methyl-N-dodecyltetradecamide, isomers of N-
methyl-N-dodecylhexadecami de, and isomers of N methyl-N-tetradecylhexadecami
de.
- 22 -
CA 02906165 2015-09-11
WO 2014/153102 PCT/US2014/029079
In certain embodiments, the amide is selected from the group consisting of
isomers of N-
methyl-N-octyloctamide, isomers of N-methyl-N-nonylnonamide, isomers of N-
methyl-
N-decyldecamide, isomers of N methyl-N undecylundecamide, isomers of N methyl-
N-
dodecyldodecamide, isomers of N methyl N-tetradecylteradecamide, and isomers
of N-
methyl-N-hexadecylhdexadecamide. In certain embodiments, amide is selected
from the
group consisting of N-methyl-N-octyloctamide, N methyl-N-dodecyldodecamide,
and N-
methyl-N-hexadecylhexadecamide. In certain embodiments, the amide is selected
from
the group consisting of isomers of N-methyl-N-octylnonamide, isomers of N-
methyl-N-
octyldecamide, isomers of N-methyl-N-octyldodecamide, isomers of N-methyl-N-
octylundecamide, isomers of N-methyl-N-octyltetradecamide, isomers of N-methyl-
N-
octylhexadecamide, N-methyl-N-nonyldecamide, isomers of N-methyl-N-
nonyldodecamide, isomers of N-methyl-N-nonyltetradecamide, isomers of N-methyl-
N-
nonylhexadecamide, isomers of N-methyl-N-decyldodecamide, isomers of N methyl-
N-
decylundecamide, isomers of N-methyl-N-decyldodecamide, isomers of N-methyl-N-
decyltetradecamide, isomers of N-methyl-N-decylhexadecamide, isomers of N
methyl-
N-dodecylundecamide, isomers of N methyl-N-dodecyltetradecamide, isomers of N-
methyl-N-dodecylhexadecamide, and isomers of N methyl-N-
tetradecylhexadecamide.
In certain embodiments, the amides is selected from the group consisting of N-
methyl-N-
octyldodecamide, N-methyl-N-octylhexadecamide, and N-methyl-N-
dodecylhexadecamide.
In some embodiments, the amide is of the formula N(C=0R4)R5R6, wherein R5
and R6 are the same or different and are hydrogen or Ci-C3 alkyl and R4 is
cyclic or
acyclic, branched or unbranched C4_16 alkyl, optionally substituted. In some
embodiments, R5 and R6 are the same or different and are selected from the
group
consisting of hydrogen, methyl, ethyl, propyl and isopropyl, and R4 is cyclic
or acyclic,
branched or unbranched C4_16 alkyl, optionally substituted. In certain
embodiments, R'
and R6 are the same or different and are selected from the group consisting of
hydrogen,
methyl, ethyl, propyl and isopropyl and R4 is cyclic or acyclic, branched or
unbranched
Cg_16 alkyl, optionally substituted. In some cases, R4 is substituted with a
hydroxy group.
In some embodiments, R5 and R6 are the same or different and are selected from
the
group consisting of hydrogen, methyl, ethyl, propyl, and isopropyl, and R4 is
selected
from the group consisting of tert-butyl, cyclic or acyclic, branched or
unbranched C5_16
-23-
CA 02906165 2015-09-11
WO 2014/153102
PCT/US2014/029079
alkyl, optionally substituted, and cyclic or acyclic, branched or unbranched
Ci_16 alkyl
substituted with an ¨OH group.
In some embodiments, the amide is of the formula N(C=0R4)R5R6, wherein R5
and R6 are the same or different and are C1-C3 alkyl and R4 is cyclic or
acyclic, branched
.. or unbranched C4_16 alkyl, optionally substituted. In some embodiments, R5
and R6 are
the same or different and are selected from the group consisting of methyl,
ethyl, propyl
and isopropyl, and R4 is cyclic or acyclic, branched or unbranched C4_16
alkyl, optionally
substituted. In certain embodiments, R5 and R6 are the same or different and
are selected
from the group consisting of methyl, ethyl, propyl and isopropyl and R4 is
cyclic or
acyclic, branched or unbranched C8_16 alkyl, optionally substituted. In some
cases, R4 is
substituted with a hydroxy group. In some embodiments, R5 and R6 are the same
or
different and are selected from the group consisting of methyl, ethyl, propyl,
and
isopropyl, and R4 is selected from the group consisting of tert-butyl, cyclic
or acyclic,
branched or unbranched C5_16 alkyl, optionally substituted, and cyclic or
acyclic,
branched or unbranched C1_16 alkyl substituted with an ¨OH group.
In some embodiments, the amide is of the formula N(C=0R4)R5R6, wherein R5
and R6 are methyl and R4 is cyclic or acyclic, branched or unbranched C8_16
alkyl. Non-
limiting examples of amides include isomers of N,N-dimethyloctamide, isomers
of N,N-
dimethylnonamide, isomers of N,N-dimethyldecamide, isomers of N,N-
dimethylundecamide, isomers of N,N-dimethyldodecamide, isomers of N,N-
dimethyltetradecamide, and isomers of N,N-dimethylhexadecamide. In certain
embodiments, the cyclic or acyclic, branched or unbranched tri-substituted
amines is
selected from the group consisting of N,N-dimethyloctarnide, N,N-dodecamide,
and
N,N-dimethylhexadecamide.
In some embodiments, the solvent is an aromatic solvent having a boiling point
between about 175-300 F. Non-limiting examples of aromatic liquid solvents
having a
boiling point between about 175-300 F include benzene, xylenes, and toluene.
In a
particular embodiment, the solvent is not xylene.
I-A3. Fatty Acid Ester Solvents
In some embodiments, at least one of the solvents present in the mieroemulsion
is
an ester of fatty acid, either naturally occurring or synthetic with the
formula
R70(C=0R8), wherein R7 and R8 are the same or different and are cyclic or
acyclic,
- 24 -
CA 02906165 2015-09-11
WO 2014/153102 PCT/US2014/029079
branched or unbranched alkyl (e.g., C1-16 alkyl), optionally substituted. In
some
embodiments, each of R7 and R8 are the same or different and are cyclic or
acyclic,
branched or unbranched alkyl, or optionally, provide at least one of R7 and R8
is methyl,
ethyl, propyl, or butyl. Non-limiting examples include isomers of methyl
octanoate,
methyl decanoate, methyl dodecanoate, methyl undecanoate, methyl
hexadecanoate,
ethyl octanoate, ethyl decanoate, ethyl dodecanoate, ethyl undecanoate, ethyl
hexadecanoate, propyl octanoate, propyl decanoate, propyl dodecanoate, propyl
undecanoate, propyl hexadecanoate, butyl octanoate, butyl decanoate, butyl
dodecanoate,
butyl undecanoate, and butyl hexadecanoate. In certain embodiments, the esters
are
selected from the group consisting of methyl dodecanoate, methyl
hexadecanoate, ethyl
dodecanoate, ethyl hexadecanoate, propyl dodecanoate, propyl hexadecanoate,
butyl
dodecanoate, and butyl hexadecanoate. Non-limiting examples include isomers of
octyl
octanoate, nonyl, nonanoate, decyl decanoate,undecyl undecanoate, dodecyl
decanoate,
hexadecyl hexadecanoate. In certain embodiments the esters are selected from
the group
consisting of octyl octonoate and decyl decanoate.
I-A4. Terpene Solvents
In some embodiments, at least one of the solvents present in the microemulsion
is
a terpene or a terpenoid. In some embodiments, the terpene or terpenoid
comprises a first
type of terpene or terpcnoid and a second type of terpcne or terpenoid.
Terpenes may be
generally classified as monoterpenes (e.g., having two isoprene units),
sesquiterpenes
(e.g., having 3 isoprene units), diterpenes, or the like. The term terpenoid
also includes
natural degradation products, such as ionones, and natural and synthetic
derivatives, e.g.,
terpene alcohols, aldehydes, ketones, acids, esters, epoxides, and
hydrogenation products
(e.g., see Ullmann's Encyclopedia of Industrial Chemistry, 2012, pages 29-45,
herein
incorporated by reference). It should be understood, that while much of the
description
herein focuses on terpenes, this is by no means limiting, and terpenoids may
be
employed where appropriate. In some cases, the terpene is a naturally
occurring terpene.
In some cases, the terpene is a non-naturally occurring terpene and/or a
chemically
modified terpene (e.g., saturated terpene, terpene amine, fluorinated terpene,
or silylated
terpene).
In some embodiments, the terpene is a monoterpene. Monoterpenes may be
further classified as acyclic, monocyclic, and bicyclic (e.g., with a total
number of
-25-
CA 02906165 2015-09-11
WO 2014/153102 PCT/US2014/029079
carbons in the range between 18-20), as well as whether the monoterpene
comprises one
or more oxygen atoms (e.g., alcohol groups, ester groups, carbonyl groups,
etc.). In some
embodiments, the terpene is an oxygenated terpene, for example, a terpene
comprising
an alcohol, an aldehyde, and/or a ketone group. In some embodiments, the
terpene
comprises an alcohol group. Non-limiting examples of terpenes comprising an
alcohol
group are linalool, geraniol, nopol, a-terpineol, and menthol. In some
embodiments, the
terpene comprises an ether-oxygen, for example, eucalyptol, or a carbonyl
oxygen, for
example, menthone. In some embodiments, the terpene does not comprise an
oxygen
atom, for example, d-limonene.
Non-limiting examples of terpenes include linalool, geraniol, nopol, a-
terpineol,
menthol, eucalyptol, menthone, d-limonene, tetpinolene, 13-occimene, y-
terpinene,
a-pinene, and citronellene. In a particular embodiment, the terpene is
selected from the
group consisting of a-terpeneol, a-pinene, nopol, and eucalyptol. In one
embodiment, the
terpene is nopol. In another embodiment, the terpene is eucalyptol. In some
embodiments, the terpene is not limonene (e.g., d-limonene). In some
embodiments, the
emulsion is free of limonene.
In some embodiments, the terpene is a non-naturally occurring terpene and/or a
chemically modified terpene (e.g., saturated terpene). In some cases, the
terpene is a
partially or fully saturated terpene (e.g., p-menthane, pinane). In some
cases, the terpene
is a non-naturally occurring terpene. Non-limiting examples of non-naturally
occurring
terpenes include, menthene, p-cymene, r-carvone, terpinenes (e.g., alpha-
terpinenes,
beta-tetpinenes, gamma-terpinenes), dipentenes, terpinolenes, borneol, alpha-
terpinamine, and pine oils.
In some embodiments, the terpene is classified in terms of its phase inversion
temperature (PIT). The term phase inversion temperature is given its ordinary
meaning in
the art and refers to the temperature at which an oil in water microemulsion
inverts to a
water in oil microemulsion (or vice versa). Those of ordinary skill in the art
will be
aware of methods for determining the PIT for a microemulsion comprising a
terpene
(e.g., see Strey, Colloid & Polymer Science, 1994. 272(8): p. 1005-1019;
Kahlweit et al.,
Angewandte Chemie International Edition in English, 1985. 24(8): p. 654-668).
The PIT
values described herein were determined using a 1:1 ratio of terpene (e.g.,
one or more
terpenes):de-ionized water and varying amounts (e.g., between about 20 wt% and
about
60 wt%; generally, between 3 and 9 different amounts are employed) of a 1:1
blend of
-26-
CA 02906165 2015-09-11
WO 2014/153102 PCT/US2014/029079
surfactant comprising linear C12-C15 alcohol ethoxylates with on average 7
moles of
ethylene oxide (e.g., Neodol 25-7):isopropyl alcohol wherein the upper and
lower
temperature boundaries of the microemulsion region can be determined and a
phase
diagram may be generated. Those of ordinary skill in the art will recognize
that such a
phase diagram (e.g., a plot of temperature against surfactant concentration at
a constant
oil-to-water ratio) may be referred to as fish diagram or a Kahlweit plot. The
temperature
at the vertex is the PIT. An exemplary fish diagram indicating the PIT is
shown in Figure
1. PITs for non-limiting examples of terpenes determined using this
experimental
procedure outlined above are given in Table 1.
Table 1: Phase inversion temperatures for non-limiting examples of terpenes.
Terpene Phase Inversion Temperature F ( C)
linalool 24.8 (-4)
geraniol 31.1 (-0.5)
nopol 36.5 (2.5)
a-terpineol 40.3 (4.6)
menthol 60.8 (16)
eucalyptol 87.8 (31)
menthone 89.6 (32)
d-limonene 109.4 (43)
terpinolene 118.4 (48)
13-occimene 120.2 (49)
y-terpinene 120.2 (49)
a-pinene 134.6 (57)
citronellene 136.4 (58)
I-A5. Crude Cut Solvents
In certain embodiments, the solvent utilized in the emulsion or microemulsion
herein may comprise one or more impurities. For example, in some embodiments,
a
solvent (e.g., a terpene) is extracted from a natural source (e.g., citrus,
pine), and may
comprise one or more impurities present from the extraction process. In some
embodiment, the solvent comprises a crude cut (e.g., uncut crude oil, for
example, made
by settling, separation, heating, etc.). In some embodiments, the solvent is a
crude oil
-27-
CA 02906165 2015-09-11
WO 2014/153102 PCT/US2014/029079
(e.g., naturally occurring crude oil, uncut crude oil, crude oil extracted
from the wellbore,
synthetic crude oil, crude citrus oil, crude pine oil, eucalyptus, etc.). In
some
embodiments, the solvent is a citrus extract (e.g., crude orange oil, orange
oil, etc.).
I-A6. Mutual Solvents
In some embodiments, at least one of the solvents comprised in the emulsion or
microemulsion comprising a mutual solvent which is miscible together with the
water
and the solvent. In some embodiments, the mutual solvent is present in an
amount
between about at 0.5 wt% to about 30% of mutual solvent. Non-limiting examples
of
suitable mutual solvents include ethyleneglycolmonobutyl ether (EGMBE),
dipropylene
glycol monomethyl ether, short chain alcohols (e.g., isopropanol),
tetrahydrofuran,
dioxane, dimethylformamide, and dimethylsulfoxide.
I-B. Aqueous Phase
Generally, the microemulsion comprises an aqueous phase. Generally, the
aqueous phase comprises water. The water may be provided from any suitable
source
(e.g., sea water, fresh water, deionized water, reverse osmosis water, water
from field
production). The water may be present in any suitable amount. In some
embodiments,
the total amount of water present in the microemulsion is between about 1 wt%
about 95
wt%, or between about 1 wt% about 90 wt%, or between about 1 wt% and about
60 wt%, or between about 5 wt% and about 60 wt% or between about 10 and about
55
wt%, or between about 15 and about 45 wt%, versus the total microemulsion
composition.
The water to solvent ratio in a microemulsion may be varied. In some
embodiments, the ratio of water to solvent, along with other parameters of the
solvent
may be varied. In some embodiments, the ratio of water to solvent by weight is
between
about 15:1 and 1:10, or between 9:1 and 1:4, or between 3.2:1 and 1:4.
I-C. Surfactants
In some embodiments, the microemulsion comprises a surfactant. The
microemulsion
may comprise a single surfactant or a combination of two or more surfactants.
For
example, in some embodiments, the surfactant comprises a first type of
surfactant and a
second type of surfactant. The term surfactant, as used herein, is given its
ordinary
-28-
CA 02906165 2015-09-11
WO 2014/153102
PCT/US2014/029079
meaning in the art and refers to compounds having an amphiphilic structure
which gives
them a specific affinity for oil/water-type and water/oil-type interfaces
which helps the
compounds to reduce the free energy of these interfaces and to stabilize the
dispersed
phase of a microemulsion. The term surfactant encompasses cationic
surfactants, anionic
.. surfactants, amphoteric surfactants, nonionic surfactants, zwitterionic
surfactants, and
mixtures thereof. In some embodiments, the surfactant is a nonionic
surfactant. Nonionic
surfactants generally do not contain any charges. Amphoteric surfactants
generally have
both positive and negative charges, however, the net charge of the surfactant
can be
positive, negative, or neutral, depending on the pH of the solution. Anionic
surfactants
generally possess a net negative charge. Cationic surfactants generally
possess a net
positive charge. Zwitterionic surfactants are generally not pH dependent. A
zwitterion is
a neutral molecule with a positive and a negative electrical charge, though
multiple
positive and negative charges can be present. Zwitterions are distinct from
dipole, at
different locations within that molecule.
is In some
embodiments, the surfactant is an amphiphilic block copolymer where
one block is hydrophobic and one block is hydrophilic. In some cases, the
total
molecular weight of the polymer is greater than 5000 daltons. The hydrophilic
block of
these polymers can be nonionic, anionic, cationic, amphoteric, or
zwitterionic.
The term surface energy, as used herein, is given its ordinary meaning in the
art
and refers to the extent of disruption of intermolecular bonds that occur when
the surface
is created (e.g., the energy excess associated with the surface as compared to
the bulk).
Generally, surface energy is also referred to as surface tension (e.g., for
liquid-gas
interfaces) or interfacial tension (e.g., for liquid-liquid interfaces). As
will be understood
by those skilled in the art, surfactants generally orient themselves across
the interface to
minimize the extent of disruption of intermolecular bonds (i.e. lower the
surface energy).
Typically, a surfactant at an interface between polar and non-polar phases
orient
themselves at the interface such that the difference in polarity is minimized.
Those of ordinary skill in the art will be aware of methods and techniques for
selecting surfactants for use in the microemulsions described herein. In some
cases, the
surfactant(s) are matched to and/or optimized for the particular oil or
solvent in use. In
some embodiments, the surfactant(s) are selected by mapping the phase behavior
of the
microemulsion and choosing the surfactant(s) that gives the desired range of
phase
behavior. In some cases, the stability of the microemulsion over a wide range
of
-29-
CA 02906165 2015-09-11
WO 2014/153102 PCT/US2014/029079
temperatures is targeted as the microemulsion may be subject to a wide range
of
temperatures due to the environmental conditions present at the subterranean
formation
and/or reservoir.
The surfactant may be present in the microemulsion in any suitable amount. In
some embodiments, the surfactant is present in an amount between about 0 wt%
and
about 99 wt%, or between about 1 wt% and about 90 wt%, or between about 0 wt%
and
about 60 wt%, or between about 1 wt% and about 60 wt%, or between about 5 wt%
and
about 60 wt%, or between about 10 wt% and about 60 wt%, or between about 5 wt%
and
about 65 wt%, or between about 5 wt% and about 55 wt%, or between about 10 wt%
and
about 55 wt%, or between about 2 wt% and about 50 wt%, or between about 0 wt%
and
about 40 wt%, or between about 15 wt% and about 55 wt%, or between about 20
wt%
and about 50 wt%, versus the total microemulsion composition.
Suitable surfactants for use with the compositions and methods described
herein
will be known in the art. In some embodiments, the surfactant is an alkyl
polyglycol
ether, for example, having 2-250 ethylene oxide (EO) (e.g., or 2-200, or 2-
150, or 2-100,
or 2-50, or 2-40) units and alkyl groups of 4-20 carbon atoms. In some
embodiments, the
surfactant is an alkylaryl polyglycol ether having 2-250 EO units (e.g., or 2-
200, or 2-
150, or 2-100, or 2-50, or 2-40) and 8-20 carbon atoms in the alkyl and aryl
groups. In
some embodiments, the surfactant is an ethylene oxide/propylene oxide (E0/P0)
block
copolymer having 2-250 EO or PO units (e.g., or 2-200, or 2-150, or 2-100, or
2-50, or
2-40). In some embodiments, the surfactant is a fatty acid polyglycol ester
having 6-24
carbon atoms and 2-250 EO units (e.g., or 2-200, or 2-150, or 2-100, or 2-50,
or 2-40). In
some embodiments, the surfactant is a polyglycol ether of hydroxyl-containing
triglycerides (e.g., castor oil). In some embodiments, the surfactant is an
.. alkylpolyglycoside of the general formula R"--0--4, where R" denotes a
linear or
branched, saturated or unsaturated alkyl group having on average 8-24 carbon
atoms and
Z11 denotes an oligoglycoside group having on average n=1-10 hexose or pentose
units or
mixtures thereof. In some embodiments, the surfactant is a fatty ester of
glycerol,
sorbitol, or pentaerythritol. In some embodiments, the surfactant is an amine
oxide (e.g.,
dodecyldimethylamine oxide). In some embodiments, the surfactant is an alkyl
sulfate,
for example having a chain length of 8-18 carbon atoms, alkyl ether sulfates
having
8-18 carbon atoms in the hydrophobic group and 1-40 ethylene oxide (E0) or
propylene
oxide (PO) units. In some embodiments, the surfactant is a sulfonate, for
example, an
-30-
alkyl sulfonate having 8-18 carbon atoms, an alkylaryl sulfonate having 8-18
carbon
atoms, an ester or half ester of sulfosuccinic acid with monohydric alcohols
or
alkylphenols having 4-15 carbon atoms, or a multisulfonate (e.g., comprising
two, three,
four, or more, sulfonate groups). In some cases, the alcohol or alkylphenol
can also be
ethoxylated with 1-250 EO units (e.g., or 2-200, or 2-150, or 2-100, or 2-50,
or 2-40). In
some embodiments, the surfactant is an alkali metal salt or ammonium salt of a
carboxylic acid or poly(ancylene glycol) ether carboxylic acid having 8-20
carbon atoms
in the alkyl, aryl, alkaryl or aralkyl group and 1-250 E0 or PO units (e.g.,
or 2-200, or 2-
150, or 2-100, or 2-50, or 2-40). In some embodiments, the surfactant is a
partial
phosphoric ester or the corresponding alkali metal salt or ammonium salt,
e.g., an alkyl
and alkaryl phosphate having 8-20 carbon atoms in the organic group, an
alkylether
phosphate or alkarylether phosphate having 8-20 carbon atoms in the alkyl or
alkaryl
group and 1-250 EO units (e.g., or 2-200, or 2-150, or 2-100, or 2-50, or 2-
40). In some
embodiments, the surfactant is a salt of primary, secondary, or tertiary fatty
amine
having 8-24 carbon atoms with acetic acid, sulfuric acid, hydrochloric acid,
and
phosphoric acid. In some embodiments, the surfactant is a quaternary alkyl-
and
alkylbenzylammonium salt, whose alkyl groups have 1-24 carbon atoms (e.g., a
halide,
sulfate, phosphate, acetate, or hydroxide salt). In some embodiments, the
surfactant is an
alkylpridinium, an alkylimidazolinium, or an alkyloxazolinium salt whose alkyl
chain
has up to 18 carbons atoms (e.g., a halide, sulfate, phosphate, acetate, or
hydroxide salt).
In some embodiments, the surfactant is amphoteric or zwitterionic, including
sultaines
(e.g., cocamidopropyl hydroxysultaine), betaines (e.g., cocamidopropyl
betaine), or
phosphates (e.g., lecithin). Non-limiting examples of specific surfactants
include a linear
C12-C15 ethoxylated alcohols with 5-12 moles of EO, lauryl alcohol ethoxylate
with 4-8
moles of EO, nonyl phenol ethoxylate with 5-9 moles of EO, octyl phenol
ethoxylate
with 5-9 moles of EO, tridecyl alcohol ethoxylate with 5-9 moles of EO,
Pluronic
matrix of EO/PO copolymers, ethoxylated cocoamide with 4-8 moles of EO,
ethoxylated
coco fatty acid with 7-11 moles of EO, and cocoamidopropyl amine oxide.
In some embodiments, the surfactant is a siloxane surfactant as described in
U.S.
Patent Application Serial No. 13/831,410, filed March 14, 2014 .
In some embodiments, the surfactant is a Gemini surfactant. Gemini surfactants
generally have the structure of multiple amphiphilic molecules linked together
by one or
- 31 -
CA 2906165 2018-05-29
CA 02906165 2015-09-11
WO 2014/153102
PCT/US2014/029079
more covalent spacers. In some embodiments, the surfactant is an extended
surfactant,
wherein the extended surfactats has the structure where a non-ionic
hydrophilic spacer
(e.g. ethylene oxide or propylene oxide) connects an ionic hydrophilic group
(e.g.
carboxylate, sulfate, phosphate).
In some embodiments the surfactant is an alkoxylated polyimine with a relative
solubility number (RSN) in the range of 5-20. As will be known to those of
ordinary skill
in the art, RSN values are generally determined by titrating water into a
solution of
surfactant in 1,4dioxanc. The RSN values is generally defined as the amount of
distilled
water necessary to be added to produce persistent turbidity. In some
embodiments the
surfactant is an alkoxylated novolac resin (also known as a phenolic resin)
with a relative
solubility number in the range of 5-20. In some embodiments the surfactant is
a block
copolymer surfactant with a total molecular weight greater than 5000 daltons.
The block
copolymer may have a hydrophobic block that is comprised of a polymer chain
that is
linear, branched, hyperbranched, dendritic or cyclic. Non-limiting examples of
monomeric repeat units in the hydrophobic chains of block copolymer
surfactants are
isomers of acrylic, methacrylic, styrenic, isoprene, butadiene, acrylamide,
ethylene,
propylene and norbomene. The block copolymer may have a hydrophilic block that
is
comprised of a polymer chain that is linear, branched, hyper branched,
dendritic or
cyclic. Non-limiting examples of monomeric repeat units in the hydrophilic
chains of the
.. block copolymer surfactants are isomers of acrylic acid, maleic acid,
methacrylic acid,
ethylene oxide, and acrylamine.
In some embodiments, the surfactant has a structure as in Formula I:
R8
R7 R9
R120
0 R1 0
R11
wherein each of R7, R8, R9, R1 , and R11 are the same or different and are
selected from
the group consisting of hydrogen, optionally substituted alkyl, and ¨CH=CHAr,
wherein
Ar is an aryl group, provided at least one of R7, R8, R9, R10, and is
¨CH=CHAr, R12
is hydrogen or alkyl, n is 1-100, and each m is independently 1 or 2. In some
-32-
CA 02906165 2015-09-11
WO 2014/153102 PCT/US2014/029079
embodiments, Ar is phenyl. In some embodiments, for a compound of Formula (I),
R12 is
hydrogen or C1_6 alkyl. In some embodiments, for a compound of Formula (I),
R12 is H,
methyl, or ethyl. In some embodiments, for a compound of Formula (I), R12 is
H.
In some embodiments, the surfactant has a structure as in Formula II:
R8
R7 R9
08
X Y..(,(
0 R1
R11
(II)
wherein each of R7, R8, R9, R1 , and RH are the same or different and are
selected from
the group consisting of hydrogen, optionally substituted alkyl, and ¨CH=CHAr,
wherein
Ar is an aryl group, provided at least one of R7, R8, R9, R1 , and RH is
¨CH=CHAr, Y- is
an anionic group, X+ is a cationic group, n is 1-100, and each m is
independently 1 or 2.
In some embodiments, Ar is phenyl. In some embodiments, for a compound of
Formula
(II), X is a metal cation or N(R13)4, wherein each R13 is independently
selected from the
group consisting of hydrogen, optionally substituted alkyl, or optionally
substituted aryl.
In some embodiments, X is NH4. Non-limiting examples of metal cations are Nat,
Mg 2, and Ca.'2. In some embodiments, for a compound of Formula (II), Y- is -0-
, -
S020-, or ¨0S020-.
In some embodiments, the surfactant has a structure as in Formula III:
R8
R7 R9
o Rl
R11
(III)
wherein each of R7, R8, R9, R1 , and R11 are the same or different and are
selected from
the group consisting of hydrogen, optionally substituted alkyl, and ¨CH=CHAr,
wherein
Ar is an aryl group, provided at least one of R7, R8, R9, R1 , and R11 is
¨CH=CHAr, Z+ is
a cationic group, n is 1-100, and each m is independently 1 or 2. In some
embodiments,
-33-
CA 02906165 2015-09-11
WO 2014/153102 PCT/US2014/029079
Ar is phenyl. In some embodiments, for a compound of Formula (III), Z is
N(R13)3,
wherein each R13 is independent selected from the group consisting of
hydrogen,
optionally substituted alkyl, or optionally substituted aryl.
In some embodiments, for a compound of Formula (I), (II), or (III), two of R7,
R8,
R9, RI , and R" are ¨CH=CHAr. In some embodiments, for a compound of Formula
(I),
(II), or (III), one of R7, R8, R9, R19, and R" is ¨CH=CHAr and each of the
other groups is
hydrogen. In some embodiments, for a compound of Formula (I), (II), or (III),
two of R7,
R8, R9, Rim, and R11 are ¨CH=CHAr and each of the other groups is hydrogen. In
some
embodiments, for a compound of Formula (1), (II), or (Ill), R7 and R8 are
¨CH=CHAr
and R9, R10, and R" are each hydrogen. In some embodiments, for a compound of
Formula (I), (II), or (III), three of R7, R8, R9, R10, and R" are ¨CH=CHAr and
each of
the other groups is hydrogen. In some embodiments, for a compound of Formula
(I), (II),
or (III), R7, R8, and R9 are ¨CH=CHAr and R19 and R11 are each hydrogen. In
embodiments, for a compound of Formula (I), (II), or (III), Ar is phenyl. In
some
embodiments, for a compound of Formula (I), (II), or (III), each m is 1. In
some
embodiments, for a compound of Formula (I), (II), or (III), each m is 2. In
some
embodiments, for a compound of Formula (I), (II), or (III), n is 6-100, or 1-
50, or 6-50,
or 6-25, or 1-25, or 5-50, or 5-25, or 5-20.
In some embodiments, an emulsion or microemulsion comprises a surfactant of
Formula (I), (II), or (111) in an amount between about 1 wt% and about 20 wt%,
or
between about 3 wt% and about 15 wt%, or between about 5 wt% and about 13 wt%,
or
between about 5 wt% and about 11 wt%, or between about 7 wt% and about 11 wt%,
or
between about 10 wt% and about 12 wt%, or between about 8 wt% and about 12
wt%, or
between about 8 wt% and about 10 wt%, or about 9 wt%. In some embodiments, the
emulsion or microemulsion comprises, in addition to the surfactant of Formula
(I), (II),
or (III), water and a non-aqueous phase (e.g., a terpene), and optionally
other additives
(e.g., one or more additional surfactants, an alcohol, a freezing point
depression agent,
etc.). In some embodiments, the emulsion or microemulsion comprises, in
addition to the
surfactant of Formula (I), (II), or (III), water, a terpene, an alcohol, one
or more
additional surfactants, and optionally other additives (e.g., a freezing point
depression
agent). In some embodiments, the emulsion or microemulsion comprises, in
addition to
the surfactant of Formula (I), (II), or (III), between about 20 wt% and 90 wt%
water,
between about 2 wt% and about 70 wt% of one or more additional surfactants,
between
-34-
CA 02906165 2015-09-11
WO 2014/153102 PCT/US2014/029079
about 1 wt% and about 80 wt% of a solvent (e.g., terpene), and between about
10 wt%
and about 40 wt% of a mutual solvent (e.g., alcohol). In some embodiments, the
emulsion or microemulsion comprises, in addition to the surfactant of Formula
(I), (II),
or (III), between about 10 wt% and 80 wt% water, between about 2 wt% and about
80
wt% of one or more additional surfactants, between about 1 wt% and about 70
wt% of a
solvent (e.g., terpene), and between about 5 wt% and about 40 wt% of a mutual
solvent
(e.g., alcohol). In some embodiments, the emulsion or microemulsion comprises,
in
addition to the surfactant of Formula (I), (II), or (III), between about 20
wt% and 90 wt%
water, between about 2 wt% and about 70 wt% of one or more additional
surfactants,
between about 1 wt% and about 78 wt% of a solvent (e.g., terpene), and between
about
22 wt% and about 40 wt% of a mutual solvent (e.g., alcohol). Non-limiting
examples of
surfactants of Formula (I), (II), or (III) include styrylphenol ethoxylate, a
tristyrylphenol
ethoxylate, a styrylphenol propoxylate, a tristyrylphenol propoxylate, a
styrylphenol
ethoxylate propoxylate, or a tristyrylphenol ethoxylate propoxylate.
I-D. Additives
In some embodiments, the emulsion or microemulsion may comprise one or more
additives in addition to water, solvent (e.g., one or more types of solvents),
and
surfactant (e.g., one or more types of surfactants). In some embodiments, the
additive is
an alcohol, a freezing point depression agent, an acid, a salt, a proppant, a
scale inhibitor,
a friction reducer, a biocide, a corrosion inhibitor, a buffer, a viscosifier,
a clay swelling
inhibitor, an oxygen scavenger, and/or a clay stabilizer.
1-D1. Alcohol
In some embodiments, the microemulsion comprises an alcohol. The alcohol may
serve as a coupling agent between the solvent and the surfactant and aid in
the
stabilization of the microemulsion. The alcohol may also lower the freezing
point of the
microemulsion. The microemulsion may comprise a single alcohol or a
combination of
two or more alcohols. In some embodiments, the alcohol is selected from
primary,
secondary and tertiary alcohols having between 1 and 20 carbon atoms. in some
embodiments, the alcohol comprises a first type of alcohol and a second type
of alcohol.
Non-limiting examples of alcohols include methanol, ethanol, isopropanol, n-
propanol,
-35-
CA 02906165 2015-09-11
WO 2014/153102 PCT/US2014/029079
n-butanol, i-butanol, sec-butanol, iso-butanol, and t-butanol. In some
embodiments, the
alcohol is ethanol or isopropanol. In some embodiments, the alcohol is
isopropanol.
The alcohol may be present in the emulsion in any suitable amount. In some
embodiments, the alcohol is present in an amount between about 0 wt% and about
50
wt%, or between about 0.1 wt% and about 50 wt%, or between about 1 wt% and
about
50 wt%, or between about 2 wt% and about 50 wt% or between about 5 wt% and
about
40 wt%, or between about 5 wt% and 35 wt%, versus the total microemulsion
composition.
I-D2. Freezing Point Depression Agents
In some embodiments, the microemulsion comprises a freezing point depression
agent. The microemulsion may comprise a single freezing point depression agent
or a
combination of two or more freezing point depression agents. For example, in
some
embodiments, the freezing point depression agent comprises a first type of
freezing point
is depression agent and a second type of freezing point depression agent.
The term freezing
point depression agent is given its ordinary meaning in the art and refers to
a compound
which is added to a solution to reduce the freezing point of the solution.
That is, a
solution comprising the freezing point depression agent has a lower freezing
point as
compared to an essentially identical solution not comprising the freezing
point
depression agent. Those of ordinary skill in the art will be aware of suitable
freezing
point depression agents for use in the microemulsions described herein. Non-
limiting
examples of freezing point depression agents include primary, secondary, and
tertiary
alcohols with between 1 and 20 carbon atoms. In some embodiments, the alcohol
comprises at least 2 carbon atoms, alkylene glycols including polyalkylene
glycols, and
salts. Non-limiting examples of alcohols include methanol, ethanol, i-
propanol,
n-propanol, t-butanol, n-butanol, n-pentanol, n-hexanol, and 2-ethyl-hexanol.
In some
embodiments, the freezing point depression agent is not methanol (e.g., due to
toxicity).
Non-limiting examples of alkylene glycols include ethylene glycol (EG),
polyethylene
glycol (PEG), propylene glycol (PG), and triethylene glycol (TEG). In some
embodiments, the freezing point depression agent is not ethylene oxide (e.g.,
due to
toxicity). In some embodiments, the freezing point depression agent comprises
an
alcohol and an alkylene glycol. In some embodiments, the freezing point
depression
agent comprises a carboxycyclic acid salt and/or a di-carboxycylic acid salt.
Another
-36-
CA 02906165 2015-09-11
WO 2014/153102 PCT/US2014/029079
non-limiting example of a freezing point depression agent is a combination of
choline
chloride and urea. In some embodiments, the microemulsion comprising the
freezing
point depression agent is stable over a wide range of temperatures, for
example, between
about -50 F to 200 F.
The freezing point depression agent may be present in the microemulsion in any
suitable amount. In some embodiments, the freezing point depression agent is
present in
an amount between about 0 wt% and about 70 wt%, or between about 0.5 and 30
wt%,
or between about 1 wt% and about 40 wt%, or between about 0 wt% and about 25
wt%,
or between about 1 wt% and about 25 wt%, or between about 1 wt% and about 20
wt%,
or between about 3 wt% and about 20 wt%, or between about 8 wt% and about 16
wt%,
versus the total microemulsion composition.
I-E. Other Additives
In addition to the alcohol and the freezing point depression agent, the
microemulsion may comprise other additives. For example, the microemulsion may
comprise an acid and/or a salt. Further non-limiting examples of other
additives include
proppants, scale inhibitors, friction reducers, biocides, corrosion
inhibitors, buffers,
viscosifiers, clay swelling inhibitors, paraffin dispersing additives,
asphaltene dispersing
additives, and oxygen scavengers.
Non-limiting examples of proppants (e.g., propping agents) include grains of
sand, glass beads, crystalline silica (e.g., Quartz), hexamethylenetetramine,
ceramic
proppants (e.g., calcined clays), resin coated sands, and resin coated ceramic
proppants.
Other proppants are also possible and will be known to those skilled in the
art.
Non-limiting examples of scale inhibitors include one or more of methyl
alcohol,
organic phosphonic acid salts (e.g., phosphonate salt), polyacrylate, ethane-
1,2-diol,
calcium chloride, and sodium hydroxide. Other scale inhibitors are also
possible and will
be known to those skilled in the art.
Non-limiting examples of buffers include acetic acid, acetic anhydride,
potassium
hydroxide, sodium hydroxide, and sodium acetate. Other buffers are also
possible and
will be known to those skilled in the art.
Non-limiting examples of corrosion inhibitors include isopropanol, quaternary
ammonium compounds, thiourea/formaldehyde copolymers, propargyl alcohol and
-37-
CA 02906165 2015-09-11
WO 2014/153102 PCT/US2014/029079
methanol. Other corrosion inhibitors are also possible and will be known to
those skilled
in the art.
Non-limiting examples of biocides include didecyl dimethyl ammonium chloride,
gluteral, Dazomet, bronopol, tributyl tetradecyl phosphonium chloride,
tetrakis
(hydroxymethyl) phosphonium sulfate, AQUCARTM, UCARCIDETM, glutaraldehyde,
sodium hypochlorite, and sodium hydroxide. Other biocides are also possible
and will be
known to those skilled in the art.
Non-limiting examples of clay swelling inhibitors include quaternary ammonium
chloride and tetramethylammonium chloride. Other clay swelling inhibitors are
also
.. possible and will be known to those skilled in the art.
Non-limiting examples of friction reducers include petroleum distillates,
ammonium salts, polyethoxylated alcohol surfactants, and anionic
polyacrylamide
copolymers. Other friction reducers are also possible and will be known to
those skilled
in the art.
Non-limiting examples of oxygen scavengers include sulfites, and bisulfites.
Other oxygen scavengers are also possible and will be known to those skilled
in the art.
Non-limiting examples of paraffin dispersing additives and asphaltene
dispersing
additives include active acidic copolymers, active alkylated polyester, active
alkylated
polyester amides, active alkylated polyester imides, aromatic naphthas, and
active amine
sulfonates. Other paraffin dispersing additives are also possible and will be
known to
those skilled in the art.
In some embodiments, for the fotmulations above, the other additives are
present
in an amount between about 0 wt% about 70 wt%, or between about 0 wt % and
about 30
wt%, or between about 1 wt% and about 30 wt%, or between about 1 wt% and about
25
.. wt%, or between about 1 and about 20 wt%, versus the total microemulsion
composition.
I-El. Acids
In some embodiments, the microemulsion comprises an acid or an acid precursor.
For example, the microemulsion may comprise an acid when used during acidizing
operations. The microemulsion may comprise a single acid or a combination of
two or
more acids. For example, in some embodiments, the acid comprises a first type
of acid
and a second type of acid. Non-limiting examples of acids or di-acids include
hydrochloric acid, acetic acid, formic acid, succinic acid, maleic acid, malic
acid, lactic
-38-
CA 02906165 2015-09-11
WO 2014/153102 PCT/US2014/029079
acid, and hydrochloric-hydrofluoric acids. In some embodiments, the
microemulsion
comprises an organic acid or organic di-acid in the ester (or di-ester) form,
whereby the
ester (or diester) is hydrolyzed in the wellbore and/or reservoir to form the
parent organic
acid and an alcohol in the wellbore and/or reservoir. Non-limiting examples of
esters or
di-esters include isomers of methyl formate, ethyl formate, ethylene glycol
diformate,
a,a-4-trimethy1-3-cyclohexene-1-methylformate, methyl lactate, ethyl lactate,
a,a-4-
trimethyl 3-cyclohexene-1-methyllactate, ethylene glycol dilactate, ethylene
glycol
diacetate, methyl acetate, ethyl acetate, a,a,-4-trimethy1-3-cyclohexene-1-
methylacetate,
dimethyl succinate, dimethyl maleate, 1-
1-methyl-4-(1-methyletheny1)-cyclohexyl formate, 1-methy1-4-(1-
ethylethenyl)cyclohexylactate, 1-methyl-4-(1-methylethenyl)cyclohexylacetate,
di(1-
methy-4-(1-methylethenyl)cyclohexyl)succinate.
I-E2. Salts
In some embodiments, the microemulsion comprises a salt. The presence of the
salt may reduce the amount of water needed as a carrier fluid, and in
addition, may lower
the freezing point of the microemulsion. The microemulsion may comprise a
single salt
or a combination of two or more salts. For example, in some embodiments, the
salt
comprises a first type of salt and a second type of salt. Non-limiting
examples of salts
include salts comprising K, Na, Br, Cr, Cs, or Li, for example, halides of
these metals,
including NaC1, KC1, CaCl2, and MgCl2.
In some embodiments, the microemulsion comprises a clay stabilizer. The
microemulsion may comprise a single clay stabilizer or a combination of two or
more
clay stabilizers. For example, in some embodiments, the salt comprises a first
type of
clay stabilizer and a second type of clay stabilizer. Non-limiting examples of
clay
stabilizers include salts above, polymers (PAC, PHPA, etc), glycols,
sulfonated asphalt,
lignite, sodium silicate, and choline chloride.
I-F. Formation and Use of Microemulsions
In some embodiments, the components of the microemulsion and/or the amounts
of the components are selected such that the microemulsion is stable over a
wide-range
of temperatures. For example, the microemulsion may exhibit stability between
about
-40 F and about 400 F, or between about -40 F and about 300 F or between
about
-39-
CA 02906165 2015-09-11
WO 2014/153102 PCT/US2014/029079
-40 F and about 150 F. Those of ordinary skill in the art will be aware of
methods and
techniques for determining the range of stability of the microemulsion. For
example, the
lower boundary may be determined by the freezing point and the upper boundary
may be
determined by the cloud point and/or using spectroscopy methods. Stability
over a wide
range of temperatures may be important in embodiments where the microemulsions
are
being employed in applications comprising environments wherein the temperature
may
vary significantly, or may have extreme highs (e.g., desert) or lows (e.g.,
artic).
The microemulsions described herein may be foimed using methods known to
those of ordinary skill in the art. In some embodiments, the aqueous and non-
aqueous
iu phases may be combined (e.g., the water and the solvent(s)), followed by
addition of a
surfactant(s) and optionally (e.g., freezing point depression agent(s)) and
agitation. The
strength, type, and length of the agitation may be varied as known in the art
depending
on various factors including the components of the microemulsion, the quantity
of the
microemulsion, and the resulting type of microemulsion formed. For example,
for small
samples, a few seconds of gentle mixing can yield a microemulsion, whereas for
larger
samples, longer agitation times and/or stronger agitation may be required.
Agitation may
be provided by any suitable source, for example, a vortex mixer, a stirrer
(e.g., magnetic
stirrer), etc.
Any suitable method for injecting the microemulsion (e.g., a diluted
microemulsion) into a wellbore may be employed. For example, in some
embodiments,
the microemulsion, optionally diluted, may be injected into a subterranean
formation by
injecting it into a well or wellbore in the zone of interest of the formation
and thereafter
pressurizing it into the formation for the selected distance. Methods for
achieving the
placement of a selected quantity of a mixture in a subterranean formation are
known in
the art. The well may be treated with the microemulsion for a suitable period
of time.
The microemulsion and/or other fluids may be removed from the well using known
techniques, including producing the well.
It should be understood, that in embodiments where a microemulsion is said to
be
injected into a wellbore, that the microemulsion may be diluted and/or
combined with
other liquid component(s) prior to and/or during injection (e.g., via straight
tubing, via
coiled tubing, etc.). For example, in some embodiments, the microemulsion is
diluted
with an aqueous carrier fluid (e.g., water, brine, sea water, fresh water, or
a well-
treatment fluid (e.g., an acid, a fracturing fluid comprising polymers,
produced water,
-40-
CA 02906165 2015-09-11
WO 2014/153102 PCT/US2014/029079
sand, slickwater, etc.,)) prior to and/or during injection into the wellbore.
In some
embodiments, a composition for injecting into a wellbore is provided
comprising a
microemulsion as described herein and an aqueous carrier fluid, wherein the
microemulsion is present in an amount between about 0.1 and about 50 gallons
per
thousand gallons (gpt) per dilution fluid, or between 0.1 and about 100 gpt,
or between
about 0.5 and about 10 gpt, or between about 0.5 and about 2 gpt.
11. Applications of the Emulsions and/or Microemulsions Relating to the
Life
Cycle of a Well
The emulsions and microemulsions described herein may be used in various
aspects of the life cycle of an oil and/or gas well, including, but not
limited to, drilling,
mud displacement, casing, cementing, perforating, stimulation, enhanced oil
recovery/
improved oil recovery, etc.). Inclusion of an emulsion or microemulsion into
the fluids
typically employed in these processes, for example, drilling fluids, mud
displacement
is fluids, casing fluids, cementing fluids, perforating fluid, stimulation
fluids, kill fluids,
etc., results in many advantages as compared to use of the fluid alone.
Various aspects of the well life cycle are described in detail below. As will
be
understood by those of ordinary skill in the art, while certain steps of the
life cycle
described below are described in sequential order, this is by no means
limiting, and the
steps may be carried out in a variety of orders. In addition, in some
embodiments, each
step may occur more than once in the life cycle of the well. For example,
fracturing may
be followed by stimulations, followed by additional fracturing steps. In some
embodiments, refracturing, or the process of repeating the above stimulation
processes,
is further improved by the addition of an emulsion or microemulsion to the
stimulation
fluid.
II-A. Drilling
As will be known to those skilled in the art, drilling to form wellbores
typically
requires the displacement (e.g., using a drill pipe and a drill bit) of
reservoir material
(e.g., rock, sand, stone, or the like). Such drilling generally requires the
use of certain
drilling fluids which may, for example, lubricate and/or cool the drill bit,
assist in the
removal of earth (e.g., cuttings), create and/or balance hydrostatic head
pressure (e.g., to
prevent, for example, a collapse of the hole being formed by the drill bit, to
control the
-41-
CA 02906165 2015-09-11
WO 2014/153102 PCT/US2014/029079
flow of hydrocarbons and/or water into the wellbore, to decrease swelling of
the
surrounding reservoir material), and/or to control or prevent a kick (e.g., an
explosive
moving of drilling fluid back to the surface). Non-limiting examples of
drilling fluids
include water-based systems, oil-based systems (e.g., synthetic oil-based
systems, low
viscosity oils such as diesel, crude oil, etc.). In water-based systems, the
water may
comprise one or more additives, for example, salts (e.g., to form brine),
solid particles,
etc. In oil-based systems, the oil can comprise any oil including, by not
limited to,
mineral oil, esters, and alpha-olefins. In some embodiments, the drilling
fluid comprises
a foam or a mist. In certain embodiments, the drilling fluid is a water-based
system. In
some embodiments, drilling fluids include one or more minerals or additives
(e.g.,
hematite, montmorillionite, barite, bentonite, ilmenite, lignite,
lignosulfonate, slacked
lime, sodium hydroxide, etc.).
In some embodiments, the drilling fluid comprises an emulsion or
microemulsion. Emulsions and microemulsions are described in more detail
herein. The
addition of an additional emulsion or microemulsion in the drilling fluid may
have many
advantages as compared to the use of a drilling fluid alone, including, for
example,
decreasing the swelling of the surrounding reservoir, changing (e.g.,
increasing or
decreasing) the viscosity of the drilling fluid, decreasing the amount of
water absorbed
into the well during the drilling process, increasing the amount of water
extracted from
the reservoir, changing (e.g., increasing and/or decreasing) the amount of
contaminants
and/or particulates extracted from the reservoir, and/or increasing the amount
of oil
and/or gas extracted from the reservoir. In some embodiments, the oil and/or
gas
comprises an oil and/or gas condensate. As will be known to those of ordinary
skill in the
art, in some cases, the composition of a drilling fluid may change during the
process of
drilling.
As will be known to those of ordinary skill in the art, imbibition is a nearly
instantaneous process that occurs when water comes in contact with the exposed
primary
permeability of, for example, water wet shales and/or clays. This exposed
primary
permeability may be on the face of the drilled cuttings and borehole wall
and/or along
the faces of the naturally occurring micro-fractures (secondary permeability).
In the case
of secondary permeability, the overall depth of invasion into the formation
may be
directly related to the depth of the micro-fractures and the volume of whole
water base
fluid and/or filtrate allowed to imbibe into the micro-fractures. The speed of
invasion of
- 42 -
CA 02906165 2015-09-11
WO 2014/153102
PCT/US2014/029079
the available water base fluid or filtrate into the secondary permeability is
generally
related to the primary permeability features of capillary diameters and degree
of
saturation of the shales and/or clays. The addition of an emulsion or
microemulsion in
the drilling fluid may have advantages as compared to the use of a drilling
fluid alone,
including, for example, the controlling imbibition (e.g., prevention,
reduction, or increase
of imbibition).
In some embodiments, the drilling fluid comprises an emulsion or microemulsion
as described herein wherein the emulsion or microemulsion is present in an
amount
between about 0.5 and about 200 gallons per thousand gallons (gpt) of drilling
fluid, or
.. between about 0.5 and about 100 gpt, or between about 0.5 and about 50 gpt,
or between
about 1 and about 50 gpt, or between about 1 and about 20 gpt, or between
about 2 and
about 20 gpt, or between about 2 and about 10 gpt, or between about 2 and
about 5 gpt.
In certain embodiments, the emulsion or microemulsion is present in an amount
between
about 5 and about 10 gpt. In some embodiments, the drilling fluid contains at
least about
0.5 gpt, or at least about 1 gpt, or at least about 2 gpt, or at least about 4
gpt, or at least
about 10 gpt, or at least about 20 gpt, or at least about 50 gpt, or at least
about 100 gpt, or
at least about 200 gpt, of an emulsion or a microemulsion. In some
embodiments, the
drilling fluid contains less than or equal to about 200 gpt, or less than or
equal to about
100 gpt, or less than or equal to about 50 gpt, or less than or equal to about
20 gpt, or less
.. than or equal to about 10 gpt, or less than or equal to about 4 gpt, or
less than or equal to
about 2 gpt, or less than or equal to about 1 gpt, or less than or equal to
about 0.5 gpt of
an emulsion or microemulsion.
II-B. Mud Displacement
As will be known to those skilled in the art, generally following the drilling
of a
wellbore, techniques are utilized to stabilize the wellbore. Stabilizing the
wellbore may
include inserting a casing (e.g., metal sleeves, steel tubes, and the like)
down the
wellbore. In some cases, a cement is injected in the annulus between the
wellbore and
casing to add further stability. Prior to injecting cement, additional fluids
(e.g., a mud
displacement fluid) may be pushed between the casing and the wellbore sides to
remove
excess mud and/or filter cake. Generally, a mud displacement fluid refers to a
fluid that
displaces drilling mud. A mud displacement fluid is typically injected at high
pressure
into the inner core of the casing, and exits at the bottom of the casing,
returning to the
-43-
CA 02906165 2015-09-11
WO 2014/153102 PCT/US2014/029079
surface via the annular region between the casing and the sides of the
wellbore.
Alternatively, the mud displacement fluid may be injected at a high pressure
between the
casing and the sides of the wellbore and exits at the bottom of the casing,
returning to the
surface via the inner core of the casing. A non-limiting example of a mud
displacement
fluid includes a water-based system. In certain embodiments, the mud
displacement fluid
comprises water and one or more solvents, surfactants, and/or other additives
known to
those skilled in the art.
In some embodiments, the mud displacement fluid comprises an emulsion or
microemulsion. Emulsions and microemulsions are described in more detail
herein. The
addition of an emulsion or microemulsion in the mud displacement fluid may
have many
advantages as compared to the use of a mud displacement fluid alone including,
for
example, preventing or minimizing damage from imbibition, assisting in
liquification
and removal of filter cakes, and/or preparing the hole for cementation. In
addition, the
presence of the emulsion or the microemulsion in the mud displacement fluid
may result
in improved (e.g., increased) delivery of the fluid to portions of the well,
which aids in
displacing surface contamination, which can result in less imbibition,
formation
blockages, and/or improves surfaces for cementing.
In some embodiments, the mud displacement fluid comprises an emulsion or
microemulsion as described herein wherein the emulsion or microemulsion is
present in
an amount between about 0.5 and about 200 gpt of mud displacement fluid, or
between
about 0.5 and about 100 gpt, or between about 0.5 and about 50 gpt, or between
about 1
and about 50 gpt, or between about 1 and about 20 gpt, or between about 2 and
about 20
gpt, or between about 2 and about 10 gpt, or between about 2 and about 5 gpt,
or
between about 5 and about 10 gpt. In some embodiments, the emulsion or
microemulsion
is present in an amount between about 1 and about 4 gpt. In some embodiments,
the mud
displacement fluid contains at least about 0.5 gpt, at least about 1 gpt, or
at least about 2
gpt, or at least about 4 gpt, or at least about 10 gpt, or at least about 20
gpt, or at least
about 50 gpt, or at least about 100 gpt, or at least about 200 gpt of an
emulsion or a
microemulsion. In some embodiments, the mud displacement fluid contains less
than or
equal to about 200 gpt, or less than or equal to about 100 gpt, or less than
or equal to
about 50 gpt, or less than or equal to about 20 gpt, or less than or equal to
about 10 gpt,
or less than or equal to about 4 gpt, or less than or equal to about 2 gpt, or
less than or
- 44 -
CA 02906165 2015-09-11
WO 2014/153102 PCT/US2014/029079
equal to about 1 gpt, or less than or equal to about 0.5 gpt of an emulsion or
microemulsion.
II-C. Cementing
As described herein, and as will be known to those skilled in the art,
generally
following drilling a wellbore, cement is placed between the casing and the
wellbore
sides. At various stages of the cementing process (e.g., during preflush,
during
preliminary cementing, during remedial cementing, etc.), pieces of cement
(e.g., cement
particles, ground cement, etc.) may alter the reservoir material or fluid
present in the
wellbore (e.g., gelling the mud such that the viscosity is significantly
increased and
rendering it generally unworkable), the viscosity of fluids injected into the
wellbore,
and/or the viscosity of fluids recovered from the wellbore. For example,
following the
cementing process, a portion of the cement (e.g., at the bottom of the well,
also known as
a cement plug) may be removed by drilling, thereby resulting in pieces of
cement. The
pieces of cement may be removed via injection of a fluid (e.g., a cementing
fluid) during
and/or following the cementing process.
In some embodiments, the cementing fluid comprises an emulsion or
microemulsion. Emulsions and microemulsions are described in more detail
herein. The
addition of an emulsion or microemulsion in the cementing fluid may have many
advantages as compared to the use of a cementing fluid alone including, for
example,
reducing the viscosity of fluids containing cement particles.
In some embodiments, the cementing fluid comprises an emulsion or
microemulsion as described herein wherein the emulsion or microemulsion is
present in
an amount between about 0.5 and about 200 gpt of cementing fluid, or between
about 0.5
.. and about 50 gpt, or between about 0.5 and about 100 gpt, or between about
1 and about
50 gpt, or between about 1 and about 20 gpt, or between about 2 and about 20
gpt, or
between about 2 and about 10 gpt, or between about 2 and about 5 gpt, or
between about
5 and about 10 gpt. In some embodiments, the cementing fluid contains at least
about 0.5
gpt, or at least about 1 gpt, or at least about 2 gpt, or at least about 4
gpt, or at least about
10 gpt, or at least about 20 gpt, or at least about 50 gpt, or at least about
100 gpt, or at
least about 200 gpt, of an emulsion or a microemulsion. In some embodiments,
the
cementing fluid contains less than or equal to about 200 gpt, or less than or
equal to
about 100 gpt, or less than or equal to about 50 gpt, or less than or equal to
about 20 gpt,
-45-
CA 02906165 2015-09-11
WO 2014/153102 PCT/US2014/029079
or less than or equal to about 10 gpt, or less than or equal to about 4 gpt,
or less than or
equal to about 2 gpt, or less than or equal to about 1 gpt, or less than or
equal to about
0.5 gpt of an emulsion or microemulsion.
II-D. Perforating
As will be known to those skilled in the art, generally following drilling and
inserting a casing into a wellbore, perforating guns may be lowered into the
wellbore to
create holes between the interior of the casing and the surrounding reservoir
material.
Typically, perforating guns utilize liquid jets (e.g., hydrocutters) or
explosives (e.g., an
expanding plume of gas) to send high velocity jets of fluid (e.g., a
perforating fluid)
between the gun and the casing to form holes of controlled size and depth into
the casing,
cement, and/or nearby reservoir material. During and/or following perforation,
the
perforating fluid generally flows into the areas formed by the perforating
gun.
In some embodiments, the perforating fluid comprises an emulsion or
microemulsion. Emulsions and microemulsions are described in more detail
herein. The
addition of an emulsion or microemulsion in the perforating fluid may have
many
advantages as compared to the use of a perforating fluid alone, including, for
example,
preventing or minimizing damage from imbibition, preventing the formation of
new
filter cakes (e.g., that may reduce hydrocarbons in the reservoir material
from entering
the casing), and/or increasing the pressure differential between the wellbore
and the
surrounding reservoir material.
In some embodiments, the perforating fluid comprises an emulsion or
microemulsion as described herein wherein the emulsion or microemulsion is
present in
an amount between about 0.5 and about 200 gpt of perforating fluid, or between
about
0.5 and about 100 gpt, or between about 0.5 and about 50 gpt, or between about
1 and
about 50 gpt, or between about 1 and about 20 gpt, or between about 2 and
about 20 gpt,
or between about 2 and about 10 gpt, or between about 2 and about 5 gpt, or
between
about 5 and about 10 gpt. In some embodiments, the emulsion or microemulsion
is
present in an amount between about 1 and about 10 gpt. In some embodiments,
the
perforating fluid contains at least about 0.5 gpt, or at least about 1 gpt, or
at least about 2
gpt, or at least about 4 gpt, or at least about 10 gpt, or at least about 20
gpt, or at least
about 50 gpt, or at least about 100 gpt, or at least about 200 gpt of an
emulsion or a
microemulsion. In some embodiments, the perforating fluid contains less than
or equal to
-46-
CA 02906165 2015-09-11
WO 2014/153102 PCT/US2014/029079
about 200 gpt, or less than or equal to about 100 gpt, or less than or equal
to about 50
gpt, or less than or equal to about 20 gpt, or less than or equal to about 10
gpt, or less
than or equal to about 4 gpt, or less than or equal to about 2 gpt, or less
than or equal to
about 1 gpt, or less than or equal to about 0.5 gpt of an emulsion or
microemulsion.
II-E. Stimulation
As will be known to those skilled in the art, generally the completion of the
formation of wellbore includes stimulation and/or re-fracturing processes. The
term
stimulation generally refers to the treatment of geological formations to
improve the
recovery of liquid hydrocarbons (e.g., formation crude oil and/or formation
gas). The
porosity and permeability of the formation determine its ability to store
hydrocarbons,
and the facility with which the hydrocarbons can be extracted from the
formation.
Common stimulation techniques include well fracturing (e.g., fracturing,
hydraulic
fracturing) and acidizing (e.g., fracture acidizing, matrix acidizing)
operations.
Non-limiting examples of fracturing operations include hydraulic fracturing,
which is commonly used to stimulate low permeability geological formations to
improve
the recovery of hydrocarbons. The process can involve suspending chemical
agents in a
stimulation fluid (e.g., fracturing fluid) and injecting the fluid down a
wellbore. The
fracturing fluid may be injected at high pressures and/or at high rates into a
wellbore.
However, the assortment of chemicals pumped down the well can cause damage to
the
surrounding formation by entering the reservoir material and blocking pores.
For
example, one or more of the following may occur: wettability reversal,
emulsion
blockage, aqueous-filtrate blockage, mutual precipitation of soluble salts in
wellbore-
fluid filtrate and formation water, deposition of paraffins or asphaltenes,
condensate
banking, bacterial plugging, and/or gas breakout. In addition, fluids may
become trapped
in the formation due to capillary end effects in and around the vicinity of
the formation
fractures. The addition of an emulsion or microemulsion in the fracturing
fluid may have
many advantages as compared to the use of a fracturing fluid alone, including,
for
example, maximizing the transfer and/or recovery of injected fluids,
increasing oil and/or
gas recovery, and/or other benefits described herein.
Non-limiting examples of acidizing operations include the use of water-based
fluids to remove drilling fluids and particles remaining in the wellbore to
permit optimal
flow feeding into the wellbore (e.g., matrix acidizing). Matrix acidizing
generally refers
-47-
CA 02906165 2015-09-11
WO 2014/153102 PCT/US2014/029079
to the formation of wormholes (e.g., pores or channels through which oil, gas,
and/or
other fluids can flow) through the use of a fluid (e.g., acidic stimulation
fluid)
comprising, for example, an acid, wherein the wormholes are continuous
channels and
holes formed in the reservoir of a controlled size and depth. The addition of
an emulsion
or microemulsion to the stimulation fluid may have many advantages as compared
to the
use of a stimulation fluid alone, including, for example, the formation of an
acidic gel
(e.g., which creates a more uniform distribution of acid across the reservoir
materials as
it travels along the surface), increasing oil and/or gas recovery, and/or
other benefits
described herein.
Fracture acidizing generally refers to the use of an acid to extend fractures
formed by the injection of treatment fluid at high-pressure (e.g.,
fracturing). The addition
of an emulsion or microemulsion to the stimulation fluid may have advantages
as
compared to the use of a stimulation fluid alone, including, for example,
increasing the
removal of fracturing fluid skin (e.g., fluid and solids from the reservoir
which may
block optimal flow of the wellbore) from the fractures allowing for more
effective acid
treatment.
As will be known to those skilled in the art, stimulation fluids (e.g.,
acidizing
fluids, fracturing fluids, etc.) may be injected into the wellbore to assist
in the removal of
leftover drilling fluids or reservoir materials. Non-limiting examples of
stimulation fluids
(e.g., as an acidizing fluid) include water and hydrochloric acid (e.g., 15%
HC1 in water).
In some embodiments, the acid is partially or completely consumed after
reacting with
carbonates in the reservoir. Further non-limiting examples of stimulation
fluids include
conventional fluids (e.g., gelling agents comprising crosslinking agents such
as borate,
zirconate, and/or titanate), water fracture fluids (e.g., friction reducers,
gelling agents,
viscoelastic surfactants), hybrid fluids (e.g., friction reducers, gelling
agents, viscoelastic
surfactants, and combinations thereof), energized fluids (e.g., foam
generating energizers
comprising nitrogen or carbon dioxide), acid fracture fluids (e.g., gelled
acid base fluids),
gas fracture fluids (e.g., propane), and matrix acidizing fluids (e.g., an
acid).
In some embodiments, the stimulation fluid comprises a viscosifier (e.g., guar
.. gum) and/or a bridging agent (e.g., calcium carbonate, size salt, oil-
soluble resins, mica,
ground cellulose, nutshells, and other fibers). In some embodiments, removal
of leftover
drilling fluids or reservoir fluids refers to the breakdown and removal of a
near-wellbore
skin (e.g., fluid and solids from the reservoir which may block optimal flow
into the
-48-
CA 02906165 2015-09-11
WO 2014/153102 PCT/US2014/029079
wellbore). Non-limiting examples of skin materials include paraffin,
asphaltene, drilling
mud components (e.g., barite, clays), non-mobile oil in place, and fines
(e.g., which may
block pores in the reservoir material). The addition of an emulsion or
microemulsion to
the acidizing fluid may have many advantages as compared to the use of a
acidizing fluid
alone, including, for example, increasing the breakdown of the skin into
smaller
components to be more easily removed by flow from the wellbore, increasing oil
and/or
gas recovery, and/or other benefits described herein.
In addition to some of the benefits described above, in some embodiments,
incorporation of an emulsion or a microemulsion into a stimulation fluid can
aid in
reducing fluid trapping, for example, by reducing capillary pressure and/or
minimizing
capillary end effects, as compared to the use of a stimulation fluid alone. In
addition,
incorporation of an emulsion or microemulsion into stimulation fluids can
promote
increased flow back of aqueous phases following well treatment, increasing
production
of liquid and/or gaseous hydrocarbons, and/or increasing the displacement of
residual
is fluids (e.g., drilling fluids, etc.) by formation crude oil and/or
formation gas. Other non-
limiting advantages as compared to the use of a stimulation fluid alone,
include
increasing the amount of water extracted from the reservoir, increasing the
amount or oil
and/or gas extracted from the reservoir, more uniformly distributing the acid
along the
surface of the wellbore and/or reservoir, improving the formation of wormholes
(e.g., by
slowing down the reaction rate to create deeper and more extensive wormholes
during
fracture acidizing). In certain embodiments, the addition of an emulsion or
microemulsion increases the amount of hydrocarbons transferred from the
reservoir to
fluids injected into the reservoir during hydraulic fracturing.
In some embodiments, the stimulation fluid comprises an emulsion or
microemulsion as described herein wherein the emulsion or microemulsion is
present in
an amount between about 0.5 and about 200 gpt of stimulation fluid, or between
about
0.5 and about 100 gpt, or between about 0.5 and about 50 gpt, or between about
1 and
about 50 gpt, or between about 1 and about 20 gpt, or between about 2 and
about 20 gpt,
or between about 2 and about 10 gpt, or between about 2 and about 5 gpt, or
between
about 5 and about 10 gpt. In some embodiments, the emulsion or microemulsion
is
present in an amount between about 2 and about 5 gpt. In some embodiments, the
stimulation fluid contains at least about 0.5 gpt, or at least about I gpt, or
at least about 2
gpt, or at least about 4 gpt, or at least about 10 gpt, or at least about 20
gpt, or at least
-49-
CA 02906165 2015-09-11
WO 2014/153102
PCT/US2014/029079
about 50 gpt, or at least about 100 gpt, or at least about 200 gpt, of an
emulsion or a
microemulsion. In some embodiments, the stimulation fluid contains less than
or equal to
about 200 gpt, or less than or equal to about 100 gpt, or less than or equal
to about 50
gpt, or less than or equal to about 20 gpt, or less than or equal to about 10
gpt, or less
than or equal to about 4 gpt, or less than or equal to about 2 gpt, or less
than or equal to
about 1 gpt, or less than or equal to about 0.5 gpt of an emulsion or
microemulsion.
In some embodiments, refracturing, or the process of repeating the above
stimulation processes, is further improved by the addition of an emulsion or
microemulsion to the stimulation fluid.
In some embodiments, the emulsion or microemulsion for use with a stimulation
fluid (e.g., a fracturing fluid) comprising a surfactant as in Formula I:
R8
R7 R9
R120
0 R1 0
R11
(I),
wherein each of R7, R8, R9, R1 , and R11 are the same or different and are
selected from
the group consisting of hydrogen, optionally substituted alkyl, and ¨CH=CHAr,
wherein
Ar is an aryl group, provided at least one of R7, R8, R9, R10, and is
¨CH=CHAr, R12
is hydrogen or alkyl, n is 1-100, and each m is independently 1 or 2. In some
embodiments, for a compound of Formula (I), R12 is hydrogen or C 1_6 alkyl. In
some
embodiments, for a compound of Formula (I), R12 is H, methyl, or ethyl. In
some
embodiments, for a compound of Formula (I), R12 is H.
In some embodiments, the emulsion or microemulsion for use with a stimulation
fluid (e.g., a fracturing fluid) comprising a surfactant as in Formula II:
-50-
CA 02906165 2015-09-11
WO 2014/153102 PCT/US2014/029079
R8
R7 R9
X Y.,(3t,,,),,c)
R10
R11
wherein each of R7, R8, R9, RI , and R11 are the same or different and are
selected from
the group consisting of hydrogen, optionally substituted alkyl, and ¨CH=CHAr,
wherein
Ar is an aryl group, provided at least one of R7, R8, R9, R10, and R" is
¨CH=CHAr, Y- is
.. an anionic group, X is a cationic group, n is 1-100, and each m is
independently 1 or 2.
In some embodiments, for a compound of Formula (II), X is a metal cation or
N(R13)4,
wherein each R13 is independently selected from the group consisting of
hydrogen,
optionally substituted alkyl, or optionally substituted aryl. In some
embodiments, X+ is
NH4. Non-limiting examples of metal cations are Nat, K+, Mg+2, and Ca+2. In
some
a) embodiments, for a compound of Formula (II), Y- is -0-, -S020-, or
¨0S020-.
In some embodiments, the emulsion or microemulsion for use with a stimulation
fluid (e.g., a fracturing fluid) comprising a surfactant as in Formula III:
R8
R7 R9
CD
Z
0 R1
m n
R11
(m)
wherein each of R7, R8, R9, RI , and R11 are the same or different and are
selected from
the group consisting of hydrogen, optionally substituted alkyl, and ¨CH=CHAr,
wherein
Ar is an aryl group, provided at least one of R7, R8, R9, R10, and R" is
¨CH=CHAr, Z 'is
a cationic group, n is 1-100, and each m is independently 1 or 2. In some
embodiments,
for a compound of Formula (III), Z+ is N(R13)3, wherein each R13 is
independent selected
from the group consisting of hydrogen, optionally substituted alkyl, or
optionally
substituted aryl.
-51-
CA 02906165 2015-09-11
WO 2014/153102 PCT/US2014/029079
In some embodiments, for a compound of Formula (I), (II), or (III), two of R7,
R8,
R9, R10, and R" are ¨CH=CHAr. In some embodiments, for a compound of Formula
(I),
(II), or (III), one of R7, R8, R9, R10, and R" is ¨CH=CHAr and each of the
other groups is
hydrogen. In some embodiments, for a compound of Formula (I), (II), or (III),
two of R7,
R8, R9, R19, and R" are ¨CH=CHAr and each of the other groups is hydrogen. In
some
embodiments, for a compound of Formula (I), (II), or (III), R7 and R8 are
¨CH=CHAr
and R9, R10, and R" are each hydrogen. In some embodiments, for a compound of
Formula (I), (II), or (III), three of R7, R8, R9, R10, and R" are ¨CH=CHAr and
each of
the other groups is hydrogen. In some embodiments, for a compound of Formula
(1), (11),
or (III), R7, R8, and R9 are ¨CH=CHAr and R19 and R11 are each hydrogen. In
embodiments, for a compound of Formula (I), (II), or (III), Ar is phenyl. In
some
embodiments, for a compound of Formula (I), (II), or (III), each m is 1. In
some
embodiments, for a compound of Formula (I), (II), or (III), each m is 2. In
some
embodiments, for a compound of Formula (I), (II), or (III), n is 6-100, or 1-
50, or 6-50,
or 6-25, or 1-25, or 5-50, or 5-25, or 5-20.
In some embodiments, an emulsion or microemulsion comprises a surfactant of
Formula (I), (II), or (III) in an amount between about 1 wt% and about 20 wt%,
or
between about 3 wt% and about 15 wt%, or between about 5 wt% and about 13 wt%,
or
between about 5 wt% and about 11 wt%, or between about 7 wt% and about 11 wt%,
or
between about 10 wt% and about 12 wt%, or between about 8 wt% and about 12
wt%, or
between about 8 wt% and about 10 wt%, or about 9 wt%. In some embodiments, the
emulsion or microemulsion comprises, in addition to the surfactant of Formula
(I), (II),
or (III), water and a non-aqueous phase (e.g., a terpene), and optionally
other additives
(e.g., one or more additional surfactants, an alcohol, a freezing point
depression agent,
etc.). In some embodiments, the emulsion or microemulsion comprises, in
addition to the
surfactant of Formula (I), (II), or (III), water, a terpene, an alcohol, one
or more
additional surfactants, and optionally other additives (e.g., a freezing point
depression
agent). In some embodiments, the emulsion or microemulsion comprises, in
addition to
the surfactant of Formula (I), (II), or (III), between about 20 wt% and 90 wt%
water,
between about 2 wt% and about 70 wt% of one or more additional surfactants,
between
about 1 wt% and about 80 wt% of a solvent (e.g., terpene), and between about
10 wt%
and about 40 wt% of a mutual solvent (e.g., alcohol). In some embodiments, the
emulsion or microemulsion comprises, in addition to the surfactant of Formula
(I), (II),
- 52 -
CA 02906165 2015-09-11
WO 2014/153102 PCT/US2014/029079
or (III), between about 10 wt% and 80 wt% water, between about 2 wt% and about
80
wt% of one or more additional surfactants, between about 1 wt% and about 70
wt% of a
solvent (e.g., terpene), and between about 5 wt% and about 40 wt% of a mutual
solvent
(e.g., alcohol). In some embodiments, the emulsion or microemulsion comprises,
in
addition to the surfactant of Formula (I), (II), or (III), between about 20
wt% and 90 wt%
water, between about 2 wt% and about 70 wt% of one or more additional
surfactants,
between about 1 wt% and about 78 wt% of a solvent (e.g., terpene), and between
about
22 wt% and about 40 wt% of a mutual solvent (e.g., alcohol). Non-limiting
examples of
surfactants of Formula (I), (II), or (III) include styrylphenol ethoxylate, a
tristyrylphenol
ethoxylate, a styrylphenol propoxylate, a tristyrylphenol propoxyl ate, a
styrylphenol
ethoxylate propoxylate, or a tristyrylphenol ethoxylate propoxylate.
II-F. Kill Fluids
As will be known to those skilled in the art, generally during the lifecycle
of the
well, it may be necessary to temporarily halt the recovery of gas and/or oil
(e.g., to
repair equipment). Generally, this is accomplished by injecting a fluid,
herein referred to
as a kill fluid, into the wellbore.
In some embodiments, a kill fluid comprises an emulsion or microemulsion.
Emulsions and microemulsions are described in more detail herein. The addition
of an
emulsion or microemulsion in the kill fluid may have many advantages as
compared to
the use of a kill fluid alone including, for example, increasing the amount of
kill fluid
recovered and/or improving the ability for the well to return to the rate of
production it
exhibited prior to injection of the kill fluid.
In some embodiments, the kill fluid comprises an emulsion or microemulsion as
described herein wherein the emulsion or microemulsion is present in an amount
between about 0.5 and about 200 gpt of kill fluid, or between about 0.5 and
about 100
gpt, or between about 0.5 and about 50 gpt, or between about 1 and about 50
gpt, or
between about 1 and about 20 gpt, or between about 2 and about 20 gpt, or
between
about 2 and about 10 gpt, or between about 2 and about 5 gpt, or between about
5 and
about 10 gpt. In some embodiments, the emulsion or microemulsion is present in
an
amount between about 1 and about 10 gpt. In some embodiments, the kill fluid
contains
at least about 0.5 gpt, or at least about 1 gpt, or at least about 2 gpt, or
at least about 4
gpt, or at least about 10 gpt, or at least about 20 gpt, or at least about 50
gpt, or at least
-53-
CA 02906165 2015-09-11
WO 2014/153102 PCT/US2014/029079
about 100 gpt, or at least about 200 gpt, of an emulsion or a microemulsion.
In some
embodiments, the kill fluid contains less than or equal to about 200 gpt, or
less than or
equal to about 100 gpt, or less than or equal to about 50 gpt, or less than or
equal to
about 20 gpt, or less than or equal to about 10 gpt, or less than or equal to
about 4 gpt, or
less than or equal to about 2 gpt, or less than or equal to about 1 gpt, or
less than or equal
to about 0.5 gpt of an emulsion or microemulsion.
II-G. Enhanced Oil Recovery and/or Improved Oil Recovery
As will be known to those skilled in the art, generally during the life cycle
of the
well, procedures may be performed to increase the amount of oil and/or gas
recovered
from the wellbore. Such procedures are generally referred to as enhanced oil
recovery
(EOR) and/or improved oil recovery (IOR). EOR/IOR typically uses a secondary
or a
tertiary system (e.g., comprising one or more of water, polymers, surfactants,
etc.) to
create a new mechanism which increases the displacement of oil and/or gas from
the
reservoir for recovery. Generally, EOR/IOR uses an existing wellbore which has
been
converted into a recovering well (e.g., an injecting well). In some
embodiments, the
recovering well is used to inject the secondary or tertiary system into the
reservoir at a
continuous or noncontinuous rate and/or pressure to increase the amount of
hydrocarbons
extracted from the reservoir. Non-limiting examples of EOR/IOR procedures
include
water flooding, gas flooding, polymer flooding, and/or the use of surfactant
polymers.
For example, the EOR/IOR procedure may comprise an EOR/IOR fluid (e.g., a
water
flooding fluid, a polymer flooding fluid, a surfactant flooding fluid, a gas
flooding fluid,
a surfactant, or combinations thereof).
Generally, water flooding (e.g., secondary recovery) refers to the injection
of a
water flooding fluid into a reservoir to increase the amount of oil and/or gas
recovered
from the wellbore. In some embodiments, the water flooding fluid comprises one
or
more of water (e.g., water, makeup water, etc.), acidizing fluids (e.g.,
matrix acidizing
fluids), surfactants, polymers, and foam. In certain embodiments, the water
flooding
fluid comprises a polymer (e.g., a polymer flooding fluid), and/or a
surfactant (i.e. during
a surfactant flood), and/or a surfactant polymer flood (i.e. during a SP-
flood), and/or an
alkaline surfactant polymer (i.e. during an ASP-flood). In some embodiments,
the water
flooding fluid comprises an emulsion or microemulsion. Emulsions and
microemulsions
are described in more detail herein. The addition of an emulsion or
microemulsion to the
- 54 -
CA 02906165 2015-09-11
WO 2014/153102 PCT/US2014/029079
water flooding fluid may have many advantages as compared to a water flooding
fluid
alone including increasing the adhesion of the polymer to oil, increasing
interfacial
efficiency of the polymer, increasing the amount of oil and/or gas extracted
from the
reservoir, decreasing the volume of water needed to extract the same amount of
oil,
and/or lowering the pressure necessary to extract hydrocarbons from the
reservoir. In
some embodiments, the addition of an emulsion or microemulsion to the water
flooding
fluid increases the recovery of fracturing fluids (e.g., fracturing fluids not
previously
removed).
Generally, polymer gels are injected into the formation during secondary and
tertiary recovery to block water and gas (carbon dioxide and nitrogen) flow
from
previously swept zones and large fractures (e.g., thief zones) or to prevent
imbibition of
water from a part of the formation that abuts the oil containing zone. Use of
polymers in
these cases is commonly referred to as conformance control or water shut-off.
In some
embodiments, emulsions and microemulsions are injected into the formation as a
preflush to prepare the formation for the polymer gel injection. The addition
of an
emulsion or microemulsion prior to the injection of a polymer gel may have
many
advantages as compared the injection of a polymer gel alone including
enhancing the
adhesion of the polymer to the formation (e.g., by removing surface
contamination and
residual oil).
Generally, gas flooding refers to the injection of a gas (e.g., carbon
dioxide,
nitrogen) into a reservoir to increase the amount of oil and/or gas recovered
from the
wellbore. In some embodiments, gas flooding comprises a gas flooding fluid
(e.g., liquid
carbon dioxide and/or liquid nitrogen). In some embodiments, the gas flooding
fluid
comprises an emulsion or microemulsion. The addition of an emulsion or a
microemulsion in the gas flooding fluid may have many advantages as compared
to the
use of a gas flooding fluid alone, including reducing the miscibility pressure
as compared
to gas flooding alone, and/or reducing the volume of liquid carbon dioxide or
liquid
nitrogen that expands into a gas during the gas flooding process.
Generally, a formulation (e.g., a foam diverter, emulsion diverter, or matrix
diverter) that forms a foam upon contact with gas (e.g., carbon dioxide, flu
gas, methane,
natural gas, or nitrogen) is injected into the formation (e.g., in an aqueous
treatment fluid
or injected into the gas stream) that forms a foam upon contact with gas
(e.g., carbon
dioxide or nitrogen) is injected into the foimation to divert gas flow from
high
- 55 -
CA 02906165 2015-09-11
WO 2014/153102 PCT/US2014/029079
permeability zones to low permeability zones during a gas flood EOR/IOR
treatment.
These matrix diversion activities are commonly employed in situations where
gas (e.g.
carbon dioxide, flu gas, methane, natural gas, or nitrogen) rapidly penetrates
the
formation after a water flooding step without producing additional
hydrocarbons. In
these cases the rapid penetration of gas through the reservoir is due to gas
gravity
override or due to exhaustion of hydrocarbon reserves in high-permeability
zones. In
some embodiments, an emulsion and/or microemulsion is injected into the
formation as a
preflush to prepare the formation for the foam diverter injection. The
addition of an
emulsion or microemulsion prior to the injection of the foam may have many
advantages
as compared the injection of the foam alone including enhancing the stability
of the foam
(e.g., by removing surface contamination and residual oil), or increasing the
penetration
of the foam into the formation (e.g., by controlling the adsorption of the
diverter onto the
rock surface).
In some embodiments, the EOR/IOR fluid comprises an emulsion or
microemulsion as described herein wherein the emulsion or microemulsion is
present in
an amount between about 0.5 and about 200 gpt of EOR/IOR fluid, or between
about 0.5
and about 100 gpt, or between about 0.5 and about 50 gpt, or between about 1
and about
50 gpt, or between about 1 and about 20 gpt, or between about 2 and about 20
gpt, or
between about 2 and about 10 gpt, or between about 2 and about 5 gpt, or
between about
5 and about 10 gpt. In some embodiments, the emulsion or microemulsion is
present in
an amount between about 1 and about 10 gpt. In some embodiments, the EOR/IOR
fluid
contains at least about 0.5 gpt, or at least about 1 gpt, or at least about 2
gpt, or at least
about 4 gpt, or at least about 10 gpt, or at least about 20 gpt, or at least
about 50 gpt, or at
least about 100 gpt, or at least about 200 gpt of an emulsion or a
microemulsion. In some
embodiments, the EOR/IOR fluid contains less than or equal to about 200 gpt,
or less
than or equal to about 100 gpt, or less than or equal to about 50 gpt, or less
than or equal
to about 20 gpt, or less than or equal to about 10 gpt, or less than or equal
to about 4 gpt,
or less than or equal to about 2 gpt, or less than or equal to about 1 gpt, or
less than or
equal to about 0.5 gpt of an emulsion or microemulsion.
II-H. Stored Fluid
As will be known to those skilled in the art, wellbores and/or reservoirs
which are
no longer used for oil and/or gas recovery may generally be used to store
excess fluid
-56-
CA 02906165 2015-09-11
WO 2014/153102 PCT/US2014/029079
(e.g., water, makeup water, salt water, brine, etc.) recovered from the
reservoir. In some
embodiments, an emulsion or microemulsion is added to the stored fluid. The
addition of
an emulsion or microemulsion to the stored fluid may reduce corrosion of the
wellbore.
In some embodiments, the stored fluid comprises an emulsion or microemulsion
as described herein wherein the emulsion or microemulsion is present in an
amount
between about 0.5 and about 200 gpt of stored fluid, or between about 0.5 and
about 100
gpt, or between about 0.5 and about 50 gpt, or between about 1 and about 50
gpt, or
between about 1 and about 20 gpt, or between about 2 and about 20 gpt, or
between
about 2 and about 10 gpt, or between about 2 and about 5 gpt, or between about
5 and
about 10 gpt. In some embodiments, the emulsion or microemulsion is present in
an
amount between about 1 and about 10 gpt. In some embodiments, the stored fluid
contains at least about 0.5 gpt, or at least about 1 gpt, or at least about 2
gpt, or at least
about 4 gpt, or at least about 10 gpt, or at least about 20 gpt, or at least
about 50 gpt, or at
least about 100 gpt, or at least about 200 gpt of an emulsion or a
microemulsion. In some
embodiments, the stored fluid contains less than or equal to about 200 gpt, or
less than or
equal to about 100 gpt, or less than or equal to about 50 gpt, or less than or
equal to
about 20 gpt, or less than or equal to about 10 gpt, or less than or equal to
about 4 gpt, or
less than or equal to about 2 gpt, or less than or equal to about 1 gpt, or
less than or equal
to about 0.5 gpt of an emulsion or microcmulsion.
Offshore Applications
It should be understood, that for each step of the life cycle of the well
described
herein, the description may apply to onshore or offshore wells. In some
embodiments,
stimulation fluids are used in onshore wells. In some embodiments, stimulation
fluids are
used in offshore wells and/or during fracture packing (e.g., gravel packing).
As will be
known by those skilled in the art, stimulation fluids for use in offshore
wells may
comprise stable media (e.g., gravel) that may be injected into a wellbore to
protect the
integrity of the wellbore itself. In some embodiments, stimulation fluids for
use in
offshore wells are used in high rate water packing wherein stimulation fluids
may be
injected at higher rates (e.g., 400 barrels/min), at higher pressures, and/or
at higher
volumes as compared to an onshore well. The addition of an emulsion or
microemulsion
in the stimulation fluid for use in offshore wells may have many advantages as
compared
to the use of a stimulation fluid alone, including, for example, minimizing
the damaging
-57 -
effects of stimulation fluids that come in contact with the reservoir, and/or
increasing the
amount of hydrocarbons extracted from the reservoir.
In some embodiments, the stimulation fluid utilized in offshore wells or
during
fracture packing comprises an emulsion or microemulsion as described herein
wherein
the emulsion or microemulsion is present in an amount between about 0.5 and
about 200
gpt of stimulation fluid for use in offshore wells or during fracture packing,
or between
about 0.5 and about 100 gpt, or between about 0.5 and about 50 gpt, or between
about 1.
and about 50 gpt, or between about 1 and about 20 gpt, or between about 2 and
about 20
gpt, or between about 2 and about 10 gpt, or between about 5 and about 10 gpt.
In some
embodiments, the emulsion or microemulsion is present in an amount between
about 2
and about 5 gpt. In some embodiments, the stimulation fluid for use in
offshore wells or
during fracture packing contains at least about 0.5 gpt, or at least about 1
gpt, or at least
about 2 gpt, or at least about 4 gpt, or at least about 10 gpt, or at least
about 20 gpt, or at
least about 50 gpt, or at least about 100 gpt, or at least about 200 gpt of an
emulsion or a
is microemulsion. In some embodiments, the stimulation fluid for use in
offshore wells or
during fracture packing contains less than or equal to about 200 gpt, or less
than or equal
to about 100 gpt, or less than or equal to about 50 gpt, or less than or equal
to about 20
gpt, or less than or equal to about 10 gpt, or less than or equal to about 4
gpt, or less than
or equal to about 2 gpt, or less than or equal to about 1 gpt, or less than or
equal to about
0.5 gpt of an emulsion or microemulsion.
III. Definitions
For convenience, certain terms employed in the specification, examples, and
appended claims are listed here.
Definitions of specific functional groups and chemical terms are described in
more detail below. For purposes of this invention, the chemical elements are
identified in
accordance with the Periodic Table of the Elements, CAS version, Handbook of
Chemistry and Physics, 75th Ed., inside cover, and specific functional groups
are
generally defined as described therein. Additionally, general principles of
organic
chemistry, as well as specific functional moieties and reactivity, are
described in Organic
Chemistry, Thomas Sorrell, University Science Books, Sausalito: 1999.
Certain compounds of the present invention may exist in particular geometric
or
- 58 -
CA 2906165 2018-05-29
CA 02906165 2015-09-11
WO 2014/153102 PCT/US2014/029079
stereoisomeric forms. The present invention contemplates all such compounds,
including
cis- and trans-isomers, R- and S-enantiomers, diastereomers, (D)-isomers, (0-
isomers,
the racemic mixtures thereof, and other mixtures thereof, as falling within
the scope of
the invention. Additional asymmetric carbon atoms may be present in a
substituent such
as an alkyl group. All such isomers, as well as mixtures thereof, are intended
to be
included in this invention.
Isomeric mixtures containing any of a variety of isomer ratios may be utilized
in
accordance with the present invention. For example, where only two isomers are
combined, mixtures containing 50:50, 60:40, 70:30, 80:20, 90:10, 95:5, 96:4,
97:3, 98:2,
99:1, or 100:0 isomer ratios are all contemplated by the present invention.
Those of
ordinary skill in the art will readily appreciate that analogous ratios are
contemplated for
more complex isomer mixtures.
The term "aliphatic," as used herein, includes both saturated and unsaturated,
nonaromatic, straight chain (i.e. unbranched), branched, acyclic, and cyclic
(i.e.
carbocyclic) hydrocarbons, which are optionally substituted with one or more
functional
groups. As will be appreciated by one of ordinary skill in the art,
"aliphatic" is intended
herein to include, but is not limited to, alkyl, alkenyl, alkynyl, cycloalkyl,
cycloalkenyl,
and cycloalkynyl moieties. Thus, as used herein, the term "alkyl" includes
straight,
branched and cyclic alkyl groups. An analogous convention applies to other
generic
terms such as "alkenyl", "alkynyl", and the like. Furthermore, as used herein,
the terms
"alkyl", "alkenyl", "alkynyl", and the like encompass both substituted and
unsubstituted
groups. In certain embodiments, as used herein, "aliphatic" is used to
indicate those
aliphatic groups (cyclic, acyclic, substituted, unsubstituted, branched or
unbranched)
having 1-20 carbon atoms. Aliphatic group substituents include, but are not
limited to,
any of the substituents described herein, that result in the formation of a
stable moiety
(e.g., aliphatic, alkyl, alkenyl, alkynyl, heteroaliphatic, heterocyclic,
aryl, heteroaryl,
acyl, oxo, imino, thiooxo, cyano, isocyano, amino, azido, nitro, hydroxyl,
thiol, halo,
aliphaticamino, heteroaliphaticamino, alkylamino, heteroalkylamino, arylamino,
heteroarylamino, alkylaryl, arylalkyl, aliphaticoxy, heteroaliphaticoxy,
alkyloxy,
heteroalkyloxy, aryloxy, heteroaryloxy, aliphaticthioxy,
heteroaliphaticthioxy,
alkylthioxy, heteroalkylthioxy, arylthioxy, heteroarylthioxy, acyloxy, and the
like, each
of which may or may not be further substituted).
-59-
CA 02906165 2015-09-11
WO 2014/153102 PCT/US2014/029079
The term "alkane" is given its ordinary meaning in the art and refers to a
saturated hydrocarbon molecule. The term "branched alkane" refers to an alkane
that
includes one or more branches, while the term "ii.nbranched alkane" refers to
an alkane
that is straight-chained. The term "cyclic alkane" refers to an alkane that
includes one or
more ring structures, and may be optionally branched. The term "acyclic
alkane" refers
to an alkane that does not include any ring structures, and may be optionally
branched.
The term "alkene" is given its ordinary meaning in the art and refers to an
unsaturated hydrocarbon molecule that includes one or more carbon-carbon
double
bonds. The term "branched alkene" refers to an alkene that includes one or
more
branches, while the term "unbranched alkene" refers to an alkene that is
straight-chained.
The term "cyclic alkene" refers to an alkene that includes one or more ring
structures,
and may be optionally branched. The term "acyclic alkene" refers to an alkene
that does
not include any ring structures, and may be optionally branched.
The term "aromatic" is given its ordinary meaning in the art and refers to
aromatic carbocyclic groups, having a single ring (e.g., phenyl), multiple
rings (e.g.,
biphenyl), or multiple fused rings in which at least one is aromatic (e.g.,
1,2,3,4-
tetrahydronaphthyl, naphthyl, anthryl, or phenanthryl). That is, at least one
ring may
have a conjugated pi electron system, while other, adjoining rings can be
cycloalkyls,
cycloalkenyls, cycloalkynyls, aryls and/or heterocyclyls.
The term "aryl" is given its ordinary meaning in the art and refers to
aromatic
carbocyclic groups, optionally substituted, having a single ring (e.g.,
phenyl), multiple
rings (e.g., biphenyl), or multiple fused rings in which at least one is
aromatic (e.g.,
1,2,3,4-tetrahydronaphthyl, naphthyl, anthryl, or phenanthryl). That is, at
least one ring
may have a conjugated pi electron system, while other, adjoining rings can be
cycloalkyls, cycloalkenyls, cycloalkynyls, aryls and/or heterocyclyls. The
aryl group
may be optionally substituted, as described herein. Substituents include, but
are not
limited to, any of the previously mentioned substitutents, i.e., the
substituents recited for
aliphatic moieties, or for other moieties as disclosed herein, resulting in
the formation of
a stable compound. In some cases, an aryl group is a stable mono- or
polycyclic
unsaturated moiety having preferably 3-14 carbon atoms, each of which may be
substituted or unsubstituted.
The term "amine" is given its ordinary meaning in the art and refers to a
primary
(-NH2), secondary (-NHR,), tertiary (-NRxRy), or quaternary (-N+R,RyRz) amine
(e.g.,
- 60 -
where Rõ, Ry, and R, are independently an aliphatic, au i cyclic, alkyl, aryl,
or other
moieties, as defined herein).
The term "amide" is given its ordinary meaning in the art and refers to a
compound containing a nitrogen atom and a carbonyl group of the structure
RõCONRyR,
(e.g., where Rx, Ry, and R, are independently an aliphatic, alicyclic, alkyl,
aryl, or other
moieties, as defined herein).
These and other aspects of the present invention will be further appreciated
upon
consideration of the following Examples, which are intended to illustrate
certain
particular embodiments of the invention but are not intended to limit its
scope, as defined
to by the claims.
Examples
Example 1:
This example describes a non-limiting experiment for determining displacement
of residual aqueous treatment fluid by formation crude oil. A 25 cm long, 2.5
cm
diameter capped glass chromatography column was packed with 77 grams of 100
mesh
sand or a mixture of 70/140 mesh shale and 100 mesh sand or a mixture of
70/140 mesh
shale and 100 mesh sand. The column was left open on one end and a PTFE insert
containing a recessed bottom, 3.2 mm diameter outlet, and nipple was placed
into the
other end. Prior to placing the insert into the column, a 3 cm diameter filter
paper disc
rm.
(Whatman, #40) was pressed firmly into the recessed bottom of the insert to
prevent
leakage of 100 mesh sand. A 2 inch piece of vinyl tubing was placed onto the
nipple of
the insert and a clamp was fixed in place on the tubing prior to packing. The
columns
were gravity-packed by pouring approximately 25 grams of the diluted
microemulsions
(e.g., the microcmulsions described in Examples 1 or 2, and diluted with 2%
KC1, e.g., to
about 2 gpt, or about 1 gpt) into the column followed by a slow, continuous
addition of
sand. After the last portion of sand had been added and was allowed to settle,
the excess
of brine was removed from the column so that the level of liquid exactly
matched the
level of sand. Pore volume in the packed column was calculated as the
difference in mass
of fluid prior to column packing and after the column had been packed. Three
additional
pore volumes of brine were passed through the column. After the last pore
volume was
passed, the level of brine was adjusted exactly to the level of sand bed,
Light condensate
oil was then added on the top of sand bed to form the 5 cm oil column above
the bed.
- 61 -
CA 2906165 2018-05-29
CA 02906165 2015-09-11
WO 2014/153102 PCT/US2014/029079
Additional oil was placed into a separatory funnel with a side arm open to an
atmosphere. Once the setup was assembled, the clamp was released from the
tubing, and
timer was started. Throughout the experiment the level of oil was monitored
and kept
constant at a 5 cm mark above the bed. Oil was added from the separatory
funnel as
necessary, to ensure this constant level of head in the column. Portions of
effluent
coming from the column were collected into plastic beakers over a measured
time
intervals. The amount of fluid was monitored. When both brine and oil were
produced
from the column, they were separated with a syringe and weighed separately.
The
experiment was conducted for 3 hours at which the steady-state conditions were
typically
reached. The cumulative % or aqueous fluid displaced from the column over 120
minute
time period, and the steady-state mass flow rate of oil at t=120 min through
the column
were determined.
Example 2:
This example describes a non-limiting experiment for determining displacement
of residual aqueous treatment fluid by formation gas. A 51 cm long, 2.5 cm
inner
diameter capped glass chromatography column was filled with approximately 410
20 g
of 20/40 mesh Ottawa sand and the diluted microemulsions. To ensure uniform
packing,
small amounts of proppant were interchanged with small volumes of liquid.
Periodically
the mixture in the column was homogenized with the help of an electrical hand
massager, in order to remove possible air pockets. Sand and brine were added
to
completely fill the column to the level of the upper cap. The exact amounts of
fluid and
sand placed in the column were determined in each experiment. The column was
oriented vertically and was connected at the bottom to a nitrogen cylinder via
a gas flow
controller pre-set at a flow rate of 60 cm3/min. The valve at the bottom was
slowly
opened and liquid exiting the column at the top was collected into a tarred
jar placed on a
balance. Mass of collected fluid was recorded as a function of time by a
computer
running a data logging software. The experiments were conducted until no more
brine
could be displaced from the column. The total % of fluid recovered was then
calculated.
Example 3:
This example describes a general preparation method for the production of
diluted microemulsion. The microemulsions were prepared in the laboratory by
mixing
- 62 -
CA 02906165 2015-09-11
WO 2014/153102
PCT/US2014/029079
the ingredients listed in specific examples. All ingredients are commercially
available
materials. In some embodiments, the components were mixed together in the
order
water-alcohol-surfactant- citrus terpene solvent, but other order of addition
may also be
employed. The mixtures were then agitated on a magnetic stirrer for 5 10
minutes. The
microemulsions were then diluted to concentrations of 1 or 2 gallons per 1000
gallons
with 2% KC1 brine and these diluted fluids were used in displacement
experiments (e.g.,
as described in Examples 1 and 2).
Example 4:
A number of microemulsions were prepared according to the method described in
Example 3 and comprising the components described in Table 2. The
microemulsions
comprises a styrylphenol ethoxylate surfactant, water, other surfactants, co-
solvents, and
a solvent (e.g., hydrocarbon). The percent displacement of brine by crude oil
was
determined using the method described in Example 1. The results are provided
in Table
2.
Table 2:
Amount of styrylphenol
Exp't ethoxylate used in the Formulation Composition
displacement
No. formulation (wt% range) of brine
by
(wt%) crude oil
Water 20-90%
Other surfactants 2-70%
1 11 1 69%
Cosolvents 10-40%
Hydrocarbon 1-80%
Water 10-80%
Other surfactants 2-80%
2 8 3 770/0
Cosolvents 5-40%
Hydrocarbon 1-70%
Water 20-90%
Other surfactants 2-70%
3 10 2 83%
Cosolvents 22-40%
Hydrocarbon 1-78%
While several embodiments of the present invention have been described and
illustrated herein, those of ordinary skill in the art will readily envision a
variety of other
means and/or structures for performing the functions and/or obtaining the
results and/or
- 63 -
CA 02906165 2015-09-11
WO 2014/153102 PCT/US2014/029079
one or more of the advantages described herein, and each of such variations
and/or
modifications is deemed to be within the scope of the present invention. More
generally,
those skilled in the art will readily appreciate that all parameters,
dimensions, materials,
and configurations described herein are meant to be exemplary and that the
actual
parameters, dimensions, materials, and/or configurations will depend upon the
specific
application or applications for which the teachings of the present invention
is/are used.
Those skilled in the art will recognize, or be able to ascertain using no more
than routine
experimentation, many equivalents to the specific embodiments of the invention
described herein. It is, therefore, to be understood that the foregoing
embodiments are
presented by way of example only and that, within the scope of the appended
claims and
equivalents thereto, the invention may be practiced otherwise than as
specifically
described and claimed. The present invention is directed to each individual
feature,
system, article, material, kit, and/or method described herein. In addition,
any
combination of two or more such features, systems, articles, materials, kits,
and/or
methods, if such features, systems, articles, materials, kits, and/or methods
are not
mutually inconsistent, is included within the scope of the present invention.
The indefinite articles "a" and "an," as used herein in the specification and
in the
claims, unless clearly indicated to the contrary, should be understood to mean
"at least
one."
The phrase "and/or," as used herein in the specification and in the claims,
should
be understood to mean "either or both" of the elements so conjoined, i.e.
elements that
are conjunctively present in some cases and disjunctively present in other
cases. Other
elements may optionally be present other than the elements specifically
identified by the
"and/or" clause, whether related or unrelated to those elements specifically
identified
unless clearly indicated to the contrary. Thus, as a non-limiting example, a
reference to
"A and/or B," when used in conjunction with open-ended language such as
"comprising"
can refer, in one embodiment, to A without B (optionally including elements
other than
B); in another embodiment, to B without A (optionally including elements other
than A);
in yet another embodiment, to both A and B (optionally including other
elements); etc.
As used herein in the specification and in the claims, "or" should be
understood
to have the same meaning as "and/or" as defined above. For example, when
separating
items in a list, "or" or "and/or" shall be interpreted as being inclusive,
i.e. the inclusion
of at least one, but also including more than one, of a number or list of
elements, and,
- 64 -
optionally, additional unlisted items. Only terms clearly indicated to the
contrary, such as
"only one of' or "exactly one of," or, when used in the claims, "consisting
of," will refer
to the inclusion of exactly one element or a list of elements. In general, the
term "or" as
used herein shall only be interpreted as indicating exclusive alternatives
(i.e. "one or the
other but not both") when preceded by terms of exclusivity, such as "either,"
"one of,"
"only one of," or "exactly one of." "Consisting essentially of," when used in
the claims,
shall have its ordinary meaning as used in the field of patent law.
As used herein in the specification and in the claims, the phrase "at least
one," in
reference to a list of one or more elements, should be understood to mean at
least one
element selected from any one or more of the elements in the list of elements,
but not
necessarily including at least one of each and every element specifically
listed within the
list of elements and not excluding any combinations of elements in the list of
elements.
This definition also allows that elements may optionally be present other than
the
elements specifically identified within the list of elements to which the
phrase "at least
one" refers, whether related or unrelated to those elements specifically
identified. Thus,
as a non-limiting example, "at least one of A and B" (or, equivalently, "at
least one of A
or B," or, equivalently "at least one of A and/or B") can refer, in one
embodiment, to at
least one, optionally including more than one, A, with no B present (and
optionally
including elements other than B); in another embodiment, to at least one,
optionally
including more than one, B, with no A present (and optionally including
elements other
than A); in yet another embodiment, to at least one, optionally including more
than one,
A, and at least one, optionally including more than one, B (and optionally
including other
elements); etc.
In the claims, as well as in the specification above, all transitional phrases
such as
"comprising," "including," "carrying," "having," "containing," "involving,"
"holding,"
and the like are to be understood to be open-ended, i.e. to mean including but
not limited
to. Only the transitional phrases "consisting of" and "consisting essentially
of' shall be
closed or semi-closed transitional phrases, respectively
- 65 -
CA 2906165 2018-05-29
