Note: Descriptions are shown in the official language in which they were submitted.
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PROCESS FOR PRODUCING OIL
Field of the Invention
The present invention is directed to a process for producing oil. In
particular, the
present invention is directed to a process for producing a heavy oil or
bitumen having a
measurable total acid number.
Background of the Invention
Large deposits of heavy oil or bitumen are present in some areas of the world.
These deposits offer the opportunity to capture large quantities of oil,
however, the nature
of the heavy oil or bitumen renders recovering the oil difficult. Heavy oil
and bitumen
contain more high molecular weight hydrocarbons such as asphaltenes and resins
than light
crudes, which renders the heavy oil/bitumen much more viscous than light
crudes. Viscous
heavy oil or bituminous crudes are more difficult to mobilize and produce from
a
subterranean formation than crudes of low viscosity since the viscous crudes
do not flow
easily.
Heat has been used for enhancing oil production from subterranean heavy oil
and
bitumen-containing formations. Heat applied to the heavy oil or bitumen within
the
formation reduces the viscosity of heavy oil or bitumen so the oil in place in
the formation
may flow more freely and be mobilized for production.
Steam flooding is one method that is commonly used to provide heat to
subterranean heavy oil and bitumen-containing formations. Steam is injected
into a heavy
oil or bitumen-containing subterranean formation through an injection well
extending into
the formation, and is contacted with the oil in place in the formation to heat
the oil,
mobilizing the oil for production from the formation. Steam provides sensible
heat and
latent heat of condensation to the oil in the formation to reduce the
viscosity of the oil.
Furthermore, the water condensed from the steam may form an oil-in-water
emulsion with
the oil in the formation, where the emulsion has a viscosity on the same order
of magnitude
as water and substantially less than the oil itself, where the oil-in-water
emulsion may be
mobilized for production from the formation. The reduced viscosity oil and the
oil-in-
water emulsion are then produced from the formation.
Steam flooding may be effected by injecting the steam into a heavy oil or
bituminous subterranean formation through one or more injection wells for a
period of time
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to lower the viscosity of the oil near the injection wellbore, then stopping
the injection of
steam and pumping the reduced viscosity oil from the formation through the
well used to
inject the steam into the formation. When the oil production drops off, steam
injection
may be resumed to heat more oil in the formation, followed by further
production. Steam
flooding may also be effected by continuously injecting the steam into a heavy
oil or
bitumen-containing subterranean formation through one or more vertical
injection wells
and continuously producing oil from the formation through one or more vertical
production
wells.
Steam-Assisted-Gravity-Drainage ("SAGD") is a method for producing heavy oil
or bitumen from a heavy oil or bitumen-containing subterranean formation that
utilizes
gravity in combination with steam induced viscosity reduction of bitumen or
heavy oil to
recover oil from the formation. A paired injection well and production well
are drilled so
that portions of the wells that are in contact with the oil-containing portion
of the formation
extend horizontally through the formation, where the horizontally extending
portions of the
paired injection well and production well are aligned in parallel¨the
horizontally
extending portion of the production well located from 2 - 10 meters below the
horizontally
extending portion of the injection well. Steam is injected into the formation
through the
injection well, heating the bitumen or heavy oil around the injection well to
reduce the
viscosity thereof and to form an oil-in-water emulsion having reduced
viscosity relative to
the bitumen or heavy oil in the formation. The reduced viscosity bitumen or
heavy oil and
the oil-in-water emulsion are mobilized and fall towards the production well,
which
produces the mobilized oil and emulsion.
When conducting a SAGD process, a steam chamber is formed extending from the
injection well upwards into the formation. As steam is injected into the
formation, the
bitumen or heavy oil is mobilized and drains towards the production well,
leaving freed
pore space in the formation which is filled with further steam being injected
into the
formation. As steam is injected into the formation it traverses the steam
chamber to
contact new bitumen or heavy oil at the edges of the steam chamber, mobilizing
the new
bitumen or heavy oil for production from the production well.
Patent application publication WO 2009/108423 Al discloses a method of
improving the recovery of bitumen from a subterranean formation using a SAGD
process
in which steam and a volatile amine, steam and a volatile amine and ammonia,
or high
quality steam (having a vapor quality of at least 0.7) and ammonia are
injected into the
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formation. The volatile amine, volatile amine plus ammonia, or ammonia in
combination
with the high quality steam traverse the steam chamber to contact bitumen at
the edge of
the steam chamber. The volatile amine and/or ammonia can potentially react
with
naphthenic acids in the bitumen to form oil-emulsifying soaps. These soaps may
combine
with condensed water to form a low viscosity oil-in-water emulsion that may
drain to the
production well for recovery from the formation.
Injection of steam into the formation from the injection well in a SAGD
process or
a combination of high quality steam and ammonia, amines, or amines plus
ammonia does
not mobilize all of the bitumen or heavy oil in the steam chamber. Significant
quantities of
residual oil are left in place within the steam chamber that are not
recovered.
Improvements to steam-based bitumen or heavy oil recovery processes are
desirable. In particular, improvements to steam-based processes for recovery
of bitumen
or heavy oil that improve recovery of residual oil are desirable.
Summary of the Invention
In one aspect, the present invention is directed to a process for producing
oil
comprising injecting an oil recovery formulation comprising ammonia and steam
into a
subterranean oil-bearing formation comprising an oil or bitumen having a total
acid
number ("TAN") of at least 0.1, wherein the steam has a vapor quality of from
greater than
0 to less than 0.7; and producing oil or bitumen from the formation after
injection of the oil
recovery formulation into the formation. In one aspect, the process further
comprises the
steps of forming a steam chamber in the oil-bearing formation, injecting the
oil recovery
formulation into the steam chamber in the formation, and recovering residual
oil from the
steam chamber after injecting the oil recovery formulation into the formation.
In another aspect, the present invention is directed to a process for
producing oil,
comprising injecting steam having a vapor quality of from greater than 0 to
less than 0.7
into an oil-bearing formation comprising an oil or bitumen having a TAN of at
least 0.1;
injecting ammonia into the oil bearing formation to contact the steam and form
an oil
recovery formulation comprising ammonia and steam having a vapor quality of
from
greater than 0 to less than 0.7; contacting the oil recovery formulation with
oil in the
formation; and producing oil from the formation after contacting the oil with
the oil
recovery formulation.
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Brief Description of the Drawings
Fig. 1 illustrates an oil production system that may be used to practice the
process of the
present invention.
Fig. 2 illustrates an oil production system that may be used to practice the
process of the
present invention.
Fig. 3 illustrates a processing facility that may be used in the practice of
the process of the
present invention.
Fig. 4 illustrates an oil production system that may be used to practice the
process of the
present invention, depicting an oil recovery formulation being injected into
an oil-bearing
formation.
Fig. 5 illustrates an oil production system that may be used to practice the
process of the
present invention, depicting production of oil from the formation.
Fig. 6 illustrates an oil production system that may be used to practice the
process of the
present invention.
Detailed Description of the Invention
The present invention is directed to a process for enhancing the recovery of
oil
from a subterranean formation containing heavy oil or bitumen. An oil recovery
formulation comprising ammonia and low quality steam¨in particular, steam
having a
vapor quality of less than 0.7¨may be injected into the formation and oil may
be produced
from the formation after injection of the oil recovery formulation into the
formation. The
combination of ammonia and low quality steam in the oil recovery formulation
produces
ammonium hydroxide in the liquid phase aqueous condensate portion of the low
quality
steam so that the ammonium hydroxide is present in the oil recovery
formulation as the oil
recovery formulation is injected into the formation. The ammonium hydroxide
may react
with petroleum acids, e.g. naphthenic acids, in the bitumen or heavy oil in
the immediate
vicinity of the injecting well to form an oil-emulsifying soap that promotes
the formation
of an oil-in-water emulsion with condensed water from the steam, where the oil-
in-water
emulsion may have a significantly reduced viscosity and interfacial tension
relative to the
bitumen or heavy oil in the formation. The steam may also provide sensible and
latent
heat to bitumen or heavy oil in the immediate vicinity of the injecting well
to reduce the
viscosity of the bitumen or heavy oil in the immediate vicinity of the
injecting well. The
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reduced viscosity bitumen or heavy oil and the oil-in-water emulsion may be
mobilized in
the formation for production from the formation.
Alternatively, the process of the present invention may comprise injecting low
quality steam¨in particular, steam having a vapor quality of less than 0.7¨and
gaseous
ammonia or liquid ammonia separately into a heavy oil or bitumen containing
formation in
which the heavy oil or bitumen has a TAN of at least 0.1, and mixing the
injected steam
and ammonia in the immediate vicinity of the injecting well. The mixture of
low quality
steam and ammonia produces or contains ammonium hydroxide as a result of
interaction
with liquid phase water with ammonia, where the ammonium hydroxide may react
with
petroleum acids in the bitumen or heavy oil in the immediate vicinity of the
injecting well
to form an oil-emulsifying soap that promotes the formation of an oil-in-water
emulsion
that is less viscous and has lower interfacial tension than the heavy oil or
bitumen in the
formation and that is mobilized for production from the formation. The steam
also
provides sensible and latent heat to bitumen or heavy oil in the immediate
vicinity of the
injecting well to reduce the viscosity and mobilize the bitumen or heavy oil
for production.
The mobilized oil and oil-in-water emulsion may be produced from the
formation.
The process of the present invention is suited for improving recovery of oil
in a
SAGD process relative to conventional SAGD processes. As noted above,
significant
quantities of oil are left as residual oil in the steam chamber formed in a
SAGD process.
SAGD typically fails to recover about 45% of the initial bitumen or heavy oil
in a
formation.
In conventional SAGD processes, high quality steam is injected through the
steam
chamber to the edge of the steam chamber where the steam contacts bitumen,
cools and
provides sensible and latent heat to the bitumen at the edge of the steam
chamber, reducing
the viscosity and mobilizing the bitumen for production. The mobilized bitumen
falls to
the producing well, expanding the steam chamber as it is removed from the
formation. A
substantial portion of the heat provided by the high quality steam to the
bitumen at the
edge of the steam chamber is latent heat, which is not provided to residual
oil left in the
steam chamber since the steam is dry when passing through the steam chamber.
Therefore,
a substantial amount of the residual oil in the steam chamber is not mobilized
for
production by injection of high quality steam into the formation.
WO 2009/108423 A1 discloses a process for improving the recovery of bitumen in
a SAGD process by injecting a mixture of high quality steam and ammonia, an
amine and
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ammonia, or an amine into a subterranean bitumen formation. The process of WO
2009/108423 does not promote substantial recovery of residual oil in the steam
chamber
when high quality steam and ammonia are used in the process. The high quality
steam is
dry as it passes through the steam chamber, and fails to provide latent heat
of condensation
to lower the viscosity of the residual oil. Further, production of a mobile
oil-in-water
emulsion of the residual oil in the steam chamber is avoided since emulsion-
inducing
ammonium hydroxide is not formed in the steam chamber by reaction of ammonia
with
liquid phase water. The high quality steam is dry as it passes through the
steam chamber
and insufficient liquid phase water condensate is present in the steam chamber
to form
ammonium hydroxide with the injected ammonia sufficient to produce recoverable
quantities of an oil-in-water emulsion of the residual oil.
The process of the present invention may promote recovery of residual oil from
the
steam chamber. Unlike the process disclosed in WO 2009/108423, ammonium
hydroxide
is present in the immediate vicinity of the injecting well, and therefore, in
the steam
chamber in a SAGD process, when the oil recovery formulation or the mixture of
separately injected ammonia and low quality steam is injected into the
formation. The
ammonium hydroxide is present in the immediate vicinity of the injecting well
and in the
steam chamber because a sufficient quantity of water condensate is present to
react with
the ammonia to form ammonium hydroxide either in the oil recovery formulation
prior to
injecting the oil recovery formulation into the formation or immediately upon
mixing
separately injected ammonia and low quality steam into the formation. The
ammonium
hydroxide may react with petroleum acids of the residual oil in the steam
chamber to form
an oil-emulsifying soap that promotes the formation of a low viscosity oil-in-
water
emulsion with the water condensate of the low quality steam. The oil-in-water
emulsion
may be mobilized for production from the formation due to its low viscosity
and low
interfacial tension.
The process of the present invention is also suited for improving the oil
recovery in
a cyclic steam stimulation (CSS) process relative to a conventional CSS
process. Further,
the process of the present invention is also suited for improving the oil
recovery in a
vertical steam drive (VSD) process relative to a conventional VSD process.
The oil recovery formulation used in the process of the present invention is
comprised of ammonia and steam, where the steam used is of low quality,
specifically the
steam has a vapor quality of less than 0.7. As used herein, "vapor quality" is
defined as the
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fraction of the mass of a saturated fluid that is vapor. Vapor quality is
defined according to
the following equation: x = r
,Mvapori (Mvapor Mliquid)1, where x is the vapor quality and m is
mass (measured in the same units for each m). Fluids that are not saturated
fluids, such as
compressed fluids and superheated fluids, do not have a defined vapor quality.
The vapor
quality of steam may be calculated from the temperature and pressure of the
steam
according to conventional methods known to those of ordinary skill in the art.
The steam
of the oil recovery formulation may have a vapor quality of less than 0.7, or
from greater
than 0 to less than 0.7, or from 0.05 to 0.65, or from 0.25 to 0.6.
The ammonia of the oil recovery formulation is preferably gaseous anhydrous
ammonia. Alternatively, the ammonia of the oil recovery formulation may be
contained in
a gaseous ammonia-steam mixture (prior to being mixed with the low quality
steam of the
oil recovery formulation) containing up to 30 wt.% steam, or up to 20 wt.%
steam, or up to
10 wt.% steam, or up to 5 wt.% steam. Alternatively, but less preferably, the
ammonia
may be a pressurized anhydrous ammonia liquid, or may be contained in an
aqueous
ammonia solution containing up to 35% ammonia by mass.
The oil recovery formulation may contain ammonia in an amount effective to
form
sufficient ammonium hydroxide to react with petroleum acids in the oil to form
one or
more surfactants in a quantity sufficient to mobilize a portion of the oil in
the formation.
The oil recovery formulation may be comprised of from 0.001 wt.% to 90 wt.%
ammonia.
Preferably the amount of ammonia in the oil recovery formulation is at or near
a minimum
amount effective to form sufficient ammonium hydroxide to react with petroleum
acids in
the oil to form one or more surfactants in a quantity sufficient to mobilize a
portion of the
oil in the formation, thereby maximizing the amount of steam and thermal
energy provided
by the oil recovery formulation to the formation for mobilization of the oil.
In this
embodiment of the process of the present invention, the oil recovery
formulation may
contain from 50 parts per million (ppm) to 50,000 ppm by weight of ammonia, or
from 100
ppm to 10,000 ppm by weight of ammonia.
The oil recovery formulation used in the process of the present invention may
contain components other than low quality steam and ammonia. The oil recovery
formulation may contain an anionic surfactant or a non-ionic surfactant that
may form an
oil-emulsifying soap upon contacting bitumen or heavy oil in a formation,
promoting the
formation of a low viscosity oil-in-water emulsion with condensed water from
the oil
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recovery formulation and thereby mobilizing the bitumen or heavy oil for
production from
the formation. An anionic surfactant or non-ionic surfactant utilized in the
oil recovery
formulation should be stable at the temperature of the steam utilized in the
oil recovery
formulation. Anionic surfactants that may be utilized in the oil recovery
formulation may
be selected from the group of high temperature stable surfactants consisting
of an alpha
olefin sulfonate compound, an internal olefin sulfonate compound, a branched
alkyl
benzene sulfonate compound, a propylene oxide sulfate compound, an ethylene
oxide
sulfate compound, an ethylene oxide-propylene oxide sulfate compound, and
blends
thereof. Amine compounds may be absent from the oil recovery formulation, and
the oil
recovery formulation may be free of amine compounds. In an embodiment of a
process of
the present invention, the oil recovery formulation may consist essentially of
ammonia and
steam having a vapor quality of less than 0.7.
The oil recovery formulation may be produced by mixing ammonia and a low
quality steam having a vapor quality of less than 0.7, or having a vapor
quality of from
greater than 0 to less than 0.7, or from 0.05 to 0.65, or from 0.25 to 0.6.
The ammonia and
the low quality steam may be contacted and mixed to form the oil recovery
formulation
prior to introducing the oil recovery formulation to a well for injection into
a subterranean
formation containing bitumen or heavy oil. Alternatively, the ammonia and low
quality
steam may be contacted and mixed upon introduction of the ammonia and the low
quality
steam to a well for injection into a subterranean formation containing bitumen
or heavy oil,
or may be contacted and mixed within the injection well prior to injection of
the oil
recovery formulation into the formation.
In another embodiment, the ammonia and low quality steam may be injected
separately into a subterranean formation containing bitumen and heavy oil and
mixed to
form the oil recovery formulation in the immediate vicinity of the injection
well. In one
embodiment of the process of the present invention, the injection well may
have a conduit
extending from the wellhead to perforations or openings in the well at a
position located in
the formation through which the low quality steam may be injected and a
separate conduit
extending from the wellhead to perforations or openings in the well at a
position located in
the formation through which the ammonia may be injected into the formation,
where the
perforations or openings through which the steam is injected into the
formation and the
perforations or openings through which the ammonia is injected into the
formation are
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positioned in the well to ensure that the steam and ammonia are mixed together
upon
injection into the formation through the well. In one embodiment, perforations
or
openings or a set of perforations or openings in the well for injecting the
steam into the
formation and perforations or openings or a set of perforations or openings in
the well for
injecting ammonia into the formation are positioned to alternate along a
portion of the
injecting well within the formation.
In the process of the present invention, the oil recovery formulation, or
components
thereof, is/are introduced into an oil-bearing formation. The oil-bearing
formation
comprises oil that may be separated and produced from the formation after
contact and
mixing with the oil recovery formulation. The oil of the oil-bearing formation
is a heavy
oil or bitumen having a TAN of at least 0.1. "TAN", as used herein, refers to
a total acid
number of a bitumen or heavy oil expressed as milligrams ("mg") of KOH per
gram of the
heavy oil or bitumen as may be determined by ASTM Method D664.
The oil contained in the oil-bearing formation may have a dynamic viscosity
under
formation conditions (in particular, at temperatures within the temperature
range of the
formation) of at least 1 mPa s (1 cP), or at least 10 mPa s (10 cP), or at
least 100 mPa s
(100 cP), or at least 1000 mPa s (1000 cP), or at least 10000 mPa s (10000
cP). The oil
contained in the oil-bearing formation may have a dynamic viscosity under
formation
temperature conditions of from 1 to 10000000 mPa s (1 to 10000000 cP).
Typically, the
heavy oil or bitumen in the formation may have a dynamic viscosity of at least
100 mPa s
(100 cP), or at least 500 mPa s (500 cP), or at least 1000 mPa s (1000 cP).
The oil-bearing formation is a subterranean formation. The subterranean
formation
may be comprised of one or more porous matrix materials selected from the
group
consisting of a porous mineral matrix, a porous rock matrix, and a combination
of a porous
mineral matrix and a porous rock matrix, where the porous matrix material may
be located
beneath an overburden at a depth ranging from 50 meters to 6000 meters, or
from 100
meters to 4000 meters, or from 200 meters to 2000 meters under the earth's
surface. The
subterranean formation may be a subsea subterranean formation.
The porous matrix material may be a consolidated matrix material in which at
least
a majority, and preferably substantially all, of the rock and/or mineral that
forms the matrix
material is consolidated such that the rock and/or mineral forms a mass in
which
substantially all of the rock and/or mineral is immobile when oil, the oil
recovery
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formulation, water, or other fluid is passed therethrough. At least 95 wt.% or
at least 97
wt.%, or at least 99 wt.% of the rock and/or mineral may be immobile when oil,
the oil
recovery formulation, water, or other fluid is passed therethrough so that any
amount of
rock or mineral material dislodged by the passage of the oil, oil recovery
formulation,
water, or other fluid is insufficient to render the formation impermeable to
the flow of the
oil recovery formulation, oil, water, or other fluid through the formation.
Alternatively, the
porous matrix material may be an unconsolidated matrix material in which at
least a
majority, or substantially all, of the rock and/or mineral that forms the
matrix material is
unconsolidated. The formation may have a permeability of from 0.0001 to 15
Darcys, or
from 0.001 to 1 Darcy. The rock and/or mineral porous matrix material of the
formation
may be comprised of sandstone and/or a carbonate selected from dolomite,
limestone, and
mixtures thereof¨where the limestone may be microcrystalline or crystalline
limestone
and/or chalk.
Oil in the oil-bearing formation may be located in pores within the porous
matrix
material of the formation. The oil in the oil-bearing formation may be
immobilized in the
pores within the porous matrix material of the formation, for example, by
capillary forces,
by interaction of the oil with the pore surfaces, by the viscosity of the oil,
or by interfacial
tension between the oil and water in the formation.
The oil-bearing formation may also be comprised of water, which may be located
in pores within the porous matrix material. The water in the formation may be
connate
water, water from a secondary or tertiary oil recovery process water-flood, or
a mixture
thereof. The water in the oil-bearing formation may be positioned to
immobilize
petroleum within the pores. Contact of the oil recovery formulation with the
oil and water
in the formation may mobilize the oil in the formation for production and
recovery from
the formation by freeing at least a portion of the oil from pores within the
formation by
reducing interfacial tension between water and oil in the formation and by
reducing the
viscosity of the oil in the formation.
In some embodiments, the oil-bearing formation may comprise unconsolidated
sand and water. The oil-bearing formation may be an oil sand formation.
Unconsolidiated oil sand material of the oil sand formation may have a tensile
strength of
about 0 Pa. In some embodiments, the oil may comprise between about 1 wt.% and
about
16 wt.% of the oil/sand/water mixture, the sand may comprise between about 80
wt.% and
about 85 wt.% of the oil/sand/water mixture, and the water may comprise
between about 1
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wt.% and about 16 wt.% of the oil/sand water mixture. The sand may be coated
with a
layer of water with the oil being located in the void space around the wetted
sand grains.
Referring now to Figs. 1 and 2, oil production systems 100 are illustrated
that may
be used to practice one or more embodiments of a SAGD process in accordance
with the
process of the present invention. An oil production system 100 includes an oil-
bearing
formation 105 that may be comprised of oil-bearing portions 104, 106, and 108
located
beneath an overburden 102. The oil production system 100 may include a first
well 132
through which the oil recovery formulation, or components thereof, may be
injected into
the formation 105, and a second well 112 through which oil, water, and
optionally gas,
may be produced. The oil production system may also include a water storage
facility 116,
an ammonia storage facility 118, an oil recovery formulation storage facility
130, an oil
storage facility 134, and a gas storage facility 136.
The oil production system 100 may also include a processing facility 110. The
processing facility 110 may include a water processing system 120 and a
separation unit
122. Referring now to Fig. 3, the water processing system 120 may be comprised
of a
water purification unit 202 comprising one or more particulate filters 204,
which may
include an ultrafiltration membrane; one or more ionic filtration units 206
such as a
nanofiltration membrane unit and/or a reverse osmosis unit; and/or one or more
ion
exchange systems 208 for removing ions from water. Source water may enter the
water
purification unit 202 through line 212 and proceed through the particulate
filters 204 for
removal of suspended solids from the source water, and then proceed through
the ionic
filtration unit 206 and/or the ion exchange system 208 for removal of ions,
particularly
multivalent cations, from the water. The water processing system may also be
comprised
of a boiler 210 that is fluidly operatively coupled to the water purification
unit 202 via line
214 to receive purified water from the water purification unit. The boiler 210
may be
configured to produce low quality steam having a vapor quality of from greater
than 0 to
less than 0.7, or from 0.05 to 0.65, or from 0.25 to 0.6, from the purified
water produced by
the water purification unit, where the steam may be exported from the water
processing
system 120 via line 216.
The separation unit 122 of the processing facility 110 may be designed to
separate
oil, gas, and an aqueous phase produced from the formation. The separation
unit 122 may
be comprised of a 2-phase separator 230 and a water knockout vessel 232. The 2-
phase
separator 230 of the separation unit 122 may be fluidly operatively coupled to
the second
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well by conduit 234 to receive oil, gas, and an aqueous solution produced from
the
formation by the second well. The produced oil and aqueous solution may be
separated
from produced gas in the 2-phase separator 230, where the separated produced
gas may be
exported from the 2-phase separator and separation unit 122 through conduit
236. The
produced oil and aqueous solution may be provided from the 2-phase separator
230 to the
water knockout vessel 232 via conduit 238. The produced oil may be separated
from the
aqueous solution in the water knockout vessel, where separation aids such as a
demulsifier
and/or a brine solution may be provided to the water knockout vessel through
inlet 240 to
aid in the separation of the produced oil from the aqueous solution in
accordance with
methods known to those skilled in the art of separating oil and aqueous phases
from a fluid
containing an oil phase and an aqueous phase. The produced oil may be exported
from the
water knockout vessel 232 and the separation unit 122 through conduit 242, and
the
aqueous solution may be exported from the water knockout vessel 232 and the
separation
unit 122 through conduit 244.
Referring back to Figures 1 and 2, the first well 132 and the second well 112
extend
from the surface 140 into one or more of the oil-bearing portions 104, 106,
and 108 of the
subterranean oil-bearing formation 105. A subsurface portion 142 of the first
well 132 and
a subsurface portion 144 of the second well may traverse one or more oil-
bearing portions
of the formation 105. The subsurface portion 144 of the second, producing,
well 112 may
be located below the subsurface portion 142 of the first, injecting, well 132.
The
subsurface portions 142 and 144 of the first and second wells 132 and 112,
respectively,
may be positioned transverse to portions 146 and 148 of the first and second
wells 132 and
112, respectively, that extend from the surface 140 to the respective
subsurface portions
142 and 144 of the wells. The subsurface portion 142 of the first well 132 and
the
subsurface portion 144 of the second well 112 may extend horizontally through
the
formation, and the horizontally extending subsurface portion 144 of the second
well 112
may extend parallel to and below the horizontally extending subsurface portion
142 of the
first well 132.
The vertical spacing between the horizontal subsurface portion 142 of the
first well
132 and the horizontal subsurface portion 144 of the second well 112 may be
from 2
meters to 150 meters, or from 5 meters to 100 meters. The horizontal
subsurface portion
142 of the first well 132 and the horizontal subsurface portion 144 of the
second well 112
may have a length of from 25 meters to 2000 meters, or from 50 meters to 1000
meters, or
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from 100 meters to 500 meters. The horizontal subsurface portion 144 of the
second well
112 is preferably as long as, or longer than, the horizontal subsurface
portion 142 of the
first well 132.
As shown in Figure 1, a toe section 150 of the subsurface portion 142 of the
first
well 132 may be aligned with a heel section 152 of the subsurface portion 144
of the
second well. Alternatively, as shown in Figure 2, a heel section 154 of the
subsurface
portion 142 of the first well 132 may be aligned with the heel section 152 of
the subsurface
portion 144 of the second well 112. Referring again to Figures 1 and 2,
although the wells
132 and 112 are shown with an abrupt right angle transition from vertical to
horizontal, in
some embodiments wells 132 and 112 may have a smooth transition from vertical
to
deviated to horizontal, for example with a smooth curved radius.
Referring now to Figures 1, 2, and 3, in a process of the present invention
the oil
recovery formulation comprising ammonia and steam having a vapor quality of
from
greater than 0 to less than 0.7, or components thereof, is/are injected into
one or more oil-
bearing portions 104, 106, or 108 of the oil-bearing formation 105 comprising
heavy oil or
bitumen through the first, injecting, well 132. The oil recovery formulation
may be
provided to the first well 132 from an oil recovery formulation storage
facility 130 that is
fluidly operatively coupled to the first well via conduit 129 to provide the
oil recovery
formulation to the first well. Steam may be provided to the oil recovery
formulation
storage facility 130 by providing source water from the water storage facility
116 to the
water processing unit 120 of the processing facility 110 via conduit 212,
where particulates
and ions are removed from the source water in the water purification unit 202
and steam
having a vapor quality of from greater than 0 to less than 0.7 is formed in
the boiler 210
and provided to the oil recovery formulation storage facility via conduit 216.
Ammonia
may be provided to the oil recovery formulation storage facility 130 from the
ammonia
storage facility 118 via conduit 160. Alternatively, steam having a vapor
quality of from
greater than 0 to less than 0.7 may be provided directly from the boiler 210
to the first well
132 and ammonia may be provided directly from the ammonia storage facility to
the first
well 132 to form the oil recovery formulation near or within the first well,
or to be injected
into the formation as separate components that are mixed in the formation in
the immediate
vicinity of the first well to form the oil recovery formulation¨in which cases
the oil
recovery formulation storage facility 130 may be excluded from the system. The
amount
of ammonia included in the oil recovery formulation injected into the
formation, or
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injected into the formation to form the oil recovery formulation, may be from
0.001 wt.%
to 90 wt.% of the oil recovery formulation, or may be from 50 parts per
million (ppm) by
weight to 50,000 ppm by weight of the oil recovery formulation.
The oil recovery formulation, or components thereof, may be injected into the
formation 105 through the subsurface portion 142 of the first well 132. The
subsurface
portion 142 of the first well 132 may have perforations or openings along the
length of the
portion 142 through which the oil recovery formulation, or components thereof,
may be
injected into the formation.
The oil recovery formulation, or components thereof, may be injected into the
formation under sufficient pressure to introduce the oil recovery formulation,
or its
components, into the formation. The oil recovery formulation, or its
components, may be
injected into the formation at a pressure above the initial pressure of the
formation at the
injection point, and may be injected at a pressure ranging from immediately
above the
initial pressure of the formation up to the fracture pressure of the
formation, or even above
the fracture pressure of the formation. In an embodiment of the process of the
present
invention, the oil recovery formulation may be injected into the formation at
a pressure of
from immediately above the formation pressure to 37,000 kPa above the initial
pressure of
the formation.
Upon injection of the oil recovery formulation into the formation 105, the oil
recovery formulation may contact and mix with oil within the formation. If one
or more of
the components of the oil recovery formulation are injected separately, the
components of
the oil recovery formulation may be contacted and mixed in the immediate
vicinity of the
first, injecting, well 132 to form the oil recovery formulation, which then
may contact and
mix with oil in the formation. Contacting the oil recovery formulation with
oil in the
formation may reduce the viscosity of the oil, for example by heating the oil
with the
sensible heat and the latent heat of condensation of the steam in the oil
recovery
formulation. Contacting the oil recovery formulation with the oil in the
formation may
also induce the formation of an oil-in-water emulsion having a viscosity of
the same
magnitude as water by contact with water present in, or condensed from, the
low quality
steam of the oil recovery formulation. Ammonium hydroxide present in the oil
recovery
formulation as a result of contact of ammonia and water present in, or
condensed from, the
low quality steam may react with the oil to form an oil emulsifying soap that
may enhance
the formation of the oil-in-water emulsion.
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The oil in the formation may be mobilized for production by contact with the
oil
recovery formulation. The reduction of the oil viscosity by exchange of
thermal energy
with the steam of the oil recovery formulation and the formation of the low
viscosity oil-in-
water emulsion may mobilize the oil contacted by the oil recovery formulation
relative to
oil initially present in the formation. The mobilized reduced viscosity oil
and the oil-in-
water emulsion may be freed to fall toward the second, production, well 112,
from which
the oil and the emulsion may be produced from the formation.
The process of the present invention may comprise forming a steam chamber 170
in
the formation 205; injecting the oil recovery formulation or the components of
the oil
recovery formulation into the steam chamber 170; and recovering residual oil
from the
steam chamber after injecting the oil recovery formulation or the components
of the oil
recovery formulation into the steam chamber. The steam chamber 170 may be
formed by
injecting steam into the formation through the first well 132 and the second
well 112 for a
first period of time. The steam injected in this first period of time is
preferably high
quality dry steam having a vapor quality of at least 0.9. The steam injected
in the first
period of time reduces the viscosity of oil in the immediate vicinity of the
first well 132
and the second well 112. Steam injection may be stopped from the second well
132 after
the first period of time, and reduced viscosity oil may be produced from the
second well
132. Steam may be injected again through the second well to reduce the
viscosity of more
oil in the formation, and then the additional reduced viscosity oil may be
recovered from
the second well. Steam injection through the first and second wells 132 and
112, and
production of oil from the second well 112 may be continued in this manner
until a steam
chamber 170 is formed in the formation. The steam chamber has a reduced
quantity of oil
therein (the "residual oil") relative to the amount of oil present in the
formation at the
boundary of the steam chamber and portions of the formation outside of the
steam
chamber.
The oil recovery formulation, or components thereof, may be injected into the
steam chamber 170 through the subsurface portion 142 of the first well 132.
The oil
recovery formulation may contact the residual oil in the steam chamber 170 and
mobilize
the residual oil as described above relative to oil in the formation. The oil
recovery
formulation is suited to mobilize the residual oil in the steam chamber since
the steam is
low vapor quality steam containing a substantial amount of condensed water
containing
ammonium hydroxide that forms oil emulsifying soaps upon contacting the
residual oil,
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where the condensed water may then form an oil-in-water emulsion that is
mobilized for
production from the formation. The mobilized residual oil may fall from the
steam
chamber 170 to the second well 112 for production from the formation.
A portion of the oil recovery formulation may pass through the steam chamber
170
to the interface of the steam chamber with portions of the formation outside
of the steam
chamber. This portion of the oil recovery formulation may mobilize oil at the
interface of
the steam chamber and the portions of the formation outside the steam chamber
for
production from the formation as described above. The mobilized "interface"
oil may fall
from the interface to the second well 112 for production from the formation.
The mobilized oil, water, and optionally gas, may be produced from the
formation
through the second well 112 by conventional oil production processes. The well
112 may
include conventional mechanisms for producing oil from a formation, including
lift pumps,
lift gases, and/or a compressor for injecting gas into the formation to
produce the oil,
water, and optionally gas from the formation.
Referring now to Figures 1, 2, and 3, the oil, water, and gas produced from
the
formation through the second well may be processed and separated. The second
well 112
may be fluidly operatively coupled to the 2-phase separator 230 of the
separation unit 122
via conduit 234. As described above, the produced oil, produced gas, and an
aqueous
solution may be separated in the separation unit 122. The separated produced
oil may be
provided from the water knockout vessel 232 of the separation unit to the oil
storage
facility 134 via conduit 242. The separated produced gas may be provided from
the 2-
phase separator 230 of the separation unit 122 to the gas storage facility 136
via conduit
236. The separated aqueous solution may be provided from the water knockout
vessel 232
to the water storage facility 116 via conduit 244.
The process of the present invention may also be utilized in a cyclic steam
stimulation ("CSS") oil recovery process. Referring now to Figures 4 and 5, an
oil
production system utilizing a single well for injection and production
according to a CSS
process in accordance with the process of the present invention is shown. The
system 300
may be similar in some respects to the system 100 described above with
reference to Figs.
1 and 2 and with the water processing system of Fig. 2. Accordingly, the
system 300 may
be understood with reference to Figs. 1, 2, and 3, where like numerals are
used to indicate
like components that will not be described again in detail.
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As shown in Fig. 4, an oil recovery formulation comprised of ammonia and low
quality steam, or components thereof, may be injected into a formation 105
through well
312. The oil recovery formulation may be provided to the well 312 from an oil
recovery
formulation storage facility 130 via conduit 302, where ammonia may be
provided to the
oil recovery formulation storage facility 130 from an ammonia storage facility
118 via
conduit 160, and steam may be provided to the oil recovery formulation storage
facility via
conduit 216 from a water processing system 120 including a water purification
system and
a boiler for producing steam having a vapor quality of from greater than 0 to
less than 0.7
from water provided from a water storage facility 116 via conduit 212.
Alternatively, the
components of the oil recovery formulation may be provided separately to the
well 312
from the ammonia storage facility 118 and the water processing system 120 of
the
processing facility 110 for mixing at the well, within the well, or upon
injection into the
formation, as described above.
The oil recovery formulation, or components thereof, may be injected into the
formation 105 through the well 312 to contact and mix with heavy oil or
bitumen in the
formation, as shown by arrows 314. The oil recovery formulation may reduce the
viscosity
of the heavy oil or bitumen upon contact by heating the heavy oil or bitumen,
as described
above, and thereby mobilize the oil for recovery from the formation. The oil
recovery
formulation may also induce the formation of an oil-in-water emulsion by the
formation of
oil-emulsifying soaps produced by reaction of ammonium hydroxide with
petroleum acids
in the oil or bitumen and thereby form and mobilize an oil-in-water emulsion
for
production from the formation.
The oil recovery formulation, or components thereof, may be injected into the
formation through the well 312 for a first period of time after which
injection of the oil
recovery formulation, or components thereof, may be ceased. The oil recovery
formulation
may be allowed to soak in the formation after cessation of injection of the
oil recovery
formulation, or the components thererof.
Then, as shown in Fig. 5, the mobilized oil, water, and optionally gas, may be
produced from the formation through the well 312. The mobilized oil, water,
and
optionally gas, may be drawn through the formation as shown by arrows 316 for
production from the well. The well 312 may include conventional mechanisms for
producing oil from a formation, including lift pumps, lift gases, and/or a
compressor for
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injecting gas into the formation to produce the oil, water, and optionally gas
from the
formation.
The oil, water, enhanced oil recovery formulation, and gas produced from the
well
312 may be separated in the processing facility 110 and stored as described
above.
In one embodiment of a CSS process in accordance with the process of the
present
invention, prior to injecting the oil recovery formulation into the formation
and
subsequently recovering mobilized oil, water, and optionally gas therefrom,
high quality
steam having a vapor quality of at least 0.7, or at least 0.9, may be injected
into the
formation 105 through well 312 to contact and mix and soak with heavy oil or
bitumen in
the formation to mobilize the heavy oil or bitumen, and then the mobilized oil
may be
recovered through well 312. The cycle of injection of high quality steam into
the
formation; contacting, mixing, and soaking the high quality steam with the
bitumen or
heavy oil to mobilize the oil, and recovery of the mobilized oil from the well
may be
effected one or two or more times prior to injecting the oil recovery
formulation into the
formation; contacting, mixing, and soaking the oil recovery formulation with
bitumen or
heavy oil in the formation to mobilize the oil in the formation; and
recovering the
mobilized oil from the well through which the oil recovery formulation was
injected into
the formation. Use of the oil recovery formulation as described above after
CSS oil
recovery using high quality steam enables recovery of residual oil in the
formation.
The process of the present invention may also be utilized in a vertical steam
drive
("VSD") oil recovery process. Referring now to Fig. 6, an oil production
system 400 is
illustrated that may be used to practice one or more embodiments of a vertical
steam drive
(VSD) process in accordance with the process of the present invention. The
system may
be similar in some respects to the system 100 described above with respect to
Figs. 1 and 2
and the water processing system as shown in Fig. 3. Accordingly, the system
400 may be
understood with reference to Figs. 1, 2, and 3, where like numerals are used
to indicate like
components that will not be described again in detail.
As shown in Fig. 6, an oil recovery formulation comprised of ammonia and low
quality steam, or components thereof, may be injected into a formation 105
through a first
well 432. The oil recovery formulation may be provided to the first well 432
from an oil
recovery formulation storage facility 130 via conduit 129, where ammonia may
be
provided to the oil recovery formulation storage facility 130 from an ammonia
storage
facility 118 via conduit 160, and steam may be provided to the oil recovery
formulation
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storage facility via conduit 216 from a water processing system 120 including
a water
purification system and a boiler for producing steam having a vapor quality of
from greater
than 0 to less than 0.7 from water provided from a water storage facility 116
via conduit
212. Alternatively, the components of the oil recovery formulation may be
provided
separately to the first well 432 from the ammonia storage facility 118 and the
water
processing system 120 for mixing at the first well, within the first well, or
upon injection
into the formation 105, as described above.
The oil recovery formulation, or components thereof, may be injected into the
formation 105 through the first well 432 to contact and mix with heavy oil or
bitumen, as
described above, and thereby mobilize the oil for recovery from the formation.
The oil
recovery formulation may reduce the viscosity of the heavy oil or bitumen upon
contact by
heating the heavy oil or bitumen, as described above, and thereby mobilize the
oil for
recovery from the formation 105. The oil recovery formulation may also induce
the
formation of an oil-in-water emulsion by the formation of oil-emulsifying
soaps produced
by reaction of ammonium hydroxide with petroleum acids in the oil or bitumen
and
thereby form and mobilize an oil-in-water emulsion for production from the
formation.
The mobilized oil may be pushed across the formation 105 from the first well
432
to the second well 412 as shown by arrows 414 and 416 by further introduction
of more oil
recovery formulation into the formation or by introduction of an oil
immiscible drive fluid
into the formation subsequent to injection of the oil recovery formulation
into the
formation.
The oil immiscible drive fluid may be introduced into the formation 105
through
the first well 432 to force or otherwise displace the mobilized oil toward the
second well
412 for production. The oil immiscible drive fluid may be configured to
displace the
mobilized oil through the formation 105. Suitable oil immiscible drive fluids
are not first
contact miscible or multiple contact miscible with oil in the formation 105.
The oil
immiscible drive fluid may be selected from the group consisting of an aqueous
polymer
fluid, water, carbon dioxide at a pressure below its minimum miscibility
pressure, nitrogen
at a pressure below its minimum miscibility pressure, air, and mixtures of two
or more of
the preceding.
Suitable polymers for use in an aqueous polymer fluid may include, but are not
limited to, polyacrylamides, partially hydrolyzed polyacrylamides,
polyacrylates, ethylenic
copolymers, biopolymers, carboxymethylcellulose, polyvinyl alcohols,
polystyrene
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sulfonates, polyvinylpyrolidones, AMPS (2-acrylamide-2-methyl propane
sulfonate),
combinations thereof, or the like. 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, guar gum, alginates,
and
alginic acids and their salts. In some embodiments, polymers may be
crosslinked in situ in
the formation 105. In other embodiments, polymers may be generated in situ in
the
formation 105.
The oil immiscible drive fluid may be stored in, and provided for introduction
into
the formation 105 from, an oil immiscible drive fluid storage facility 420
that may be
fluidly operatively coupled to the first well 432 via conduit 422. The amount
of oil
immiscible drive fluid introduced into the formation 105 should be sufficient
to drive the
mobilized oil across at least a portion of the formation.
If the oil immiscible drive fluid is in liquid phase, the oil immiscible drive
fluid
may have a viscosity of at least the same magnitude as the viscosity of the
mobilized oil at
formation temperature conditions to enable the oil immiscible drive fluid to
drive the
mobilized oil across the formation 105 to the second well 412. The oil
immiscible
formulation may have a viscosity of at least 0.8 mPa s (0.8 cP) or at least 10
mPa s (10 cP),
or at least 50 mPa s (50 cP), or at least 100 mPa s (100 cP), or at least 500
mPa s (500 cP),
or at least 1000 mPa s (1000 cP), or at least 10000 mPa s (10000 cP) at
formation
temperature conditions or at 25 C. If the oil immiscible drive fluid is in
liquid phase,
preferably the oil immiscible drive fluid may have a viscosity at least one
order of
magnitude greater than the viscosity of the mobilized oil at formation
temperature
conditions so the oil immiscible drive fluid may drive the mobilized oil
across the
formation in plug flow, minimizing and inhibiting fingering of the mobilized
oil through
the driving plug of oil immiscible formulation.
The oil recovery formulation and the oil immiscible drive fluid may be
introduced
into the formation 105 through the first well 432 in alternating slugs. For
example, the oil
recovery formulation may be introduced into the formation 105 through the
first well 432
for a first time period, after which the oil immiscible drive fluid may be
introduced into the
formation through the first well for a second time period subsequent to the
first time
period, after which the oil recovery formulation may be introduced into the
formation
through the first well for a third time period subsequent to the second time
period, after
which the oil immiscible drive fluid may be introduced into the formation
through the first
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well for a fourth time period subsequent to the third time period. As many
alternating
slugs of the oil recovery formulation and the oil immiscible drive fluid may
be introduced
into the formation through the first well as desired.
Oil may be mobilized for production from the formation 105 via the second well
412 by introduction of the oil recovery formulation and, optionally, the oil
immiscible
drive fluid into the formation, where the mobilized oil is driven through the
formation for
production from the second well as indicated by arrows 416 by introduction of
the oil
recovery formulation and optionally the oil immiscible drive fluid into the
formation via
the first well 432.
The mobilized oil, water and optionally gas may be produced from the formation
105 through the second well 412 by conventional oil production processes. The
well 412
may include conventional mechanisms for producing oil from a formation,
including lift
pumps, lift gases, and/or a compressor for injecting gas into the formation to
produce the
oil, water, and optionally gas from the formation. Oil, water and gas produced
from the
formation may be processed, separated, and stored as described above.
In an embodiment of a VSD process in accordance with the process of the
present
invention, the first well 432 may be used for introducing the oil recovery
formulation and,
optionally, subsequently the oil immiscible drive fluid into the formation 105
and the
second well 412 may be used for producing oil, water, and optionally gas from
the
formation for a first time period; then the second well 412 may be used for
introducing the
oil recovery formulation and, optionally, subsequently the oil immiscible
drive fluid into
the formation 105 and the first well 432 may be used for producing oil, water,
and
optionally gas from the formation for a second time period; where the first
and second time
periods comprise a cycle. Multiple cycles may be conducted which include
alternating the
first well 432 and the second well 412 between introducing the oil recovery
formulation
and, optionally, subsequently the oil immiscible drive fluid into the
formation 105, and
producing oil, water, and optionally gas from the formation, where one well is
introducing
and the other is producing for the first time period, and then they are
switched for a second
time period. A cycle may be from about 12 hours to about 1 year, or from about
3 days to
about 6 months, or from about 5 days to about 3 months. The oil recovery
formulation
may be introduced into the formation at the beginning of a cycle and the oil
immiscible
drive fluid may be introduced at the end of the cycle. 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
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cycle, the first 25% to about 40% of a cycle, and the end may be the remainder
of the
cycle.
In one embodiment of a VSD process in accordance with the process of the
present
invention, high quality steam is injected through the first well 432 and oil
is produced from
the second well 412, or one or more cycles of alternately injecting high
quality steam and
producing oil from the first and second wells, respectively, is effected prior
to injecting the
oil recovery formulation into the formation and subsequently recovering
mobilized oil
therefrom. The high quality steam has a vapor quality of at least 0.7, and may
have a vapor
quality of at least 0.9, or at least 0.95, or at least 0.97. The high quality
steam may be
provided by the water processing system 120, where the operating conditions of
the boiler
210 may be adjusted to produce the high quality steam. The high quality steam
may be
injected into the formation 105 through the first well 432 to contact and mix
with heavy oil
or bitumen in the formation to mobilize the heavy oil or bitumen, and then the
mobilized
oil may be recovered through the second well 412. An oil immiscible drive
fluid as
described above may by injected into the formation subsequent to injection of
the high
quality steam to drive mobilized oil across the formation 105 for production
through the
second well 412. Alternating slugs of the high quality steam and the oil
immiscible drive
fluid may be injected into the formation through the first well 412 while
producing oil
through the second well 432 prior to injection of the oil recovery formulation
into the
formation and attendant recovery of oil from the formation. Optionally, cycles
of
alternating slugs of high quality steam and an oil immiscible drive fluid may
be injected
into the formation via the first and second wells while producing oil through
the second
and first wells, respectively, prior to injection of the oil recovery
formulation into the
formation and attendant recovery of oil from the formation. Injection of the
oil recovery
formulation into the formation subsequent to injection of high quality steam
and attendant
production of mobilized oil from the formation may promote the recovery of
residual oil
from the formation, where the residual oil is oil left in the formation and
not mobilized or
recovered by the injection of the high quality steam into the formation and
production of
oil mobilized by the high quality steam.
The present invention is well adapted to attain the ends and advantages
mentioned
as well as those that are inherent therein. The particular embodiments
disclosed above are
illustrative only, as the present invention may be modified and practiced in
different but
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equivalent manners apparent to those skilled in the art having the benefit of
the teachings
herein. Furthermore, no limitations are intended to the details of
construction or design
herein shown, other than as described in the claims below. It is therefore
evident that the
particular illustrative embodiments disclosed above may be altered, combined,
or modified
and all such variations are considered within the scope of the present
invention. The
invention illustratively disclosed herein suitably may be practiced in the
absence of any
element that is not specifically disclosed herein and/or any optional element
disclosed
herein. While compositions and methods are described in terms of "comprising,"
"containing," or "including" various components or steps, the compositions and
methods
can also "consist essentially of' or "consist of' the various components and
steps. All
numbers and ranges disclosed above may vary by some amount. Whenever a
numerical
range with a lower limit and an upper limit is disclosed, any number and any
included
range falling within the range is specifically disclosed. In particular, every
range of values
(of the form, "from about a to about b," or, equivalently, "from approximately
a to b," or,
equivalently, "from approximately a-b") disclosed herein is to be understood
to set forth
every number and range encompassed within the broader range of values. Also,
the terms
in the claims have their plain, ordinary meaning unless otherwise explicitly
and clearly
defined by the patentee. Moreover, the indefinite articles "a" or "an," as
used in the
claims, are defined herein to mean one or more than one of the element that it
introduces.
If there is any conflict in the usages of a word or term in this specification
and one or more
patent or other documents that may be incorporated herein by reference, the
definitions that
are consistent with this specification should be adopted.
23
