Note: Descriptions are shown in the official language in which they were submitted.
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SYSTEMS AND METHODS FOR ENHANCING PRODUCTION OF VISCOUS
HYDROCARBONS FROM A SUBTERRANEAN FORMATION
Field
The present disclosure is directed generally to systems and methods for
enhancing
production of viscous hydrocarbons from a subterranean formation, and more
particularly to
systems and methods that utilize a hydrocarbon solvent mixture to reduce a
viscosity of the
viscous hydrocarbons.
Background
Viscous hydrocarbons, which also may be referred to herein as heavy oils
and/or as
bitumen, represent a significant fraction of worldwide hydrocarbon reserves.
These viscous
hydrocarbons may have a relatively high viscosity, precluding their
production, or at least
economic production, by flowing from a subterranean formation. Several methods
have been
utilized to decrease the viscosity of the viscous hydrocarbons, thereby
decreasing a resistance to
flow thereof and/or permitting production of the viscous hydrocarbons from the
subterranean
formation by piping, flowing, and/or pumping the viscous hydrocarbons from the
subterranean
formation. While each of these methods may be effective under certain
conditions, they each
possess inherent limitations.
As an illustrative, non-exclusive example, steam injection may be utilized to
heat the
viscous hydrocarbons and to thereby decrease their viscosity. While water
and/or steam may
represent an effective heat transfer medium, the pressure required to produce
saturated steam at a
desired temperature may be relatively high, limiting the applicability of
steam recovery
processes to high pressure operation and/or requiring a large amount of energy
to heat the steam
and decreasing an overall thermal efficiency of a viscous hydrocarbon recovery
process. In
addition, water and/or steam may damage certain subterranean formations.
As another illustrative, non-exclusive example, cold and/or heated solvents
have been
injected into a subterranean formation to decrease the viscosity of viscous
hydrocarbons that are
present within the subterranean formation. These methods traditionally inject
a pure (i.e., single-
component), or at least substantially pure, volatile solvent, such as propane,
into the subterranean
formation and permit the solvent to dissolve the viscous hydrocarbons, dilute
the viscous
hydrocarbons, and/or transfer thermal energy to the viscous hydrocarbons.
While effective under
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certain conditions, these traditional solvent injection processes suffer from
limited injection
temperature and/or pressure operating ranges, an inability to effectively
decrease the viscosity of
the viscous hydrocarbons, and/or challenges associated with maintaining the
traditional solvent
in a vaporous state during transport to the subterranean formation. Thus,
there exists a need for
improved systems and methods for enhancing production of viscous hydrocarbons
from a
subterranean formation.
Summary
A method of enhancing production of viscous hydrocarbons from a subterranean
formation may comprise heating a hydrocarbon solvent mixture to generate a
vapor stream at a
stream temperature, wherein:(i) the hydrocarbon solvent mixture includes a
heavy hydrocarbon
fraction that consists essentially of hydrocarbons with five or more carbon
atoms and comprises
greater than 30 mole percent of the hydrocarbon solvent mixture; and (ii) the
heavy hydrocarbon
fraction includes a first compound, which has at least five carbon atoms and
comprises at least
10 mole percent of the vapor stream, and a second compound, which has more
carbon atoms than
the first compound and comprises at least 10 mole percent of the vapor stream;
injecting the
vapor stream into the subterranean formation via an injection well, which
extends within the
subterranean formation, to decrease a viscosity of the viscous hydrocarbons
within the
subterranean formation and thereby generate reduced-viscosity hydrocarbons;
and producing the
reduced-viscosity hydrocarbons from the subterranean formation via a
production well, which
extends within the subterranean formation, wherein the production well is
spaced apart from the
injection well.
A method of enhancing production of viscous hydrocarbons from a subterranean
formation may comprise heating a hydrocarbon solvent mixture to generate a
vapor stream at a
stream temperature of 30-250 C, wherein the hydrocarbon solvent mixture
includes a first
compound and a second compound with more carbon atoms than the first compound;
injecting
the vapor stream into the subterranean formation via an injection well that
extends within the
subterranean formation to decrease a viscosity of the viscous hydrocarbons
within the
subterranean formation and thereby generate reduced-viscosity hydrocarbons;
and producing the
reduced-viscosity hydrocarbons from the subterranean formation via a
production well that
extends within the subterranean formation, wherein the production well is
spaced apart from the
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injection well; wherein a vapor pressure of the hydrocarbon solvent mixture is
less than a
threshold maximum pressure of the subterranean formation.
A method of selecting a composition of a hydrocarbon solvent mixture for
injection into a
subterranean formation to enhance production of viscous hydrocarbons
therefrom, wherein the
hydrocarbon solvent mixture is injected into the subterranean formation as a
vapor stream at an
injection pressure may comprise determining a threshold maximum pressure of
the subterranean
formation; determining a stream temperature at which the vapor stream is to be
injected into the
subterranean formation; and selecting the composition of the hydrocarbon
solvent mixture based,
at least in part, on the stream temperature and the threshold maximum
pressure, wherein the
selecting includes: (i) selecting a first proportion of the hydrocarbon
solvent mixture that
comprises a first compound with at least five carbon atoms, wherein the first
proportion
comprises at least 10 mole percent of the hydrocarbon solvent mixture; and
(ii) selecting a
second proportion of the hydrocarbon solvent mixture that comprises a second
compound with
more carbon atoms than the first compound, wherein the second proportion
comprises at least 10
mole percent of the hydrocarbon solvent mixture.
A hydrocarbon production system may comprise an injection well that extends
within a
subterranean formation; an injectant supply assembly that is configured to
provide a vapor
stream to the injection well to generate reduced-viscosity hydrocarbons within
the subterranean
formation, the injectant supply assembly comprising: (i) a hydrocarbon solvent
mixture, wherein
the hydrocarbon solvent mixture includes a heavy hydrocarbon fraction that
consists essentially
of hydrocarbons with five or more carbon atoms and comprises greater than 30
mole percent of
the hydrocarbon solvent mixture, and further wherein the heavy hydrocarbon
fraction includes a
first compound, which has at least five carbon atoms and comprises at least 10
mole percent of
the hydrocarbon solvent mixture, and a second compound, which has more carbon
atoms than
the first compound and comprises at least 10 mole percent of the hydrocarbon
solvent mixture;
and (ii)a vaporization assembly that is configured to receive and vaporize the
hydrocarbon
solvent mixture to generate the vapor stream; and a production well that is
spaced apart from the
injection well and extends within the subterranean formation, wherein the
production well is
configured to receive the reduced-viscosity hydrocarbons and to convey the
reduced-viscosity
hydrocarbons from the subterranean formation.
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The foregoing has broadly outlined the features of the present disclosure so
that the
detailed description that follows may be better understood. Additional
features will also be
described herein.
Brief Description of the Drawings
Fig. 1 is a schematic representation of a hydrocarbon production system.
Fig. 2 is a plot of vapor pressure vs. temperature for a plurality of
hydrocarbons.
Fig. 3 is a histogram depicting a carbon content of compounds that may be
present in a
gas plant condensate.
Fig. 4 is a flowchart depicting disclosure method of enhancing production of
viscous
hydrocarbons from a subterranean formation.
Fig. 5 is a flowchart depicting disclosure method of selecting a composition
of a
hydrocarbon solvent mixture.
It should be noted that the figures are merely examples and no limitations on
the scope of
the present disclosure are intended thereby. Further, the figures are
generally not drawn to scale,
but are drafted for purposes of convenience and clarity in illustrating
various aspects of the
disclosure.
Detailed Description
For the purpose of promoting an understanding of the principles of the
disclosure,
reference will now be made to the features illustrated in the drawings and
specific language will
be used to describe the same. It will nevertheless be understood that no
limitation of the scope of
the disclosure is thereby intended. Any alterations and further modifications,
and any further
applications of the principles of the disclosure as described herein are
contemplated as would
normally occur to one skilled in the art to which the disclosure relates. It
will be apparent to
those skilled in the relevant art that some features that are not relevant to
the present disclosure
may not be shown in the drawings for the sake of clarity.
Figs. 1 and 4-5 provide illustrative, non-exclusive examples of hydrocarbon
production
systems 10 according to the present disclosure, of methods 100 according to
the present
disclosure of enhancing production of viscous hydrocarbons from a subterranean
formation,
and/or of methods 200 according to the present disclosure of selecting a
composition of a
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hydrocarbon solvent mixture for injection into the subterranean formation as a
vapor stream. All
elements and/or method steps may not be labeled in each of Figs. 1 and 4-5,
but reference
numerals associated therewith may be utilized herein for consistency.
Elements, components,
features, and/or method steps that are discussed herein with reference to one
or more of Figs. I
and 4-5 may be included in and/or utilized with any of Figs. 1 and 4-5 without
departing from
the scope of the present disclosure.
In general, elements and/or method steps that are likely to be included are
illustrated in
solid lines, while elements and/or method steps that may be optional are
illustrated in dashed
lines. However, elements and/or method steps that are shown in solid lines are
not necessarily
essential, and an element and/or method step shown in solid lines may be
omitted without
departing from the scope of the present disclosure.
Fig. 1 is a schematic representation of a hydrocarbon production system 10
that may be
utilized with, may be included in, and/or may include the systems and methods
according to the
present disclosure. Hydrocarbon production system 10 may include an injection
well 30 and a
production well 70 that extend between a surface region 20 and a subterranean
formation 24 that
is present within a subsurface region 22.
Injection well 30 may be in fluid communication with an injectant supply
system 40.
Injection well 30 may be configured to receive a hydrocarbon solvent mixture
44 from any
suitable source (e.g., a storage structure 42). The hydrocarbon solvent
mixture 44 may be
provided to a vaporization assembly 50 to generate a vapor stream 52. The
vapor stream 52 may
be provided to subterranean formation 24 via injection well 30.
Once provided to the subterranean formation, the vapor stream 52 may condense
within a
vapor chamber 60. When the vapor stream 52 condenses, the vapor stream 52 may
release latent
heat (or latent heat of condensation), transfer thermal energy to the
subterranean formation,
and/or generate a condensate 54. Condensation of the vapor stream 52 may heat
viscous
hydrocarbons 26 that may be present within the subterranean formation, thereby
decreasing a
viscosity of the viscous hydrocarbons. Vapor stream 52 and/or condensate 54
may combine
with, mix with, be dissolved in, dissolve, and/or dilute viscous hydrocarbons
26, thereby further
decreasing the viscosity of the viscous hydrocarbons.
The energy transfer between vapor stream 52 and viscous hydrocarbons 26 and/or
the
mixing of vapor stream 52 with viscous hydrocarbons 26 may generate reduced-
viscosity
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hydrocarbons 74, which may flow to production well 70. After flowing to the
production well
70, the reduced-viscosity hydrocarbons 74 may be produced from the
subterranean formation as
a reduced-viscosity hydrocarbon mixture 72. The reduced-viscosity hydrocarbon
mixture may
comprise reduced-viscosity hydrocarbons 74, vapor stream 52, and/or condensate
54 in any
suitable ratio and/or relative proportion.
Hydrocarbon production system 10 may include a condensate recovery system 77.
The
condensate recovery system 77 may include and/or be a separation assembly 78.
Condensate
recovery system 77 may receive reduced-viscosity hydrocarbon mixture 72.
Condensate
recovery system 77 may separate the reduced-viscosity hydrocarbon mixture into
reduced-
viscosity hydrocarbons 74, light hydrocarbon gasses 75, and/or recovered
hydrocarbon solvent
76.
Reduced-viscosity hydrocarbons 74 may be removed from the hydrocarbon
production
system, utilized in another downstream process of the hydrocarbon production
system, and/or
pipelined or otherwise transported to a suitable processing site, such as a
hydrocarbon refinery,
for further processing.
Recovered hydrocarbon solvent 76 may be utilized as a feed stream 43 that may
be
combined with (or may be) hydrocarbon solvent mixture 44 to generate vapor
stream 52.
Light hydrocarbon gasses 75 may include hydrocarbons and/or carbon compounds
with
four or fewer carbon atoms, such as methane, ethane, propane, and/or butane.
Light hydrocarbon
gasses 75 may be provided to vaporization assembly 50 as a fuel stream that
may be combusted
to heat hydrocarbon solvent mixture 44.
Hydrocarbon production system 10 may include a solvent purification system 79.
Solvent purification system 79 may include a purification assembly 80. Solvent
purification
system 79 may be configured to receive a feed stream 43 from any suitable
source. For example,
feed stream 43 may be provided by storage structure 42 and/or may be separated
from reduced-
viscosity hydrocarbons 72 and recovered hydrocarbon solvent 76. Regardless of
the source of
feed stream 43, the solvent purification system 79 may be configured to remove
one or more
components from the feed stream 43 to generate hydrocarbon solvent mixture 44
with a target, or
desired, composition. The hydrocarbon solvent mixture then may be provided to
vaporization
assembly 50 to generate vapor stream 52.
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Injectant supply system 40 may receive hydrocarbon solvent mixture 44, such as
from
storage structure 42. Injectant supply system 40 may vaporize the hydrocarbon
solvent mixture
within vaporization assembly 50 to generate vapor stream 52. Injectant supply
system 40 may
receive recovered hydrocarbon solvent 76 from condensate recovery system 77.
Injectant supply
system 40 may vaporize the recovered hydrocarbon solvent within vaporization
assembly 50 to
generate vapor stream 52. Injectant supply system 40 may receive feed stream
43, such as from
storage structure 42 and/or from condensate recovery system 77. Injectant
supply system may
purify the feed stream within purification assembly 80 to generate hydrocarbon
solvent mixture
44, with the hydrocarbon solvent mixture then being vaporized within
vaporization assembly 50
to generate vapor stream 52.
As discussed, conventional hydrocarbon production systems that utilize an
injected vapor
stream to decrease the viscosity of high viscosity hydrocarbons traditionally
utilize a pure (i.e.,
single-component), or at least substantially pure, injected vapor stream that
comprises a light
hydrocarbon, such as propane. In contrast, the systems and methods according
to the present
disclosure may utilize hydrocarbon solvent mixture 44 to generate vapor stream
52.
Hydrocarbon solvent mixture 44 may include a heavy hydrocarbon fraction that
comprises,
consists of, or consists essentially of hydrocarbons with five or more carbon
atoms. The heavy
hydrocarbon fraction may comprise greater than or equal to 10 mole percent,
greater than or
equal to 20 mole percent, greater than or equal to 30 mole percent greater
than or equal to 40
mole percent, greater than or equal to 50 mole percent, greater than or equal
to 60 mole percent,
greater than or equal to 70 mole percent, or greater than or equal to 80 mole
percent of the
hydrocarbon solvent mixture. Additionally or alternatively, the heavy
hydrocarbon fraction also
may comprise less than or equal to 99 mole percent, less than or equal to 95
mole percent, less
than or equal to 90 mole percent, less than or equal to 80 mole percent, less
than or equal to 70
mole percent, less than or equal to 60 mole percent, or less than or equal to
50 mole percent of
the hydrocarbon solvent mixture. Suitable ranges may include combinations of
any upper and
lower amount of mole percentage listed above. Additional examples of suitable
mole
percentages may include any of the illustrative threshold amounts listed
above.
The heavy hydrocarbon fraction may include at least a first compound that has
five or
more carbon atoms and a second compound that has more carbon atoms than the
first compound.
The first compound and the second compound each may comprise at least 10 mole
percent of
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hydrocarbon solvent mixture 44. For example, the first and/or second compounds
may comprise
at least 20 mole percent, at least 30 mole percent, at least 40 mole percent,
at least 50 mole
percent, at least 60 mole percent, at least 70 mole percent, or at least 80
mole percent of the
hydrocarbon solvent mixture. Suitable ranges may include combinations of any
upper and lower
amount of mole percentage listed above.
The heavy hydrocarbon fraction may comprise any suitable hydrocarbon
molecules,
materials, and/or compounds. For example, the heavy hydrocarbon fraction may
comprise one
or more of alkanes, n-alkanes, branched alkanes, alkenes, n-alkenes, branched
alkenes, alkynes,
n-alkynes, branched alkynes, aromatic hydrocarbons, and/or cyclic
hydrocarbons.
As used herein, a "compound that has five or more carbon atoms" may include
any
suitable single chemical species that includes five or more carbon atoms. A
"compound that has
five or more carbon atoms" also may include any suitable mixture of chemical
species. Each of
the chemical species in the mixture of chemical species may include five or
more carbon atoms
and each of the chemical species in the mixture of chemical species also may
include the same
number of carbon atoms as the other chemical species in the mixture of
chemical species.
For example, a compound that has five carbon atoms may include a pentane, n-
pentane, a
branched pentane, cyclopentane, a pentene, n-pentene, a branched pentene,
cyclopentene, a
pentyne, n-pentyne, a branched pentyne, cyclopentyne, methylbutane,
dimethylpropane,
ethylpropane, and/or any other hydrocarbon with five carbon atoms. A compound
with six
carbon atoms, seven carbon atoms, or eight carbon atoms may include a single
chemical species
with six carbon atoms, seven carbon atoms, or eight carbon atoms,
respectively, and/or may
include a mixture of chemical species that each include six carbon atoms,
seven carbon atoms, or
eight carbon atoms, respectively.
Generating vapor stream 52 from hydrocarbon solvent mixture 44 may provide
advantages over more traditional hydrocarbon production systems that utilize
an injected vapor
stream that is formed from a substantially pure light hydrocarbon. For
example, and as
illustrated in Fig. 2 (which is a plot of vapor pressure vs. temperature for a
number of
hydrocarbons with varying carbon content), compounds with a larger number of
carbon atoms
generally exhibit a lower vapor pressure at a given temperature when compared
to compounds
with a smaller number of carbon atoms. Thus, injecting vapor stream 52 that is
formed from
hydrocarbon solvent mixture 44, a majority of which comprises compounds with
five or more
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carbon atoms, may permit injecting the vapor stream at a lower pressure for a
given temperature
when compared to propane injection and/or may permit tailoring (i.e.,
selecting, regulating,
and/or controlling) a temperature-pressure behavior of the vapor stream to a
given subterranean
formation.
Vapor stream 52 may be injected into subterranean formation 24 at a stream
temperature.
A composition of hydrocarbon solvent mixture 44 may be selected such that the
vapor pressure
of the hydrocarbon solvent mixture at the stream temperature is less than a
threshold maximum
pressure of the subterranean formation. This may prevent damage to the
subterranean formation
and/or escape of vapor stream 52 from the subterranean formation. Threshold
maximum
pressures may include, for example, a characteristic pressure of the
subterranean formation, such
as 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 is present within the subterranean formation,
and/or an aquifer
pressure for an aquifer that is located above and/or under the subterranean
formation. The
above-mentioned pressures may be measured and/or determined in any suitable
manner. For
example, this may include measuring a selected pressure with a downhole
pressure sensor,
calculating the pressure from any suitable property and/or characteristic of
the subterranean
formation, and/or estimating the pressure, such as via modeling the
subterranean formation. The
threshold pressures disclosed herein may be selected to correspond in any
suitable or desired
manner to one or more of these measured or calculated pressures. For example,
the threshold
pressures disclosed herein may be selected to be, to be greater than, to be
less than, to be within a
selected range of, to be a selected percentage of, to be within a selected
constant of, etc. one or
more of these selected or measured pressures. A threshold pressure may be a
user-selected, or
operator-selected, value that does not directly correspond to a measured or
calculated pressure.
The threshold maximum pressure also may be related to and/or based upon the
characteristic pressure of the subterranean formation. This may include
threshold maximum
pressures that are less than or equal to 95%, less than or equal to 90%, less
than or equal to 85%,
less than or equal to 80%, less than or equal to 75%, less than or equal to
70%, less than or equal
to 65%, less than or equal to 60%, less than or equal to 55%, or less than or
equal to 50% of the
characteristic pressure for the subterranean formation and/or threshold
maximum pressures that
are at least 20%, at least 25%, at least 30%, at least 35%, at least 40%, at
least 45%, at least 50%,
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at least 55%, at least 60%, at least 65%, at least 70%, at least 75%, or at
least 80% of the
characteristic pressure for the subterranean formation.
Suitable ranges may include
combinations of any upper and lower amount of characteristic pressure listed
above. Additional
examples of suitable threshold maximum pressures may include any of the
illustrative threshold
amounts listed above.
Non-exclusive examples of vapor pressures for hydrocarbon solvent mixtures
that may be
utilized with and/or included in the systems and methods according to the
present disclosure
include vapor pressures that are greater than a lower threshold pressure of at
least 0.2
megapascals (MPa), at least 0.3 MPa, at least 0.4 MPa, at least 0.5 MPa, at
least 0.6 MPa, at least
0.7 MPa, at least 0.8 MPa, at least 0.9 MPa, at least 1 MPa, at least 1.1 MPa,
at least 1.2 MPa, at
least 1.3 MPa, at least 1.4 MPa, at least 1.5 MPa, at least 1.6 MPa, at least
1.7 MPa, at least 1.8
MPa, at least 1.9 MPa, at least 2 MPa, at least 2.1 MPa, at least 2.2 MPa, at
least 2.3 MPa, at
least 2.4 MPa, and/or at least 2.5 MPa. Additionally or alternatively, the
vapor pressure for the
hydrocarbon solvent mixture may be less than an upper threshold pressure that
is less than or
equal to 3 MPa, less than or equal to 2.9 MPa, less than or equal to 2.8 MPa,
less than or equal to
2.7 MPa, less than or equal to 2.6 MPa, less than or equal to 2.5 MPa, less
than or equal to 2.4
MPa, less than or equal to 2.3 MPa, less than or equal to 2.2 MPa, less than
or equal to 2.1 MPa,
less than or equal to 2 MPa, less than or equal to 1.9 MPa, less than or equal
to 1.8 MPa, less
than or equal to 1.7 MPa, less than or equal to 1.6 MPa, less than or equal to
1.5 MPa, less than
or equal to 1.4 MPa, less than or equal to 1.3 MPa, less than or equal to 1.2
MPa, less than or
equal to 1.1 MPa, less than or equal to 1 MPa, less than or equal to 0.9 MPa,
less than or equal to
0.8 MPa, less than or equal to 0.7 MPa, less than or equal to 0.6 MPa, less
than or equal to 0.5
MPa, less than or equal to 0.4 MPa, and/or less than or equal to 0.3 MPa.
Suitable ranges may
include combinations of any upper and lower amount of pressure listed above.
Additional
examples of suitable pressures may include any of the illustrative threshold
amounts listed
above.
Non-exclusive examples of stream temperatures of vapor stream 52 when it is
injected
into injection well 30 include stream temperatures of at least 30 C, at least
35 C, at least 40 C,
at least 45 C, at least 50 C, at least 55 C, at least 60 C, at least 65
C, at least 70 C, at least 75
C, at least 80 C, at least 85 C, at least 90 C, at least 95 C, at least
100 C, at least 105 C, at
least 110 C, at least 115 C, at least 120 C, at least 125 C, at least 130
C, at least 135 C, at
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least 140 C, at least 145 C, at least 150 C, at least 155 C, at least 160
C, at least 165 C, at
least 170 C, at least 175 C, at least 180 C, at least 185 C, at least 190
C, at least 195 C, at
least 200 C, at least 205 C, and/or at least 210 C. Additionally or
alternatively, the stream
temperature also may be less than or equal to 250 C, less than or equal to
240 C, less than or
equal to 230 C, less than or equal to 220 C, less than or equal to 210 C,
less than or equal to
200 C, less than or equal to 190 C, less than or equal to 180 C, less than
or equal to 170 C,
less than or equal to 160 C, less than or equal to 150 C, less than or equal
to 140 C, less than or
equal to 130 C, less than or equal to 120 C, less than or equal to 110 C,
less than or equal to
100 C, less than or equal to 90 C, less than or equal to 80 C, less than or
equal to 70 C, less
than or equal to 60 C, less than or equal to 50 C, and/or less than or equal
to 40 C. Suitable
ranges may include combinations of any upper and lower amount of stream
temperatures listed
above. Additional examples of suitable stream temperatures may include any of
the illustrative
threshold amounts listed above.
The composition of hydrocarbon solvent mixture 44 may be selected such that a
dew
point temperature of vapor stream 52 and a bubble point temperature of the
hydrocarbon solvent
mixture differ by at least a threshold temperature difference. Illustrative,
non-exclusive
examples of the threshold temperature difference include threshold temperature
differences of at
least 10 C, at least 15 C, at least 20 C, at least 25 C, at least 30 C,
at least 35 C, at least 40
C, at least 45 C, at least 50 C, at least 55 C, at least 60 C, at least 65
C, at least 70 C, at least
75 C, at least 80 C, at least 85 C, at least 90 C, at least 95 C, or at
least 100 C. Additional
examples and/or ranges of temperature differences may be based upon the
difference between
any include combinations of any upper and lower stream temperatures listed
above.
When vapor stream 52 is injected into subterranean formation 24 via injection
well 30 (as
illustrated in Fig. 1), the vapor stream may decrease in temperature (or lose
thermal energy)
while being conveyed through the injection well to the subterranean formation
and/or while
being conveyed through the subterranean formation from injection well 30 to an
interface 62
between vapor chamber 60 and viscous hydrocarbons 26 that are not within the
vapor chamber.
Thus, and for traditional single-component vapor streams, the vapor stream
must be superheated
significantly prior to being injected into the subterranean formation and/or a
significant portion
of the vapor stream will condense prior to reaching interface 62.
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However, and since vapor stream 52 according to the present disclosure is
formed from
hydrocarbon solvent mixture 44, only a portion, such as a minority portion, of
the vapor stream
(such as a lower vapor pressure portion, a higher molecular weight portion,
and/or a portion that
is formed from hydrocarbon compounds with a greater number of carbon atoms)
may condense
during transport between surface region 20 and subterranean formation 24
ancUor during
transport between injection well 30 and interface 62. Thus, this portion of
vapor stream 52 may
act as a "thermal buffer" for a remainder of vapor stream 52, decreasing a
potential for undesired
condensation of the remainder of the vapor stream. This may increase an
overall efficiency of
hydrocarbon production system 10, may permit the hydrocarbon production system
to operate
with less energy, and/or may permit vapor stream 52 to extend farther into
subterranean
formation 24 prior to condensing within the subterranean formation, when
compared to
traditional vapor injection processes that do not utilize hydrocarbon solvent
mixture 44.
Hydrocarbon solvent mixture 44 may be obtained from any suitable source. As
illustrative, non-exclusive examples, hydrocarbon solvent mixture 44 may
include, be obtained
from, and/or be a gas plant condensate and/or a crude oil refinery condensate.
Fig. 3 is a
histogram depicting a mole fraction of hydrocarbons that may be present in a
given gas plant
condensate as a function of the carbon content of the hydrocarbons. As may be
seen in Fig. 3,
the gas plant condensate may include a significant fraction of compounds with
five or more
carbon atoms and thus may be suitable for use as hydrocarbon solvent mixture
44, either directly
or after further purification and/or separation (such as via solvent
purification system 79).
Thus, and when hydrocarbon solvent mixture 44 includes gas plant condensate
(such as
the gas plant condensate of Fig. 3), solvent purification system 79 may be
utilized to remove one
or more components from the gas plant condensate to generate a desired
composition for the
hydrocarbon solvent mixture. For example, solvent purification system 79 may
remove at least a
portion of the compounds with four or fewer carbon atoms from the gas plant
condensate. As
another example, solvent purification system 79 may remove at least a portion
of one or more of
the compounds with five or more carbon atoms from the gas plant condensate.
Hydrocarbon solvent mixture 44 may define any suitable composition. As
illustrative,
non-exclusive examples, a majority fraction, at least 50 mole percent, at
least 60 mole percent, at
least 70 mole percent, at least 80 mole percent, at least 90 mole percent, or
at least 95 mole
percent of hydrocarbon solvent mixture 44 may comprise a compound with five
carbon atoms, a
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compound with six carbon atoms, a compound with seven carbon atoms, and/or a
compound
with eight carbon atoms. As additional illustrative, non-exclusive examples,
the first compound
may be pentane and/or the second compound may be hexane.
Hydrocarbon solvent mixture 44 may comprise any suitable number of compounds
and/or chemical species. The hydrocarbon solvent mixture may include a third
compound that
includes more carbon atoms than the second compound. When the hydrocarbon
solvent mixture
includes the third compound, the third compound may comprise any suitable
portion, or fraction,
of the hydrocarbon solvent mixture. The third compound may comprise at least
20 mole percent,
at least 30 mole percent, at least 40 mole percent, at least 50 mole percent,
at least 60 mole
percent, or at least 70 mole percent of the hydrocarbon solvent mixture.
The hydrocarbon solvent mixture 44 may include a light hydrocarbon fraction
that
includes hydrocarbons with fewer than five carbon atoms, such as hydrocarbons
with one carbon
atom, two carbon atoms, three carbon atoms, and/or four carbon atoms; however,
this light
hydrocarbon fraction (when present) may comprise a minority portion of the
hydrocarbon
solvent mixture. The light hydrocarbon fraction may comprise at least 5 mole
percent, at least 10
mole percent, at least 15 mole percent, at least 20 mole percent, at least 30
mole percent, at least
40 mole percent, at least 50 mole percent, or at least 60 mole percent of the
hydrocarbon solvent
mixture. The light hydrocarbon fraction may comprise less than or equal to 70
mole percent, less
than 60 or equal to mole percent, less than or equal to 50 mole percent, less
than or equal to 40
mole percent, less than or equal to 30 mole percent, less than or equal to 20
mole percent, less
than or equal to 15 mole percent, or less than or equal to 10 mole percent of
the hydrocarbon
solvent mixture. Suitable ranges may include combinations of any upper and
lower amount of
hydrocarbon fractions listed above. Additional examples of suitable mole
percentages of light
hydrocarbons may include any of the illustrative threshold amounts listed
above.
Condensate recovery system 77 may include any suitable structure, such as at
least one
separation assembly 78, that is configured to separate at least a portion of
condensate 54 from
reduced-viscosity hydrocarbon mixture 72 and/or from reduced-viscosity
hydrocarbons 74 that
are present within the reduced-viscosity hydrocarbon mixture and to generate
recovered
hydrocarbon solvent 76. This may include any suitable (single stage)
separation vessel,
(multistage) distillation assembly, liquid-liquid separation, or extraction,
assembly and/or any
suitable gas-liquid separation, or extraction, assembly. Condensate recovery
system 77 may
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include a recycle conduit 82 that is configured to convey the recovered
hydrocarbon solvent
stream, which also may be referred to herein as condensate 54 and/or as a
portion of the
condensate stream, to vaporization assembly 50.
Solvent purification system 79 may include any suitable structure, such as at
least one
purification assembly 80, that may be configured to receive any suitable feed
stream 43, such as
a hydrocarbon feedstock stream and/or recovered hydrocarbon solvent 76, and to
purify the feed
stream to generate hydrocarbon solvent mixture 44. This may include any
suitable liquid-liquid
separation, or extraction, assembly, any suitable gas-liquid separation, or
extraction, assembly,
any suitable gas-gas separation, or extraction, assembly, single stage
separation vessel, and/or
any suitable (multistage) distillation assembly. In addition, solvent
purification system 79 may
be configured to produce hydrocarbon solvent mixture 44 with any suitable
composition, such as
those that are discussed herein. This may include removing compounds with
fewer than five
carbon atoms from the feed stream to generate the hydrocarbon solvent mixture.
Vaporization assembly 50 may include any suitable structure that is configured
to
vaporize hydrocarbon solvent mixture 44 to generate vapor stream 52.
Vaporization assembly
50 may include a heating assembly that is configured to heat and vaporize the
hydrocarbon
solvent mixture. Vaporization assembly 50 may include a steam co-injection
assembly that is
configured to co-inject steam into injection well 30 with hydrocarbon solvent
mixture 44. The
steam may heat and vaporize the hydrocarbon solvent mixture to generate vapor
stream 52. This
may include heating and vaporizing the hydrocarbon solvent mixture prior to
the hydrocarbon
solvent mixture being supplied to the injection well (as illustrated in Fig.
1). Additionally or
alternatively, this also may include heating and vaporizing the hydrocarbon
solvent mixture
within the injection well (or subsequent to supply to the injection well).
Injection well 30 may include any suitable structure that may form a fluid
conduit to
convey vapor stream 52 to, or into, subterranean formation 24. Similarly,
production well 70
may include any suitable structure that may form a fluid conduit to convey
reduced-viscosity
hydrocarbon mixture 72 from subterranean formation 24 to, toward, and/or
proximal, surface
region 20. As illustrated, for example, in Fig. 1, injection well 30 may be
spaced apart from
production well 70. Production well 70 may extend at least partially below
injection well 30,
may extend at least partially vertically below injection well 30, and/or may
define a greater
distance (or average distance) from surface region 20 when compared to
injection well 30. At
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least a portion of production well 70 may be parallel to, or at least
substantially parallel to, a
corresponding portion of injection well 30. At least a portion of injection
well 30, and/or of
production well 70, may include a horizontal, or at least substantially
horizontal, portion.
Fig. 4 is a flowchart depicting methods 100 according to the present
disclosure of
enhancing production of viscous hydrocarbons from a subterranean formation.
Methods 100
may include preheating at least a portion of the subterranean formation at
105, selecting a
composition of a hydrocarbon solvent mixture at 110, and/or regulating the
composition of the
hydrocarbon solvent mixture at 115. Methods 100 may include heating the
hydrocarbon solvent
mixture to generate a vapor stream at a stream temperature at 120 and
injecting the vapor stream
into the subterranean formation at 125. Methods 100 also may include
condensing the vapor
stream within the subterranean formation at 130 to generate a condensate
and/or generating
reduced-viscosity hydrocarbons at 135. Methods 100 further may include
producing the
reduced-viscosity hydrocarbons at 140 and may include producing the condensate
at 145 and/or
recycling the condensate at 150.
Preheating a portion of the subterranean formation at 105 may include
preheating, or
providing thermal energy to, the subterranean formation in any suitable manner
and may be
performed prior to the injecting at 125. The preheating at 105 may include
electrically
preheating the subterranean formation, chemically preheating the subterranean
formation, and/or
injecting a preheating steam stream into the subterranean formation. The
preheating at 105 may
include preheating any suitable portion of the subterranean formation, such as
a portion of the
subterranean formation that is proximal to the injection well, a portion of
the subterranean
formation that is proximal to the production well, and/or a portion of the
subterranean formation
that defines a vapor chamber that receives the vapor stream.
Selecting the composition of a hydrocarbon solvent mixture at 110 may include
selecting
the composition of the hydrocarbon solvent mixture such that a vapor pressure
of the
hydrocarbon solvent mixture is less than a threshold maximum pressure of the
subterranean
formation, such that the vapor pressure of the hydrocarbon solvent mixture is
at least a lower
threshold pressure, and/or such that the vapor pressure of the hydrocarbon
solvent mixture is less
than an upper threshold pressure. Illustrative, non-exclusive examples of the
threshold
maximum pressure, the lower threshold pressure, and the upper threshold
pressure are discussed
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herein. Additionally or alternatively, the selecting at 110 also may include
selecting using any of
the subsequently described methods 200.
Regulating the composition of the hydrocarbon solvent mixture at 115 may
include
regulating the composition, or chemical composition, of the hydrocarbon
solvent mixture in any
suitable manner. The regulating at 115 may include receiving a hydrocarbon
feedstock, or a feed
stream, that comprises a desired composition for the hydrocarbon solvent
mixture, and the
regulating further may include utilizing the hydrocarbon feedstock as the
hydrocarbon solvent
mixture. The regulating at 115 may include receiving the hydrocarbon feedstock
and altering a
composition of the hydrocarbon feedstock to generate the hydrocarbon solvent
mixture. The
altering may include diluting the hydrocarbon feedstock, distilling the
hydrocarbon feedstock,
removing a portion of the hydrocarbon feedstock, and/or decreasing a
proportion of the
hydrocarbon feedstock that comprises compounds with fewer than five carbon
atoms to generate
the hydrocarbon solvent mixture. Illustrative, non-exclusive examples of the
composition, or the
desired composition, of the hydrocarbon solvent mixture are discussed in more
detail herein.
Heating the hydrocarbon solvent mixture to generate a vapor stream at 120 may
include
heating the hydrocarbon solvent mixture in any suitable manner to generate the
vapor stream at a
suitable stream temperature. Illustrative, non-exclusive examples of the
stream temperature are
disclosed herein.
The heating at 120 may include directly heating the hydrocarbon solvent
mixture in a
surface region to generate the vapor stream. The heating at 120 may include co-
injecting the
hydrocarbon solvent mixture and a steam stream to vaporize the hydrocarbon
solvent mixture.
When the heating at 120 includes co-injecting the steam stream, the steam
stream may be a
saturated steam stream. Additionally or alternatively, the co-injecting may
include co-injecting
at least 5, at least 6, at least 7, at least 8, at least 9 at least 10, at
least 20, at least 25, at least 50, at
least 75, or at least 100 moles of the hydrocarbon solvent mixture for each
mole of steam.
Injecting the vapor stream into the subterranean formation at 125 may include
injecting
the vapor stream via an injection well that extends within the subterranean
formation and/or
injecting the vapor stream to decrease a viscosity of viscous hydrocarbons
that may be present
within the subterranean formation. This may include injecting to facilitate
and/or produce the
generating at 135.
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The injecting at 125 may include flowing the vapor stream through, or through
at least a
portion of, the injection well and into the subterranean formation. The
injecting at 125 also may
include contacting the vapor stream with the viscous hydrocarbons within the
subterranean
formation.
Condensing the vapor stream within the subterranean formation at 130 may
include
condensing any suitable portion of the vapor stream to release a latent heat
of condensation of
the vapor stream, heat the subterranean formation, heat the viscous
hydrocarbons, and/or
generate the reduced-viscosity hydrocarbons within the subterranean formation.
The condensing
at 130 may include condensing a majority, at least 50%, at least 60%, at least
70%, at least 80%,
at least 90%, at least 95%, at least 99%, or substantially all of the vapor
stream within the
subterranean formation. The condensing at 130 may include generating a
condensate, which also
may be referred to herein as a condensate stream, from the vapor stream and/or
within the
subterranean formation. The condensing at 130 may include regulating a
temperature within the
subterranean formation to facilitate, or permit, the condensing at 130.
Generating reduced-viscosity hydrocarbons at 135 may include generating the
reduced-
viscosity hydrocarbons in any suitable manner. The generating at 135 may be
facilitated by,
produced by, and/or a result of the injecting at 125 and/or the condensing at
130. The generating
at 135 also may include dissolving the condensate in the viscous hydrocarbons,
dissolving the
viscous hydrocarbons in the condensate, and/or diluting the viscous
hydrocarbons with the
condensate to generate the reduced-viscosity hydrocarbons.
Producing the reduced-viscosity hydrocarbons at 140 may include producing the
reduced-
viscosity hydrocarbons via any suitable production well, which may extend
within the
subterranean formation and/or may be spaced apart from the injection well.
This may include
flowing the reduced-viscosity hydrocarbons from the subterranean formation,
through the
production well, and to, proximal to, and/or toward the surface region.
The producing at 140 may include producing asphaltenes. The asphaltenes may be
present within the subterranean formation and/or within the viscous
hydrocarbons. The
asphaltenes may be produced as a portion of the reduced-viscosity hydrocarbons
(and/or the
reduced-viscosity hydrocarbons may include, or comprise, asphaltenes). The
injecting at 125
may include injecting into a stimulated region of the subterranean formation
that includes
asphaltenes, and the producing at 140 may include producing at least a
threshold fraction of the
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asphaltenes from the stimulated region. This may include producing at least 10
wt%, at least 20
wt%, at least 30 wt%, at least 40 wt%, at least 50 wt%, at least 60 wt%, at
least 70 wt%, at least
80 wt%, or at least 90 wt% of the asphaltenes that are, or were, present
within the stimulated
region prior to the injecting at 125.
Producing the condensate at 145 may include producing the condensate, or
condensate
stream, that is generated during the condensing at 130. The producing at 145
may include
producing the condensate with the reduced-viscosity hydrocarbons and/or
producing a reduced-
viscosity hydrocarbon mixture that includes the reduced-viscosity hydrocarbons
and the
condensate.
Recycling the condensate at 150 may include recycling the condensate in any
suitable
manner. The recycling at 150 may include separating at least a separated
portion of the
condensate from the reduced-viscosity hydrocarbon mixture and/or from the
reduced-viscosity
hydrocarbons. The recycling at 150 also may include utilizing at least a
recycled portion of the
condensate, which also may be referred to herein as a recovered hydrocarbon
solvent, as, or as a
portion of, the hydrocarbon solvent mixture and/or returning the recycled
portion of the
condensate to the subterranean formation via the injection well. The recycling
at 150 further
may include purifying the recycled portion of the condensate prior to
utilizing the recycled
portion of the condensate and/or prior to returning the recycled portion of
the condensate to the
subterranean formation.
Fig. 5 is a flowchart depicting illustrative, non-exclusive examples of
methods 200
according to the present disclosure of selecting a composition of a
hydrocarbon solvent mixture
for injection into a subterranean formation as a vapor stream to enhance
production of viscous
hydrocarbons from the subterranean formation. Methods 200 may include
determining a
threshold maximum pressure for the subterranean formation at 210, determining
a stream
temperature at which the vapor stream is injected into the subterranean
formation at 220, and
selecting a composition of the hydrocarbon solvent mixture at 230. Methods 200
may include
injecting the vapor stream into the subterranean formation at 240 and/or
producing reduced-
viscosity hydrocarbons from the subterranean formation at 250.
Determining the threshold maximum pressure for the subterranean formation at
210 may
include determining any suitable threshold maximum pressure for the
subterranean formation.
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Illustrative, non-exclusive examples of the threshold maximum pressure are
discussed in more
detail herein.
Determining the stream temperature at which the vapor stream is injected into
the
subterranean formation at 220 may include determining the stream temperature
in any suitable
manner. The determining at 220 may include determining a thermally efficient
stream
temperature. The determining at 220 may include determining a stream
temperature at which a
viscosity, or average viscosity, of the viscous hydrocarbons is The yet
another illustrative, non-
exclusive example, the determining at 220 may include determining a stream
temperature at
which a production rate of the viscous hydrocarbons from the subterranean
formation is at least a
threshold production rate. Illustrative, non-exclusive examples of the stream
temperature are
disclosed herein.
Selecting the composition of the hydrocarbon solvent mixture at 230 may
include
selecting the composition of the hydrocarbon solvent mixture based, at least
in part, on the
stream temperature and/or on the threshold maximum pressure. Additionally or
alternatively, the
selecting at 230 also may include selecting, at 232, a first proportion of the
hydrocarbon solvent
mixture that comprises a first compound with at least five carbon atoms,
selecting, at 234, a
second proportion of the hydrocarbon solvent mixture that comprises a second
compound with
more carbon atoms than the first compound, and/or (optionally) selecting, at
236, a third (or
additional) proportion of the hydrocarbon solvent mixture that comprises a
third (or additional)
compound with more carbon atoms than the second (or a prior) compound. The
selecting at 230
further may include selecting such that the first proportion, the second
proportion, and/or the
third proportion (when present) individually comprise at least 10, at least
20, at least 30, at least
40, at least 50, or at least 60 mole percent of the hydrocarbon solvent
mixture. Additionally or
alternatively, the selecting at 230 also may include selecting such that the
first compound, the
second compound, and/or the third compound (when present) together comprise 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 least
95, or at least 99 mole percent of the hydrocarbon solvent mixture and/or such
that the
hydrocarbon solvent mixture comprises at least 50, at least 60, at least 70,
at least 80, at least 90,
at least 95, or at least 99 mole percent hydrocarbons.
The selecting at 230 also may include selecting such that a vapor pressure of
the
hydrocarbon solvent mixture at a stream temperature of the vapor stream is
less than the
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maximum threshold pressure of the subterranean formation. Illustrative, non-
exclusive examples
of the stream temperature are disclosed herein.
This selecting may include increasing the first proportion of the hydrocarbon
solvent
mixture and/or decreasing the second proportion of the hydrocarbon solvent
mixture to increase
the vapor pressure of the hydrocarbon solvent mixture. Additionally or
alternatively, this may
include decreasing the first proportion of the hydrocarbon solvent mixture
and/or increasing the
second proportion of the hydrocarbon solvent mixture to decrease the vapor
pressure of the
hydrocarbon solvent mixture.
The selecting at 230 also may include selecting such that the vapor pressure
of the
hydrocarbon solvent mixture is less than an upper threshold pressure and/or
greater than a lower
threshold pressure. Illustrative, non-exclusive examples of the upper
threshold pressure and/or
of the lower threshold pressure are disclosed herein.
When the viscous hydrocarbons include asphaltenes, the selecting at 230
further may
include selecting such that at least a threshold fraction of the asphaltenes
within the sample are
soluble within the hydrocarbon solvent mixture at the temperature and pressure
at which the
hydrocarbon solvent mixture contacts the viscous hydrocarbons within the
subterranean
formation. This may include measuring the solubility of the asphaltenes within
the hydrocarbon
solvent mixture. This is in direct contrast to traditional solvent injection
processes, which
typically are unable to remove asphaltenes, or at least a significant fraction
of the asphaltenes,
from the subterranean formation.
Illustrative, non-exclusive examples of the threshold fraction include
threshold fractions
of at least 20 weight % (wt%), at least 30 wt%, at least 40 wt%, at least 50
wt%, at least 60 wt%,
at least 70 wt%, at least 80 wt%, at least 90 wt%, at least 95 wt%, or at
least 99 wt%.
Additionally or alternatively, the selecting at 230 also may include selecting
such that a
solubility of the asphaltenes within the hydrocarbon solvent mixture is
greater than a solubility of
the asphaltenes in propane and/or butane.
Injecting the vapor stream into the subterranean formation at 240 may include
injecting
the vapor stream into the subterranean formation in any suitable manner to
generate reduced-
viscosity hydrocarbons within the subterranean formation. As an illustrative,
non-exclusive
example, the injecting at 240 may be at least substantially similar to the
injecting at 125, which is
discussed in more detail herein with reference to Fig. 4.
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Producing reduced-viscosity hydrocarbons from the subterranean formation at
250 may
include producing the reduced-viscosity hydrocarbons in any suitable manner.
As an illustrative,
non-exclusive example, the producing at 250 may be at least substantially
similar to the
producing at 140, which is discussed in more detail herein with reference to
Fig. 4.
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, the order of the 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.
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.
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.
In the event that any patents, patent applications, or other references are
incorporated by
reference herein and (1) define a term in a manner that is inconsistent with
and/or (2) are
otherwise inconsistent with, either the non-incorporated portion of the
present disclosure or any
of the other incorporated references, the non-incorporated portion of the
present disclosure shall
control, and the term or incorporated disclosure therein shall only control
with respect to the
reference in which the term is defined and/or the incorporated disclosure was
present originally.
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
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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.
Industrial Applicability
The systems and methods disclosed herein are applicable to the oil and gas
industry.
The subject matter of the disclosure 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.
It is believed that the following claims particularly point out certain
combinations and
subcombinations that are novel and non-obvious. Other combinations and
subcombinations of
features, functions, elements and/or properties may be claimed through
amendment of the
present claims or presentation of new claims in this or a related application.
Such amended or
new claims, whether different, broader, narrower, or equal in scope to the
original claims, are
also regarded as included within the subject matter of the present disclosure.
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