Note: Descriptions are shown in the official language in which they were submitted.
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METHOD AND COMPOSITION FOR ENHANCED HYDROCARBONS RECOVERY
Field of the Invention
The present invention generally relates to methods for
recovery of hydrocarbons from hydrocarbon formations. More
particularly, embodiments described herein relate to methods
of enhanced hydrocarbons recovery and to compositions useful
therein.
Background of the Invention
Hydrocarbons may be recovered from hydrocarbon
containing formations by penetrating the formation with one
or more wells. Hydrocarbons may flow to the surface through
the wells. Conditions (e.g., permeability, hydrocarbon
concentration, porosity, temperature, pressure) of the
hydrocarbon containing formation may affect the economic
viability of hydrocarbon production from the hydrocarbon
containing formation. A hydrocarbon containing formation may
have natural energy (e.g., gas, water) to aid in mobilizing
hydrocarbons to the surface of the hydrocarbon containing
formation. Natural energy may be in the form of water.
Water may exert pressure to mobilize hydrocarbons to one or
more production wells. Gas may be present in the hydrocarbon
containing formation at sufficient pressures to mobilize
hydrocarbons to one or more production wells. The natural
energy source may become depleted over time. Supplemental
recovery processes may be used to continue recovery of
hydrocarbons from the hydrocarbon containing formation.
Examples of supplemental processes include waterflooding,
polymer flooding, alkali flooding, thermal processes,
solution flooding or combinations thereof.
Compositions and methods for enhanced hydrocarbons
recovery utilizing an alpha olefin sulfate-containing
surfactant component are known. U.S. Patents 4,488,976 and
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4,537,253 describe enhanced oil or recovery compositions
containing such a component. Compositions and methods for
enhanced hydrocarbons recovery utilizing internal olefin
sulfonates are also known. Such a surfactant composition is
described in U.S. Patent 4,597,879. The compositions
described in the foregoing patents have the disadvantages
that brine solubility and divalent ion tolerance are
insufficient at certain reservoir conditions. U.S. Patent
4,979,564 describes the use of internal olefin sulfonates in
a method for enhanced oil recovery using low tension viscous
water flood. An example of a commercially available material
described as being useful was ENORDET IOS 1720, a product of
Shell Oil Company identified as a sulfonated C17_20 internal
olefin sodium salt. This material has a low degree of
branching.
Summary of the Invention
In an embodiment, hydrocarbons may be produced from a
hydrocarbon containing formation by a method that includes
treating at least a portion of the hydrocarbon containing
formation with a hydrocarbon recovery composition. In
certain embodiments, at least a portion of the hydrocarbon
containing formation may be oil wet. In some embodiments, at
least a portion of the hydrocarbon formation may include low
salinity water. In other embodiments, at least a portion of
the hydrocarbon containing formation may exhibit an average
temperature of greater than 30 C, even greater than 60 C.
Fluids, substances or combinations thereof may be added to at
least a portion of the hydrocarbon containing formation to
aid in mobilizing hydrocarbons to one or more production
wells in certain embodiments.
In one embodiment, a hydrocarbon recovery composition
may include a branched internal olefin sulfonate-containing
surfactant. The branched internal olefin sulfonate may have
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an average carbon number of at least 15 or it may range from
15 to 26. As used herein, the phrase "carbon number" refers
to the total number of carbons in a molecule. In certain
embodiments, the average carbon number of the branched
internal olefin sulfonate may range from 15 to 18 or from 17
to 20. In other embodiments, the average carbon number of
the branched internal olefin sulfonate may range from 20 to
24. The average carbon number may be determined by NMR
analysis. The average number of branches per molecule of the
branched internal olefin sulfonate may be at least 0.8 in
some embodiments. Branches on the branched internal olefin
sulfonate may include, but are not limited to, methyl and/or
ethyl branches. In some embodiments, the average number of
branches per molecule may be at least 1 or at least 2. The
average number of branches per molecule is generally no more
than 3. The average number of branches per molecule may also
be determined by NMR analysis.
In an embodiment, a hydrocarbon containing composition
may be produced from a hydrocarbon containing formation. The
hydrocarbon containing composition may include any
combination of hydrocarbons, a branched internal olefin
sulfonate, methane, water, asphaltenes, carbon monoxide and
ammonia.
Brief Description of the Drawings
Advantages of the present invention will become apparent
to those skilled in the art with the benefit of the following
detailed description of embodiment and upon reference to the
accompanying drawings, in which:
FIG. 1 depicts an embodiment of treating a hydrocarbon
containing formation;
FIG. 2 depicts an embodiment of treating a hydrocarbon
containing formation;
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FIG. 3 depicts a graphical representation of interfacial
tension values at 5% NaCl;
FIG. 4 depicts a graphical representation of interfacial
tension values at 7% NaCl; and
FIG. 5 depicts a graphical representation of interfacial
tension values at 9% NaCl.
While the invention is susceptible to various
modifications and alternative forms, specific embodiments
thereof are shown by way of example in the drawings and will
herein be described in detail. It should be understood that
the drawing and detailed description thereto are not intended
to limit the invention to the particular form disclosed, but
on the contrary, the intention is to cover all modifications,
equivalents and alternatives falling within the spirit and
scope of the present invention as defined by the appended
claims.
Detailed Description of Embodiments
Hydrocarbons may be produced from hydrocarbon formations
through wells penetrating a hydrocarbon containing formation.
"Hydrocarbons" are generally defined as molecules formed
primarily of carbon and hydrogen atoms such as oil and
natural gas. Hydrocarbons may also include other elements,
such as, but not limited to, halogens, metallic elements,
nitrogen, oxygen and/or sulfur. Hydrocarbons derived from a
hydrocarbon formation may include, but are not limited to,
kerogen, bitumen, pyrobitumen, asphaltenes, oils or
combinations thereof. Hydrocarbons may be located within or
adjacent to mineral matrices within the earth. Matrices may
include, but are not limited to, sedimentary rock, sands,
silicilytes, carbonates, diatomites and other porous media.
A"formation" includes one or more hydrocarbon
containing layers, one or more non-hydrocarbon layers, an
overburden and/or an underburden. An "overburden" and/or an
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"underburden" includes one or more different types of
impermeable materials. For example, overburden/underburden
may include rock, shale, mudstone, or wet/tight carbonate
(i.e., an impermeable carbonate without hydrocarbons). For
example, an underburden may contain shale or mudstone. In
some cases, the overburden/underburden may be somewhat
permeable. For example, an underburden may be composed of a
permeable mineral such as sandstone or limestone. In some
embodiments, at least a portion of a hydrocarbon containing
formation may exist at less than or more than 1000 feet below
the earth's surface.
Properties of a hydrocarbon containing formation may
affect how hydrocarbons flow through an
underburden/overburden to one or more production wells.
Properties include, but are not limited to, porosity,
permeability, pore size distribution, surface area, salinity
or temperature of formation. Overburden/underburden
properties in combination with hydrocarbon properties, such
as, capillary pressure (static) characteristics and relative
permeability (flow) characteristics may effect mobilization
of hydrocarbons through the hydrocarbon containing formation.
Permeability of a hydrocarbon containing formation may
vary depending on the formation composition. A relatively
permeable formation may include heavy hydrocarbons entrained
in, for example, sand or carbonate. "Relatively permeable,"
as used herein, refers to formations or portions thereof,
that have an average permeability of 10 millidarcy or more.
"Relatively low permeability" as used herein, refers to
formations or portions thereof that have an average
permeability of less than 10 millidarcy. One darcy is equal
to about 0.99 square micrometers. An impermeable portion of
a formation generally has a permeability of less than 0.1
millidarcy. In some cases, a portion or all of a hydrocarbon
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portion of a relatively permeable formation may include
predominantly heavy hydrocarbons and/or tar with no
supporting mineral grain framework and only floating (or no)
mineral matter (e.g., asphalt lakes).
Fluids (e.g., gas, water, hydrocarbons or combinations
thereof) of different densities may exist in a hydrocarbon
containing formation. A mixture of fluids in the hydrocarbon
containing formation may form layers between an underburden
and an overburden according to fluid density. Gas may form a
top layer, hydrocarbons may form a middle layer and water may
form a bottom layer in the hydrocarbon containing formation.
The fluids may be present in the hydrocarbon containing
formation in various amounts. Interactions between the
fluids in the formation may create interfaces or boundaries
between the fluids. Interfaces or boundaries between the
fluids and the formation may be created through interactions
between the fluids and the formation. Typically, gases do
not form boundaries with other fluids in a hydrocarbon
containing formation. In an embodiment, a first boundary may
form between a water layer and underburden. A second
boundary may form between a water layer and a hydrocarbon
layer. A third boundary may form between hydrocarbons of
different densities in a hydrocarbon containing formation.
Multiple fluids with multiple boundaries may be present in a
hydrocarbon containing formation, in some embodiments. It
should be understood that many combinations of boundaries
between fluids and between fluids and the
overburden/underburden may be present in a hydrocarbon
containing formation.
Production of fluids may perturb the interaction between
fluids and between fluids and the overburden/underburden. As
fluids are removed from the hydrocarbon containing formation,
the different fluid layers may mix and form mixed fluid
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layers. The mixed fluids may have different interactions at
the fluid boundaries. Depending on the interactions at the
boundaries of the mixed fluids, production of hydrocarbons
may become difficult. Quantification of the interactions
(e.g., energy level) at the interface of the fluids and/or
fluids and overburden/underburden may be useful to predict
mobilization of hydrocarbons through the hydrocarbon
containing formation.
Quantification of energy required for interactions
(e.g., mixing) between fluids within a formation at an
interface may be difficult to measure. Quantification of
energy levels at an interface between fluids may be
determined by generally known techniques (e.g., spinning drop
tensiometer). Interaction energy requirements at an
interface may be referred to as interfacial tension.
"Interfacial tension" as used herein, refers to a surface
free energy that exists between two or more fluids that
exhibit a boundary. A high interfacial tension value (e.g.,
greater than 10 dynes/cm) may indicate the inability of one
fluid to mix with a second fluid to form a fluid emulsion.
As used herein, an "emulsion" refers to a dispersion of one
immiscible fluid into a second fluid by addition of a
composition that reduces the interfacial tension between the
fluids to achieve stability. The inability of the fluids to
mix may be due to high surface interaction energy between the
two fluids. Low interfacial tension values (e.g., less than
1 dyne/cm) may indicate less surface interaction between the
two immiscible fluids. Less surface interaction energy
between two immiscible fluids may result in the mixing of the
two fluids to form an emulsion. Fluids with low interfacial
tension values may be mobilized to a well bore due to reduced
capillary forces and subsequently produced from a hydrocarbon
containing formation.
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Fluids in a hydrocarbon containing formation may wet
(e.g., adhere to an overburden/underburden or spread onto an
overburden/underburden in a hydrocarbon containing
formation). As used herein, "wettability" refers to the
preference of a fluid to spread on or adhere to a solid
surface in a formation in the presence of other fluids.
Methods to determine wettability of a hydrocarbon formation
are described by Craig, Jr. in "The Reservoir Engineering
Aspects of Waterflooding", 1971 Monograph Volume 3, Society
of Petroleum Engineers, which is herein incorporated by
reference. In an embodiment, hydrocarbons may adhere to
sandstone in the presence of gas or water. An
overburden/underburden that is substantially coated by
hydrocarbons may be referred to as "oil wet." An
overburden/underburden may be oil wet due to the presence of
polar and/or heavy hydrocarbons (e.g., asphaltenes) in the
hydrocarbon containing formation. Formation composition
(e.g., silica, carbonate or clay) may determine the amount of
adsorption of hydrocarbons on the surface of an
overburden/underburden. In some embodiments, a porous and/or
permeable formation may allow hydrocarbons to more easily wet
the overburden/underburden. A substantially oil wet
overburden/underburden may inhibit hydrocarbon production
from the hydrocarbon containing formation. In certain
embodiments, an oil wet portion of a hydrocarbon containing
formation may be located at less than or more than 1000 feet
below the earth's surface.
A hydrocarbon formation may include water. Water may
interact with the surface of the underburden. As used
herein, "water wet " refers to the formation of a coat of
water on the surface of the overburden/underburden. A water
wet overburden/underburden may enhance hydrocarbon production
from the formation by preventing hydrocarbons from wetting
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the overburden/underburden. In certain embodiments, a water
wet portion of a hydrocarbon containing formation may include
minor amounts of polar and/or heavy hydrocarbons.
Water in a hydrocarbon containing formation may contain
minerals (e.g., minerals containing barium, calcium, or
magnesium) and mineral salts (e.g., sodium chloride,
potassium chloride, magnesium chloride). Water salinity
and/or water hardness of water in a formation may affect
recovery of hydrocarbons in a hydrocarbon containing
formation. As used herein "salinity" refers to an amount of
dissolved solids in water. "Water hardness," as used herein,
refers to a concentration of divalent ions (e.g., calcium,
magnesium) in the water. Water salinity and hardness may be
determined by generally known methods (e.g., conductivity,
titration). As used herein, "high salinity water" refers to
water that has greater than 30,000 ppm total dissolved solids
based on sodium chloride. As water salinity increases in a
hydrocarbon containing formation, interfacial tensions
between hydrocarbons and water may be increased and the
fluids may become more difficult to produce.
Low salinity water in a hydrocarbon containing formation
may enhance hydrocarbon production from a hydrocarbon
containing formation. Hydrocarbons and low salinity water
may form a well dispersed emulsion due to a low interfacial
tension between the low salinity water and the hydrocarbons.
Production of a flowable emulsion (e.g., hydrocarbons/water
mixture) from a hydrocarbon containing formation may be more
economically viable to a producer. As used herein, "low
salinity water" refers to water salinity in a hydrocarbon
containing formation that is less than 20,000 parts per
million (ppm) total dissolved solids based on sodium
chloride. In some embodiments, hydrocarbon containing
formations may include water with a salinity of less than
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13,000 ppm. In certain embodiments, hydrocarbon containing
formations may include water with a salinity ranging from
3,000 ppm to 10,000 ppm. In other embodiments, salinity of
the water in hydrocarbon containing formations may range from
5,000 ppm to 8,000 ppm.
A hydrocarbon containing formation may be selected for
treatment based on factors such as, but not limited to,
thickness of hydrocarbon containing layers within the
formation, assessed liquid production content, location of
the formation, salinity content of the formation, temperature
of the formation, and depth of hydrocarbon containing layers.
Initially, natural formation pressure and temperature may be
sufficient to cause hydrocarbons to flow into well bores and
out to the surface. Temperatures in a hydrocarbon containing
formation may range from 0 C to 300 C. As hydrocarbons are
produced from a hydrocarbon containing formation, pressures
and/or temperatures within the formation may decline.
Various forms of artificial lift (e.g., pumps, gas injection)
and/or heating may be employed to continue to produce
hydrocarbons from the hydrocarbon containing formation.
Production of desired hydrocarbons from the hydrocarbon
containing formation may become uneconomical as hydrocarbons
are depleted from the formation.
Mobilization of residual hydrocarbons retained in a
hydrocarbon containing formation may be difficult due to
viscosity of the hydrocarbons and capillary effects of fluids
in pores of the hydrocarbon containing formation. As used
herein "capillary forces" refers to attractive forces between
fluids and at least a portion of the hydrocarbon containing
formation. In an embodiment, capillary forces may be
overcome by increasing the pressures within a hydrocarbon
containing formation. In other embodiments, capillary forces
may be overcome by reducing the interfacial tension between
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fluids in a hydrocarbon containing formation. The ability to
reduce the capillary forces in a hydrocarbon containing
formation may depend on a number of factors, including, but
not limited to, the temperature of the hydrocarbon containing
formation, the salinity of water in the hydrocarbon
containing formation, and the composition of the hydrocarbons
in the hydrocarbon containing formation.
As production rates decrease, additional methods may be
employed to make a hydrocarbon containing formation more
economically viable. Methods may include adding sources of
water (e.g., brine, steam), gases, polymers, monomers or any
combinations thereof to the hydrocarbon formation to increase
mobilization of hydrocarbons.
In an embodiment, a hydrocarbon containing formation may
be treated with a flood of water. A waterflood may include
injecting water into a portion of a hydrocarbon containing
formation through injections wells. Flooding of at least a
portion of the formation may water wet a portion of the
hydrocarbon containing formation. The water wet portion of
the hydrocarbon containing formation may be pressurized by
known methods and a water/hydrocarbon mixture may be
collected using one or more production wells. The water
layer, however, may not mix with the hydrocarbon layer
efficiently. Poor mixing efficiency may be due to a high
interfacial tension between the water and hydrocarbons.
Production from a hydrocarbon containing formation may
be enhanced by treating the hydrocarbon containing formation
with a polymer and/or monomer that may mobilize hydrocarbons
to one or more production wells. The polymer and/or monomer
may reduce the mobility of the water phase in pores of the
hydrocarbon containing formation. The reduction of water
mobility may allow the hydrocarbons to be more easily
mobilized through the hydrocarbon containing formation.
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Polymers include, but are not limited to, polyacrylamides,
partially hydrolyzed polyacrylamide, polyacrylates, ethylenic
copolymers, biopolymers, carboxymethylcellulose, polyvinyl
alcohol, polystyrene sulfonates, polyvinylpyrrolidone, AMPS
(2-acrylamide-2-methyl propane sulfonate) or combinations
thereof. Examples of ethylenic copolymers include copolymers
of acrylic acid and acrylamide, acrylic acid and lauryl
acrylate, lauryl acrylate and acrylamide. Examples of
biopolymers include xanthan gum and guar gum. In some
embodiments, polymers may be crosslinked in situ in a
hydrocarbon containing formation. In other embodiments,
polymers may be generated in situ in a hydrocarbon containing
formation. Polymers and polymer preparations for use in oil
recovery are described in U.S. Patent No. 6,427,268 to Zhang
et al., entitled "Method For Making Hydrophobically
Associative Polymers, Methods of Use and Compositions;" U.S.
Patent No. 6,439,308 to Wang, entitled "Foam Drive Method;"
U.S. Patent No. 5,654,261 to Smith, entitled, "Permeability
Modifying Composition For Use In Oil Recovery;" U.S. Patent
No. 5,284,206 to Surles et al., entitled "Formation
Treating;" U.S. Patent 5,199,490 to Surles et al., entitled
"Formation Treating" and U.S. Patent No. 5,103,909 to
Morgenthaler et al., entitled "Profile Control In Enhanced
Oil Recovery," all of which are incorporated by reference
herein.
In an embodiment, a hydrocarbon recovery composition may
be provided to the hydrocarbon containing formation. In an
embodiment, a composition may include a branched internal
olefin sulfonate.
An internal olefin is an olefin whose double bond is
located anywhere along the carbon chain except at a terminal
carbon atom. A linear internal olefin does not have any
alkyl, aryl, or alicyclic branching on any of the double bond
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carbon atoms or on any carbon atoms adjacent to the double
bond carbon atoms. Typical commercial products produced by
isomerization of alpha olefins are predominantly linear and
contain a low average number of branches per molecule.
In one embodiment, the branched internal olefin may have
an average carbon number of at least 15 or the average carbon
number may range from 15 to 26. In certain embodiments, the
average carbon number of the branched internal olefin may
range from 15 to 18 or 17 to 20. In other embodiments, the
average carbon number of the branched internal olefin may
range from 20 to 24. The average carbon number may be
determined by NMR analysis.
In another embodiment, the average number of branches
per molecule of the branched internal olefin may be at least
0.8. In another embodiment, the amount the branches per
molecule in the branched internal olefin may be at least 1,
or at least 2. The average number of branches per molecule
is generally no more than 3. The reason for this is that 3
is generally the most number of branches that may be
incorporated with known technologies. The average number of
branches per molecule may also be determined by NMR analysis.
Without wishing to limit the scope of this invention in any
way, we theorize that the role of the branching in the
internal olefin within the ranges described above affects the
internal molecular interaction in the molecule, affects the
formation and type of micelles, prevents or discourages the
formation of liquid crystals, reduces interfacial tension
effectively, and allows emulsions to break up easier. This
is advantageous because these properties allow efficient oil
displacement and mobility within the pores of reservoir rock.
The internal olefins which are used to make the internal
olefin sulfonates of the present invention may be made by
skeletal isomerization. Suitable processes for making the
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branched internal olefins include those described in U.S.
Patents 5,510,306, 5,633,422, 5,648,584, 5,648,585,
5,849,960, and European Patent EP 0,830,315 Bl, all of which
are herein incorporated by reference in their entirety. A
hydrocarbon stream comprising at least one linear olefin is
contacted with a suitable catalyst, such as the catalytic
zeolites described in the aforementioned patents, in a vapor
phase at a suitable reaction temperature, pressure, and space
velocity. Generally, suitable reaction conditions include a
temperature of 200 to 650 C, an olefin partial pressure of
above 0.5 atmosphere, and a total pressure of 0.5 to 10.0
atmospheres or higher. Preferably, the internal olefins of
the present invention are made at a temperature in the range
of from 200 to 500 C at an olefin partial pressure of from
0.5 to 2 atmospheres.
It is generally known that internal olefins are more
difficult to sulfonate than alpha olefins (see "Tenside
Detergents" 22 (1985) 4, pp. 193-195). In the article
entitled "Why Internal Olefins are Difficult to Sulfonate,"
the authors state that by the sulfonation of various
commercial and laboratory produced internal olefins using
falling film reactors, internal olefins gave conversions of
below 90 percent and further they state that it was found
necessary to raise the S03:internal olefin mole ratio to over
1.6:1 in order to achieve conversions above 95 percent.
Furthermore, there resulting products were very dark in color
and had high levels of di- and poly-sulfonated prducts.
U.S. Patents 4,183,867 and 4,248,793, which are herein
incorporated by reference, disclose processes which may be
used to make the branched internal olefin sulfonates of the
invention. They are carried out in a falling film reactor
for the preparation of light color internal olefin
sulfonates. The amounts of unreacted internal olefins are
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between 10 and 20 percent and at least 20 percent,
respectively, in the processes and special measures must be
taken to remove the unreacted internal olefins. The internal
olefin suflonates containing between 10 and 20 percent and at
least 20 percent, respectively, of unreacted internal olefins
must be purified before being used. Consequently, the
preparation of internal olefin sulfonates having the desired
light color and with the desired low free oil content offer
substantial difficulty.
Such difficulties may be avoided by following the
process disclosed in European Patent EP 0,351,928 Bl, which
is herein incorporated by reference.
A process which may be used to make internal olefin
sulfonates for use in the present invention comprises
reacting in a film reactor an internal olefin as described
above with a sulfonating agent in a mole ratio of sulfonating
agent to internal olefin of 1:1 to 1.25:1 while cooling the
reactor with a cooling means having a temperaturee not
exceeding 35 C, directly neutralizing the obtained reaction
product of the sulfonating step and, without extracting the
unreacted internal olefin, hydrolyzing the neutralized
reaction product.
In the preparation of the sulfonates derived from
internal olefins, the internal olefins are reacted with a
sulfonating agent, which may be sulfur trioxide, sulfuric
acid, or oleum, with the formation of beta-sultone and some
alkane sulfonic acids. The film reactor is preferably a
falling film reactor.
The reaction products are neutralized and hydrolyzed.
Under certain circumstances, for instance, aging, the beta-
sultones are converted into gamma-sultones which may be
converted into delta-sultones. After neutralization and
hydrolysis, gamma-hydroxy sulfonates and delta-hydroxy
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sulfonates are obtained. A disadvantage of these two
sultones is that they are more difficult to hydrolyze than
beta-sultones. Thus, in most embodiments it is preferable to
proceed without aging. The beta sultones, after hydrolysis,
give beta-hydroxy sulfonates. These materials do not have to
be removed because they form useful surfactant structures.
The cooling means, which is preferably water, has a
temperature not exceeding 35 C, especially a temperature in
the range of from 0 to 25 C. Depending upon the
circumstances, lower temperatures may be used as well.
The reaction mixture is then fed to a neutralization
hydrolysis unit. The neutralization/hydrolysis is carried
out with a water soluble base, such as sodium hydroxide or
sodium carbonate. The corresponding bases derived from
potassium or ammonium are also suitable. The neutralization
of the reaction product from the falling film reactor is
generally carried out with excessive base, calculated on the
acid component. Generally, neutralization is carried out at
a temperature in the range of from 0 to 80 C. Hydrolysis
may be carried out at a temperature in the range of from 100
to 250 C, preferably 130 to 200 C. The hydrolysis time
generally may be from 5 minutes to 4 hours. Alkaline
hydrolysis may be carried out with hydroxides, carbonates,
bicarbonates of (earth) alkali metals, and amine compounds.
This process may be carried out batchwise, semi-
continuously, or continuously. The reaction is generally
performed in a falling film reactor which is cooled by
flowing a cooling means at the outside walls of the reactor.
At the inner walls of the reactor, the internal olefin flows
in a downward direction. Sulfur trioxide is diluted with a
stream of nitrogen, air, or any other inert gas into the
reactor. The concentration of sulfur trioxide generally is
between 2 and 4 percent by volume based on the volume of the
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carrier gas. In the preparation of internal olefin
sulfonates derived from the olefins of the present invention,
it is required that in the neutralization hydrolysis step
very intimate mixing of the reactor product and the aqueous
base is achieved. This may be done, for example, by
efficient stirring or the addition of a polar cosolvent (such
as a lower alcohol) or by the addition of a phase transfer
agent.
In one embodiment, the hydrocarbon recovery composition
may include a branched internal olefin sulfonate surfactant
as described above. In some embodiments, an amount of a
branched internal olefin sulfonate surfactant in a
composition may be greater than 10 wt.% of the total
composition. In an embodiment, an amount of a branched
internal olefin sulfonate surfactant in a hydrocarbon
recovery composition main range from 10 wt.% to 80 wt.% of
the total composition. An amount of a branched internal
olefin sulfonate surfactant in a composition may range from
30 wt.% to 60 wt.% of the total weight of the composition.
The remainder of the composition may include, but is not
limited to, water, low molecular weight alcohols, organic
solvents, alkyl sulfonates, aryl sulfonates, brine or
combinations thereof. Low molecular weight alcohols include,
but are not limited to, methanol, ethanol, propanol,
isopropyl alcohol, tert-butyl alcohol, sec-butyl alcohol,
butyl alcohol, tert-amyl alcohol or combinations thereof.
Organic solvents include, but are not limited to, methyl
ethyl ketone, acetone, lower alkyl cellosolves, lower alkyl
carbitols or combinations thereof.
The hydrocarbon recovery composition may interact with
hydrocarbons in at least a portion of the hydrocarbon
containing formation. Interaction with the hydrocarbons may
reduce an interfacial tension of the hydrocarbons with one or
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more fluids in the hydrocarbon containing formation. In
other embodiments, a hydrocarbon recovery composition may
reduce the interfacial tension between the hydrocarbons and
an overburden/underburden of a hydrocarbon containing
formation. Reduction of the interfacial tension may allow at
least a portion of the hydrocarbons to mobilize through the
hydrocarbon containing formation.
The ability of a hydrocarbon recovery composition to
reduce the interfacial tension of a mixture of hydrocarbons
and fluids may be evaluated using known techniques. In an
embodiment, an interfacial tension value for a mixture of
hydrocarbons and water may be determined using a spinning
drop tensiometer. An amount of the hydrocarbon recovery
composition may be added to the hydrocarbon/water mixture and
an interfacial tension value for the resulting fluid may be
determined. A low interfacial tension value (e.g., less than
1 dyne/cm) may indicate that the composition reduced at least
a portion of the surface energy between the hydrocarbons and
water. Reduction of surface energy may indicate that at
least a portion of the hydrocarbon/water mixture may mobilize
through at least a portion of a hydrocarbon containing
formation.
In an embodiment, a hydrocarbon recovery composition may
be added to a hydrocarbon/water mixture and the interfacial
tension value may be determined. An ultralow interfacial
tension value (e.g., less than 0.01 dyne/cm) may indicate
that the hydrocarbon recovery composition lowered at least a
portion of the surface tension between the hydrocarbons and
water such that at least a portion of the hydrocarbons may
mobilize through at least a portion of the hydrocarbon
containing formation. At least a portion of the hydrocarbons
may mobilize more easily through at least a portion of the
hydrocarbon containing formation at an ultra low interfacial
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tension than hydrocarbons that have been treated with a
composition that results in an interfacial tension value
greater than 0.01 dynes/cm for the fluids in the formation.
Addition of a hydrocarbon recovery composition to fluids in a
hydrocarbon containing formation that results in an ultra-low
interfacial tension value may increase the efficiency at
which hydrocarbons may be produced. A hydrocarbon recovery
composition concentration in the hydrocarbon containing
formation may be minimized to minimize cost of use during
production.
In an embodiment of a method to treat a hydrocarbon
containing formation, a hydrocarbon recovery composition
including a branched olefin sulfonate may be provided (e.g.,
injected) into hydrocarbon containing formation 100 through
injection well 110 as depicted in FIG. 1. Hydrocarbon
formation 100 may include overburden 120, hydrocarbon layer
130, and underburden 140. Injection well 110 may include
openings 112 that allow fluids to flow through hydrocarbon
containing formation 100 at various depth levels. In certain
embodiments, hydrocarbon layer 130 may be less than 1000 feet
below earth's surface. In some embodiments, underburden 140
of hydrocarbon containing formation 100 may be oil wet. Low
salinity water may be present in hydrocarbon containing
formation 100, in other embodiments.
A hydrocarbon recovery composition may be provided to
the formation in an amount based on hydrocarbons present in a
hydrocarbon containing formation. The amount of hydrocarbon
recovery composition, however, may be too small to be
accurately delivered to the hydrocarbon containing formation
using known delivery techniques (e.g., pumps). To facilitate
delivery of small amounts of the hydrocarbon recovery
composition to the hydrocarbon containing formation, the
hydrocarbon recovery composition may be combined with water
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and/or brine to produce an injectable fluid. An amount of a
hydrocarbon recovery composition injected into hydrocarbon
containing formation 100 may be less than 0.5 wt.% of the
total weight of the injectable fluid. In certain
embodiments, an amount of a hydrocarbon recovery composition
provided to a hydrocarbon containing formation may be less
than 0.3 wt.% of the total weight of injectable fluid. In
some embodiments, an amount of a hydrocarbon recovery
composition provided to a hydrocarbon containing formation
may be less than 0.1 wt.% of the total weight of injectable
fluid. In other embodiments, an amount of a hydrocarbon
recovery composition provided to a hydrocarbon containing
formation may be less than 0.05 wt.% of the total weight of
injectable fluid.
The hydrocarbon recovery composition may interact with
at least a portion of the hydrocarbons in hydrocarbon layer
130. The interaction of the hydrocarbon recovery composition
with hydrocarbon layer 130 may reduce at least a portion of
the interfacial tension between different hydrocarbons. The
hydrocarbon recovery composition may also reduce at least a
portion of the interfacial tension between one or more fluids
(e.g., water, hydrocarbons) in the formation and the
underburden 140, one or more fluids in the formation and the
overburden 120 or combinations thereof. In an embodiment, a
hydrocarbon recovery composition may interact with at least a
portion of hydrocarbons and at least a portion of one or more
other fluids in the formation to reduce at least a portion of
the interfacial tension between the hydrocarbons and one or
more fluids. Reduction of the interfacial tension may allow
at least a portion of the hydrocarbons to form an emulsion
with at least a portion of one or more fluids in the
formation. An interfacial tension value between the
hydrocarbons and one or more fluids may be altered by the
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hydrocarbon recovery composition to a value of less than 0.1
dyne/cm. In some embodiments, an interfacial tension value
between the hydrocarbons and other fluids in a formation may
be reduced by the hydrocarbon recovery composition to be less
than 0.05 dyne/cm. An interfacial tension value between
hydrocarbons and other fluids in a formation may be lowered
by the hydrocarbon recovery composition to less than 0.001
dyne/cm, in other embodiments. At least a portion of the
hydrocarbon recovery composition/hydrocarbon/fluids mixture
may be mobilized to production well 150. Products obtained
from the production well 150 may include, but are not limited
to, components of the hydrocarbon recovery composition (e.g.,
a long chain aliphatic alcohol and/or a long chain aliphatic
acid salt), methane, carbon monoxide, water, hydrocarbons,
ammonia, asphaltenes, or combinations thereof. Hydrocarbon
production from hydrocarbon containing formation 100 may be
increased by greater than 50% after the hydrocarbon recovery
composition has been added to a hydrocarbon containing
formation.
In certain embodiments, hydrocarbon containing formation
100 may be pretreated with a hydrocarbon removal fluid. A
hydrocarbon removal fluid may be composed of water, steam,
brine, gas, liquid polymers, foam polymers, monomers or
mixtures thereof. A hydrocarbon removal fluid may be used to
treat a formation before a hydrocarbon recovery composition
is provided to the formation. Hydrocarbon containing
formation 100 may be less than 1000 feet below the earth's
surface, in some embodiments. A hydrocarbon removal fluid
may be heated before injection into a hydrocarbon containing
formation 100, in certain embodiments. A hydrocarbon removal
fluid may reduce a viscosity of at least a portion of the
hydrocarbons within the formation. Reduction of the
viscosity of at least a portion of the hydrocarbons in the
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formation may enhance mobilization of at least a portion of
the hydrocarbons to production well 150. After at least a
portion of the hydrocarbons in hydrocarbon containing
formation 100 have been mobilized, repeated injection of the
same or different hydrocarbon removal fluids may become less
effective in mobilizing hydrocarbons through the hydrocarbon
containing formation. Low efficiency of mobilization may be
due to hydrocarbon removal fluids creating more permeable
zones in hydrocarbon containing formation 100. Hydrocarbon
removal fluids may pass through the permeable zones in the
hydrocarbon containing formation 100 and not interact with
and mobilize the remaining hydrocarbons. Consequently,
displacement of heavier hydrocarbons adsorbed to underburden
140 may be reduced over time. Eventually, the formation may
be considered low producing or economically undesirable to
produce hydrocarbons.
In certain embodiments, injection of a hydrocarbon
recovery composition after treating the hydrocarbon
containing formation with a hydrocarbon removal fluid may
enhance mobilization of heavier hydrocarbons absorbed to
underburden 140. The hydrocarbon recovery composition may
interact with the hydrocarbons to reduce an interfacial
tension between the hydrocarbons and underburden 140.
Reduction of the interfacial tension may be such that
hydrocarbons are mobilized to and produced from production
well 150. Produced hydrocarbons from production well 150 may
include, in some embodiments, at least a portion of the
components of the hydrocarbon recovery composition, the
hydrocarbon removal fluid injected into the well for
pretreatment, methane, carbon dioxide, ammonia, or
combinations thereof. Adding the hydrocarbon recovery
composition to at least a portion of a low producing
hydrocarbon containing formation may extend the production
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life of the hydrocarbon containing formation. Hydrocarbon
production from hydrocarbon containing formation 100 may be
increased by greater than 50% after the hydrocarbon recovery
composition has been added to hydrocarbon containing
formation. Increased hydrocarbon production may increase the
economic viability of the hydrocarbon containing formation.
The internal olefin sulfonate component of the
composition is thermally stable and may be used over a wide
range of temperature. To facilitate delivery of an amount of
the hydrocarbon recovery composition to the hydrocarbon
containing formation, the hydrocarbon composition may be
combined with water or brine to produce an injectable fluid.
Less than 0.5 wt% of the hydrocarbon recovery composition,
based on the total weight of injectable fluid, may be
injected into hydrocarbon containing formation 100 through
injection well 110. In certain embodiments, the
concentration of the hydrocarbon recovery composition
injected through injection well 110 may be less than 0.3
wt.%, based on the total weight of injectable fluid. In some
embodiments, the concentration of the hydrocarbon recovery
composition may be less 0.1 wt.% based on the total weight of
injectable fluid. In other embodiments, the concentration of
the hydrocarbon recovery composition may be less 0.05 wt.%
based on the total weight of injectable fluid.
Interaction of the hydrocarbon recovery composition with
at least a portion of hydrocarbons in the formation may
reduce at least a portion of an interfacial tension between
the hydrocarbons and underburden 140. Reduction of at least
a portion of the interfacial tension may mobilize at least a
portion of hydrocarbons through hydrocarbon containing
formation 100. Mobilization of at least a portion of
hydrocarbons, however, may not be at an economically viable
rate. In one embodiment, polymers may be injected into
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hydrocarbon formation 100 through injection well 110, after
treatment of the formation with a hydrocarbon recovery
composition, to increase mobilization of at least a portion
of the hydrocarbons through the formation. Suitable polymers
include, but are not limited to, CIBA ALCOFLOOD ,
manufactured by Ciba Specialty Additives (Tarrytown, New
York), Tramfloc manufactured by Tramfloc Inc. (Temple,
Arizona), and HE polymers manufactured by Chevron Phillips
Chemical Co. (The Woodlands, Texas). Interaction between the
hydrocarbons, the hydrocarbon recovery composition and the
polymer may increase mobilization of at least a portion of
the hydrocarbons remaining in the formation to production
well 150.
In some embodiments, a hydrocarbon recovery composition
may be added to a portion of a hydrocarbon containing
formation 100 that has an average temperature of from 0 to
150 C because of the high thermal stability of the internal
olefin sulfonate. In some embodiments, a hydrocarbon
recovery composition may be combined with at least a portion
of a hydrocarbon removal fluid (e.g. water, polymer
solutions) to produce an injectable fluid. Less than 0.5 wt%
of the hydrocarbon recovery composition, based on the total
weight of injectable fluid, may be injected into hydrocarbon
containing formation 100 through injection well 110 as
depicted in FIG. 2. In certain embodiments, a concentration
of the hydrocarbon recovery composition injected through
injection well 110 may be less than 0.3 wt.%, based on the
total weight of injectable fluid. In some embodiments, less
than 0.1 wt.% of the hydrocarbon recovery composition, based
on the total weight of injectable fluid, may be injected
through injection well 110 into hydrocarbon containing
formation 100. In other embodiments, less than 0.05 wt.% of
the hydrocarbon recovery composition, based on the total
24
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weight of injectable fluid, may be injected through injection
well 110 into hydrocarbon containing formation 100.
Interaction of the hydrocarbon recovery composition with
hydrocarbons in the formation may reduce at least a portion
of an interfacial tension between the hydrocarbons and
underburden 140. Reduction of at least a portion of the
interfacial tension may mobilize at least a portion of
hydrocarbons to a selected section 160 in hydrocarbon
containing formation 100 to form hydrocarbon pool 170. At
least a portion of the hydrocarbons may be produced from
hydrocarbon pool 170 in the selected section of hydrocarbon
containing formation 100.
In other embodiments, mobilization of at least a portion
of hydrocarbons to selected section 160 may not be at an
economically viable rate. Polymers may be injected into
hydrocarbon formation 100 to increase mobilization of at
least a portion of the hydrocarbons through the formation.
Interaction between at least a portion of the hydrocarbons,
the hydrocarbon recovery composition and the polymers may
increase mobilization of at least a portion of the
hydrocarbons to production well 150.
In some embodiments, a hydrocarbon recovery composition
may include an inorganic salt (e.g. sodium carbonate
(Na2CO3) , sodium chloride (NaCl), or calcium chloride
(CaClz)). The addition of the inorganic salt may help the
hydrocarbon recovery composition disperse throughout a
hydrocarbon/water mixture. The enhanced dispersion of the
hydrocarbon recovery composition may decrease the
interactions between the hydrocarbon and water interface.
The decreased interaction may lower the interfacial tension
of the mixture and provide a fluid that is more mobile.
In another embodiment, a hydrocarbon recovery
composition may include polymers and/or monomers. As
CA 02672632 2009-06-12
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described above, polymers may be used to increase
mobilization of at least a portion of the hydrocarbons
through the formation. Suitable polymers have been described
previously. Interaction between the hydrocarbons and the
polymer containing hydrocarbon recovery composition may
increase mobilization of at least a portion of the
hydrocarbons remaining in the formation.
EXAMPLES
Example 1
Hydrocarbon recovery compositions including
branched internal olefin sulfonates were prepared and
interfacial tension measurements were compared for a variety
of different compositions. Three different branched C15_18
internal olefins were made (25731-77-2 with a medium amount
of branching, 25731-78-2 with a higher amount of branching
and 25889-113 which was intended to be representative of
mostly linear internal olefins used previously for
hydrocarbon recovery). These internal olefins were
characterized by NMR analysis. The average number of
branches per molecule analyses are shown in Table 1. The NMR
analysis was carried out as described below.
This method describes the characterization of branched
olefins. The proton nuclear magnetic resonance (1H NMR)
method assays the various types of olefinic units and reports
the average number of branches per molecule, and the number
of aliphatic and olefinic branches per chain.
Typically, 0.1 ml of sample is dissolved in 1.0 ml of
deuterated chloroform and transferred to a high-grade 5 mm
NMR tube. The Hl-NMR data is acquired, processed and
branching and olefin analyses are computed as detailed below.
The method assumes that the sample contains only acyclic,
hydrocarbon, mono-olefins. The method is not intended to be
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used in the presence of dienes, naphthenes, paraffins,
aromatics, or heteroatom-containing species. It is assumed
that the olefins are of sufficient molecular weight and low
volatility that the sample may be easily handled at room
temperature without loss of material. It is assumed that the
olefins are not so large that they will not readily dissolve
in chloroform. Long, linear, wax-like molecules might not be
readily soluble in chloroform at room temperature. Another
solvent may be necessary. The chloroform solvent used for
dissolution of the sample should be dry since water in the
solvent will interfere with the analysis.
APPARATUS
. Varian Inova 500 NMR spectrometer (or equivalent)
equipped with a 5mm 'H-only or 13C/1H dual probe.
= Denville Scientific Pipete-Mate Pipettors (1000 ul and
100ul). Denville Scientific Company.
= 5-mm high grade NMR sample tubes with plastic caps.
Kontes Glass Company.
OPERATING CONDITIONS
The following acquisition parameters are used:
1H tip angle: 1.5 usec. (12 degrees)
Delay between acquisitions: 5 sec. (dl=4.0 sec and at =1.0 sec)
Spectral width: 8 kHz
Buffer Size: 16 K complex
Number of scans: 64
SAMPLE PREPARATION
0.1 ml of sample is added to 1.0 ml deuterated
chloroform and then transferred to a 5 mm NMR tube.
A quality control sample may be prepared the same way
and run alongside each sample set to check the precision.
CALCULATING & REPORTING RESULTS
Aliphatic Analysis
ch db = I2 .80-2 .35 (methine next to double bond)
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ch2db = I2.3s-i.7s / 2 (methylene next to double bond)
ch3db = Ii.7s-i.si / 3 (methyl next to double bond)
subs = ch db + ch2 db + ch3 db
ch3 = Il.oi-o.2o / 3 (methyl not next to double bond)
ch = ch3 - 2 ch db - ch2 db (methine not next to double bond)
ch2 = (Il.sl-l.ol - ch) / 2 (methylene not next to double bond)
Olefinic Analysis
vinyl = Is.9o-s.7o (vinyl olefin)
disub = Is.7o-s.2o / 2 (disubstituted olefin)
f I5.02-9.75 > 2 Is.9o-s.7o (trisubstituted olefin)
trisub - Is.2o-5.02 + I5.0 2-4.75 - 2 * I5.90-5.70
else
trisub = Is.2o-5.02
vdene = I9.75_9.58 / 2 (vinylidene olefin)
branch = 2 * disub + 3 * trisub + vinyl + 2 vdene
tetra = (subs - branch) / 4 (tetrasubstituted olefin)
if tetra < 0 then tetra = 0 endif
olef = disub + trisub + tetra + vinyl + vdene (sum of all olefins)
where Im_n refers to the integral between m and n ppm.
Based on the above quantities, the following may be computed:
olefb = (trisub + vdene + 2 * tetra)/ olef (olefin branches per chain)
alip b= (ch db + ch) / olef (aliphatic branches per chain)
c no = 2 + (subs + ch3 + ch2 + ch) / olef (carbons per chain)
di = 100 * disub / olef (% disubstituted olefin)
tri = 100 * trisub / olef (% trisubstituted olefin)
tet = 100 * tetra / olef (% tetrasubstituted olefin)
vi = 100 * vinyl / olef (% vinyl olefin)
vd = 100 * vdene / olef (% vinylidene olefin)
The quantities olef b, alip b, and c no listed above are
reported.
olef_b = (olefin branches per chain)
alip_b = (aliphatic branches per chain)
c no = (carbons per chain)
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Table 1
NMR Analysis
Medium Branching
Sample 25731-77-2 C1518 10
Branch on Olefin 0.41
Branch on Aliphatic 0.74
Total Branches 1.15
Disub Olefin 66.5
Trisub Olefin 23.0
Tetrasub Olefin 8.1
Vinyl Olefin 0.8
Vinylidene Olefin 1.6
High Branching C1518 10
Sample 25731-78-2
Branch on Olefin 0.50
Branch on Aliphatic 1.61
Total Branches 2.11
Disub Olefin 52.4
Trisub Olefin 41.2
Tetrasub Olefin 2.9
Vinyl Olefin 0.5
Vinylidene Olefin 3.1
Comparative C1518 10
Sample 25889-113
Branch on Olefin 0.06
Branch on Aliphatic 0.22
Total Branches 0.28
Disub Olefin 90.2
Trisub Olefin 5.1
Tetrasub Olefin 0.2
Vinyl Olefin 4.0
Vinylidene Olefin 0.5
These branched internal olefins were sulfonated and
tested as described below. The comparative 0.28 mostly
linear sulfonated IO was made from sample 25889-113. The
1.15 branched sulfonated IO was made from sample 25731-77-2.
The 2.11 branched sulfonated IO was made from sample 25731-
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78-2. The 0.89 branched sulfonated IO was made by blending
the 0.28 mostly linear sulfonated IO with the 2.11 branched
sulfonated IO in a 2:1 ratio (0.666 x 0.28 + 0.333 x 2.11 =
0.89 branches per molecule).
Compositions and interfacial tension measurements are
tabulated in Table 2. The compositions described in Table 2 were
made by mixing the hydrocarbon recovery composition with brine at
the desired salinity level to obtain a 0.5% active solution.
Interfacial tension values for the hydrocarbon/
hydrocarbon recovery composition/water mixtures were
determined using a University of Texas model spinning drop
tensiometer. A four microliter (pL) drop of n-dodecane
hydrocarbon was placed into a glass capillary tube that
contained a hydrocarbon recovery composition/brine solution to
provide a brine-to-hydrocarbon volume ratio of 400. The tube
was placed into a spinning drop apparatus and then capped.
The motor was turned on rapidly to rotate the tube to create a
cylindrical drop within the tube (e.g. 6 to 12 ms/rev). The
drop length may be greater than or equal to 4 times the width
of a drop. The capillary tube and drop were heated to various
temperatures (at and above 25, 50, 75 and 98 C). The drop was
video taped for later replay for measurement of the drop
dimensions and calculation of the interfacial tension between
the drop and the composition/brine using an Optima System.
The time range of the measurements was from about 0.1 to about
1.0 hours to achieve drop equilibrium.
The Krafft temperatures were measured by determining the
minimum temperature at which no obvious crystals were
observed in the 0.5% hydrocarbon recovery composition
(denoted initial) and the minimum temperature at which the
compositions became completely soluble in the brine phase as
indicated by clarity of the solution (denoted final). The
results of these measurements are shown in Table 3.
CA 02672632 2009-06-12
WO 2008/079852 PCT/US2007/088069
N N O 6l ~I
HA
, N N N i
oW rl U . rl rl O
0) O = O
N 6 p , p
O
U N ~ 6l ~
N ch ul r ~o
= ~) O i
oW ri U O O O O
01 G
O O O
?4
Ul c`') Ln r N
N Qo rn rn un
oW CO 0
= O O O
O
O O O O
?4
Ul r N i lD
'c~
(D N CO co r
cc) N O rl
oW N U . .
o ~ O O O O
E
W v) v co I'D u-)
m ~ ~ ~
cn oW ~ U O O O O
W N~ O O O O
N U l9 HLO co
H N co ~I m N
co Lo .1'- rl O rl O
o\0 ~ U . . p
~ P. ~ O O = O
o
N Q
~n ~r~lo Ln
~ a ~ H N Lo a
u) ~ ~ . IZT Qo Ln
or co 0 O O co ~l
r p r,
. = O.
o
N ~ O
W
~ ~ ~ ~ m Ln
W u) CO co N
rl
co ,' N Ln co
a oW N U = N~' N
= G O = (`") r
O 6 O rl rl
O O
cn rn ~ r r vZ N ~ ~ ~ ~
W H~ rl O N C`')
E oW ~ U . O O O
ifl = C p
~l N (d o 0 0
H
~
rf) u-) ur7 m u-)
N 6l 6l O rl
W Ln .s:.' ~o c~ Lf)
oW ~ U O O O
Lo~ O o 0 0
H y{
~
~ cc) Ls' H N
6l Ln 6l un
o\O co U -1 N O r
O(0 O O O
A O
~ N r N ~
N N c`')
CO ,I" rl H l9 CO
oW cV 0 o-~ G) N G)
Lo 0 N N M
~4 O O O O
N
rI
U
+,J
rt
7 y ULn O n co
0 NLn r 6
0\0
Ln N
E-E
31
CA 02672632 2009-06-12
WO 2008/079852 PCT/US2007/088069
o00o rn rn rn n ~~ rn rn
-~ ~rnrn~ rnrn~~ A A rnco
~
0
m
c,.,
(D ro H o o Ln o Ln Ln o o '-n Ln Ln o
4-) ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ rn ~
n n
H ~
LH
-
LH
ci:5
ro urn ~
LO rl N
32
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It may be seen by analyzing Tables 2 and 3 and reviewing
Figures 3, 4 and 5 that for the systems chosen that branching
at 1 or about 2 average number of branches per molecule
provides lower interfacial tensions at optimum salinity and
temperature conditions than those of the less branched systems
although branching at about 0.9 average number of branches per
molecule provided lower interfacial tension at a few isolated
conditions. The comparative mostly linear internal olefin
sulfonate (average number of branches per molecule of 0.28)
yielded the highest interfacial tensions at most conditions.
These results support the contention that branching in an
internal olefin sulfate molecule may result in improved
performance for enhanced oil recovery. It is also seen that
branching tends to lower the Krafft temperatures slightly and
thus increases the solubility of the surfactants which is also
an advantage in enhanced oil recovery.
Further modifications and alternative embodiments of
various aspects of the invention may be apparent to those skilled
in the art in view of this description. Accordingly, this
description is to be construed as illustrative only and is for
the purpose of teaching those skilled in the art the general
manner of carrying out the invention. It is to be understood
that the forms of the invention shown and described herein are to
be taken as the presently preferred embodiments. Elements and
materials may be substituted for those illustrated and described
herein, parts and processes may be reversed, and certain features
of the invention may be utilized independently, all as would be
apparent to one skilled in the art after having the benefit of
this description to the invention. Changes may be made in the
elements described herein without departing from the spirit and
scope o the invention as described in the following claims. In
addition, it is to be understood that features described herein
independently may, in certain embodiments, be combined.
33
