Note: Descriptions are shown in the official language in which they were submitted.
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SYSTEM AND METHOD FOR
ENHANCING OIL RECOVERY FROM A SUBTERRANEAN RESERVOIR
CROSS-REFERENCE TO A RELATED APPLICATION
[001] The present application for patent claims the benefit of United
States Provisional
Application bearing Serial No. 61/425,517, filed on December 21, 2010, which
is
incorporated by reference in its entirety.
TECHNICAL FIELD
[002] The present invention generally relates to a system and method for
enhancing oil
recovery from a subterranean reservoir, and more particularly, to a system and
method
utilizing electrokinetic-induced migration to enhance the distribution of an
enhanced oil
recovery fluid within a subterranean reservoir.
BACKGROUND
[003] Reservoir systems, such as petroleum reservoirs, typically contain
fluids including
water and a mixture of hydrocarbons such as oil and gas. Primary, secondary,
and tertiary
recovery processes can be utilized to produce the hydrocarbons from the
reservoir.
[004] In a primary recovery process, hydrocarbons are displaced from a
reservoir due to
the high natural differential pressure between the reservoir and the
bottomhole pressure
within a wellbore. The reservoir's energy and natural forces drive the
hydrocarbons
contained in the reservoir into the production well and up to the surface.
Artificial lift
systems, such as sucker rod pumps, electrical submersible pumps or gas-lift
systems, are
often implemented in the primary production stage to reduce the bottomhole
pressure within
the well. Such systems increase the differential pressure between the
reservoir and the
wellbore intake; thus, increasing hydrocarbon production. However, even with
the use of
such artificial lift systems only a small fraction of the original-oil-in-
place (00IP) is typically
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recovered in a primary recovery process. This is the case because the
reservoir pressure and
the differential pressure between the reservoir and the wellbore intake
declines overtime due
to production. For example, typically only about 10-20% of the 00IP can be
produced
before primary recovery reaches its limit - either when the reservoir pressure
is too low that
the production rates are not economical, or when the proportions of gas or
water in the
production stream are too high.
[005] To address the declining recoveries and increase the production life
of the reservoir,
secondary recovery processes can be used. Typically in these processes, fluids
such as water
or gas are injected into the reservoir to maintain reservoir pressure and
drive the
hydrocarbons to production wells. Secondary recovery processes have already
converted
billions of barrels of proven oil resources to reserves, and typically produce
an additional
10-30% of 00IP to that produced during primary recovery. Additional actions
such as
optimizing rate allocation, mechanical and chemical conformance control,
infill drilling, well
conversion, pattern realignment, or a combination thereof, can also be taken
to improve the
sweep efficiency in these flooding processes.
[006] Despite these efforts, a significant amount of the 00IP still remains
trapped in the
reservoir as conventional oil recovery methods (primary and secondary)
typically only extract
up to about half the oil present in a reservoir. As oil reservoirs age, oil
recovery becomes
increasingly difficult. The hydraulic injection of fluid results in channeling
of the fluid
through higher permeability features, such as fractures or coarser lenses
present within the
reservoir, leaving other zones of the reservoir unswept. Furthermore, the
unrecovered oil in
the swept zones is typically in the form of discontinuous blobs and globules
trapped by
capillary pressure within the porous framework of the reservoir soil and rock.
Tertiary
recovery processes such as chemical flooding (e.g., surfactant, solvent or
oxidant injection),
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gas miscible displacement (e.g., carbon dioxide or hydrocarbon injection),
thermal recovery
(e.g., steam injection or in-situ combustion), microbial flooding, or a
combination thereof,
have been used in attempt to further increase recovery from these depleted
reservoirs.
[007] Chemical flooding, which as used herein refers to an injection
process using a
chemical or mixture of chemicals to enhance oil recovery typically by reducing
interfacial
tensions and fluid viscosity in the reservoir, currently contributes to a
small portion of tertiary
production. Despite recent advances in generating new chemical formulations
that have
shown to successfully release trapped oil globules from the porous framework
of the
reservoir, good contact between the injected chemical and oil is typically
limited to
preferential flow channels due to channeling of flow through high conductivity
zones.
Accordingly, the injected chemicals typically do not contact the majority of
trapped oil in the
reservoir.
[008] Polymer injections can supplement chemical floods (or water floods)
by acting as a
viscosity modifier, thereby reducing channeling and helping to mobilize or
drive the oil to a
production well. In some embodiments, the polymer can be used to block the
high
conductivity zones or permeability features, thereby diverting the injected
fluids or chemicals
into areas that have not previously been subjected to flow. However, the
benefits of polymer
injection are typically minimal because the radius of influence around a well
where the
polymer can move is limited leaving the flow dynamics throughout the majority
of the
reservoir unchanged. Therefore, the increased oil recovery resulting from a
chemical flood
has typically been low, such as less than about 1 percent. Due to the cost of
injecting
chemicals, this low increase in oil recovery is rarely cost effective even
though a slight
increase in oil recovery efficiency producing an additional 1 percent of
residual oil can
represent billions of dollars.
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[009] A main limitation of water or chemical floods is that conventional
well-injection
techniques do not allow for wide-spread contact between the injected fluid and
the trapped
oil. A way to evenly distribute the injected fluid throughout a larger portion
of the reservoir
is needed for enhancing oil recovery.
SUMMARY
[010] A method is disclosed for enhancing hydrocarbon recovery in
subterranean
reservoirs. An injection well and a production well extend into a hydrocarbon
bearing zone
of the subterranean reservoir and are in fluid communication therewith. The
method includes
injecting an enhanced oil recovery fluid into the hydrocarbon bearing zone
through the
injection well. An electric field is generated through at least a portion of
the hydrocarbon
bearing zone to induce electrokinetic migration of the enhanced oil recovery
fluid.
Hydrocarbons from the hydrocarbon bearing zone of the subterranean reservoir
are recovered
through the production well.
[011] In one or more embodiments, the electric field is generated by
emitting a direct
current between a pair of electrodes having opposite charges and being spaced
apart from one
another within the hydrocarbon bearing zone. In one or more embodiments, the
electric field
is generated by emitting a direct current between a first electrode coupled to
the injection
well and a second electrode coupled to the production well. In one or more
embodiments, the
electric field is generated by emitting a direct current less than about 50
volts per meter
between a pair of electrodes. In one or more embodiments, the direct current
is periodically
pulsed. In one or more embodiments, the polarity of the pair of electrodes is
periodically
reversed.
[012] In one or more embodiments, the electric field is generated by
emitting a direct
current between a plurality of electrodes interspersed within the hydrocarbon
bearing zone.
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The direct current emitted between one or more of the plurality of electrodes
can be adjusted
such that the enhanced oil recovery fluid migrates to unswept areas of the
hydrocarbon
bearing zone.
[013] In one or more embodiments, the enhanced oil recovery fluid comprises
a polar
fluid. In one or more embodiments, the enhanced oil recovery fluid has a net
total charge. In
one or more embodiments, the enhanced oil recovery fluid comprises water. In
one or more
embodiments, the enhanced oil recovery fluid comprises a surfactant. In one or
more
embodiments, the enhanced oil recovery fluid comprises an oxidant. In one or
more
embodiments, the enhanced oil recovery fluid alters a physical property of a
formation matrix
of the hydrocarbon bearing zone.
[014] According to another aspect of the present invention, a method is
disclosed for
enhancing hydrocarbon recovery in subterranean reservoirs. The method includes
providing
an injection well and a production well that extend into and are in fluid
communication with a
hydrocarbon bearing zone of a subterranean reservoir and providing a pair of
electrodes
having opposite charges and being spaced apart from one another within the
hydrocarbon
bearing zone. An enhanced oil recovery fluid is injected into the hydrocarbon
bearing zone
through the injection well. A direct current is emitted between the pair of
electrodes to
induce electrokinetic migration of the enhanced oil recovery fluid.
Hydrocarbons are
recovered from the hydrocarbon bearing zone of the subterranean reservoir
through the
production well.
[015] In one or more embodiments, the direct current is less than about 50
volts per meter.
In one or more embodiments, the direct current is periodically pulsed. In one
or more
embodiments, the polarity of the pair of electrodes is periodically reversed.
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[016] In one or more embodiments, an electrode of the pair of electrodes is
coupled to the
injection well. In one or more embodiments, an electrode of the pair of
electrodes is coupled
to the production well.
[017] In one or more embodiments, the enhanced oil recovery fluid comprises
water. In
one or more embodiments, the enhanced oil recovery fluid comprises a
surfactant. In one or
more embodiments, the enhanced oil recovery fluid comprises an oxidant. In one
or more
embodiments, the enhanced oil recovery fluid alters a physical property of a
formation matrix
of the hydrocarbon bearing zone.
[018] According to another aspect of the present invention, a method is
disclosed for
enhancing hydrocarbon recovery in subterranean reservoirs. The method includes
providing
an injection well and a production well that extend into a hydrocarbon bearing
zone of a
subterranean reservoir and are in fluid communication therewith. A plurality
of electrodes
are interspersed within the hydrocarbon bearing zone of a subterranean
reservoir. An
enhanced oil recovery fluid is injected into the hydrocarbon bearing zone
through the
injection well. A direct current is emitted between the plurality of
electrodes to induce
electrokinetic migration of the enhanced oil recovery fluid. Hydrocarbons from
the
hydrocarbon bearing zone of the subterranean reservoir are recovered through
the production
well.
[019] In one or more embodiments, the direct current emitted between one or
more of the
plurality of electrodes is adjusted such that the enhanced oil recovery fluid
migrates to
unswept areas of the hydrocarbon bearing zone.
BRIEF DESCRIPTION OF THE DRAWINGS
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[020] Figure 1 is a schematic sectional view of an example oil recovery
system that
includes a reservoir that is in fluid communication with an injection well and
a production
well during enhanced oil recovery operations, in accordance with an embodiment
of the present
invention.
[021] Figure 2 is a schematic sectional view of an example oil recovery
system that
includes a reservoir that is in fluid communication with an injection well and
a production
well equipped with a pair of electrodes during enhanced oil recovery
operations, in
accordance with an embodiment of the present invention.
DETAILED DESCRIPTION
[022] The system and method described herein are directed to enhancing oil
recovery of
reservoirs, particularly by maximizing the distribution of an enhanced oil
recovery fluid
within a reservoir via electrokinetic-induced migration. A general treatise on
conventional
enhanced oil recovery is, "Basic Concepts in Enhanced Oil Recovery Processes,"
edited by
M. Baviere (published for SCI by Elsevier Applied Science, London and New
York, 1991).
[023] Referring to Figure 1, subterranean reservoir 10 includes a plurality
of rock layers
including hydrocarbon bearing strata or zone 11. Injection well 13 extends
into hydrocarbon
bearing zone 11 of subterranean reservoir 10 such that injection well 13 is in
fluid
communication with hydrocarbon bearing zone 11. Subterranean reservoir 10 can
be any
type of subsurface formation in which hydrocarbons are stored, such as
limestone, dolomite,
oil shale, sandstone, or a combination thereof Production well 15 is also in
fluid
communication with hydrocarbon bearing zone 11 of subterranean reservoir 10 in
order to
receive hydrocarbons therefrom. Production well 15 is positioned a
predetermined lateral
distance away from injection well 13. For example, production well 15 can be
positioned
between 100 feet to 10,000 feet away from injection well 13. As will be
readily appreciated
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by those skilled in the art, there can be additional injection wells 13 and
production wells 15,
such that production wells 15 are spaced apart from injection wells 13 at
predetermined
locations to optimally receive the hydrocarbons being pushed due to injections
from injection
wells 13 through hydrocarbon bearing zone 11 of subterranean reservoir 10.
Furthermore,
while not shown in Figure 1, injection well 13 and production well 15 can
deviate from the
vertical position such that in some embodiments, injection well 13 and/or
production well 15
can be a directional well, horizontal well, or a multilateral well.
[024] As will be described in further detail below, in operation, an
enhanced oil recovery
(EOR) fluid 17 is injected into hydrocarbon bearing zone 11 of subterranean
reservoir 10
through injection well 13. The EOR fluid 17 comprises a polar fluid or a fluid
having a net
total charge. For example, EOR fluid 17 can be water as it has an uneven
distribution of
electron density and therefore, comprises a polar molecule. In one or more
embodiments,
EOR fluid 17 comprises a polar gas. In one or more embodiments, EOR fluid 17
comprises a
chemical or mixture of chemicals having a net total charge. For example, EOR
fluid 17 can
comprise oxidizing agents (e.g., peroxides, hypohalites, ozone, persulphates,
permanganates),
reducing agents (e.g. nascent hydrogen, organic acids), surfactants/co-
surfactants,
solvents/co-solvents, polymers, or a combination thereof.
[025] In some embodiments, EOR fluid 17 alters the physical properties of
the formation
or rock matrix of hydrocarbon bearing zone 11 such as by increasing the
effective porosity
and permeability of the matrix so that the hydrocarbons are more accessible
and recoverable.
For example, oil shale often contains large amounts of tightly bonded
carbonates and pyrites
that can be dissolved using acid, such as thiobacillus. Depletion of these
carbonate minerals
from the shale matrix, such as through bioleaching, results in newly formed
cavities that
effectively increases the porosity (e.g., from less than 0.5% to about 4 or
5%) and
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permeability of the oil shale, thereby enhancing recovery of the hydrocarbons.
In some
embodiments, EOR fluid 17 penetrates into pore spaces of the formation
contacting the
trapped oil globules such that the oil trapped in the pore spaces of the
reservoir rock matrix is
released. For example, EOR fluid 17 can be a surface active agent reducing the
interfacial
tension between the water and oil in the subterranean reservoir such that the
oil trapped in the
pore spaces of the reservoir rock matrix is released.
[026] Referring to Figure 1, an electric field is generated through at
least a portion of the
hydrocarbon bearing zone 11 to induce electrokinetic migration of EOR fluid
17.
Electrokinetic induced migration allows for the EOR fluid 17 to contact
portions of the
reservoir that previously were unswept due to the limitations of traditional
hydraulic
injection, thereby enhancing recovery of hydrocarbons from hydrocarbon bearing
zone 11 of
subterranean reservoir 10 through production well 15. The electric field is
generated by
electrodes that impose a low voltage direct current through at least the
portion of the
hydrocarbon bearing zone 11 between injection well 13 and production well 15.
[027] In one embodiment, one or more electrodes are placed in communication
with
injection well 13 such that the electrically charged injection well acts as
either an anode or a
cathode. Similarly, one or more electrodes are placed in communication with
production
well 15 such that the electrically charged production well acts as an opposing
cathode or
anode to injection well 13. The respective charges create an electric current
in the reservoir
fluids contained within hydrocarbon bearing zone 11 of subterranean reservoir
10, which
induces electrokinetic migration of EOR fluid 17 such that it is distributed
within
hydrocarbon bearing zone 11 of subterranean reservoir 10. One skilled in the
art will
appreciate that additional electrodes can be placed in locations other than in
communication
with injection well 13 and production well 15, such that an electric field is
created that is
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capable of directing EOR fluid 17 to a plurality of areas of within
subterranean reservoir 10.
In some embodiments, the electrodes are positioned directly within the
hydrocarbon bearing
zone 11. In some embodiments, the electrodes are positioned at locations above
or below
hydrocarbon bearing zone 11 such as within rock layers adjacent to hydrocarbon
bearing
zone 11.
[028] The electrodes can be made of any conductive material such as carbon
or graphite.
Electrodes of carbon and graphite are generally more resistant to corrosion.
In another
embodiment, the electrodes are conductive polymeric materials or intrinsically
conducting
polymers (ICPs), which also inhibit corrosion. In one embodiment, the
electrodes create a
low voltage direct current of less than about 10 volts per meter (Vim). In
another
embodiment, the electrodes create a low voltage direct current of less than
about 20 volts per
meter (Vim). In another embodiment, the electrodes create a low voltage direct
current of
less than about 50 volts per meter (Vim). In some embodiments, the low voltage
direct
current is periodically pulsed or reversed, which can help prevent buildup of
acidic conditions
at the cathode. In one embodiment, the frequency of pulsing and/or reversal of
polarity is
less than about a second. In another embodiment, the frequency of pulsing
and/or reversal of
polarity is greater than about a minute, such as ranging from periods of
minutes to days.
[029] Figure 2 shows an embodiment of the present invention in which
injection well 13
and production well 15 are equipped with a pair of electrodes 21, 23,
respectively. A power
source 25 is provided such that the positive and negative terminals are
connected to
electrodes 21, 23. The size of the power source is dependent on the size and
characteristics
of the reservoir. The size of the power source is however, large enough to
sufficiently
produce a low voltage direct current through at least a portion of the
hydrocarbon bearing
zone 11. In one embodiment, the positive terminal of power source 25 is in
communication
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with electrode 21 such that electrode 21, which is coupled to injection well
13, acts as an
anode. The negative terminal of power source 25 is in communication with
electrode 23 such
that electrode 23, which is coupled to production well 15, acts as a cathode.
In another
embodiment, the positive and negative terminals of the power source 25 are
switched such
that the positive terminal of power source 25 is in communication with
electrode 23 and the
negative terminal of power source 25 is in communication with electrode 21.
Here, injection
well 13 acts as the cathode and production well 15 acts as the anode. In
either embodiment,
the pair of electrodes 21, 23 generates an electric field through at least a
portion of the
hydrocarbon bearing zone 11 to induce electrokinetic migration of EOR fluid
17. In other
embodiments (not shown in Figure 2), electrodes 21, 23 are positioned in
locations other than
being coupled to injection well 13 and production well 15. The electrodes can
also be
positioned at locations above or below hydrocarbon bearing zone 11 such as
within rock
layers adjacent to hydrocarbon bearing zone 11. Additionally, a plurality of
electrodes can be
interspersed within subterranean reservoir 10 such that an electric field is
created to drive
EOR fluid 17 to unswept areas within hydrocarbon bearing zone 11.
[030] Therefore, embodiments of the present invention utilize
electrokinetic-induced
migration to overcome the fluid channeling limitations related to traditional
hydraulic
injection. In particular, a low voltage direct current is used to move or
distribute EOR
fluid 17 within the saturated porous media of the reservoir. For example,
polar fluids or
fluids having a net charge, including water, gas, surfactants, dissolved
species, colloids, and
micelles, can be moved rapidly through porous media under the influence of a
direct current.
In general, the rate of movement is associated with the power output of the
power source,
porosity of the reservoir matrix, and charge density. Further, the rate of
migration of the
EOR fluid 17 is independent of the hydraulic conductivity. Accordingly, as EOR
fluid 17
migrates through the subterranean reservoir the rate of movement is
independent of the
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permeability and connectivity of the porous rock matrix. For example, EOR
fluid 17 under
electrokinetics migration can penetrate through rocks having a very small
porosity, such as a
porosity of 0.02% or less. EOR fluid 17 is therefore distributed to portions
of the
subterranean reservoir where trapped oil is located, such as those areas where
traditional
enhanced oil recovery floods have not swept. One skilled in the art will
recognize that this is
advantageous as injected EOR fluid 17, such as water during an induced water
flood, can be
mobilized from one portion of the reservoir where oil saturations are low into
another portion
of the reservoir where oil saturations are high.
[031] In one embodiment, EOR fluid 17 penetrates into pore spaces of the
formation
contacting the trapped oil globules such that the oil trapped in the pore
spaces of the reservoir
rock matrix is released by reducing the interfacial tension between the water
and oil in the
subterranean reservoir. For example, EOR fluid 17 can comprise at least one
surfactant or a
component that will produce at least one surfactant in situ having a net total
charge. EOR
fluid 17 can produce naturally occurring surfactants, such as from a
biologically mediated
reaction. Alternatively, EOR fluid 17 can produce surfactant in situ as a by-
product of an
induced process. For example, one or more compounds can be injected into the
reservoir
such that they react with reservoir materials to produce a surfactant. In
another embodiment,
one or more compounds can be injected into the reservoir that when mixed in
the rock matrix
react with each other to produce surfactant. Examples of surfactants that can
be utilized for
as or in EOR fluid 17 include anionic surfactants, cationic surfactants,
amphoteric
surfactants, non-ionic surfactants, and a combination thereof As a skilled
artisan may
appreciate, the surfactant(s) selection may vary depending upon such factors
as salinity and
clay content in the reservoir. The surfactants can be injected in any manner
such as in an
aqueous solution, a surfactant-polymer (SP) flood or an alkaline-surfactant-
polymer (ASP)
flood. The surfactants can be injected continuously or in a batch process.
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[032] EOR fluid 17 can comprise anionic surfactants such as sulfates,
sulfonates,
phosphates, or carboxylates. Such anionic surfactants are known and described
in the art in,
for example, SPE 129907 and U.S. Patent No. 7,770,641, which are both
incorporated herein
by reference. Example cationic surfactants include primary, secondary, or
tertiary amines, or
quaternary ammonium cations. Example amphoteric surfactants include cationic
surfactants
that are linked to a terminal sulfonate or carboxylate group. Example non-
ionic surfactants
include alcohol alkoxylates such as alkylaryl alkoxy alcohols or alkyl alkoxy
alcohols.
Currently available alkoxylated alcohols include Lutensol0 TDA 10E0 and
Lutensol0 0P40, which are manufactured by BASF SE headquartered in Rhineland-
Palatinate, Germany. Neodol 25, which is manufactured by Shell Chemical
Company, is also
a currently available alkoxylated alcohol. Chevron Oronite Company LLC, a
subsidiary of
Chevron Corporation, also manufactures alkoxylated alcohols such as L24-12 and
L14-12,
which are twelve-mole ethoxylates of linear carbon chain alcohols. Other non-
ionic
surfactants can include alkyl alkoxylated esters and alkyl polyglycosides. In
some
embodiments, multiple non-ionic surfactants such as non-ionic alcohols or non-
ionic esters
are combined. The surfactant(s) of EOR fluid 17 can be any combination or
individual
anionic, cationic, amphoteric, or non-ionic surfactant so long as EOR fluid 17
has a net total
charge.
[033] In one embodiment, electrokinetics is utilized for environmental
treatment of wastes
(ex situ and/or in situ). In particular, electrokinetics can enhance chemical
treatment of
contaminated soil or sediment. The contaminant may be organic, such as oil or
solvent, or
inorganic, such as mercury and arsenic. The EOR fluid can include a surfactant
that reduces
the interfacial tension between oil and water, thereby increasing the
solubility of the
contaminant.
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[034] Applications of electrokinetic-induced migration are illustrated in
U.S. Patent
No. 7,547,160 and in "Electrokinetic Migration of Permanganate Through Low-
Permeability
Media," by D.A. Reynolds et al., Ground Water, Jul-Aug 2008, 46(4), pp. 629-
37, which are
both incorporated herein by reference. These publications illustrate rapid
electrokinetic-
induced migration of an oxidant (potassium permanganate) through low
permeability clay
material. In particular, the oxidant is delivered through the low permeability
clay material at
orders of magnitude faster than that of hydraulically induced flow.
[035] For example, the advantages of electrokinetic-induced migration over
traditional
hydraulic delivery is illustrated in the following experiment. A thin glass
tank having a width
of about 4 cm was constructed to simulate a two-dimensional flow field through
a
heterogeneous porous media. House-brick sized pieces of clay, which represent
low
permeability features, were emplaced within a zone of contiguous glass beads.
The glass
beads represent the high permeability zones of channeled flow. The tank was
saturated with
water and a flow field was established across the apparatus by fixing the
hydraulic head
(water elevation) at different heights on either side of the tank. Potassium
permanganate was
introduced into one side of the tank and allowed to flow through the
apparatus. The
potassium permanganate was substantially distributed within the glass beads
after two hours.
However, essentially no infiltration into the clay bricks occurred, indicating
that the
potassium permanganate bypassed the low permeability zones. This experiment
was
repeated, however, an anode and cathode were placed at either end of the tank
after the
potassium permanganate had flowed through the apparatus for two hours. A low
voltage
direct current of approximately 10 volts per meter (Vim) was applied between
the anode and
cathode for 20 minutes. The clay blocks were dissected and showed that the
potassium
permanganate fully penetrated the clay bricks.
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[036] Application of electrokinetic induced migration to enhance the
distribution of an
EOR fluid is disclosed. Use of electrokinetic induced migration allows for the
EOR fluid to
contact portions of the reservoir that previously were unswept due to the
limitations of
traditional hydraulic injection. In some embodiments, the EOR fluid further
penetrates into
pore spaces of the formation contacting the trapped oil globules, thereby
reducing the
interfacial tension between the water and oil in the reservoir and releasing
the oil from the
pore spaces.
[037] While in the foregoing specification this invention has been
described in relation to
certain preferred embodiments thereof, and many details have been set forth
for purpose of
illustration, it will be apparent to those skilled in the art that the
invention is susceptible to
alteration and that certain other details described herein can vary
considerably without
departing from the basic principles of the invention. For example, in one
embodiment,
electrokinetic migration is used to prevent corrosion or scale build-up in
injection or
production wells by migrating polar gases, such as hydrogen sulfide (H2S), to
portions of the
subterranean reservoir away from the wells. In this case, the polar gases are
naturally present
in the reservoir rather than being injected through the injection well like
the EOR fluid.
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