Note: Descriptions are shown in the official language in which they were submitted.
CA 02764306 2012-01-16
METHODS OF TREATING A SUBTERRANEAN FORMATION CONTAINING
HYDROCARBONS
TECHNICAL FIELD
[0001] This document relates to methods of treating a subterranean formation
containing hydrocarbons.
BACKGROUND
[0002] In the conventional fracturing of wells, producing formations, new
wells or
low producing wells that have been taken out of production, a formation can be
fractured
to attempt to achieve higher production rates. Proppant and fracturing fluid
are pumped
into a well that penetrates an oil or gas bearing formation. High pressure is
applied to the
well, the formation fractures and proppant carried by the fracturing fluid
flows into the
fractures. The proppant in the fractures holds the fractures open after the
pressure is
relaxed and production is resumed. Various fluids have been disclosed for use
as the
fracturing fluid, including liquefied petroleum gas (LPG). Various chemicals
may be
added to the fracturing fluid, such as gelling agents, breakers, activators,
and surfactants.
SUMMARY
[0003] A method of treating a subterranean formation containing hydrocarbons
is
disclosed, the method comprising: modifying the subterranean formation with a
surface
energy reducing agent; and injecting into the subterranean formation a
fracturing fluid
containing a base fluid and a gelling agent; in which the surface energy
reducing agent is
selected to effectively reduce the surface energy of the subterranean
formation to at or
below the surface tension of the gelling agent.
[0004] In various embodiments, there may be included any one or more of the
following features: The surface energy reducing agent is selected such that
the modified
subterranean formation does not bond with the gelling agent. The surface
energy
reducing agent adheres to the subterranean formation more strongly than the
gelling
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agent adheres to the subterranean formation. The surface energy reducing agent
is
selected to effectively reduce the net force of adhesion between the
subterranean
formation and the gelling agent (FFG) from above to below the net force of
cohesion of
the gelling agent (FGG). The method comprises breaking a gel, formed of the
gelling
agent, in the subterranean formation, in which the surface energy reducing
agent is
selected to effectively reduce the surface energy of the subterranean
formation to at or
below the surface tension of the gelling agent when broken. Modifying is
carried out by
injecting fracturing fluid comprising the surface energy reducing agent.
Modifying
comprises coating. The surface energy reducing agent comprises a surfactant.
The
surfactant comprises one or more of an ionic surfactant and a non-ionic
surfactant. The
ionic surfactant comprises one or more of an anionic surfactant, a cationic
surfactant, and
a zwitterionic surfactant. The surface energy reducing agent comprises an
alkyne-diol.
The surface energy reducing agent comprises one or more of Surfanol MB,
Surfanol 104-
PG50, Surfanol 2502, Dynol 604, and Dynol 607. The base fluid comprises
hydrocarbons and the gelling agent comprises a gelling agent for hydrocarbons.
The
gelling agent comprises a polyacrylimide. The gelling agent comprises a
phosphate. The
base fluid comprises liquefied petroleum gas. The gelling agent comprises a
gelling agent
for liquefied petroleum gas. The gelling agent is selected to have a surface
tension of
between twenty and forty-six dynes/cm when in the subterranean formation after
breaking.
[0005] These and other aspects of the device and method are set out in the
claims,
which are incorporated here by reference.
BRIEF DESCRIPTION OF THE FIGURES
[0006] Embodiments will now be described with reference to the figures, in
which
like reference characters denote like elements, by way of example, and in
which:
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[0007] Fig. 1A is side elevation view of an apparatus for treating a
subterranean
formation.
[0008] Fig. 113 is a flow diagram of a method of treating a subterranean
formation
containing hydrocarbons.
[0009] Fig. 2A is an exploded view that illustrates a gelling agent adhering
to an
untreated formation.
[0010] Fig. 2B is an exploded view that illustrates the reduced adherence of
gelling
agent to the formation of Fig. 2A after coating, for example adsorbing, the
formation
with surface energy reducing agent.
[0011] Figs. 3A-F are photographs of a formation test surface coated with no
surfactant, Surfanol MB, Surfanol 104-PG50, Surfanol 2502, Dynol 604, and
Dynol 607,
respectively, immersed in gelled pentane, and spotted with accudyne pens of
varying
surface tensions.
DETAILED DESCRIPTION
[0012] Immaterial modifications may be made to the embodiments described here
without departing from what is covered by the claims.
[0013] During well treatment, gelling agents or other injected chemicals may
stick to
the formation on flowback, reducing permeability and potentially plugging the
well.
Surface science has identified at least five mechanisms of adhesion to explain
why one
material sticks to another, namely mechanical adhesion, electrostatic
adhesion, chemical
adhesion, dispersive adhesion, and diffusive adhesion. Regarding the adherence
of a
liquid to a solid or coated solid in a downhole environment, the latter three
appear most
relevant. Chemical adhesion occurs when two materials form a compound at the
join.
Ionic, covalent, and hydrogen bonding are examples of chemical adhesion.
Diffusive
adhesion occurs when materials merge at the joint by diffusion, for example if
the
molecules of the liquid are mobile and soluble in the solid or liquid coating
the solid.
Dispersive adhesion, similar to chemical adhesion, occurs when two materials
are held
together by van der Waals forces, which involve the attraction between
slightly charged
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molecules, such as polar compounds. Positive and negative poles may be a
permanent
property of a molecule (Keesom forces) or a transient effect which can occur
in any
molecule (London forces).
[0014] In surface science, adhesion usually refers to dispersive adhesion. In
a solid-
liquid-gas system (such as a drop of liquid on a solid surrounded by air)
contact angle
may quantify adhesiveness. In general, where the contact angle 45 is low (ex.
Fig. 2A)
more adhesion is present than when the contact angle 45 is large (ex. Fig.
2B). The
amount of adhesion is related to the difference between the surface energy of
the surface
and the surface tension of the liquid. Surface energy is the excess energy at
the surface of
a material compared with the material as a whole. Surface tension refers to
the surface
energy of a liquid. Regardless, the contact angle of a three-phase system is a
function not
only of dispersive adhesion between the molecules in the liquid and the
molecules in the
solid, but also cohesion, which is dispersive interaction between like liquid
molecules.
Strong adhesion and weak cohesion may result in a high degree of wetting (ex.
Fig. 2A),
which may be a lyophilic condition with low measured contact angles.
Conversely, weak
adhesion and strong cohesion may result in lyophobic conditions with high
measured
contact angles and poor wetting (Fig. 2B). Table 1 below illustrates surface
energies
from some example materials.
[0015] Table 1: Example Surface Energies
SURFACE SURFACE ENERGY/TENSION (Dynes/cm)
Copper 1,103
Sand 1000
Aluminum 840
Water 72
Broken Polyacrylimide Gel 35
Hydrocarbons 20-30
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Propane <20
Teflon (DuPont) 18
[0016] Referring to Fig. 1A, a system 11 for treating a subterranean formation
24
containing hydrocarbons is illustrated. Subterranean formation 24 is a
hydrocarbon
reservoir, which may be treated for example by injection through a well 22
penetrating
the hydrocarbon reservoir 24. Fracturing fluid base fluid may be initially
contained
within a storage tank 10. Tank 10 may comprise a tanker truck or a large
vessel.
[0017] A generic example treatment of subterranean formation 24 goes as
follows.
The fracturing fluid may be pumped from reservoir 10 down line 12, where
various
components may be added to the fluid, for example via one or more component
addition
systems 14, 16, 18. For example, components such as gelling agent and proppant
may be
added from addition systems 16 and 18, respectively. The addition systems may
be, for
example, hoppers. Once the fracturing fluid is prepared and ready, a frac
pressure pump
20 injects the frac fluid down a well 22 and into subterranean formation 24.
In some
cases, one or more component or fluid may be added to the frac fluid after the
pump 20.
The concept of reservoir treatment is well known, and the details need not be
described
here. In fracturing treatments, pressure may be applied to the frac fluid
injected into the
subterranean formation 24. The pressure may be sufficient to cause fracturing
of the
subterranean formation.
[0018] Referring to Fig. 1 B, a method of treating subterranean formation 24
is
illustrated. The method will now be described with reference to the other
Figures.
Referring to Fig. 1A, in a stage 40, the subterranean formation 24 is modified
with a
surface energy reducing agent, for example from addition system 18. Modifying
may be
carried out by injecting fracturing fluid comprising the surface energy
reducing agent.
For example, a pad of base fluid from tank 10 may be combined with surface
energy
reducing agent from addition unit 18, and pumped via frac pressure pump 20
down well
22. However, the surface energy reducing agent may also be injected neat or
with another
suitable fluid. As the surface energy reducing agent contacts the subterranean
formation,
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the surface energy reducing agent may coat the formation (Fig. 2B) and
effectively
reducing the surface energy of the formation. In some embodiments
substantially the
entire surface area of the subterranean formation that will come into contact
with the
fracturing fluid is coated. In some cases, the surface energy reducing agent
is supplied
throughout the entire injection of frac fluid. In some embodiments, the
proppant used,
such as sand, may be pre-coated or co-injected with surface energy reducing
agent.
Coating a surface reduces roughness of the coated surface and thus is
beneficial as
adherence may increase with greater degrees of roughness.
[0019] In a stage 42, a fracturing fluid containing a base fluid, for example
from tank
10, and a gelling agent, for example from addition unit 16, is injected into
the
subterranean formation 24. The treatment, which may be a fracturing treatment,
may then
be completed, for example by pressuring up the fluid in well 22 to frac, and
delivering
proppant from addition unit 16 into the fractures formed in the subterranean
formation.
[0020] Referring to Figs. 2A and 2B, the effect of the surface energy reducing
agent
44 will now be described. Fig. 2A illustrates a situation where the injected
gelling agent
46 has a surface tension that is lower than the surface energy of the
formation 24. As is
shown, a contact angle 45 less than 90 degrees indicates high adherence. In
most
formations, for example sandstone formations, the surface energy of the
formation 24
will be larger than the surface tension of the gelling agent 46, effectively
causing gelling
agent 46 to wet and adhere to the formation 24. Fig. 2B illustrates the
beneficial effect of
the surface energy reducing agent 44, which has been selected to effectively
reduce the
surface energy of the formation 24 to at or below the surface tension of the
gelling agent
46. In Fig. 2B, the contact angle 45 is greater than 90 degrees, indicating a
low degree of
wetting, and likely a low degree of adherence. Thus, for a polymer gel such as
polyacrylamide gel with a surface tension of 35, the surface energy reducing
agent 44
must reduce the surface energy to thirty-five dynes/cm or lower, for example
down to
twenty dynes/cm. In most cases, the desired result will be achieved if the
surface energy
reducing agent 44 is selected to reduce the net force of adhesion between the
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subterranean formation 24 and the gelling agent (FFG) from above to below the
net force
of cohesion of the gelling agent (FGG).
[0021] The surface energy reducing agent 44 may be selected such that the
modified
subterranean formation shown in Fig. 2B does not bond, for example chemically,
with
the gelling agent 46. For example, the surface energy reducing agent 44 may be
selected
to form a hydrophobic coating if the gelling agent 46 is known to be
hydrophilic. Thus,
when the frac pressure is reduced and flowback induced, gelling agent 46 is
able to slide
off of formation 24 and be removed from the well 22. The surface energy
reducing agent
44 may also be selected to adhere to the subterranean formation 24 more
strongly than
the gelling agent 46 adheres to the subterranean formation 24. Thus, diffusion
of the
gelling agent 46 into the thin film coating formed by the surface energy
reducing agent
46 does not result in gelling agent 46 displacing surface energy reducing
agent 44 and
adhering to the formation 24. However, in some cases this is not required, and
a thin low
adherence film of surface energy reducing agent may be sufficient to allow
substantial
removal of gelling agent and related chemicals from the well 22.
[0022] The gelling agent 46 selected may have a surface tension of between
twenty
and forty-six dynes/cm when in the subterranean formation after breaking. In
some cases
the method includes the stage of breaking a gel, formed of the gelling agent
46, in the
subterranean formation 24, in which the surface energy reducing agent 44 is
selected to
effectively reduce the surface energy of the subterranean formation 24 to at
or below the
surface tension of the gelling agent 46 when broken. Thus, the broken gelling
agent is
targeted by the surface energy reducing agent 44, as it is broken gel that may
be left in
formation 24. This may be a consideration if the gelling agent changes surface
tension
upon breaking due to a chemical change in the gelling agent. The surface
energy
reducing agent may make the formation 24 omniphobic, in order to allow easy
removal
of the base fluid as well as the fracturing chemicals.
[0023] Referring to Figs. 3A-F, the surface energy reducing agent may comprise
a
surfactant, such as an alkyne-diol. Accudyne testing was carried out on a
formation 24
sample immersed in pentane gelled with 16 L/m3 gel, 16 L/m3 activator, and 8
L/m3
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breaker. The formation sample tested was a shale sample from Alberta. In this
test, a
surface energy reducing agent was introduced and coated on formation 24
sample.
Afterwards, accudyne pens of different surface tensions were spotted on the
formation 24
sample, in order to determine if surface energy had been reduced. In general,
a solid spot
produced by a pen with a surface tension X indicates that the formation has a
surface
energy above X, while a splotchy or beaded spot produced by the same pen
indicates low
adherence due to the fact that the formation has a surface energy at or below
X. For ease
of illustration, reference numerals 54, 56, 58, 60, 62, and 64 identify spots
made by
accudyne pens of surface tensions 30, 32, 34, 36, 38, and 40 dynes/cm,
respectively. Fig.
3A was used as a blank formation sample 24, with no surface energy reducing
agent
added to the gelled pentane. In Figs. 3B-F, the surface energy reducing agent
comprises
Surfanol MB (Fig. 3B), Surfanol 104-PG50 (Fig. 3C), Surfanol 2502 (Fig. 3D),
Dynol
604 (Fig. 3E), and Dynol 607 (Fig. 3F). In Fig. 3A where no surface energy
reducing
agent was used, accudyne pens having surface tensions 34 dynes/cm and 36
dynes/cm
were able to clearly form solid spots 58 and 60, respectively, indicating that
the surface
energy of formation sample 24 was at least greater than 36 dynes/cm and likely
much
higher. By contrast, the surfactants used in Figs. 3B-F all effectively
reduced the surface
energy of formation 24 sample, as evidenced by the beaded spots left by most
of the
pens. The following Table 2 indicates the estimated effective surface energy
of the
modified formation 24 samples based on the tesing.
[0024] Table 2: Accudyne Test Results
Fig. Surfactant added Effective Surface Energy of
Modified Formation 24
Sample
3A none >36 (likely much higher)
3B Surfanol MB <30
3C Surfanol104-PG50 <30
3D Surfanol 2502 34-36
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3E Dyno1604 32-34
3F Dyno1607 <30
[0025] The base fluid may comprise hydrocarbons, such as C6-C20 hydrocarbons,
and the gelling agent may comprise a gelling agent for hydrocarbons. The
gelling agent
may comprise a phosphate based chemical. In other cases the base fluid may be
water,
and the gelling agent may be a gelling agent for water. The base fluid may
comprise
liquefied petroleum gas, and the gelling agent may comprise a gelling agent
for liquefied
petroleum gas. LPG has been advantageously used as a fracturing fluid to
simplify the
recovery and clean-up of frac fluids after a frac. Exemplary LPG frac systems
are
disclosed in W02007098606, incorporated herein by reference. One example of a
suitable gelling agent for LPG is created by first reacting diphosphorous
pentoxide with
triethyl phosphate and an alcohol having hydrocarbon chains of 3-7 carbons
long, or in a
further for example alcohols having hydrocarbon chains 4-6 carbons long. The
orthophosphate acid ester formed is then reacted with aluminum sulphate to
create the
desired gelling agent. The gelling agent created will have hydrocarbon chains
from 3-7
carbons long or, as in the further example, 4-6 carbons long. The hydrocarbon
chains of
the gelling agent are thus commensurate in length with the hydrocarbon chains
of liquid
petroleum gas used for the frac fluid. This gelling agent is more effective at
gelling a
propane or butane fluid than a gelling agent with longer hydrocarbon chains.
The
proportion of gelling agent in the frac fluid is adjusted to obtain a suitable
viscosity in the
gelled frac fluid.
[0026] In some embodiments, a volatile-phosphorus free gelling agent may be
used,
for example for gelling hydrocarbons. Such a gelling agent may have the
general formula
of
0
II
H O-P-X
Y
[0027] where X is an OR', NR'R2, or SR' group, R' is an organic group having 2-
24
carbon atoms, and R2 is an organic group or a hydrogen. Y is an NR3R4 or SR3
group, R3
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is an organic group having 2-24 carbon atoms, and R4 is an organic group or a
hydrogen.
Such gelling agent may be made as follows. Phosphorus oxyhalide is reacted
with a
chemical reagent to produce substantially only diester phosphorus oxyhalide,
the
chemical reagent comprising at least one of an organic alcohol having 2-24
carbon
atoms, an organic amine with an organic group having 2-24 carbon atoms, and an
organic sulfide having 2-24 carbon atoms. The diester phosphorus oxyhalide is
then
hydrolyzed to produce diester phosphoric acid. Further examples are given in
WO/2010/022496, incorporated herein by reference.
[0028] LPG may include a variety of petroleum and natural gases existing in a
liquid
state at ambient temperatures and moderate pressures. In some cases, LPG
refers to a
mixture of such fluids. These mixes are generally more affordable and easier
to obtain
than any one individual LPG, since they are hard to separate and purify
individually.
Unlike conventional hydrocarbon based fracturing fluids, common LPGs are
tightly
fractionated products resulting in a high degree of purity and very
predictable
performance. Exemplary LPGs include ethane, propane, butane, or various
mixtures
thereof. As well, exemplary LPGs also include isomers of propane and butane,
such as
iso-butane. Further LPG examples include HD-5 propane, commercial butane, and
n-
butane. The LPG mixture may be controlled to gain the desired hydraulic
fracturing and
clean-up performance. LPG fluids used may also include minor amounts of
pentane
(such as i-pentane or n-pentane), and higher weight hydrocarbons.
[0029] LPGs tend to produce excellent fracturing fluids. LPG is readily
available,
cost effective and is easily and safely handled on surface as a liquid under
moderate
pressure. LPG is completely compatible with formations and formation fluids,
is highly
soluble in formation hydrocarbons and eliminates phase trapping - resulting in
increased
well production. LPG may be readily and predictably viscosified to generate a
fluid
capable of efficient fracture creation and excellent proppant transport. After
fracturing,
LPG may be recovered very rapidly, allowing savings on clean up costs. In some
embodiments, LPG may be predominantly propane, butane, or a mixture of propane
and
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butane. In some embodiments, LPG may comprise more than 80%, 90%, or 95%
propane, butane, or a mixture of propane and butane.
[0030] Exemplary gelling agents that may be used are disclosed by Whitney in
US
Patent nos. 3,775,069 and 3,846,310, the specifications of which are
incorporated by
reference. Such gelling agents may create water-sensitive gels. An example of
a suitable
gelling agent comprises a combination of an alkoxide of a group IIIA element
and an
alkoxide of an alkali metal. When combined, the alkoxide of the group IIIA
element and
the alkoxide of the alkali metal react to form a polymer gel. The group IIIA
element may
comprise one or more of boron and aluminum for example. In some embodiments,
the
alkoxide of a group IIIA element comprises M'(OR')(OR2)(OR3), in which M' =
the
group IIIA element, and R', R2, and R3 are organic groups. Each of the organic
groups of
R', R2, and R3 may have 2-10 carbon atoms, and may comprise an alkyl group. In
one
embodiment, M1 = boron, and R', R2, and R3 comprise 2-10 carbon atoms. The
alkali
metal may comprise one or more of lithium, sodium, and potassium for example.
In some
embodiments, the alkoxide of an alkali metal further comprises M2(OR4), in
which M2 =
the alkali metal, and R4 comprises an organic group. The organic group of R4
may
comprise 2-24 carbon atoms, for further example 12 carbon atoms, and may
comprise an
alkyl group. In one embodiment, M2 = lithium and the organic group of R4
comprises 2-
24 carbon atoms. In some embodiments, R4 may further comprise:
(AQ)õ(R5),,(R6)y. in
which A is an organic group, Q is 0 or N, n is 1-10, R5 and R6 are organic
groups, x is
either I or 2 depending on the valence of Q, and y is 0 or 1 depending on the
valence of
Q. Thus, the alkoxide of an alkali metal formed would have the formula of
M2O(AQ).(R5)X(R6)y. A may have 2-4 carbon atoms. The organic groups of R5 and
R6
may each have 1-16 carbons. Where y=1, R6 is bonded to the Q atom. Organic
groups as
disclosed herein may refer to groups with at least one carbon atom, as long
the resulting
gelling agent is suitable for its purpose. Examples of organic groups include
phenyl, aryl,
alkenyl, alkynyl, cyclo, and ether groups. A suitable amount of gelling agent
may be
used, for example 0.25 - 5 % by weight of the fracturing fluid. In addition,
the a suitable
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ration of the alkoxide of a group IIIA element and the alkoxide of an alkali
metal may be
used, for example 3:1 to 1:3, with 1:1 being a preferable ratio.
[0031] The following exemplary procedure may be used to form a fracturing
fluid
containing a water sensitive gel as discussed in the preceding paragraph.
Butyl lithium
(3.53 mL of a 1.7 M solution in pentane, 6 mmol) was added dropwise to a
stirring
solution of dodecanol (1.12 g, 6 mmol) in pentane (125.00 g, 1% by wt gelling
agents in
pentane). This mixture was then stirred for a further 1 h at room temperature.
A separate
solution of tributyl borate (1.62 mL, 6 mmol) in pentane (125.00 g) was
prepared in a
blender at 17% variance with a rheostat for 5 min. To this solution was added
the lithium
alkoxide solution and a hydrated breaker, for example CaSO4(2H20) (2.91 g,
0.15% by
vol. H2O, 60 mesh) Blending was continued for 1 min at 30% variance. Over this
time
cloudy white gels formed. These were tested on a Brookfield viscometer- 60 C,
4 h, 110
psi.
[0032] Exemplary breakers for use with water-sensitive gels include hydrated
breakers. For example, the hydrated breaker may comprise one or more hydrates,
wherein water of the one or more hydrates is releasable so as to act with the
water-
sensitive carrier to reduce the viscosity of the fracturing fluid. A hydrated
breaker may
have a crystalline framework containing water that is bound within the
crystalline
framework and releasable into the fracturing fluid to act on the water-
sensitive gel to
reduce the viscosity of the fracturing fluid. Hydrated breakers are disclosed
for example
in US application no. 12/609893 and CA application no. 2685298 the content of
which is
incorporated here by reference where permitted by law.
[0033] In some embodiments, a gelling agent need not be specifically targeted
by the
surface energy reducing agent. For example, the surface energy reducing agent
may be
selected to effectively reduce the surface energy of the subterranean
formation to at or
below the surface tension of one or more of the base fluid, breaker,
activator, gelling
agent, or other treating chemical. Thus, the targeted injected chemicals may
be easily
removed after treatment is complete, and potential for well damage by tacky
chemicals is
reduced or eliminated.
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[0034] Various surfactants may be used as the surface energy reducing agent.
For
example, the surfactant may comprise one or more of an ionic surfactant and a
non-ionic
surfactant. For further example, if used the ionic surfactant may comprise one
or more of
an anionic surfactant, a cationic surfactant, and a zwitterionic surfactant.
[0035] Anionic surfactants may be based on permanent anions such as sulfate,
sulfonate, and phosphate, or pH-dependent anions such as carboxylate. Example
anionic
surfactants based on sulfates include alkyl sulfates such as ammonium lauryl
sulfate and
sodium lauryl sulfate (SDS), alkyl ether sulfates such as sodium laureth
sulfate (also
known as sodium lauryl ether sulfate or SLES), and sodium myreth sulfate.
Example
anionic surfactants based on sulfonates include docusates such as dioctyl
sodium
sulfosuccinate. Example anionic surfactants based on sulfonates also include
sulfonate
fluorosurfactants such as perfluorooctanesulfonate (PFOS), and
perfluorobutanesulfonate. Example anionic surfactants based on sulfonates also
include
alkyl benzene sulfonates. Example anionic surfactants based on phosphates
include alkyl
aryl ether phosphate and alkyl ether phosphate. Example anionic surfactants
based on
carboxylates include alkyl carboxylates such as fatty acid salts (soaps) and
sodium
stearate. Example anionic surfactants based on carboxylates also include
sodium lauroyl
sarcosinate. Example anionic surfactants based on carboxylates also include
carboxylate
fluorosurfactants such as perfluorononanoate, and perfluorooctanoate (PFOA or
PFO).
[0036] Cationic surfactants may be based on pH-dependent amines or permanently
charged quaternary ammonium cations. Example cationic surfactants based on pH-
dependent amines include primary, secondary or tertiary amines. For example,
primary
amines may be used that become positively charged at pH < 10, and secondary
amines
may be used that become charged at pH < 4. One example of a pH-dependent amine
is
octenidine dihydrochloride. Example cationic surfactants based on permanently
charged
quaternary ammonium cations include alkyltrimethylammonium salts such as cetyl
trimethylammonium bromide (CTAB a.k.a. hexadecyl trimethyl ammonium bromide),
and cetyl trimethylammonium chloride (CTAC). Example cationic surfactants
based on
permanently charged quaternary ammonium cations also include cetylpyridinium
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chloride (CPC), polyethoxylated tallow amine (POEA), benzalkonium chloride
(BAC),
benzethonium chloride (BZT), 5-bromo-5-nitro-1,3-dioxane,
dimethyldioctadecylammonium chloride, and dioctadecyldimethylammonium bromide
(DODAB).
[0037] Zwitterionic surfactants, which may be amphoteric, may be based on
primary,
secondary or tertiary amines or quaternary ammonium cations with sulfonate,
carboxylate, or phosphate anions. Example zwitterionic surfactants with
sulfonates
include CHAPS (3-[(3-Cholamidopropyl)dimethylammonio]-1-propanesulfonate), and
sultaines such as cocamidopropyl hydroxysultaine. Example zwitterionic
surfactants with
carboxylates include amino acids, imino acids, and betaines such as
cocamidopropyl
betaine. Example zwitterionic surfactants with phosphates include lecithin.
[0038] Nonionic surfactants may include fatty alcohols such as cetyl alcohol,
stearyl
alcohol, cetostearyl alcohol (for example comprising predominantly of cetyl
and stearyl
alcohols), and oleyl alcohol. Nonionic surfactants may also include
polyoxyethylene
glycol alkyl ethers (Brij or CH3-(CH2)10-16-(O-C2H4)I 25-OH) such as
octaethylene
glycol monododecyl ether, and pentaethylene glycol monododecyl ether. Nonionic
surfactants may also include polyoxypropylene glycol alkyl ethers (CH3-
(CH2)10_16-(O-
C3H6)1_25-OH). Nonionic surfactants may also include glucoside alkyl ethers
(CH3-
(CH2)1o-16-(O-Glucoside)1_3-OH) such as decyl glucoside, lauryl glucoside, and
octyl
glucoside. Nonionic surfactants may also include polyoxyethylene glycol
octylphenol
ethers (C8H17-(C6H4)-(O-C2H4)1_25-OH) such as Triton X-100. Nonionic
surfactants
may also include polyoxyethylene glycol alkylphenol ethers (C9H19- (C6H4)- (O-
C2H4)1_
25-OH) such as nonoxynol-9. Nonionic surfactants may also include glycerol
alkyl esters
such as glyceryl laurate. Nonionic surfactants may also include
polyoxyethylene glycol
sorbitan alkyl esters such as polysorbates. Nonionic surfactants may also
include sorbitan
alkyl esters such as spans. Nonionic surfactants may also include cocamide
MEA, and
cocamide DEA. Nonionic surfactants may also include dodecyl dimethylamine
oxide,
and block copolymers of polyethylene glycol and polypropylene glycol such as
poloxamers.
14
CA 02764306 2012-01-16
[0039] Table 3: Accudyne Test Results on non-ionic, anionic, and cationic
surfactants in gelled LPG (LP 10).
Surfactant added Effective Surface Energy of Modified
Formation 24 Sample
1-hexadecanol (non-ionic) 34-36
Sodium dodecyl sulfate (anionic) 32-34
Benzalkonium Chloride (cationic) 38-40
[0040] LP 10 is a broken dialkyl phosphate LPG gel.
[0041] In the claims, the word "comprising" is used in its inclusive sense and
does
not exclude other elements being present. The indefinite article "a" before a
claim feature
does not exclude more than one of the feature being present. Each one of the
individual
features described here may be used in one or more embodiments and is not, by
virtue
only of being described here, to be construed as essential to all embodiments
as defined
by the claims.
