Note: Descriptions are shown in the official language in which they were submitted.
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SYSTEMS AND METHODS FOR PRODUCING OIL AND/OR GAS
Field of the Invention
The present disclosure relates to systems and methods for producing oil and/or
gas.
Background of the Invention
Enhanced Oil Recovery (EOR) may be used to increase oil recovery in fields
worldwide. There are three main types of EOR, thermal, chemical/polymer and
gas
injection, which may be used to increase oil recovery from a reservoir, beyond
what
can be achieved by conventional means - possibly extending the life of a field
and
boosting the oil recovery factor.
Thermal enhanced recovery works by adding heat to the reservoir. The most
widely practised form is a steamdrive, which reduces oil viscosity so that can
flow to
the producing wells. Chemical flooding increases recovery by reducing the
capillary
forces that trap residual oil and/or by reducing the interfacial tension
between oil and
water. Polymer flooding improves the sweep efficiency of injected water.
Miscible
injection works by creating a mixture of the injectant and the oil that flows
more easily
towards the production well than the oil by itself.
Referring to Figure 1, there is illustrated prior art system 100. System 100
includes underground formation 102, underground formation 104, underground
formation 106, and underground formation 108. Production facility 110 is
provided at
the surface. Well 112 traverses formations 102 and 104, and terminates in
formation
106. The portion of formation 106 is shown at 114. Oil and gas are produced
from
formation portion 114 through well 112, to production facility 110. Gas and
liquid are
separated from each other, gas is stored in gas storage 116 and liquid is
stored in
liquid storage 118.
U.S. Patent Number 6,022,834 discloses a concentrated surfactant formulation
and process for the recovery of residual oil from subterranean petroleum
reservoirs,
and more particularly an alkali surfactant flooding process which results in
ultra-low
interfacial tensions between the injected material and the residual oil,
wherein the
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concentrated surfactant formulation is supplied at a concentration above, at,
or, below
its CMC, also providing in situ formation of surface active material formed
from the
reaction of naturally occurring organic acidic components with the injected
alkali
material which serves to increase the efficiency of oil recovery. U.S. Patent
Number
6,022,834 is herein incorporated by reference in its entirety.
U.S. Patent Number 5,068,043 discloses an aqueous alkaline flood for
recovering oil from a reservoir containing acidic oil which includes adding to
the
injected aqueous alkaline solution both a stoichiometric excess of the
alkaline
material and a kind and amount of preformed cosurfactant material that
increases the
salinity of that solution so that, in contact with the oil in the reservoir,
it will form a
surfactant system having a salinity requirement which minimizes the
interfacial
tension between it and the oil. U.S. Patent Number 5,068,043 is herein
incorporated
by reference in its entirety.
U.S. Patent Application Publication Number 2009/0194276, published August
6, 2009, discloses systems and methods for the determination of an optimum
salinity
type and an optimum salinity of a surfactant microemulsion system. Optimum
salinity
type and optimum salinity in surfactant/polymer flooding is determined by core-
flood
experiments so that a variety of multiphase flow parameters such as relative
permeability and phase trapping that affects oil recovery factor, influences
the
determination of the optimum salinity type and optimum salinity. The optimum
salinity
determined preferably corresponds to the highest oil recovery factor. U.S.
Patent
Application Publication Number 2009/0194276 is herein incorporated by
reference in
its entirety.
U.S. Patent Application Publication Number 2009/0194281, published August
6, 2009, discloses an optimum salinity profile in surfactant/polymer flooding
from
formation water to post-flush drive that leads to the highest oil recovery
factor. The
optimum salinity determined from core-flooding experiments may be used in the
surfactant slug. The surfactant slug is protected from deterioration by the
injection of
cushion slugs immediately before and after the injection of the surfactant
slug in a
reservoir wherein the cushion slugs have the same salinity or about the same
salinity
as the surfactant slug. A salinity lower may be used in the post-flush drive,
while
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formation water could be of any salinity. U.S. Patent Application Publication
Number
2009/0194281 is herein incorporated by reference in its entirety.
There is a need in the art for improved systems and methods for enhanced oil
recovery. There is a further need in the art for improved systems and methods
for
enhanced oil recovery using an alkali surfactant polymer (ASP) flood, for
example
through increased viscosity of the injectant, reduced interfacial tension of
the injectant
and the oil, formation of an emulsion with the injectant and the oil, and/or
other
chemical effects. There is a further need in the art for improved systems and
methods for ASP flooding.
Summary of the Invention
In one aspect, the invention provides a method for producing oil and/or gas
from an underground formation comprising locating a suitable reservoir in a
subsurface formation; creating a model of the reservoir; populating the model
with
laboratory data; modeling the reservoir to determine fluid displacements based
on
fluids injected and fluids produced; determining an optimum fluid mixture for
the fluids
to be injected based on a series of sensitivity analyses performed with the
model;
drilling a first well in the formation; injecting the optimum fluid mixture
into the first
well; drilling a second well in the formation; and producing oil and/or gas
from the
second well.
Advantages of the invention include one or more of the following:
Improved systems and methods for enhanced recovery of hydrocarbons from a
formation with an ASP flood.
Improved systems and methods for enhanced recovery of hydrocarbons from a
formation with a fluid containing an ASP flood.
Improved compositions and/or techniques for secondary and/or tertiary
recovery of hydrocarbons.
Improved systems and methods for enhanced oil recovery.
Improved systems and methods for enhanced oil recovery using an ASP flood.
Improved systems and methods for enhanced oil recovery using a compound
which has an increased viscosity and a lowered interfacial tension compared to
water.
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Brief Description of the Drawings
Figure 1 illustrates an oil and/or gas production system.
Figure 2a illustrates a well pattern.
Figures 2b and 2c illustrate the well pattern of Figure 2a during enhanced oil
recovery processes.
Figure 3 illustrates oil and/or gas production systems.
Figure 4 illustrates a well pattern.
Figure 5 illustrates mixtures of crude oil and brine.
Figure 6 illustrates mixtures of crude oil and brine.
Figure 7 illustrates results of a core flood experiment.
Figure 8 illustrates results of a core flood experiment.
Figure 9 illustrates results of a core flood experiment.
Figure 10 illustrates a simulation of a pilot ASP flood.
Figure 11 illustrates a relationship between the optimal salinity of a
surfactant
and the optimal salinity of a soap.
Figure 12 illustrates the partitioning of soap and surfactant based on
salinity.
Figure 13 illustrates the results of a well log.
Figure 14 illustrates field data from a Single-Well Chemical tracer test.
Figure 15 illustrates field data from a Single-Well Chemical tracer test.
Figure 16 illustrates a simulation of a pilot ASP flood.
Detailed Description of the Invention
Figure 2a:
Referring now to Figure 2a, in some embodiments, an array of wells 200 is
illustrated. Array 200 includes well group 202 (denoted by horizontal lines)
and well
group 204 (denoted by diagonal lines).
Array 200 defines a production area, enclosed by the rectangle. Array 200
defines an interior of the system. Exterior to array 200 may be located a
plurality of
containment wells 250.
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Each well in well group 202 has horizontal distance 230 from the adjacent well
in well group 202. Each well in well group 202 has vertical distance 232 from
the
adjacent well in well group 202.
Each well in well group 204 has horizontal distance 236 from the adjacent well
in well group 204. Each well in well group 204 has vertical distance 238 from
the
adjacent well in well group 204.
As shown in Figure 2a, horizontal distance 230 and horizontal distance 236
refer to a distance from left to right of the paper, and vertical distance 232
and vertical
distance 238 refer to a distance from up to down of the paper. In practice,
array may
be composed of vertical wells that are perpendicular to the earth's surface,
horizontal
wells that are parallel to the earth's surface, or wells that are inclined at
some other
angle, for example 30 to 60 degrees with respect to the earth's surface.
Each well in well group 202 is distance 234 from the adjacent wells in well
group 204. Each well in well group 204 is distance 234 from the adjacent wells
in well
group 202.
In some embodiments, each well in well group 202 is surrounded by four wells
in well group 204. In some embodiments, each well in well group 204 is
surrounded
by four wells in well group 202.
In some embodiments, horizontal distance 230 is from about 25 to about 1000
meters, or from about 30 to about 500 meters, or from about 35 to about 250
meters,
or from about 40 to about 100 meters, or from about 45 to about 75 meters, or
from
about 50 to about 60 meters.
In some embodiments, vertical distance 232 is from about 25 to about 1000
meters, or from about 30 to about 500 meters, or from about 35 to about 250
meters,
or from about 40 to about 100 meters, or from about 45 to about 75 meters, or
from
about 50 to about 60 meters.
In some embodiments, horizontal distance 236 is from about 25 to about 1000
meters, or from about 30 to about 500 meters, or from about 35 to about 250
meters,
or from about 40 to about 100 meters, or from about 45 to about 75 meters, or
from
about 50 to about 60 meters.
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In some embodiments, vertical distance 238 is from about 25 to about 1000
meters, or from about 30 to about 500 meters, or from about 35 to about 250
meters,
or from about 40 to about 100 meters, or from about 45 to about 75 meters, or
from
about 50 to about 60 meters.
In some embodiments, distance 234 is from about 15 to about 750 meters, or
from about 20 to about 500 meters, or from about 25 to about 250 meters, or
from
about 30 to about 100 meters, or from about 35 to about 75 meters, or from
about 40
to about 50 meters.
In some embodiments, array of wells 200 may have from about 10 to about
1000 wells, for example from about 5 to about 500 wells in well group 202, and
from
about 5 to about 500 wells in well group 204. Optionally, there may be
provided from
about 2 to about 1000 containment wells 250, for example from about 5 to about
500,
or from about 10 to about 200.
In some embodiments, array of wells 200 is seen as a top view with well group
202 and well group 204 being vertical wells spaced on a piece of land. In some
embodiments, array of wells 200 is seen as a cross-sectional side view with
well
group 202 and well group 204 being horizontal wells spaced within a formation.
The recovery of oil and/or gas with array of wells 200 from an underground
formation may be accomplished by any known method. Suitable methods include
subsea production, surface production, primary, secondary, or tertiary
production.
The selection of the method used to recover the oil and/or gas from the
underground
formation is not critical.
In some embodiments, the containment of oil and/or gas and/or an enhanced
oil recovery agent with containment wells 250 may be accomplished by any known
method. Suitable methods include pumping water, steam, produced connate water,
sea water, carbon dioxide, natural gas or other gaseous or liquid
hydrocarbons,
nitrogen, air, brine, or other liquids or gases into containment wells 250. In
another
embodiment, containment wells 250 may be used to create a freeze wall barrier.
One
suitable freeze wall barrier is disclosed in U.S. Patent Number 7,225,866 is
herein
incorporated by reference in its entirety. The selection of the method used to
contain
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oil and/or gas and/or an enhanced oil recovery agent with containment wells
250 is
not critical.
In some embodiments, oil and/or gas may be recovered from a formation into a
well, and flow through the well and flowline to a facility. In some
embodiments,
enhanced oil recovery, with the use of an ASP mixture for example a mixture of
water,
an alkali, a surfactant, and a polymer, may be used to increase the flow of
oil and/or
gas from the formation.
Figure 2b:
Referring now to Figure 2b, in some embodiments, array of wells 200 is
illustrated. Array 200 includes well group 202 (denoted by horizontal lines)
and well
group 204 (denoted by diagonal lines). Optional containment wells 250 are
provided
about array of wells 200.
In some embodiments, an ASP mixture is injected into well group 204, and oil
is recovered from well group 202. As illustrated, the ASP mixture has
injection profile
208, and oil recovery profile 206 is being produced to well group 202. In some
embodiments, a containment agent is injected into containment wells 250. As
illustrated, the containment agent has an injection profile about each of the
containment wells 250. Containment agent may be used to force ASP mixture
and/or
oil and/or gas towards producing well group 202.
In some embodiments, ASP mixture is injected into well group 202, and oil is
recovered from well group 204. As illustrated, the ASP mixture has injection
profile
206, and oil recovery profile 208 is being produced to well group 204. In some
embodiments, a containment agent is injected into containment wells 250. As
illustrated, the containment agent has an injection profile about each of the
containment wells 250. Containment agent may be used to force ASP mixture
and/or
oil and/or gas towards producing well group 204.
In some embodiments, well group 202 may be used for injecting an ASP
mixture, and well group 204 may be used for producing oil and/or gas from the
formation for a first time period; then well group 204 may be used for
injecting an ASP
mixture, and well group 202 may be used for producing oil and/or gas from the
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formation for a second time period, where the first and second time periods
comprise
a cycle.
In some embodiments, an ASP mixture or a mixture including an ASP mixture
may be injected at the beginning of a cycle, and water optionally with added
polymer
may be injected at the end of the cycle to push the ASP mixture towards the
producing wells. In some embodiments, the beginning of a cycle may be the
first 10%
to about 80% of a cycle, or the first 20% to about 60% of a cycle, the first
25% to
about 40% of a cycle, and the end may be the remainder of the cycle.
In some embodiments, water optionally with added polymer may be used as a
containment agent and injected into containment wells 250.
In some embodiments, ASP mixtures injected into the formation may be
recovered from the produced oil and/or gas and re-injected into the formation.
In some embodiments, oil as present in the formation prior to the injection of
any enhanced oil recovery agents has a viscosity of at least about 5
centipoise, or at
least about 10 centipoise, or at least about 25 centipoise, or at least about
50
centipoise, or at least about 75 centipoise, or at least about 90 centipoise.
In some
embodiments, oil as present in the formation prior to the injection of any
enhanced oil
recovery agents has a viscosity of up to about 125 centipoise, or up to about
200
centipoise, or up to about 500 centipoise, or up to about 1000 centipoise.
Figure 2c:
Referring now to Figure 2c, in some embodiments, array of wells 200 is
illustrated. Array 200 includes well group 202 (denoted by horizontal lines)
and well
group 204 (denoted by diagonal lines). Containment wells 250 are located
exterior to
array 200 to form a perimeter about array 200.
In some embodiments, an ASP mixture is injected into well group 204, and oil
is recovered from well group 202. As illustrated, the ASP mixture has
injection profile
208 with overlap 210 with oil recovery profile 206, which is being produced to
well
group 202. In some embodiments, a containment agent is injected into
containment
wells 250. As illustrated, the containment agent has an injection profile
about each of
the containment wells 250. Containment agent may be used to force ASP mixture
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and/or oil and/or gas towards producing well group 202. After a sufficient
period of
time containment agent injection profile may overlap with one or more of
injection
profile 208 and oil recovery profile 206 so that enhanced oil recovery agent
is
contained within array 200; and/or so that oil and/or gas is contained within
array 200;
and/or so that containment agent is produced to well group 202.
In some embodiments, an ASP mixture is injected into well group 202, and oil
is recovered from well group 204. As illustrated, the ASP mixture has
injection profile
206 with overlap 210 with oil recovery profile 208, which is being produced to
well
group 204. In some embodiments, a containment agent is injected into
containment
wells 250. As illustrated, the containment agent has an injection profile
about each of
the containment wells 250. Containment agent may be used to force ASP mixture
and/or oil and/or gas towards producing well group 204. After a sufficient
period of
time containment agent injection profile may overlap with one or more of
injection
profile 208 and oil recovery profile 206 so that enhanced oil recovery agent
is
contained within array 200; and/or so that oil and/or gas is contained within
array 200;
and/or so that containment agent is produced to well group 204.
Releasing at least a portion of the ASP mixture and/or other liquids and/or
gases may be accomplished by any known method. One suitable method is
injecting
the ASP mixture into a first well, and pumping out at least a portion of the
ASP
mixture with gas and/or liquids through a second well. The selection of the
method
used to inject at least a portion of the ASP mixture and/or other liquids
and/or gases is
not critical.
In some embodiments, the ASP mixture and/or other liquids and/or gases may
be pumped into a formation at a pressure up to the fracture pressure of the
formation.
In some embodiments, the ASP mixture may be mixed in with oil and/or gas in
a formation to form a mixture which may be recovered from a well.
In some embodiments, a quantity of the ASP mixture may be injected into a
well, followed by another component to force the ASP mixture across the
formation.
For example water in liquid or vapor form, water with a dissolved polymer to
increase
its viscosity, carbon dioxide, other gases, other liquids, and/or mixtures
thereof may
be used to force the ASP mixture across the formation.
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In some embodiments, from about 0.1 to about 5 pore volumes of the ASP
mixture may be injected, for example from about 0.2 to about 2 pore volumes,
or from
about 0.3 to about 1 pore volumes of the ASP mixture may be injected. The
injection
of the ASP mixture may be followed by from about 2 to about 10 pore volumes of
a
polymer water mixture, for example from about 3 to about 8 pore volumes of the
polymer-water mixture. The inject of a polymer water mixture may be followed
with
water from about 1 to about 10 pore volumes.
Figure 3:
Referring now to Figure 3, in some embodiments of the invention, system 400
is illustrated. System 400 includes underground formation 402, formation 404,
formation 406, and formation 408. Production facility 410 is provided at the
surface.
Well 412 traverses formation 402 and 404 has openings at formation 406.
Portions of
formation 414 may be optionally fractured and/or perforated. As oil and gas is
produced from formation 406 it enters portions 414, and travels up well 412 to
production facility 410. Gas and liquid may be separated, and gas may be sent
to gas
storage 416, and liquid may be sent to liquid storage 418. Production facility
410 is
able to mix, produce and/or store ASP mixture, which may be produced and
stored in
production / storage 430.
ASP mixture is pumped down well 432, to portions 434 of formation 406. ASP
mixture traverses formation 406 to aid in the production of oil and gas, and
then the
ASP mixture, oil and/or gas may all be produced to well 412, to production
facility
410. ASP mixture may then be recycled, for example by utilizing a oil-water
gravity
separator, centrifuge, demulsifiers, boiling, condensing, filtering, and other
separation
methods as are known in the art, then re-injecting the ASP mixture into well
432.
Containment well 450 with injection mechanism 452 and containment well 460
with injection mechanism 462 may be provided to contain ASP mixture between
containment well 450 and containment well 460. Injection mechanisms 452 and
462
may be used to inject a containment agent, for example a refrigerant to create
a
freeze wall, or a liquid or gas such as water, water mixed with a viscosifier,
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mixed with an alkali, water mixed with a surfactant, carbon dioxide, natural
gas, other
C1 - C15 hydrocarbons, nitrogen, or air, or mixtures thereof.
In some embodiments, a quantity of ASP mixture or ASP mixture mixed with
other components may be injected into well 432, followed by another component
to
force ASP mixture or ASP mixture mixed with other components across formation
406, for example water in gas or liquid form; water mixed with one or more
salts,
polymers, alkalis, and/or surfactants; carbon dioxide; other gases; other
liquids;
and/or mixtures thereof.
In one embodiment, from about 0.1 to about 2, for example from about 0.25 to
about 1 pore volumes of ASP mixture may be injected into well 432. Then from
about
0.5 to about 10, for example from about 1 to about 5 pore volumes of a polymer
-
water mixture having a viscosity within about 25%, for example within about
10% of
the viscosity of the ASP mixture may be injected into well 432. Then from
about 1 to
about 10 pore volumes of water may be injected into well 432.
In some embodiments, well 412 which is producing oil and/or gas is
representative of a well in well group 202, and well 432 which is being used
to inject
ASP mixture is representative of a well in well group 204.
In some embodiments, well 412 which is producing oil and/or gas is
representative of a well in well group 204, and well 432 which is being used
to inject
ASP mixture is representative of a well in well group 202.
Figure 4:
Figure for illustrates a process 500 to design an ASP flood. Process 500
includes determining the optimum salinity for the surfactant 502, determining
the
optimum salinity for the soap 504, determining the viscosity of the mixture
due to the
added polymer 506, creating a model for the ASP flood including formation,
chemical,
and oil properties 508, correlating the model with known data 510, and
designing the
ASP flood using the model 512. Further details of each of the steps will be
set forth
below.
The ASP process is a combination of two earlier chemical flooding techniques:
the surfactant-polymer flood and the alkaline flood. The task of the chemicals
injected
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in these processes is two-fold: firstly, to reduce the interfacial tension
between oil and
water in order to liberate oil trapped by capillary forces; and secondly, to
stabilise the
displacement, when necessary, by increasing the water viscosity through the
addition
of a polymer. In the case of a surfactant-polymer flood, the reduction of the
interfacial
tension is achieved by the injected surfactant. In the case of the alkaline
flood, the
alkali (e.g. NaOH or Na2CO3) raises the pH of the brine which, in turn, leads
to a
saponification of crude-borne oleic acids to generate a natural surfactant in-
situ,
commonly referred to as "soap."
While the injected surfactant (in the following referred to in short as "the
surfactant") and the in-situ generated surfactant (referred to as "the soap")
are
chemically rather different, they share the general property that their
interfacial activity
depends on the environment, for example on salinity. At otherwise constant
external
conditions, there exists an optimum brine salinity at which the surfactant or
the soap
reduce the oil-water interfacial tension most strongly.
At lower salinities ("under-optimum regime") or at higher salinities ("over-
optimum regime") the reduction of interfacial tension is less. In the under-
optimum
regime, the surfactant and the soap partition favourably into the brine phase;
in the
over-optimum regime they partition favourably into the oil phase; only near
their
respective optimum salinities are they able to generate a third, separate
"micro-
emulsion" phase that exhibits very low interfacial tensions with both the
water and the
oil phases. The optimum salinity is surfactant-specific; the optimum salinity
of soap is
generally significantly lower than that of typical injected surfactants
The ASP mixture may be designed such that the optimum salinity of the
chemical slug is at or close to the actual brine salinity of the injected
water in order to
achieve a low oil-water interfacial tension. A high or a low salinity will
cause the
surfactant or the soap to be pushed ineffectively to the producing wells
(under-
optimum case) or to be partitioned into immobile oil, i. e. to be retained,
and thus lost
(over-optimum case).
The ASP mixture may include alkali, surfactant and polymer which are injected
together as one slug. In this slug, the alkali and the surfactant will
generally travel at
(slightly) different velocities: the surfactant is subject to partitioning
into any remaining
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oil and to matrix adsorption while the alkali is consumed by the
saponification, by
precipitation of carbonates and possibly by exchange reactions with the
matrix.
As injected, the phase behaviour of the ASP slug is under-optimum or near
optimum. Then, upon contact of the alkali with crude oil, the saponification
process
leads to a reduction of the optimum salinity in the region where soap is
generated
such that the phase behaviour locally changes to over-optimum. As a
consequence,
a gradient in optimum salinity from over-optimum at the front of the chemical
slug to
(under-)optimum at the rear of the chemical slug establishes which serves to
confine
the chemical slug and limit dispersive dilution. This inherent gradient can be
progressed through the reservoir, moving, in principle, an optimally
interfacially active
zone though the reservoir which leaves no oil behind.
Determining the Surfactant phase optimum salinity:
In order to determine the chemical phase behavior of a surfactant, an array of
samples with different concentrations of alkali and sodium chloride, for
example test
tubes may be used. One such example, at zero alkali concentration, from which
the
optimum salinity of the pure surfactant solution can be inferred as shown in
Figure 5.
The test tubes which generate a separate emulsion phase may be inferred to be
at or
near the optimum salinity such that the interfacial tension reduction is at a
maximum.
Determining the Soap phase optimum salinity:
In order to determine the chemical phase behavior of a soap follows
essentially
the same procedure as the surfactant determination, albeit with one
complication: The
soap is a reactive product of alkali or, more specifically, hydroxide with
oleic acid. As
such, the amount of soap generated is dependent on the amount of alkali added
to
the brine.
Adding alkali, however, also raises the salinity such that the behaviour at
low
salinity combined with high soap concentration cannot be studied. Using sodium
carbonate for the alkali, the equilibrium reactions that govern saponification
are, in its
most simple form, the aqueous reactions:
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Na2CO3 - 2Na+ +C03 2- (Equation 1)
C032- + H20HC032- + OH- (Equation 2)
and the saponification reaction:
HA. + OH- A- + H2O (Equation 3)
In equation 3, HA, represents the oil-borne acids and A- represents the soap.
Since HA, + OH- reside in oil and water, respectively, the latter reaction is
understood
to occur at the interface between oil and water.
Depending on the "total acid number" (TAN) of the oil, a quantity that
measures
the molar concentration of acid in oil, different amounts of alkali are
required to
establish complete saponification. A comparison of the molar concentrations of
carbonate and acid can indicate whether saponification can occur to a
significant
degree in a given mixture of oil and brine.
Determining the Polymer solution viscosity:
In order to determine the polymer solution viscosity, samples with varying
salinities may have a given volume of polymer added to them, and then the
viscosity
of the samples determined. Generally, increasing salinity leads to a lower
viscosity,
while an increased volume of polymer leads to a higher viscosity.
In one embodiment, the mobility ratio of the ASP mixture is matched to the oil
in the formation. In general, the mobility ratio of the ASP mixture and of the
oil is a
function of the viscosity. Therefore, polymer is added to the ASP mixture
until the
viscosity of the mixture is similar to that of the oil. In one embodiment, the
ASP
mixture has a viscosity value within 50% of the viscosity value of the oil,
for example
within 20%, or within 10%.
Model Setup:
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In short, the model is a two-phase (water and oil) multi-component
(surfactant,
acid, soap, polymer, aqueous chemistry) description of the ASP process
including
brine chemistry, compositionally dependent partitioning of the chemicals,
adsorption
and viscosity modification.
The model contains two liquid phases (water and oil) over which it partitions
the surfactant and the soap depending on the ratio of salinity versus optimum
salinity,
and one stationary solid phase.
One central feature of an ASP mixture discussed above is the transition from
over-optimum behavior (soap-rich zone) to under-optimum behaviour (surfactant-
rich
zone). As the ratio of soap to surfactant concentration varies at a given
position in the
reservoir, so must the optimum salinity. The individual optimum salinities for
the
surfactant and the soap are taken as input parameters that may be determined
experimentally.
Both the surfactant and the soap are allowed to partition over water and oil
as
a function of the local chemical concentrations (phase composition). This
partitioning
determines the flow of the surfactant and the soap. Underlying the
partitioning model
is the qualitative observation that the surfactant and the soap partition
strongly into
either water or oil as the local composition is under-optimum or over-optimum,
respectively. At optimum salinity, however, surfactant and soap partition into
both
water and oil in equal parts. Since an ASP flood may be over-optimum ahead of
the
surfactant bank and under-optimum inside the bank, the exact nature of the
partitioning coefficient may be less relevant.
An interfacial tension correlation is provided in the model. This correlation
assumes that a user-defined minimum interfacial tension is obtained at optimum
salinity. Moreover, at a high ratio of soap to surfactant concentration, a
minimum
interfacial tension due to the soap is established. Finally, minimum
interfacial tension
can only be achieved if the total surfactant concentration (i.e. the sum of
the
surfactant and soap concentrations) is at or above the critical micelle
concentration.
As the total concentration of soap and surfactant is reduced, the interfacial
tension
gradually approaches the unmodified oil-water value.
CA 02784910 2012-06-18
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The model has a viscosity model taking into account viscosity dependence on
polymer mass fraction in water and on effective salinity.
The extent of saponification depends on the local concentration of alkali.
Therefore, tracking this as well as the concentrations of acid and other
components
that affect the soap generation is a feature of the ASP model. The number of
reactants may be kept as small as possible in order not to inflate simulation
time,
involving the saponification equations set forth above.
The complexity of an ASP flood and of the ASP model alongside with the
necessary simplifications of the model require a validation of the forecasts
generated
by the model. To this end, detailed one-dimensional simulations may be carried
out
and the resulting chemical and production profiles compared to other models or
other
known data. Thereafter, experimental ASP core flood data may be history
matched in
order to correlate the model with the data generated by the core-floods. The
model
may then be further improved by using field trial and commercial scale data
obtained
from a reservoir.
Designing an ASP mixture
Once the model has been successfully designed and the parameters set for a
given field or formation, the model may be used to determine the components
for an
ASP mixture. Given the complexity of the number of parameters and the complex
chemistry, one suitable starting point would be a previously used ASP mixture
chemistry, or to use the optimum mixture chemistry determined from the
laboratory
experiments discussed above. From there, the salinity of the mixture can be
varied,
as well as the concentration of surfactant, the concentration of polymer, and
the
concentration of alkali can be varied. The model may require further
calibration with
the use of additional lab tests and experiments in order to properly model
varied
salinity, surfactant concentration, polymer concentration, and/or alkali
concentration.
In one embodiment, a sensitivity analysis for the surfactant concentration may
be completed first to achieve the optimum surfactant concentration, followed
by the
same analysis for the alkali, then the polymer. However, the order is not
critical.
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In general, the incremental oil recovery is compared to the cost of the
chemicals to come up with the optimum mixture.
Alternatives:
In some embodiments, oil and/or gas produced may be transported to a
refinery and/or a treatment facility. The oil and/or gas may be processed to
produce
commercial products such as transportation fuels such as gasoline and diesel,
heating fuel, lubricants, chemicals, and/or polymers. Processing may include
distilling
and/or fractionally distilling the oil and/or gas to produce one or more
distillate
fractions. In some embodiments, the oil and/or gas, and/or the one or more
distillate
fractions may be subjected to a process of one or more of the following:
catalytic
cracking, hydrocracking, hydrotreating, coking, thermal cracking, distilling,
reforming,
polymerization, isomerization, alkylation, blending, and dewaxing.
Examples:
The route from the design of a suitable ASP formulation to actual piloting in
the field, to evaluate and
demonstrate the feasibility of an ASP project in a giant sandstone reservoir.
Laboratory work and model calibration
A suite of laboratory experiments is required to quantify the behaviour of an
ASP formulation. Initially, the phase
behaviour of the surfactant mixture and the polymer viscosity behaviour are
analysed independently. Thereafter,
the two are combined in a core-flood experiment to study oil recovery for a
given combination, and to calibrate a
flow simulation for subsequent forecasting.
Phase Behaviour Experiments
For the present purpose, the surfactant mixture may be considered as
consisting of two independent species:
the manufactured injected surfactant and the in-situ generated petroleum
soaps. Although these two are, in
principle, of rather different molecular structure, they share the ability to
reduce the interfacial tension between
crude oil and brine, albeit at different brine salinities, all other
thermodynamic properties assuming to be
determined by the reservoir. The salinity at which a given surfactant achieves
the lowest interfacial tension is
referred to as its optimum salinity. A low interfacial tension promotes the
generation of an oil-brine emulsion
phase, which, in turn, may be used as evidence for the achievement of optimum
salinity. Along with the
interfacial activity, the partitioning of a surfactant between the oil, brine
and emulsion phases depends on salinity:
at optimum salinity the surfactant partitions into the emulsion phase; at a
salinity lower than the optimum salinity
(under-optimum case) the surfactant partitions predominantly into brine; at a
salinity higher than the optimum
salinity (over-optimum case) the surfactant partitions predominantly into oil.
Petroleum soaps originate from naturally occurring petroleum acids, which are
saponified by raising the
alkalinity of the brine (pH) through the addition of an alkali, such as sodium
hydroxide or sodium carbonate. As
such, however, the intentional saponification comes jointly with an
unintentional rise in salinity (sodium
concentration) with a possibility of rendering the environment for the
generated petroleum soaps over-optimum,
i.e. less effective in reducing oil-water interfacial tension. This
interdependence means that plain alkali floods can
be difficult to control. Manufactured surfactants, on the other hand, can be
tailored to a desired optimum salinity.
Originating from industrial chemical synthesis, these molecules are, however,
significantly more costly than
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petroleum soaps which come at the cost of the injected alkali only. Moreover,
a dominant loss mechanism for
manufactured surfactants is adsorption to the reservoir rock.
Mixtures of surfactants with different optimum salinities are known to exhibit
a combined optimum salinity
that obeys a simple concentration-dependent mixing rule. With this extra
degree of freedom, ASP formulations
can be designed that make use of the potential of the petroleum soaps (if
present) while guaranteeing optimum
phase behaviour through the choice of the manufactured surfactant. As an
additional benefit, the presence of
alkali reduces the tendency of the manufactured surfactant to adsorb, thereby
reducing the required amount of this
valuable ingredient.
The optimum salinity behaviour of the petroleum soaps alone can be determined
by test tube experiments
where oil and brine are combined in different ratios, and where alkali is
subsequently added in varying
concentrations. One such set of test tubes is displayed in Figure 5 from which
the optimum salinity of the
petroleum soaps of the particular crude can be inferred to be about 0.22 mol/l
Na'. An independent but similar
analysis for a manufactured surfactant mixture selected for this particular
crude resulted in a value of
0.76 mol/l Na'. Error! Reference source not found. shows an alkali scan using
oil and brine at a volume ratio
of 50/50. The brine contains 0.3 wt.% of the manufactured surfactant mixture.
From the existence of the large
emulsion phase at a concentration of 1.25 wt.% Na2CO3 the optimum salinity for
the combination of surfactants
and petroleum soaps can be inferred to be 0.31 mol/l Na', i.e. in-between the
individual values of the petroleum
soaps and the manufactured surfactant mixture.
Core Flood Experiments
Following the demonstration of optimum phase behaviour, an ASP formulation is
tested in core flood
experiments to prove its ability to liberate and mobilise remaining oil. These
experiments provide information
about the adsorption characteristics of the chemical components as well as the
displacement stability of the
(internal) polymer drive. Error! Reference source not found. through Error!
Reference source not found.
show experimental data of a core flood carried out on a 30 cm long outcrop
sandstone core with a diameter of
5 cm. The flooding sequence in this experiment was as follows: a 2.2 PV
waterflood; a 0.3 PV ASP flood; a
2.6 PV polymer drive. The ASP formulation consisted of 0.3 wt.% manufactured
surfactant, 1 wt.% Na2CO3, and
a 27 mPa.s polymer solution. The polymer drive also had a viscosity of 27
mPa.s.
The injection pump pressure along with the effluent oil cut and recovery
factor are displayed in Error!
Reference source not found.7, clearly showing the production of an oil-bank
between 2.6 PV and 3.4 PV
injected, at the end of which 98% of the initial present oil has been
recovered. Comparing this to the carbonate-
bicarbonate effluent concentrations and pH (Error! Reference source not
found.8) as well as the effluent
surfactant concentration and viscosity (Error! Reference source not found.9)
reveals that, while the first half of
this oil bank is produced as "clean" oil, the second half is emulsified and
contains ASP chemicals. The
conversion of carbonate to bicarbonate, observed as a temporary increase of
the bicarbonate concentration around
3 PV in Error! Reference source not found.8, is reminiscent of two chemical
processes occurring in the porous
medium: the saponification of petroleum acids, and clay exchange. In the
simulation, these are represented by the
following small set of reactions:
1. Carbonate-bicarbonate balance:
C03 + H2O HC03 + OH-
2. Saponification of petroleum acids (HA.) to soaps (A-):
HAo +OH- A- +H20
3. Exchange of sodium for clay-bound hydrogen:
Na+ + H+ + OH- Na+ + H 20
This set is considered to be sufficient unless the behaviour at pH values
below 8 must be accurately reproduced,
which would require inclusion of the carbonic acid dissociation reaction, or
if the brine hardness (concentration
of Ca2+ and Mgz+) is significant enough to precipitate carbonate scale.
The effluent surfactant concentration (Error! Reference source not found.9)
allows determining the
adsorption characteristics of the surfactant by way of its breakthrough time.
For the present case, a maximum
adsorption as low as 2 g/g (amount of surfactant per amount of porous medium)
was found, representative for
the very clean outcrop core. The simulation model does not reproduce the
magnitude of the experimentally
determined effluent surfactant concentration. This is likely owing to the fact
that only water-borne surfactant was
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WO 2011/090921 PCT/US2011/021493
measured whereas the larger fraction of the surfactant was expected to be
produced in the emulsion or oil phase.
Our simulation, however, does not model the emulsion phase but uses a
simplified phase behaviour: The
optimum salinity (cf. Error! Reference source not found. 11) is calculated
from a thermodynamic mixing rule as
pop, (R) = PA 11(1+11R) Ps 11(1+R)
where poPr denotes the optimum salinity as a function of the individual
optimum salinities of the petroleum soap
(PA) and the surfactant (ps), and the ratio R = (moles of soap) / (moles
surfactant). The oil-water partitioning
coefficient of the petroleum soap and the surfactant is subsequently assumed
to obey a power law of the type
6
K(p,R) = p
[P0(R)
which mimics the functional dependence proposed by Liu et al (Liu et al,
2006).It satisfies the condition
K(p.pt(R),R)=1, i.e. equal partitioning over oil and water at optimum
salinity. (cf. Error! Reference source not
found.12).
Piloting
Although, in principle, well understood in the laboratory, there are
significant uncertainties around the
implementation of ASP in the field. Following successful core flood
experiments, a series of Single-Well
Chemical Tracer tests has been carried out in three fields (two sandstones,
one carbonate) to demonstrate and
verify the effectiveness of the selected ASP formulation in the subsurface. In
parallel, the objectives and the
design for a pattern flood ASP pilot have been developed. Computer simulations
were performed to predict
injection pressures, liquid rates and effluent concentrations for different
pilot configurations.
Series of Single-Well Chemical Tracer Tests
Single-Well Chemical Tracer tests (SWCT) provide a means to establish the
immobile oil saturation in a volume
extending a few meters out from the well bore into the reservoir. During an
SWCT, in essence, one tracer
chemical is injected as a finite slug into the well and, subsequently, starts
reacting into another tracer chemical in
situ. The injected chemical and the in-situ generated chemical have different
partitioning characteristics and,
therefore, different convection properties depending on the prevalent oil
saturation. Hence, after a short shut-in
period, upon back-production of the injected slug, they arrive after different
times. An interpretation of their
resulting effluent concentration profiles yields the remaining oil saturation.
Ideally, each concentration profile exhibits a single maximum. The separation
between the maxima of the two
profiles relates to the remaining oil saturation through an explicit
analytical formula. Deviations from this ideal
situation can be caused, for example, by poor well integrity, or by any
subsurface rearrangement, during the shut-
in period, of the chemical slug, such as well-bore cross-flow or fluid drift.
The selection criteria for a well
undergoing an SWCT include, therefore, good well integrity as well as a short,
single-zone perforation interval
and a safe distance from active wells to avoid any interference.
In practice, using existing producing wells with high water-cut may mean that
not all selection criteria can be
equally well satisfied. Error! Reference source not found.13 shows the
reservoir description log of a well in a
PDO sandstone reservoir that was tested by an SWCT. Like most other candidate
wells taken into consideration
in this field, the selected well features a 30 m wire-wrapped screen
completion interval that accesses more than
one reservoir. Pressure and rate data as well as the effluent tracer
concentration profiles recorded during the
SWCT are displayed in Error! Reference source not found. and Error! Reference
source not found.,
respectively. Error! Reference source not found.13 shows the individual flow
periods during the SWCT: a
3000 m3 water-flood followed by a short perforation clean-out production; a 30
m3 chemical tracer slug
containing 1 wt.% ethyl formate (EtF) as the injected tracer chemical as well
as 0.5 wt.% normal propyl alcohol
(NPA) to earmark this slug; a 120 m3 water slug driving the chemical out to 3
m from the well-bore; a two day
shut-in period during which EtF partially hydrolyses to from ethanol (EtOH); a
1.2 day back-production period.
Both the 30 m3 and the 120 m3 slug were, moreover, tagged by 0.25 wt.%
methanol (MeOH). A glance at the
effluent tracer concentration profiles shown in Error! Reference source not
found. reveals the significant
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WO 2011/090921 PCT/US2011/021493
deviation from the ideal situation described above. Reservoir simulation,
including a model for the reactive
transport of the chemical tracers, suggests that cross-flow between three
separate geological layers through the
well-bore is responsible for the observed effect. This cross-flow, which was
not apparent on a previously run
shut-in PLT, occurs as a consequence of the dynamic pressurisation of the
individual layers during the tracer
injection phase: the lower the total compressibility and the smaller the
extent of a layer, the faster its average
pressure increases during the injection phase. This can cause an average
pressure differential across the layers
which rapidly equilibrates, by means of well-bore cross-flow, during the shut-
in period. For the particular case of
the three-layer model discussed above, the cross-flow required to achieve the
match displayed in Error!
Reference source not found. amounts to about 10 m3 out of the 6.5 m thick
layer, and 4 m3 out of the thick
5.0 m layer, both into the top-most 13.5 m thick layer (cf. caption of Error!
Reference source not found.).
Remaining oil saturations of 34% in the 13.5 m layer, and 20% in the other two
layers, yielded the best numerical
fit which corresponds to a volume average of 28%, in line with expectation for
this reservoir.
After this first "base-line" SWCT, 420 m3 of the previously identified ASP
formulation were injected into the
well followed by a total of 60 m3 tapered polymer drive and 420 m3 water
drive. Subsequently, a second SWCT
was carried out in the same well to measure the remaining oil saturation and,
thus, to assess the efficiency of the
ASP formulation. This test was interpreted to yield a remaining oil saturation
of 1% (uncertainty range 0-6%).
This almost complete desaturation agrees well with the experimental core flood
results, suggestion that the
reservoir conditions had been suitably reproduced in the laboratory.
Similar sequences were carried out of firstly a base-line SWCT, secondly an
ASP injection phase, and thirdly
another SWCT, in a total of five wells in three different fields. The first
two of these wells were located in a
relatively heavy oil high-quality sandstone reservoir; the next two wells were
located in two different formations
of a medium oil high-quality sandstone reservoir; the fifth well was located
in a tight carbonate reservoir. Of the
first two wells, which targeted the same formation in the same field, and
which stood only 430 m apart, the
second well received a smaller ASP slug (44 m3) followed by a polymer drive
(131 m), a short tapered polymer
drive (20 m3) and, finally, a long water drive (830 m). Whereas the base-line
SWCT for this second well resulted
in a similar remaining oil saturation (25%) as the first well, the final SWCT
was interpreted to yield an oil
saturation of 23%. Despite the significantly reduced ASP slug this apparent
lack of desaturation was unexpected
from the experimental core flood results. Pending a closer analysis it is,
however, not inconceivable that local
reservoir heterogeneity and unstable fluid displacement caused the water-based
chemical tracer slug to penetrate
through the high-viscosity ASP slug and polymer drive such that, in essence,
the SWCT yields once more the
original remaining oil saturation prevalent beyond the reach of the ASP
treatment. The recorded co-production of
diluted alkaline and polymer during the recovery of the chemical tracer slug
supports this hypothesis. As a
consequence, it may be concluded that the SWCT technique is not suited to
determine the efficiency of small
(commercial scale) FOR treatments, a lesson heeded for the design of the
subsequent tests. The analysis of the
results of the latter yet remains to be carried out.
Pattern-Flood Pilot
Whereas the Single-Well Chemical Tracer test series provided evidence for the
subsurface desaturation efficiency
of the selected ASP formulations it cannot, by design, verify the robustness
of the ASP process in a typical
flooding application: the stability of the chemicals in the subsurface
throughout the duration of a pattern flood;
the formation of an oil bank and the stable displacement thereof; the
susceptibility to reservoir heterogeneity; the
maximum sustainable injection rate of an ASP slug and a polymer drive without
uncontrolled fracturing of the
reservoir; the commercially optimal volume of these slugs. Further to these
subsurface-related uncertainties,
significant challenges dominate the surface design of an ASP injection scheme:
the formation of carbonate scale
or silica scale near producing wells and in the production facilities; the
production of emulsified oil at very low
oil-water interfacial tension; the supply chain and handling of the involved
chemicals.
The main criteria for this work are: the maximisation of data acquisition,
such as injectivity, desaturation and
recovery factor; the robustness against well or equipment failure; the
quantification and mitigation of emulsion
and scale formation; a representative geological setting; a feasible pilot
duration. Identified risks include the
contamination of near-by production wells with ASP chemicals as well as
uncontrolled fracturing.
In view of the above, an inverted five-spot pattern (one central injector
surrounded by four corner producers)
with an edge length of the order of 75 m x 75 m is considered the best
compromise. Moreover, if desired, this
pattern allows an extension of the pilot toward a larger pattern size by
converting the corner producers into
injectors and drilling four new corner producers at a larger distance
surrounding the original pilot pattern. Using
the reservoir simulation model calibrated by the aforementioned core flood
experiments, ASP forecast
CA 02784910 2012-06-18
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simulations have been carried out starting from a current "history-matched"
fine-gridded field model. The
injection and production rate results are displayed in Error! Reference source
not found. 16 while the expected
effluent concentration profiles are shown in Error! Reference source not
found.. Of the total duration of
1.5 years, approximately half a year is spent for the injection of ASP and a
polymer drive while the remaining
time is used for a subsequent water-flood period. The production of the oil
bank is essentially complete after one
year of pilot operation. Given that chemical breakthrough occurs after 0.3-0.4
years a part of the oil bank is
expected to be produced emulsified, albeit with a comparatively small
surfactant concentration. This is owing to
the production stream dilution in a single inverted five-spot pattern, and it
would not be representative for a field-
wide implementation of ASP.
Illustrative Embodiments:
In one embodiment of the invention, there is disclosed a method producing oil
and/or gas from an underground formation comprising locating a suitable
reservoir in
a subsurface formation; creating a model of the reservoir; populating the
model with
laboratory data; modeling the reservoir to determine fluid displacements based
on
fluids injected and fluids produced; determining an optimum fluid mixture for
the fluids
to be injected based on a series of sensitivity analyses performed with the
model;
drilling a first well in the formation; injecting the optimum fluid mixture
into the first
well; drilling a second well in the formation; and producing oil and/or gas
from the
second well. In some embodiments, the first well is at a distance of 25 meters
to 1
kilometer from the second well. In some embodiments, the optimum fluid mixture
comprises water, a surfactant, a polymer, and an alkali. In some embodiments,
the
method also includes a mechanism for injecting a water based mixture into the
formation, after the optimum fluid mixture has been released into the
formation. In
some embodiments, populating the model with laboratory data further comprises
determining an optimum salinity of a surfactant in the optimum fluid mixture.
In some
embodiments, populating the model with laboratory data further comprises
determining an optimum salinity of a soap formed by a reaction of an alkali in
the
optimum fluid mixture with the oil in the formation. In some embodiments,
drilling a
first well further comprises drilling a first array of wells comprising from 5
to 500 wells,
and wherein drilling a second well further comprises drilling a second array
of wells
comprising from 5 to 500 wells. In some embodiments, populating the model with
laboratory data further comprises determining a viscosity of the optimum fluid
mixture
based on a volume of polymer added to the mixture. In some embodiments, the
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method also includes mixing the optimum fluid mixture prior to injecting the
mixture.
In some embodiments, the underground formation comprises an oil having a
viscosity
from 0.5 to 250 centipoise, prior to the injection of the optimum fluid
mixture. In some
embodiments, the first well comprises a ASP mixture profile in the formation,
and the
second well comprises an oil recovery profile in the formation, the method
further
comprising an overlap between the ASP mixture profile and the oil recovery
profile. In
some embodiments, populating the model with laboratory data further comprises
performing a core flood experiment with a core sample from the formation
comprising
oil from the formation. In some embodiments, performing the series of
sensitivity
analyses with the model comprises modifying each ingredient in the mixture and
determining an optimum value for each said ingredients. In some embodiments,
the
oil in the formation comprises a first viscosity, and the optimum fluid
mixture
comprises a second viscosity, the first viscosity is within 75 centipoise of
the second
viscosity. In some embodiments, the oil in the formation comprises a first
viscosity,
and the optimum fluid mixture comprises a second viscosity, the second
viscosity is
from about 25% to about 200% of the first viscosity. In some embodiments, the
second well produces the optimum fluid mixture, and oil and/or gas. In some
embodiments, the method also includes recovering the optimum fluid mixture
from the
oil and/or gas, if present, and then optionally re-injecting at least a
portion of the
recovered optimum fluid mixture into the formation. In some embodiments, the
optimum fluid mixture is injected at a pressure from 0 to 37,000 kilopascals
above the
initial reservoir pressure, measured prior to when injection begins. In some
embodiments, the underground formation comprises a permeability from 0.0001 to
15
Darcies, for example a permeability from 0.001 to 1 Darcy. In some
embodiments,
the method also includes converting at least a portion of the recovered oil
and/or gas
into a material selected from the group consisting of transportation fuels
such as
gasoline and diesel, heating fuel, lubricants, chemicals, and/or polymers.
Those of skill in the art will appreciate that many modifications and
variations
are possible in terms of the disclosed embodiments of the invention,
configurations,
materials and methods without departing from their spirit and scope.
Accordingly, the
scope of the claims appended hereafter and their functional equivalents should
not be
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limited by particular embodiments described and illustrated herein, as these
are
merely exemplary in nature.
23
