Note: Descriptions are shown in the official language in which they were submitted.
METHODS OF RECOVERING VISCOUS HYDROCARBONS FROM A
SUBTERRANEAN FORMATION
Field of the Disclosure
[0001] The present disclosure relates to methods of recovering viscous
hydrocarbons from a
subterranean formation.
Background of the Disclosure
[0002]
Hydrocarbons often are utilized as fuels and/or as chemical feedstocks for
manufacturing industries. Hydrocarbons naturally may be present within
subterranean
formations, which also may be referred to herein as reservoirs and/or as
hydrocarbon reservoirs.
Such hydrocarbons may occur in a variety of forms, which broadly may be
categorized herein as
conventional hydrocarbons and unconventional hydrocarbons. A process utilized
to remove a
given hydrocarbon from a corresponding subterranean folination may be selected
based upon
one or more properties of the hydrocarbon and/or of the subterranean
formation.
[0003]
As an example, conventional hydrocarbons generally have a relatively lower
viscosity
and extend within relatively higher fluid permeability subterranean
formations. As such, these
conventional hydrocarbons may be pumped from the subterranean formation
utilizing a
conventional oil well.
[0004] As another example, unconventional hydrocarbons generally have a
relatively higher
viscosity and/or extend within relatively lower fluid permeability
subterranean formations. As
such, a conventional oil well may be ineffective at producing unconventional
hydrocarbons.
Instead, unconventional hydrocarbon production techniques may be utilized.
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[0005] An example of an unconventional hydrocarbon production technique
that may be
utilized to produce viscous hydrocarbons from a subterranean formation
includes a vapor
extraction, or VAPEX, process, in which a solvent vapor is injected into the
subterranean
formation via an injection well. The solvent vapor contacts the viscous
hydrocarbons, within the
subterranean formation, dissolving and/or diluting the viscous hydrocarbons
and generating
reduced-viscosity hydrocarbons. The reduced-viscosity hydrocarbons also may be
referred to
herein as mobilized viscous hydrocarbons. The mobilized viscous hydrocarbons
may flow,
within the subterranean formation, to a production well, which produces the
mobilized viscous
hydrocarbons from the subterranean formation.
[0006] In a variant of the VAPEX process, which may be referred to herein
as heated
VAPEX and/or as H-VAPEX, the solvent vapor is heated prior to injection into
the subterranean
formation. The heated solvent vapor condenses in the subterranean foiniation
and both
dissolves/dilutes and heats the viscous hydrocarbons to generate the mobilized
viscous
hydrocarbons. Heating of the viscous hydrocarbons may decrease the viscosity
thereof and/or
may increase relative solubility between the solvent and the viscous
hydrocarbons, thereby
enhancing production of the viscous hydrocarbons from the subterranean
formation as mobilized
viscous hydrocarbons.
[0007] In a variant of the H-VAPEX process, which may be referred to
herein as azeotropic
heated VAPEX, as Azeo H-VAPEX, and/or as AH-VAPEX, steam is co-injected with
the
solvent vapor as a solvent-steam vapor mixture. In the AH-VAPEX process, a
relative
proportion of steam and solvent injection may be determined based upon phase
behavior of the
solvent-steam vapor mixture at an operating pressure within the subterranean
formation. More
specifically, the relative proportion of steam and solvent may be selected to
be at, or near, an
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azeotropic, or minimum boiling point, composition for the solvent-steam vapor
mixture. The
AH-VAPEX process is described in detail in Canadian Patent Application
Publication No.
2,915,571.
[0008] Solvents utilized in the AH-VAPEX process generally may include
hydrocarbon
solvents that include 3 to 12 carbon atoms. However, medium-boiling
hydrocarbon solvents,
such as those with 5 to 9 carbon atoms, may provide the highest production
rate of mobilized
viscous hydrocarbons from the subterranean formation. In contrast, lower-
boiling hydrocarbon
solvents, such as those with 3 to 5 carbon atoms, may provide lower production
rates of
mobilized viscous hydrocarbons from the subterranean formation.
[0009] While medium-boiling hydrocarbon solvents may be effective at
providing increased
production rates, they generally are more difficult to obtain and/or more
costly when compared
to lower-boiling hydrocarbon solvents. In addition, they may cause higher
energy use to produce
viscous hydrocarbons from the subterranean formation due to their relatively
higher saturation
temperature. Lower-boiling hydrocarbon solvents may be more economical to
obtain. In
addition, they may cause lower energy use to produce viscous hydrocarbons from
the
subterranean formation due to their relatively lower saturation temperature.
However, they
provide lower production rates and/or may facilitate formation of a second
heavy liquid phase
within the subterranean formation, thereby limiting overall production of the
viscous
hydrocarbons from the subterranean formation. These factors may cause the
economics of the
AH-VAPEX process to be unfavorable under certain conditions. Thus, there
exists a need for
improved methods of recovering viscous hydrocarbons from a subterranean
formation.
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Summary of the Disclosure
[0010] Methods of recovering viscous hydrocarbons from a subterranean
formation. The
methods include injecting a first solvent-steam vapor mixture into the
subterranean formation for
a first injection time period to maintain a target operating pressure within
the subterranean
formation. The first solvent-steam vapor mixture includes a first solvent and
steam and has a
first dew point temperature. A first solvent molar fraction of the first
solvent in the first solvent-
steam vapor mixture is 70%-100% of a first azeotropic solvent molar fraction
of the first solvent-
steam vapor mixture at the target operating pressure.
[0011] The methods also include transitioning, during a transition time
period, from injecting
the first solvent-steam vapor mixture to injecting a second solvent-steam
vapor mixture. The
second solvent-steam vapor mixture includes a second solvent and .steam and
has a second dew
point temperature. The second dew point temperature is less than the first dew
point
temperature.
[0012] The methods further include injecting the second solvent-steam
vapor mixture into
the subterranean formation for a second injection time period. The methods
also include
producing mobilized viscous hydrocarbons from the subterranean formation
during the injecting
the first solvent-steam vapor mixture, during the transitioning, and/or during
the injecting the
second solvent-steam vapor mixture.
Brief Description of the Drawings
[0013] Fig. 1 is a schematic representation illustrating examples of a
hydrocarbon production
system that may include and/or utilize methods according to the present
disclosure.
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[0014] Fig. 2 is a flowchart depicting methods, according to the present
disclosure, of
recovering viscous hydrocarbons from a subterranean formation utilizing
injection of a near-
azeotropic solvent-steam vapor mixture.
[0015] Fig. 3 is a schematic plot illustrating deposited heavy fraction
for mixtures of a
viscous hydrocarbon with different solvents, each mixture having a
concentration of solvent of
70 weight (wt.) % at 23 C, and onset solvent concentration to initiate heavy
fraction formation
for the mixtures of the viscous hydrocarbon with the different solvents.
[0016] Fig. 4 is a schematic plot illustrating dew point temperature as
a function of solvent
mole fraction for a plurality of solvent-steam vapor mixtures at a pressure of
0.5 MPa.
[0017] Fig. 5 is a schematic plot illustrating an example of an injectant
composition vs. time
that may be utilized with the methods of Fig. 2.
[0018] Fig. 6 is a schematic plot illustrating an example of another
injectant composition vs.
time that may be utilized with the methods of Fig. 2.
[0019] Fig. 7 is a schematic plot illustrating an example of another
injectant composition vs.
time that may be utilized with the methods of Fig. 2.
[0020] Fig. 8 is a schematic plot illustrating an example of mobilized
viscous hydrocarbon
production rate vs. time that may be generated by the methods of Fig. 2.
Detailed Description of the Embodiments
[0021] Figs. 1-8 provide examples of hydrocarbon production systems 10, of
methods 200,
and/or of data that may be utilized by and/or produced during performance of
methods 200,
according to the present disclosure. Elements that serve a similar, or at
least substantially
similar, purpose are labeled with like numbers in each of Figs. 1-8, and these
elements may not
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be discussed in detail herein with reference to each of Figs. 1-8. Similarly,
all elements may not
be labeled in each of Figs. 1-8, but reference numerals associated therewith
may be utilized
herein for consistency. Elements, components, and/or features that are
discussed herein with
reference to one or more of Figs. 1-8 may be included in and/or utilized with
any of Figs. 1-8
without departing from the scope of the present disclosure. In Figs. 1 and 2,
elements that are
likely to be included in a particular embodiment are illustrated in solid
lines, while elements that
are optional are illustrated in dashed lines. However, elements that are shown
in solid lines may
not be essential and, in some embodiments, may be omitted without departing
from the scope of
the present disclosure.
[0022] Fig. 1 is a schematic representation illustrating examples of a
hydrocarbon production
system 10 that may include and/or utilize methods according to the present
disclosure.
Hydrocarbon production system 10, which also may be referred to herein as a
system 10,
includes an injection well 40 that includes an injection wellhead 44 and an
injection wellbore 46
that extends within a subterranean formation 32. System 10 also includes a
production well 50
that includes a production wellhead 54 and a production wellbore 56 that
extends within the
subterranean formation. Injection wellbore 46 also may be referred to herein
as a wellbore 46.
Similarly, production wellbore 56 also may be referred to herein as a wellbore
56.
Wellbores 46/56 may extend within a subsurface region 30 and/or may extend
between a surface
region 20 and the subterranean formation. Subsurface region 30 may include an
overburden 36
that extends between, or spatially separates, surface region 20 and
subterranean formation 32.
[0023] As used herein, the phrase "subterranean formation" may refer to
any suitable portion
of the subsurface region that includes viscous hydrocarbons and/or from which
mobilized
viscous hydrocarbons may be produced utilizing the methods disclosed herein.
In addition to the
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viscous hydrocarbons, the subterranean formation also may include other
subterranean strata,
such as sand and/or rocks, as well as lower viscosity hydrocarbons, natural
gas, and/or water.
The subterranean strata may form, define, and/or be referred to herein as a
porous media, and the
viscous hydrocarbons may be present, or may extend, within pores of the porous
media.
[0024] As used herein, the phrase, "viscous hydrocarbons" may refer to any
suitable carbon-
containing compound and/or compounds that may be naturally occurring within
the subterranean
formation and/or that may have a viscosity that precludes their production, or
at least economic
production, utilizing conventional hydrocarbon production techniques and/or
conventional
hydrocarbon wells. Examples of such viscous hydrocarbons include heavy oils,
oil sands, and/or
bitumen.
[0025] As illustrated, wellbores 46/56 may include at least one vertical
region 64 and at least
one horizontal, or deviated, region 66. As also illustrated, the horizontal
region of injection
wellbore 46 may extend, within subterranean formation 32, vertically above the
horizontal region
of production wellbore 56.
[0026] During operation of system 10, and as discussed in more detail
herein with reference
to methods 200 of Fig. 2, injection well 40 may be utilized to inject an
injected stream 42, which
may be referred to herein as and/or may be a vapor mixture of steam and
solvent, into
subterranean formation 32 via wellbore 46. This also may be referred to herein
as providing the
injected stream to the subterranean formation. Injected stream 42 may flow
from wellbore 46
into the subterranean formation, wherein the injected stream may contact,
interact with, heat,
dissolve, and/or dilute viscous hydrocarbons 34 that naturally may be present,
or may occur,
within the subterranean formation. The interaction between the viscous
hydrocarbons and the
injected stream may generate reduced-viscosity hydrocarbons 35 within the
subterranean
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formation. Reduced-viscosity hydrocarbons 35 may flow, under the influence of
gravity and
within the subterranean formation, to production wellbore 56 as a produced
stream 52, and
production well 50 may convey the produced stream, via production wellbore 56,
from the
subterranean formation and/or to the surface region.
[0027] Injection of injected stream 42 and production of produced stream 52
may occur, may
be performed, and/or may be performed continuously, over a long period of
time, such as over
many days, weeks, months, or years. Injection of injected stream 42 and
production of produced
stream 52 from the subterranean formation may generate a vapor chamber 38
therein; and this
vapor chamber may grow, or increase in size and/or volume, responsive to
injection of the
injected stream and production of the produced stream, eventually reaching
and/or contacting
overburden 36. As used herein, the phrase "vapor chamber" may refer to any
suitable region of
the subterranean formation within which injection of the injected stream and
production of the
produced stream has depleted, at least substantially depleted, and/or depleted
a producible
fraction of naturally occurring viscous hydrocarbons.
[0028] As also illustrated in Fig. 1, system 10 may include an injected
stream source 70 and
a heating assembly 60. Injected stream source 70 may be configured to provide
one or more
suitable fluid streams to heating assembly 60. Heating assembly 60 may be
configured to heat
and/or combine the one or more fluid streams to produce and/or generate
injected stream 42,
which then may be provided to injection well 40. As discussed, the injected
stream may be a
vapor mixture of steam and solvent.
[0029] As illustrated in dashed lines in Fig. 1, system 10 also may be
configured to recycle a
portion of produced stream 52 as a recycled stream 80. Recycled stream 80 may
include
portions of injected stream 42 that are produced within produced stream 52 and
may be re-
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injected into subterranean formation 32, such as via being provided to, or
functioning as, injected
stream source 70 and/or via being provided to heating assembly 60.
[0030] As illustrated, injected stream source 70 may include a first
solvent source 72, a
second solvent source 74, and/or a water/steam source 76. As discussed in more
detail herein
with reference to methods 200 of Fig. 2, system 10 may be configured to inject
a first solvent-
steam vapor mixture into the subterranean formation and subsequently to inject
a second solvent-
steam vapor mixture into the subterranean formation. Injected stream 42 may
include the first
solvent-steam vapor mixture when first solvent source 72 and water/steam
source 76 provide
corresponding streams to heating assembly 60. Similarly, injected stream 42
may include the
second solvent-steam vapor mixture when second solvent source 74 and
water/steam source 76
provide corresponding streams to heating assembly 60.
[0031] As also discussed herein with reference to methods 200 of Fig. 2,
the first solvent-
steam vapor mixture may be injected at, or near, azeotropic, or minimum
boiling point,
conditions for a given target operating pressure within the subterranean
formation. Stated
another way, a relative concentration of the first solvent and steam may be
selected such that the
first solvent-steam vapor mixture forms an azeotrope at the target operating
pressure of the
subterranean formation. Stated yet another way, the first solvent-steam vapor
mixture may be
injected as part of an AH-VAPEX process, examples of which are discussed
herein.
[0032] For industrial applications, commercially available solvents
generally are a mixture of
hydrocarbon compounds rather than a pure single compound. Commercial gas
condensate,
diluents, and naphtha are among the used solvents. The phase behavior of these
multicomponent
solvents with steam is more complicated than that of single-component solvents
with steam.
However, their phase behavior when mixed with steam may be considered as a
superposition of
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the behavior of individual pure compounds. These systems exhibit a semi-
azeotropic behavior
with a minimum boiling characteristic similar to single compound solvents. The
discussion
herein involving azeotrope, azeotropic behavior, azeotropic solvent-steam
vapor mixture, and
near-azeotropic solvent-steam vapor mixture may be extended to a vapor mixture
of a
multicomponent solvent and steam vapor mixture by replacing the azeotrope
point with the
minimum boiling point of the multicomponent solvent and steam vapor mixture.
[0033] Solvents utilized in the AH-VAPEX process generally may include
hydrocarbon
solvents that include 3 to 12 carbon atoms. Examples of industrial solvents
composed of these
compounds are Natural gas liquids (NGL), liquefied petroleum gases (LPG), gas
condensates,
diluents, naphtha, and refinery products. Solvents and solvent mixtures
composed of medium-
boiling hydrocarbon solvents, such as those with 5 to 9 carbon atoms, may
provide the highest
production rate of mobilized viscous hydrocarbons from the subterranean
formation. In contrast,
solvents and solvent mixtures composed of lower-boiling hydrocarbon solvents,
such as those
with 3 to 5 carbon atoms, may provide lower production rates of mobilized
viscous hydrocarbons
from the subterranean formation. In addition, lower-boiling hydrocarbon
solvent mixtures
composed of solvents with 3-4 carbon atoms have a greater tendency to form a
second heavy
liquid phase when they are mixed with naturally occurring viscous hydrocarbons
such as heavy
oils, oil sands and/or bitumen.
[0034] Fig. 3 is a schematic plot illustrating the second heavy liquid
phase formation
tendency of normal, or straight-chain, alkane hydrocarbon compounds with 3 to
7 carbon atoms.
In Fig. 3, solvents with 3 carbon atoms are indicated as C3, solvents with 4
carbon atoms are
indicated as nC4, etc.
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[0035] In general, the lighter the hydrocarbon solvent compound is, the
lower is the onset
concentration of solvent to initiate the second heavy liquid phase formation.
For example, a
mixture of a heavy oil and C3 will form two liquid phases (light-solvent rich
and heavy) once the
concentration of C3 solvent in the mixture of solvent and heavy oil is greater
than approximately
20 weight percent. According to Fig. 3, at 23 C, approximately 45% of the
heavy oil mass will
deposit as the heavy fraction to the second heavy liquid phase in a mixture of
C3 solvent and
heavy oil with the concentration of C3 solvent in the mixture of solvent and
heavy oil equal to 70
weight percent. In contrast, as another example, a mixture of a heavy oil and
nC7 will form two
liquid phases (light-solvent rich and heavy) once the concentration of nC7
solvent in the mixture
of solvent and heavy oil is greater than approximately 56 weight percent.
According to Fig. 3, at
23 C, approximately 6% of the heavy oil mass will deposit as the heavy
fraction to the second
heavy liquid phase in a mixture of nC7 solvent and heavy oil with the
concentration of nC7
solvent in the mixture of solvent and heavy oil equal to 70 weight percent.
[0036] In the AH-VAPEX process, in general, the second heavy liquid
phase may be formed
in the subterranean formation due to mixing of hydrocarbon solvents and
naturally occurring
viscous hydrocarbons such as heavy oils, oil sands and bitumen. In general,
some or all of the
formed second heavy liquid phase may segregate from the production stream,
and/or may deposit
in the subterranean formation and may not be produced. The formation and
deposition of the
second heavy liquid phase in the subterranean formation may cause reduction of
the available
viscous hydrocarbons resource volumes for production. A significant resource
loss may be
unfavorable, as it may adversely affect the economic viability of the viscous
hydrocarbon
recovery.
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[0037] In contrast, due to formation and deposition of the second heavy
liquid phase, the
produced viscous hydrocarbon from the subterranean formation may have some
desirable
properties in comparison to the naturally occurring viscous hydrocarbons in
the subterranean
formation. Hence, the AH-VAPEX process may provide a desired degree of in situ
upgrading of
the viscous hydrocarbons within the subterranean formation. Examples of
desirable properties
are a lower viscosity, a higher API , a lower heavy metal compound content,
and/or a lower
asphaltene content. A balance between resource loss and the degree of in situ
upgrading of the
viscous hydrocarbons may provide the most favorable economic performance of
the AH-
VAPEX process.
[0038] While medium-boiling hydrocarbon solvents may be effective at
providing increased
production rates, they generally are more difficult to obtain and/or more
costly when compared
to lower-boiling hydrocarbon solvents. In addition, they may cause higher
energy use to produce
viscous hydrocarbons from the subterranean formation due to their relatively
higher saturation
temperature. They also may cause a lower degree of in situ upgrading of
viscous hydrocarbons
within the subterranean formation. In contrast, they may prevent higher
volumes of viscous
hydrocarbons resource losses.
[0039] Lower-boiling hydrocarbon solvents may be more economical to
obtain. In addition,
they may cause lower energy use to produce viscous hydrocarbons from the
subterranean
formation due to their relatively lower saturation temperature. However, they
provide lower
production rates and/or may facilitate a greater degree of formation of the
second heavy liquid
phase within the subterranean formation. Thus, injection of lower-boiling
hydrocarbons may
result in a higher degree of in situ upgrading of viscous hydrocarbons within
the subterranean
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formation. In contrast, they also may cause greater volumes of resource
losses, thereby limiting
overall production of the viscous hydrocarbons from the subterranean
formation.
[0040] As discussed herein, the AH-VAPEX process generally is performed
utilizing
medium-boiling hydrocarbon solvents. As also discussed, the AH-VAPEX process,
when
performed utilizing medium-boiling hydrocarbon solvents, is quite effective at
producing
mobilized viscous hydrocarbons within the subterranean formation; however, the
medium-
boiling hydrocarbon solvents may be costly. With this in mind, the present
disclosure transitions
from injection of the first solvent-steam vapor mixture, as part of the AH-
VAPEX process, to
injection of the second solvent-steam vapor mixture, which also may be part of
the AH-VAPEX
process.
[0041] The first solvent in the solvent-steam vapor mixture may have a
first dew point
temperature, and the second solvent in the solvent-steam vapor mixture may
have a second dew
point temperature that is less than the first dew point temperature. Stated
another way, the
second solvent-steam vapor mixture may include a second solvent that is, on
average, lighter
and/or more volatile than the first solvent that is included in the first
solvent-steam vapor
mixture. Stated yet another way, an average number of carbon atoms in
hydrocarbon molecules
that comprise the second solvent may be less than an average number of carbon
atoms in
hydrocarbon molecules that comprise the first solvent.
[0042] This transition from the first solvent-steam vapor mixture to the
second solvent-steam
vapor mixture may provide several benefits over the prior art. As an example,
the second solvent
generally is cheaper to purchase, cheaper to obtain, and/or less valuable when
compared to the
first solvent. The transition from the first solvent-steam vapor mixture to
the second solvent-
steam vapor mixture decreases an overall volume of the first solvent that is
utilized during
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production of the viscous hydrocarbons from the subterranean formation,
thereby decreasing an
overall cost of the production process.
[0043] As another example, injection of the second solvent-steam vapor
mixture may
provide a motive force for production of the first solvent, or of mobilized
viscous hydrocarbons
that include the first solvent, from the subterranean formation. In general,
some of the injected
first solvent may be retained within the subterranean formation and/or within
the vapor chamber
due to thermodynamic equilibrium conditions and fluid flow behaviors in a
porous media that
extends within the subterranean formation. The retained first solvent may be
present in vapor
and/or liquid phases. The injection of the second solvent in the second
solvent-steam vapor
mixture may dilute the retained first solvent in the vapor phase and strip and
evaporate the
retained first solvent in liquid phase to vapor phase as described herein.
Thus, the transition
from the first solvent-steam vapor mixture to the second solvent-steam vapor
mixture may
increase recovery of the first solvent from the subterranean formation,
thereby decreasing the
overall cost of the production process.
[0044] As yet another example, and since the second dew point temperature
is less than the
first dew point temperature, the transition from the first solvent-steam vapor
mixture to the
second solvent-steam vapor mixture may decrease an overall energy requirement
of the
production process. More specifically, injection of the first solvent-steam
vapor mixture may
heat the subterranean formation to a first temperature. This may include
storage of a significant
amount of thermal energy within the subterranean formation. In contrast,
injection of the second
solvent-steam vapor mixture may permit the temperature of the subterranean
formation to
decrease to a second temperature that is less than the first temperature.
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[0045] The first temperature and the second temperature of the
subterranean formation may
be directly related to the first dew point of the first solvent and the second
dew point of the
second solvent, respectively. In general, after the transition, the injected
second solvent in the
second solvent-steam vapor mixture may not condense within the subterranean
formation before
the temperature of the subterranean formation is reduced to the second
temperature. During this
period, the second solvent may act as a diluting and/or stripping agent and
may change the
thermodynamic equilibrium condition in the vapor chamber in favor of
evaporation of the
retained liquid first solvent. The latent heat of evaporation of the retained
liquid first solvent
may be provided by the stored thermal energy from the subterranean formation.
Thus, injection
of the second solvent-steam vapor mixture facilitates recovery of a portion of
the stored thermal
energy from the subterranean formation by the decrease of the subterranean
formation
temperature from the first temperature to the second temperature and by the
evaporation of the
retained liquid first solvent.
[0046] As discussed in more detail herein, the transition from injection
of the first solvent-
steam vapor mixture to the second solvent-steam vapor mixture may occur in any
suitable
manner. As an example, the transition may include a step change in which
system 10 ceases
injection of the first solvent-steam vapor mixture concurrently with, or
before, initiating injection
of the second solvent-steam vapor mixture. As another example, the transition
may include one
or more staged, stepped, and/or ramped changes in solvent injection. As a more
specific
example, injection of the first solvent-steam vapor mixture may be ramped down
and injection of
the second solvent-steam vapor mixture concurrently may be ramped up. As
another more
specific example, injection of the first solvent-steam vapor mixture may be
decreased in a series
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of steps and injection of the second solvent-steam vapor mixture concurrently
may be increased
in a series of steps.
[0047] Fig. 2 is a flowchart depicting methods 200, according to the
present disclosure, of
recovering viscous hydrocarbons from a subterranean formation utilizing
injection of a near-
azeotropic solvent-steam vapor mixture. Methods 200 may include selecting a
target operating
pressure at 205, selecting a first solvent at 210, and/or determining a first
azeotropic solvent
molar fraction for a first solvent-steam vapor mixture at 215. Methods 200
include injecting the
first solvent-steam vapor mixture at 220 and transitioning at 225. Methods 200
also may include
selecting a second solvent at 230, determining a second azeotropic solvent
molar fraction for a
second solvent-steam vapor mixture at 235, and/or ceasing injection of the
first solvent-steam
vapor mixture at 240. Methods 200 also include injecting the second solvent-
steam vapor
mixture at 245 and may include recovering the second solvent from the
subterranean formation
at 250. Methods 200 further include producing mobilized viscous hydrocarbons
at 255 and may
include separating a recycled solvent stream at 260.
[0048] Selecting the target operating pressure at 205 may include selecting
any suitable
target operating pressure for the subterranean formation during a remainder of
methods 200,
selecting a target operating pressure to be maintained, within the reservoir,
by the injecting at
220, and/or selecting a target operating pressure to be maintained, within the
reservoir, by the
injecting at 245. The selecting at 205 may be based upon any suitable
criteria. As an example,
the selecting at 205 may be based, at least in part, on a vertical depth,
within the subterranean
formation, for the injecting at 220 and/or for the injecting at 245. Stated
another way, the
selecting at 205 may be based, at least in part, upon a vertical depth, within
the subterranean
formation, at which the injecting at 220 and/or the injecting at 245 are
performed. As additional
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examples, the selecting at 205 may be based, at least in part, on one or more
of a fracture
pressure of the subterranean formation, a hydrostatic pressure within the
subterranean formation,
a lithostatic pressure within the subterranean formation, a gas cap pressure
for a gas cap that
extends within the subterranean formation, and/or an aquifer pressure for an
aquifer that extends
above and/or below the subterranean formation.
[0049] It is within the scope of the present disclosure that the target
operating pressure may
be constant, or at least substantially constant, during methods 200, during
the injecting at 220,
during the transitioning at 225, and/or during the injecting at 245.
alternatively, it also is within
the scope of the present disclosure that the target operating pressure may
vary, may be varied,
and/or may be systematically varied during methods 200, during the injecting
at 220, during the
transitioning at 225, and/or during the injecting at 245.
[0050] Examples of the target operating pressure include target
operating pressures that are
at least 5%, at least 10%, at least 20%, at least 30%, at least 40%, at least
50%, at least 60%, at
least 70%, at least 80%, at least 90%, at most 95%, at most 90%, at most 80%,
at most 70%, at
most 60%, at most 50%, at most 40%, at most 30%, at most 20%, and/or at most
10% of the
fracture pressure of the subterranean formation. Additional examples of the
target operating
pressure include target operating pressures of at least 0.1 megapascals (MPa),
at least 0.2 MPa, at
least 0.3 MPa, at least 0.4 MPa, at least 0.6 MPa, at least 0.8 MPa, at least
1 MPa, at least 1.25
MPa, at least 1.5 MPa, at least 2 MPa, at least 2.5 MPa, at most 5 MPa, at
most 4.5 MPa, at
most 4 MPa, at most 3.5 MPa, at most 3 MPa, at most 2.5 MPa, and/or at most 2
MPa.
[0051] Selecting the first solvent at 210 may include selecting the
first solvent based, at least
in part, on the target operating pressure within the subterranean formation.
As an example, the
selecting at 210 may include selecting such that the first solvent forms a
first vapor at the target
17
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operating pressure. As another example, the selecting at 210 may include
selecting such that the
first solvent forms a first azeotropic, or near-azeotropic, vapor mixture with
water at the target
operating pressure.
[0052] The selecting at 210 may include selecting based, at least in
part, on phase behavior
of the first solvent and/or on phase behavior of mixtures of the first solvent
and water. As an
example, Fig. 4 is a schematic plot illustrating dew point temperature as a
function of solvent
mole fraction for a plurality of different water-solvent mixtures that form
azeotropes 100 at a
pressure of 0.5 MPa. These water-solvent mixtures include mixtures of water
with butane (C4),
or with pentane (C5), or with hexane (C6), or with heptane (C7), or with
octane (C8), and or with
nonane (C9). Fig. 4 illustrates phase behavior for normal-alkane hydrocarbon
molecules;
however, it is within the scope of the present disclosure that any suitable
hydrocarbon molecule,
and corresponding phase behavior, may be utilized.
[0053] Thus, and for a target operating pressure of 0.5 MPa, the phase
behavior illustrated in
Fig. 4 may be utilized to select a solvent, or a relative concentration of
water and solvent in a
water-solvent mixture, that forms a vapor at the target operating pressure. As
an example, a
mixture of a solvent and water forms a vapor mixture when at a temperature
that is above dew
point temperature line 110 of Fig. 4.
[0054] Additionally or alternatively, the phase behavior illustrated in
Fig. 4 may be utilized
to select a solvent, or a relative concentration of water and solvent in a
water-solvent vapor
mixture, that forms an azeotrope at the target operating pressure. As an
example, Fig. 4
illustrates that C4-C9 solvent-steam vapor mixtures form azeotropes 100 at
corresponding
relative solvent-steam compositions and at corresponding azeotropic dew point
temperatures.
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[0055] Determining the first azeotropic solvent molar fraction at 215
may include
determining the first azeotropic solvent molar fraction in any suitable
manner. As an example,
the phase behavior illustrated in Fig. 4 may be utilized to determine the
first azeotropic solvent
molar fraction. As a more specific example, Fig. 4 illustrates that a vapor
mixture of water and
C7 solvent forms an azeotrope at 0.5 MPa and a molar composition of
approximately 52% water
and 48% heptane. Thus, the first azeotropic solvent molar fraction for the
water-heptane vapor
mixture at 0.5 MPa is approximately 48% heptane. A near-azeotropic vapor
mixture of heptane
and water contains 70-100% of the azeotropic heptane solvent molar fraction of
the heptane-
steam mixture. Stated another way, heptane molar fraction in a near-azeotropic
vapor mixture of
heptane and water is approximately 33.6-48 % heptane at 0.5 MPa.
[0056] Injecting the first solvent-steam vapor mixture at 220 may
include injecting the first
solvent-steam vapor mixture into the subterranean formation during a first
injection time period.
The injecting at 220 also may include injecting the first solvent-steam vapor
mixture to produce,
generate, support, sustain, promote, and/or maintain the target operating
pressure within the
subterranean formation. As discussed herein, the first solvent-steam vapor
mixture includes a
first solvent and steam. As also discussed herein, the first solvent-steam
vapor mixture is
injected into the subterranean formation at azeotropic, or near-azeotropic,
conditions. More
specifically, the first solvent-steam vapor mixture may be injected such that
a first solvent molar
fraction of the first solvent in the first solvent-steam vapor mixture is
within a threshold fraction
of the first azeotropic solvent molar fraction of the first solvent-steam
vapor mixture at the target
operating pressure. Examples of the threshold fraction include threshold
fractions of at
least 70%, at least 80%, at least 90%, at least 95%, at most 100%, at most
95%, at most 90%,
and/or at most 85% of the first azeotropic solvent molar fraction.
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[0057] The first solvent-steam vapor mixture additionally or
alternatively may include any
suitable volumetric relative proportion of the first solvent and steam to be
considered an
azeotropic or near-azeotropic vapor mixture. As an example, an azeotropic
vapor mixture of
heptane and steam includes approximately 88 volume percent heptane and 12
volume percent
steam in cold liquid equivalents calculated at standard temperature and
pressure. As another
example, a near-azeotropic vapor mixture of heptane and steam includes
approximately 80-88
volume percent heptane and 12-20 volume percent steam in cold liquid
equivalents calculated at
standard temperature and pressure. In general, depending on the selected first
solvent, the first
solvent-steam vapor mixture may include at least 15 volume percent first
solvent, at least 20
volume percent first solvent, at least 30 volume percent first solvent, at
least 40 volume percent
first solvent, at least 50 volume percent first solvent, at least 60 volume
percent first solvent, at
least 70 volume percent first solvent, at least 80 volume percent first
solvent, at least 90 volume
percent first solvent, at most 98 volume percent first solvent, at most 95
volume percent first
solvent, at most 90 volume percent first solvent, at most 80 volume percent
first solvent, at most
70 volume percent first solvent, at most 60 volume percent first 'solvent, at
most 50 volume
percent first solvent, at most 40 volume percent first solvent, at most 30
volume percent first
solvent, and/or at most 20 volume percent first solvent in cold liquid
equivalents calculated at
standard temperature and pressure.
[0058] As additional examples, the first solvent-steam vapor mixture may
include at least 2
volume percent steam, at least 3 volume percent steam, at least 5 volume
percent steam, at least
10 volume percent steam, at least 20 volume percent steam, at least 30 volume
percent steam, at
least 40 volume percent steam, at least 50 volume percent steam, at least 60
volume percent
steam, at least 70 volume percent steam, at least 80 volume percent steam, at
most 85 volume
CA 2974714 2017-07-27
percent steam, at most 80 volume percent steam, at most 70 volume percent
steam, at most 60
volume percent steam, at most 50 volume percent steam, at most 40 volume
percent steam, at
most 30 volume percent steam, at most 20 volume percent steam, and/or at most
10 volume
percent steam in cold liquid equivalents calculated at standard temperature
and pressure.
[0059] The injecting at 220 may include injecting the first solvent-steam
vapor mixture with,
via, and/or utilizing an injection well that extends within the subterranean
formation. Examples
of the injection well are discussed herein with reference to injection well 40
of Fig. 1.
[0060] It is within the scope of the present disclosure that the
injecting at 220 further may
include generating the mobilized viscous hydrocarbons, within the subterranean
formation, from
the viscous hydrocarbons. As examples, the generating may include heating the
viscous
hydrocarbons with the first solvent-steam vapor mixture to generate the
mobilized viscous
hydrocarbons, diluting the viscous hydrocarbons with a condensed first solvent
of the first
solvent-steam vapor mixture to generate the mobilized viscous hydrocarbons,
and/or dissolving
the viscous hydrocarbons in the condensed first solvent of the first solvent-
steam vapor mixture
to generate the mobilized viscous hydrocarbons.
[0061] The first solvent-steam vapor mixture may include any suitable
first solvent and
water, or steam, in any suitable relative concentration that is azeotropic, or
near-azeotropic, at the
target operating pressure. Examples of the first solvent include medium-
boiling hydrocarbons
including hydrocarbon molecules with at least 4, at least 5, at least 6, at
least 7, at most 10, at
most 9, at most 8, at most 7 carbon atoms, between 4-10 carbon atoms, and/or
between 5-9
carbon atoms. The first solvent may include any suitable proportion, fraction,
and/or percentage,
of the medium-boiling hydrocarbons. As examples, the first solvent may include
at least 40
weight percent, at least 50 weight percent, at least 60 weight percent, at
least 70 weight percent,
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at least 80 weight percent, at least 90 weight percent, at most 99 weight
percent, at most 95
weight percent, at most 90 weight percent, and/or at most 80 weight percent of
the medium-
boiling hydrocarbons. Stated another way, hydrocarbon molecules within the
first solvent may
have and/or define a first average carbon number of at least 4, at least 5, at
least 6, at least 7, at
least 8, at least 9, at most 10, at most 9, at most 8, at most 7, between 4-
10, and/or between 5-9.
As used herein, the phrase "first average carbon number" refers to an average,
or mean, number
of carbon atoms within the hydrocarbon molecules that comprise the first
solvent. Additional
examples of the first solvent include hydrocarbons, alkanes, alkenes, alkynes,
aliphatic
compounds, naphthenic compounds, aromatic compounds, olefinic compounds,
natural gas
condensate, liquefied petroleum gas, and/or a crude oil refinery stream.
100621 It is within the scope of the present disclosure that the
injecting at 220 may include
injecting the first solvent-steam vapor mixture with any suitable steam
quality. As examples, the
steam quality may be at least 5%, at least 10%, at least 20%, at least 40%, at
least 60%, at least
80%, at most 100%, at most 90%, and/or at most 80%.
[0063] The injecting at 220 may include injecting the first solvent-steam
vapor mixture at
any suitable injection temperature. As examples, the injection temperature may
be at least 20 C,
at least 30 C, at least 40 C, at least 50 C, at least 60 C, at least 70
C, at least 80 C, at
least 90 C, at least 100 C, at least 150 C, at most 300 C, at most 250 C,
at most 200 C,
and/or at most 150 'C. As additional examples, the injecting at 220 may
include injecting with at
least a threshold degree of superheat relative to a first saturation
temperature of the first solvent-
steam vapor mixture at the target operating pressure. Examples of the
threshold degree of
superheat include at least 1 C of superheat, at least 2 C of superheat, at
least 5 C of superheat,
at least 10 C of superheat, at least 20 C of superheat, at most 60 C of
superheat, at most 50 C
22
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of superheat, at most 40 C of superheat, at most 30 C of superheat, and/or
at most 20 C of
superheat.
100641 The first solvent may have and/or define any suitable first dew
point temperature. As
examples, and at a pressure of 101.325 kilopascals, the first dew point
temperature may be at
least 20 C, at least 40 C, at least 60 C, at least 80 'C, at least 100 C,
at least 120 C, at
least 140 C, and/or at least 160 C.
[0065] Transitioning at 225 may include transitioning from the injecting
at 220 to the
injecting at 245 and may be performed during a transition time period. The
second solvent-
steam vapor mixture, which is injected during the injecting at 245, includes a
second solvent and
steam, and the second solvent has a second dew point temperature that is less
than the first dew
point temperature of the first solvent. As discussed in more detail herein,
the transitioning at 225
may include transitioning in any suitable manner, including an abrupt
transition, a step-change
transition, a gradual transition, a graded transition, a continuous
transition, and/or a stepped
transition.
[0066] As an example, the transitioning at 225 may include the abrupt
and/or step-change
transition. Such a transition may be simple to implement but may increase a
potential for
generation of the second heavy liquid phase due to the injection of the second
solvent-steam
vapor mixture, or precipitation of asphaltenes, within the subterranean
formation.
[0067] The abrupt and/or step-change transition may include ceasing the
injecting the first
solvent-steam vapor mixture and concurrently, or subsequently, initiating the
injecting the
second solvent-steam vapor mixture. The abrupt and/or step-change transition
additionally or
alternatively may include instantaneously, or at least substantially
instantaneously, ceasing the
23
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injecting the first solvent-steam vapor mixture and/or instantaneously, or at
least substantially
instantaneously, initiating the injecting the second solvent-steam vapor
mixture.
[0068]
An example of the abrupt and/or step transition is illustrated in Fig. 5. As
illustrated
therein, and during first injection time period 90, an injectant, or injected
stream, that is provided
to the subterranean formation includes, primarily includes, and/or consists
essentially of first
solvent-steam vapor mixture 91. Then, and during transition time period 92,
injection of the first
solvent-steam vapor mixture ceases, and injection of the second solvent-steam
vapor mixture is
initiated. Subsequently, and during second injection time period 94, the
injectant that is provided
to the subterranean formation includes, primarily includes, and/or consists
essentially of second
solvent-steam vapor mixture 95. Fig. 5 illustrates transition time period
92 as being
instantaneous, or nearly instantaneous. However, this is simply for
illustrative purposes, and it is
to be understood that the transition time period generally will be a finite
time period.
[0069]
As another example, the transitioning at 225 may include the gradual,
graded, and/or
continuous transition. Such a transition may decrease a potential for
formation of the second
heavy liquid phase due to the injection of the second solvent-steam vapor
mixture and/or for
precipitation of asphaltenes within the subterranean formation.
[0070]
The gradual, graded, and/or continuous transition may include continuing the
injecting the first solvent-steam vapor mixture subsequent to initiating the
injecting the second
solvent-steam vapor mixture. This may include decreasing, or systematically
decreasing, a first
flow rate of the first solvent-steam vapor mixture and increasing,
systematically increasing,
and/or concurrently increasing, a second flow rate of the second solvent-steam
vapor mixture,
such as to maintain the target operating pressure within the subterranean
formation. Stated
another way, the graded, gradual, and/or continuous transition may include
injecting, or
24
CA 2974714 2017-07-27
concurrently injecting, both the first solvent-steam vapor mixture and the
second solvent-steam
vapor mixture during the transition time period.
[0071] When the transitioning at 225 includes the gradual, graded,
and/or continuous
transition, it is within the scope of the present disclosure that a rate of
change in the flow rates of
the first and second solvent-steam vapor mixtures may be regulated and/or
controlled in any
suitable manner. As an example, a first rate of change of the first flow rate
may be selected, or
systematically selected, to provide a desired degree of in situ upgrading of
the viscous
hydrocarbons within the subterranean formation. As another example, a second
rate of change of
the second flow rate may be selected, or systematically selected, to provide a
desired degree of in
situ upgrading of the viscous hydrocarbons within the subterranean formation.
[0072] An example of the gradual, graded, and/or continuous transition
is illustrated in Fig.
6. As illustrated therein, and during first injection time period 90, the
injectant that is provided
to the subterranean formation includes, primarily includes, and/or consists
essentially of first
solvent-steam vapor mixture 91. Then, and during transition time period 92,
injection of the first
solvent-steam vapor mixture gradually decreases, and injection of the second
solvent-steam
vapor mixture is initiated and gradually increases. Subsequently, and during
second injection
time period 94, the injectant that is provided to the subterranean formation
includes, primarily
includes, and/or consists essentially of second solvent-steam vapor mixture
95. Fig. 6 illustrates
a linear change in the injectant composition during the transition time
period; however, it is
within the scope of the present disclosure that the injectant composition may
change in any
suitable gradual, graded, and/or continuous manner during the transition time
period.
[0073] As yet another example, the transitioning at 225 may include the
stepped transition.
This may include changing the first flow rate of the first solvent-steam vapor
mixture and the
CA 2974714 2017-07-27
second flow rate of the second solvent-steam vapor mixture, relative to one
another, in a plurality
of transition steps. This may include decreasing, or systematically
decreasing, the first flow rate
relative to the second flow rate during the, or during each of the, plurality
of transition steps.
The plurality of transition steps may include any suitable number of
transition steps, including at
least 2, at least 4, at least 6, at least 8, at least 10, at least 15, at
least 20, at most 25, at most 15, at
most 10, and/or at most 6 transition steps. It is within the scope of the
present disclosure that the
plurality of transition steps may include a plurality of discrete and/or
distinct transition steps,
each occurring during a corresponding, or distinct, subset of the transition
time period.
[0074] An example of the stepped transition is illustrated in Fig. 7. As
illustrated therein,
and during first injection time period 90, the injectant that is provided to
the subterranean
formation includes, primarily includes, and/or consists essentially of first
solvent-steam vapor
mixture 91. Then, and during transition time period 92, injection of the first
solvent-steam vapor
mixture gradually decreases in a series of steps, and injection of the second
solvent-steam vapor
mixture is initiated and gradually increases in a corresponding series of
steps. Subsequently, and
during second injection time period 94, the injectant that is provided to the
subterranean
formation includes, primarily includes, and/or consists essentially of second
solvent-steam vapor
mixture 95.
[0075] It is within the scope of the present disclosure that the
transitioning at 225 may be
initiated based upon and/or responsive to any suitable transition criteria.
Examples of the
transition criteria include one or more of the first injection time period
exceeding a threshold first
injection time period, production of a predetermined volume of mobilized
viscous hydrocarbons
from the subterranean formation, contact between a vapor chamber, which is
generated within
the subterranean formation responsive to the injecting at 225 and/or to the
producing at 255, with
26
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an overburden, fluid communication between the vapor chamber and a lean zone
of the
subterranean formation, fluid communication between the vapor chamber and a
thief, sink,
and/or injectant-retaining zone of the subterranean formation, detection of an
unexpected
pressure decrease within the subterranean formation, and/or detection of an
unexpected loss of
the first solvent-steam vapor mixture within the subterranean formation.
100761 As used herein, the phrase "lean zone" may refer to a zone, or
region, of the
subterranean formation that does not include viscous hydrocarbons and/or that
includes a lower
saturation of viscous hydrocarbons when compared to a remainder of the
subterranean formation.
As used herein, the phrases "thief zone," "sink zone," and/or "injectant-
retaining zone" may refer
to a zone, or region, of the subterranean formation that retains the injectant
stream, that permits
the injectant stream to escape from the vapor chamber, and/or that consumes,
receives, and/or
retains a relatively larger volume of the injectant stream, when compared to a
remainder of the
subterranean formation, to generate a given volume of mobilized viscous
hydrocarbons.
[0077] Additional examples of the transition criteria include production
and/or recovery of at
least a threshold fraction of original oil in place from the subterranean
formation. Examples of
the threshold fraction include at least 10%, at least 20%, at least 30%, at
least 40%, at least 50%,
at least 60%, at least 70%, and/or at least 80% of the original oil in place.
[0078] It is within the scope of the present disclosure that the
transition criteria may include
and/or be predetermined transition criteria that are established prior to
initiation of the injecting
at 220. Additionally or alternatively, it also is within the scope of the
present disclosure that the
transition criteria may include and/or be dynamic transition criteria that are
established during
the injecting at 220.
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[0079] Selecting the second solvent at 230 may include selecting the
second solvent based, at
least in part, on the target operating pressure within the subterranean
formation. As an example,
the selecting at 230 may include selecting such that the second solvent forms
a second vapor at
the target operating pressure. As another example, the selecting at 230 may
include selecting
such that the second solvent forms a second azeotropic, or near-azeotropic,
vapor mixture with
water at the target operating pressure. The selecting at 230 may include
selecting with, via,
and/or utilizing phase behavior of the second solvent and/or on phase behavior
of mixtures of the
second solvent and water and may be at least substantially similar to the
selecting at 210.
However, the selecting at 230 further may include selecting such that the
second dew point
temperature of the second solvent is less than the first dew point temperature
of the first solvent,
as discussed herein.
[0080] Determining the second azeotropic solvent molar fraction at 235
may include
determining the second azeotropic molar fraction at the target operating
pressure and in any
suitable manner. As an example, and similar to the determining at 215, the
phase behavior
illustrated in Fig. 4 may be utilized to determine the second azeotropic
solvent molar fraction.
[0081] Ceasing injection of the first solvent-steam vapor mixture at 240
may include ceasing
the injecting at 220 during the transition time period. Additionally or
alternatively, the ceasing
at 240 may include ceasing the injecting at 220 prior to initiating the
injecting at 245 and/or prior
to the second injection time period.
[0082] Injecting the second solvent-steam vapor mixture at 245 may include
injecting the
second solvent-steam vapor mixture into the subterranean formation during the
second injection
time period. The injecting at 245 may be similar, or at least substantially
similar, to the injecting
28
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=
at 220; however, and as discussed, the injecting at 245 may utilize a second
solvent having a
second dew point temperature that is less than a first dew point temperature
of the first solvent.
[0083] The second solvent-steam vapor mixture may, but is not required
to be, injected into
the subterranean formation at azeotropic, or near-azeotropic, conditions. More
specifically, the
second solvent-steam vapor mixture may be injected such that a second solvent
molar fraction of
the second solvent in the second solvent-steam vapor mixture is within a
threshold fraction of the
second azeotropic solvent molar fraction of the second solvent-steam vapor
mixture at the target
operating pressure. Examples of the threshold fraction include threshold
fractions of at
least 70%, at least 80%, at least 90%, at least 95%, at most 100%, at most
95%, at most 90%,
and/or at most 85% of the second azeotropic solvent molar fraction.
100841 The second solvent-steam vapor mixture additionally or
alternatively may include any
suitable relative volume proportion of the second solvent and steam. As
examples, the second
solvent-steam vapor mixture may include at least 1 volume percent second
solvent, at least 5
volume percent second solvent, at least 10 volume percent second solvent, at
least 20 volume
percent second solvent, at least 30 volume percent second solvent, at least 40
volume percent
second solvent, at least 50 volume percent second solvent, at least 60 volume
percent second
solvent, at least 70 volume percent second solvent, at least 80 volume percent
second solvent, at
least 90 volume percent second solvent, at least 98 volume percent second
solvent, at most 99
volume percent second solvent, at most 98 volume percent second solvent, at
most 95 volume
percent second solvent, at most 90 volume percent second solvent, at most 80
volume percent
second solvent, at most 70 volume percent second solvent, at most 60 volume
percent second
solvent, at most 50 volume percent second solvent, at most 40 volume percent
second solvent, at
most 30 volume percent second solvent, at most 20 volume percent second
solvent, at most 10
29
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volume percent second solvent, at most 5 volume percent second solvent, and/or
at most 2
volume percent second solvent in cold liquid equivalents calculated at
standard temperature and
pressure. As additional examples, the second solvent-steam vapor mixture may
include at least 1
volume percent steam, at least 2 volume percent steam, at least 5 volume
percent steam, at least
10 volume percent steam, at least 20 volume percent steam, at least 30 volume
percent steam, at
least 40 volume percent steam, at least 50 volume percent steam, at least 60
volume percent
steam, at least 70 volume percent steam, at least 80 volume percent steam, at
least 90 volume
percent steam, at least 95 volume percent steam, at least 98 volume percent
steam, at most 99
volume percent steam, at most 95 volume percent steam, at most 90 volume
percent steam, at
most 80 volume percent steam, at most 70 volume percent steam, at most 60
volume percent
steam, at most 50 volume percent steam, at most 40 volume percent steam, at
most 30 volume
percent steam, at most 20 volume percent steam, at most 10 volume percent
steam and/or at most
2 volume percent steam in cold liquid equivalents calculated at standard
temperature and
pressure.
[0085] The injecting at 245 may include injecting the second solvent-steam
vapor mixture
with, via, and/or utilizing an injection well that extends within the
subterranean formation.
Examples of the injection well are discussed herein with reference to
injection well 40 of Fig. 1.
[0086] It is within the scope of the present disclosure that the
injecting at 245 further may
include generating the mobilized viscous hydrocarbons, within the subterranean
formation, from
the viscous hydrocarbons. As examples, the generating may include heating the
viscous
hydrocarbons with the second solvent-steam vapor mixture to generate the
mobilized viscous
hydrocarbons, diluting the viscous hydrocarbons with a condensed second
solvent of the second
solvent-steam vapor mixture to generate the mobilized viscous hydrocarbons,
and/or dissolving
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the viscous hydrocarbons in the condensed second solvent to generate the
mobilized viscous
hydrocarbons.
[0087] The second solvent-steam vapor mixture may include any suitable
second solvent and
water, or steam, in any suitable relative concentration that may be, but is
not required to be,
azeotropic, or near-azeotropic, at the target operating pressure. Examples of
the second solvent
include lower-boiling hydrocarbons including hydrocarbon molecules with at
least 3, at least 4,
at least 5, at most 7, at most 6, at most 5, at most 4 carbon atoms, between 3-
7 carbon atoms,
and/or between 3-6 carbon atoms. The second solvent may include any suitable
proportion,
fraction, and/or percentage, of the lower-boiling hydrocarbons. As examples,
the second solvent
may include at least 40 weight percent, at least 50 weight percent, at least
60 weight percent, at
least 70 weight percent, at least 80 weight percent, at least 90 weight
percent, at most 99 weight
percent, at most 95 weight percent, at most 90 weight percent, and/or at most
80 weight percent
of the lower-boiling hydrocarbons. Stated another way, hydrocarbon molecules
within the
second solvent may have and/or define a second average carbon number of at
least 3, at least 4.
at least 5, at most 7, at most 6, at most 5, at most 4, between 3-7, and/or
between 3-6. The
second average carbon number may be determined in a manner that is at least
substantially
similar to the first average carbon number, which is discussed herein.
Additional examples of
the second solvent include hydrocarbons, alkanes, alkenes, alkynes, aliphatic
compounds,
naphthenic compounds, aromatic compounds, olefinic compounds, natural gas
condensate,
liquefied petroleum gas, and/or a crude oil refinery stream.
[0088] It is within the scope of the present disclosure that the
injecting at 245 may include
injecting the second solvent-steam vapor mixture with any suitable steam
quality. As examples,
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the steam quality may be at least 5%, at least 100/u, at least 20%, at least
40%, at least 60%, at
least 80%, at most 100%, at most 90%, and/or at most 80%.
[0089] The injecting at 245 may include injecting the second solvent-
steam vapor mixture at
any suitable injection temperature. As examples, the injection temperature may
be at least 20 C,
at least 30 C, at least 40 C, at least 50 C, at least 60 C, at least 70
C, at least 80 C, at
least 90 C, at least 100 C, at most 300 C, at most 250 C, at most 200 C,
and/or at
most 150 C. As additional examples, the injecting at 220 may include
injecting with at least a
threshold degree of superheat relative to a second saturation temperature of
the second solvent-
steam vapor mixture at the target operating pressure. Examples of the
threshold degree of
superheat include at least 1 C of superheat, at least 2 C of superheat, at
least 5 C of superheat,
at least 10 C of superheat, at least 20 C of superheat, at most 60 C of
superheat, at most 50 C
of superheat, at most 40 C of superheat, at most 30 C of superheat, and/or
at most 20 "C of
superheat.
[0090] The second solvent may have and/or define any suitable second dew
point
temperature. As examples, and at a pressure of 101.325 kilopascals, the second
dew point
temperature may be at least -50 C, at least -30 C, at least -10 C, at least
0 C, at least 10 C, at
least 30 C, at least 50 C, at least 70 C, at least 90 C, and/or at least
110 C.
[0091] As discussed, the second dew point temperature of the second
solvent is less than the
first dew point temperature of the first solvent. It is within the scope of
the present disclosure
that a difference between the first dew point temperature and the second dew
point temperature
may have any suitable magnitude. As examples, the difference between the first
dew point
temperature and the second dew point temperature may be at least 10 C, at
least 30 C, at
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=
least 50 C, at least 70 C, at least 90 'V, at least 110 C, at least 130 C,
at least 150 C, at
least 170 C, at least 190 C, and/or at least 210 C at 101.325 kilopascals.
[0092] In general, the transition time period is subsequent to thc first
injection time period.
In addition, the second injection time period is subsequent to both the first
injection time period
and the transition time period.
[0093] The first injection time period, the transition time period, and
the second injection
time period may have any suitable temporal relation. As an example, and as
illustrated in Fig. 5,
the first injection time period may be distinct from the second injection time
period. As another
example, and as also illustrated in Fig. 5, the first injection time period
may be distinct from the
transition time period. As yet another example, and as illustrated in Figs. 6-
7, the first injection
time period may be at least partially concurrent with the transition time
period and/or may
include the transition time period. As another example, and as illustrated in
Fig. 5, the second
injection time period may be distinct from the transition time period. As yet
another example,
and as illustrated in Figs. 6-7, the second injection time period may be at
least partially
concurrent with the transition time period and/or may include the transition
time period.
[0094] The first injection time period, the transition time period, and
the second injection
time period additionally or alternatively may have any suitable duration. As
examples, the first
injection time period may be less than the transition time period, at least
substantially equal to
the transition time period, greater than the transition time period, and/or at
least a threshold
multiple of the transition time period. As additional examples, the second
injection time period
may be less than the transition time period, at least substantially equal to
the transition time
period, greater than the transition time period, and/or at least the threshold
multiple of the
transition time period. Examples of the threshold multiple include threshold
multiples of at
33
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least 5, at least 10, at least 25, at least 50, and/or at least 100. As
additional examples, the first
injection time period may be less than, at least substantially equal to,
and/or greater than the
second injection time period.
[0095] It is within the scope of the present disclosure that the first
injection time period, the
transition time period, and/or the second injection time period may be
selected and/or established
in any suitable manner. As examples, one or more of these time periods may be
systematically
selected to provide a desired level of in situ upgrading of the viscous
hydrocarbons, to provide a
predetermined amount of first solvent recovery from the subterranean
formation, to provide a
predetermined amount of heat recovery from the subterranean formation, and/or
to decrease a
potential for loss of the first solvent within the subterranean formation.
[0096] Recovering the second solvent from the subterranean formation at
250 may include
recovering at least a portion, or fraction, of the second solvent from the
subterranean formation
in any suitable manner and may be performed subsequent to the second injection
time period.
As an example, the recovering at 250 may include producing the second solvent
from the
subterranean formation, such as during the producing at 255. As another
example, the
recovering at 250 may include injecting a non-condensable gas into the
subterranean formation
to facilitate production of the second solvent from the subterranean
formation.
[0097] Producing mobilized viscous hydrocarbons at 255 may include
producing the
mobilized viscous hydrocarbons from the subterranean formation as a produced
mobilized
viscous hydrocarbon stream. This may include producing with, via, and/or
utilizing a production
well, such as production well 50 of Fig. 1, that may be spaced-apart and/or
distinct from the
injection well that is utilized during the injecting at 220 and/or during the
injecting at 245. The
producing at 255 may be performed during, concurrent with, and/or at least
substantially
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=
concurrent with the injecting at 220, the transitioning at 225, and/or the
injecting at 245. The
producing at 255 also may include producing the first solvent from the
subterranean formation,
producing the second solvent from the subterranean formation, producing water
from the
subterranean formation, and/or producing steam from the subterranean
formation.
[0098] The producing at 255 is schematically illustrated in Fig. 8. As
illustrated therein, the
mobilized viscous hydrocarbon production rate may be highest during first
injection time
period 90 and prior to transition time period 92 since, as discussed, the
medium-boiling solvent
utilized during the first injection time period may provide enhanced viscous
hydrocarbon
recovery when compared to the lower-boiling solvent utilized during second
injection time
period 94. However, when considered in the context of the overall economics of
viscous
hydrocarbon recovery from the subterranean formation, methods 200 may provide
a significant
improvement over methods that inject the medium-boiling solvent but that do
not transition to
injection of the lower-boiling solvent.
[0099] Separating the recycled solvent stream at 260 may include
separating the first solvent,
as a first recycled solvent, and/or separating the second solvent, as a second
recycled solvent,
from the mobilized viscous hydrocarbons that are produced during the producing
at 255. When
methods 200 include the separating at 260, the first recycled solvent and/or
the second recycled
solvent may be re-injected into the subterranean formation, such as during the
injecting at 220
and/or during the injecting at 245, respectively.
[0100] In the present disclosure, several of the illustrative, non-
exclusive examples have
been discussed and/or presented in the context of flow diagrams, or flow
charts, in which the
methods are shown and described as a series of blocks, or steps. Unless
specifically set forth in
the accompanying description, it is within the scope of the present disclosure
that the order of the
CA 2974714 2017-07-27
=
blocks may vary from the illustrated order in the flow diagram, including with
two or more of the
blocks (or steps) occurring in a different order and/or concurrently.
[0101] As used herein, the term "and/or" placed between a first entity
and a second entity
means one of (1) the first entity, (2) the second entity, and (3) the first
entity and the second
entity. Multiple entities listed with "and/or" should be construed in the same
manner, i.e., "one
or more" of the entities so conjoined. Other entities may optionally be
present other than the
entities specifically identified by the "and/or" clause, whether related or
unrelated to those
entities specifically identified. Thus, as a non-limiting example, a reference
to "A and/or B,"
when used in conjunction with open-ended language such as "comprising" may
refer, in one
embodiment, to A only (optionally including entities other than B); in another
embodiment, to B
only (optionally including entities other than A); in yet another embodiment,
to both A and B
(optionally including other entities). These entities may refer to elements,
actions, structures,
steps, operations, values, and the like.
[0102] As used herein, the phrase "at least one," in reference to a list
of one or more entities
should be understood to mean at least one entity selected from any one or more
of the entity in
the list of entities, but not necessarily including at least one of each and
every entity specifically
listed within the list of entities and not excluding any combinations of
entities in the list of
entities. This definition also allows that entities may optionally be present
other than the entities
specifically identified within the list of entities to which the phrase "at
least one" refers, whether
related or unrelated to those entities specifically identified. Thus, as a non-
limiting example, "at
least one of A and B" (or, equivalently, "at least one of A or B," or,
equivalently "at least one of
A and/or B") may refer, in one embodiment, to at least one, optionally
including more than one,
A, with no B present (and optionally including entities other than B); in
another embodiment, to
36
CA 2974714 2017-07-27
at least one, optionally including more than one, B, with no A present (and
optionally including
entities other than A); in yet another embodiment, to at least one, optionally
including more than
one, A, and at least one, optionally including more than one, B (and
optionally including other
entities). In other words, the phrases "at least one," "one or more," and
"and/or" are open-ended
expressions that are both conjunctive and disjunctive in operation. For
example, each of the
expressions "at least one of A, B and C," "at least one of A, B, or C," "one
or more of A, B, and
C," "one or more of A, B, or C" and "A, B, and/or C" may mean A alone, B
alone, C alone, A
and B together, A and C together, B and C together, A, B and C together, and
optionally any of
the above in combination with at least one other entity.
[0103] As used herein the terms "adapted" and "configured" mean that the
element,
component, or other subject matter is designed and/or intended to perform a
given function.
Thus, the use of the terms "adapted" and "configured" should not be construed
to mean that a
given element, component, or other subject matter is simply "capable of'
performing a given
function but that the element, component, and/or other subject matter is
specifically selected,
created, implemented, utilized, programmed, and/or designed for the purpose of
performing the
function. It is also within the scope of the present disclosure that elements,
components, and/or
other recited subject matter that is recited as being adapted to perform a
particular function may
additionally or alternatively be described as being configured to perform that
function, and vice
versa.
[0104] As used herein, the phrase, "for example," the phrase, "as an
example," and/or simply
the term "example," when used with reference to one or more components,
features, details,
structures, embodiments, and/or methods according to the present disclosure,
are intended to
convey that the described component, feature, detail, structure, embodiment,
and/or method is an
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CA 2974714 2018-01-03
illustrative, non-exclusive example of components, features, details,
structures, embodiments,
and/or methods according to the present disclosure. Thus, the described
component, feature,
detail, structure, embodiment, and/or method is not intended to be limiting,
required, or
exclusive/exhaustive; and other components, features, details, structures,
embodiments, and/or
methods, including structurally and/or functionally similar and/or equivalent
components,
features, details, structures, embodiments, and/or methods, are also within
the scope of the
present disclosure.
Industrial Applicability
[0105] The methods disclosed herein are applicable to the oil and gas
industries.
[0106] It is believed that the disclosure set forth above encompasses
multiple distinct
inventions with independent utility. While each of these inventions has been
disclosed in its
preferred form, the specific embodiments thereof as disclosed and illustrated
herein are not to be
considered in a limiting sense as numerous variations are possible. The
subject matter of the
inventions includes all novel and non-obvious combinations and subcombinations
of the various
elements, features, functions and/or properties disclosed herein. Similarly,
where the claims
recite "a" or "a first" element or the equivalent thereof, such claims should
be understood to
include incorporation of one or more such elements, neither requiring nor
excluding two or more
such elements.
[0107] It is believed that the following claims particularly point out
certain combinations and
subcombinations that are directed to one of the disclosed inventions and are
novel and non-
obvious. Inventions embodied in other combinations and subcombinations of
features, functions,
elements and/or properties may be claimed through amendment of the present
claims or
38
CA 2974714 2018-01-03
presentation of new claims in this or a related application. Such amended or
new claims,
whether they are directed to a different invention or directed to the same
invention, whether
different, broader, narrower, or equal in scope to the original claims, are
also regarded as
included within the subject matter of the inventions of the present
disclosure.
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