U.S. patent application number 14/301746 was filed with the patent office on 2015-02-26 for systems and methods for enhancing production of viscous hydrocarbons from a subterranean formation.
The applicant listed for this patent is Thomas J. Boone, Rahman Khaledi, B. Karl Pustanyk. Invention is credited to Thomas J. Boone, Rahman Khaledi, B. Karl Pustanyk.
Application Number | 20150053401 14/301746 |
Document ID | / |
Family ID | 52479317 |
Filed Date | 2015-02-26 |
United States Patent
Application |
20150053401 |
Kind Code |
A1 |
Khaledi; Rahman ; et
al. |
February 26, 2015 |
Systems and Methods for Enhancing Production of Viscous
Hydrocarbons From a Subterranean Formation
Abstract
Systems and methods for enhancing production of viscous
hydrocarbons from a subterranean formation. The methods may include
heating a hydrocarbon solvent mixture to generate a vapor stream,
injecting the vapor stream into the subterranean formation to
generate reduced-viscosity hydrocarbons, and producing the
reduced-viscosity hydrocarbons from the subterranean formation. The
methods also may include selecting a composition of the hydrocarbon
solvent mixture by 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 upon the stream temperature and the threshold maximum
pressure. The systems may include a hydrocarbon production system
that may be configured to perform the methods and/or that may
include an injection well, an injectant supply assembly, and a
production well.
Inventors: |
Khaledi; Rahman; (Calgary,
CA) ; Pustanyk; B. Karl; (Bragg Creek, CA) ;
Boone; Thomas J.; (Calgary, CA) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Khaledi; Rahman
Pustanyk; B. Karl
Boone; Thomas J. |
Calgary
Bragg Creek
Calgary |
|
CA
CA
CA |
|
|
Family ID: |
52479317 |
Appl. No.: |
14/301746 |
Filed: |
June 11, 2014 |
Current U.S.
Class: |
166/272.4 ;
166/57 |
Current CPC
Class: |
E21B 43/2408 20130101;
E21B 43/2406 20130101 |
Class at
Publication: |
166/272.4 ;
166/57 |
International
Class: |
E21B 43/24 20060101
E21B043/24; E21B 43/25 20060101 E21B043/25 |
Foreign Application Data
Date |
Code |
Application Number |
Aug 22, 2013 |
CA |
2824549 |
Claims
1. A method of enhancing production of viscous hydrocarbons from a
subterranean formation, the method comprising: 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 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 injection well.
2. The method of claim 1, wherein a composition of the hydrocarbon
solvent mixture is selected such that a vapor pressure of the
hydrocarbon solvent mixture at the stream temperature is less than
a threshold maximum pressure of the subterranean formation.
3. The method of claim 1, wherein the stream temperature is at
least 30.degree. C. and less than 250.degree. C.
4. The method of claim 1, wherein the injecting includes condensing
at least 50% of the vapor stream within the subterranean formation
to transfer a latent heat of the vapor stream to the viscous
hydrocarbons and generate the reduced-viscosity hydrocarbons and to
generate a condensate from the vapor stream.
5. The method of claim 4, wherein the method further includes at
least one of dissolving the condensate in the viscous hydrocarbons,
dissolving the viscous hydrocarbons in the condensate, and diluting
the viscous hydrocarbons with the condensate to generate the
reduced-viscosity hydrocarbons.
6. The method of claim 4, wherein the producing includes producing
the condensate with the reduced-viscosity hydrocarbons, and further
wherein the method includes separating a separated portion of the
condensate from the reduced-viscosity hydrocarbons and utilizing a
recycled portion of the condensate as the hydrocarbon solvent
mixture.
7. The method of claim 6, wherein the method further includes
purifying the recycled portion of the condensate prior to the
utilizing.
8. The method of claim 1, wherein the injecting includes injecting
into a stimulated region of the subterranean formation, wherein the
stimulated region includes asphaltenes, and further wherein the
producing includes producing at least 50 wt % of the asphaltenes
that are present within the stimulated region prior to the
injecting.
9. The method of claim 1, wherein the method further includes
preheating a portion of the subterranean formation that is proximal
to the injection well prior to the injecting the vapor stream.
10. The method of claim 1, wherein the method further includes
regulating a composition of the hydrocarbon solvent mixture,
wherein the regulating includes receiving a hydrocarbon feedstock
and altering a composition of the hydrocarbon feedstock to generate
the hydrocarbon solvent mixture, and further wherein the altering
includes decreasing a proportion of the hydrocarbon feedstock that
comprises hydrocarbons with fewer than five carbon atoms.
11. The method of claim 1, wherein the threshold maximum pressure
includes at least one of a fracture pressure for 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 within the subterranean
formation, and an aquifer pressure for an aquifer that is at least
one of above and under the subterranean formation.
12. 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, the method
comprising: 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.
13. The method of claim 12, wherein the selecting includes
selecting such that a vapor pressure of the hydrocarbon solvent
mixture at the stream temperature is less than the threshold
maximum pressure of the subterranean formation.
14. The method of claim 12, wherein the selecting includes at least
one of: (i) increasing the first proportion of the hydrocarbon
solvent to increase a vapor pressure of the hydrocarbon solvent
mixture; (ii) the second proportion of the hydrocarbon solvent
mixture to increase the vapor pressure of the hydrocarbon solvent
mixture; (iii) decreasing the first proportion of the hydrocarbon
solvent mixture to decrease the vapor pressure of the hydrocarbon
solvent mixture; and (iv) increasing the second proportion of the
hydrocarbon solvent mixture to decrease the vapor pressure of the
hydrocarbon solvent mixture.
15. The method of claim 12, wherein the stream temperature is at
least 30.degree. C. and less than 250.degree. C.
16. The method of claim 12, wherein the selecting includes
selecting such that the first compound and the second compound
together comprise at least 50 mole percent of the hydrocarbon
solvent mixture.
17. The method of claim 12, wherein the selecting includes
selecting such that at least 50 weight % of asphaltenes that are
present within the subterranean formation are soluble within the
hydrocarbon solvent mixture at the injection pressure and the
stream temperature.
18. The method of claim 12, wherein the vapor stream is injected
into the subterranean formation at an injection pressure, and
further wherein the selecting includes selecting such that a
difference between a dew point of the vapor stream and a bubble
point of the hydrocarbon solvent mixture is at least 10.degree. C.
at the injection pressure.
19. The method of claim 12, wherein the determining the threshold
maximum pressure includes determining at least one of a fracture
pressure for 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 within
the subterranean formation, and an aquifer pressure for an aquifer
that is at least one of above and under the subterranean
formation.
20. The method of claim 12, wherein the method further includes
injecting the vapor stream into the subterranean formation to
generate reduced viscosity hydrocarbons within the subterranean
formation.
21. The method of claim 20, wherein the method further includes
producing the reduced viscosity hydrocarbons from the subterranean
formation.
22. A hydrocarbon production system, comprising: 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.
23. The system of claim 22, wherein, subsequent to being provided
to the subterranean formation, the vapor stream condenses to a
condensate stream, wherein the production well receives the
condensate stream and conveys the condensate stream from the
subterranean formation with the reduced-viscosity hydrocarbons, and
further wherein the hydrocarbon production system further includes
a condensate recovery system that is configured to separate at
least a portion of the condensate stream from the reduced-viscosity
hydrocarbons.
24. The system of claim 23, wherein the hydrocarbon production
system further includes a recycle conduit that is configured to
convey the portion of the condensate stream to the vaporization
assembly, wherein the vaporization assembly is configured to
vaporize the portion of the condensate stream to generate the vapor
stream.
25. The system of claim 23, wherein the hydrocarbon production
system further includes a purification system that is configured to
receive a feed stream that includes at least one of a hydrocarbon
feedstock stream and the condensate stream and to purify the feed
stream to generate the hydrocarbon solvent mixture.
26. The system of claim 22, wherein the hydrocarbon solvent mixture
comprises at least one of a gas plant condensate and a crude oil
refinery condensate.
27. The system of claim 22, wherein at least 50 mole percent of the
hydrocarbon solvent mixture comprises at least two of a compound
with five carbon atoms, a compound with six carbon atoms, a
compound with seven carbon atoms, and a compound with eight carbon
atoms.
28. The system of claim 22, wherein less than 30 mole percent of
the hydrocarbon solvent mixture comprises a compound with one to
three carbon atoms.
29. The system of claim 22, wherein the production well extends at
least partially below the injection well.
30. The system of claim 22, wherein at least a portion of the
production well is parallel to a corresponding portion of the
injection well.
31. The system of claim 22, wherein both of the injection well and
the production well include a horizontal portion.
32. The system of claim 22, wherein at least a portion of the
production well is located vertically below a corresponding portion
of the injection well.
33. The system of claim 22, wherein the threshold maximum pressure
is at least one of a fracture pressure for 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 within the subterranean
formation, and an aquifer pressure for an aquifer that is above the
subterranean formation.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application claims the priority benefit of Canadian
Patent Application 2,824,549 filed Aug. 22, 2013 entitled SYSTEMS
AND METHODS FOR ENHANCING PRODUCTION OF VISCOUS HYDROCARBONS FROM A
SUBTERRANEAN FORMATION, the entirety of which is incorporated by
reference herein.
FIELD
[0002] 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
[0003] 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.
[0004] 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.
[0005] 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
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
[0006] 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.
[0007] 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.degree. 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 injection well; wherein a
vapor pressure of the hydrocarbon solvent mixture is less than a
threshold maximum pressure of the subterranean formation.
[0008] 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.
[0009] 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.
[0010] 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
[0011] FIG. 1 is a schematic representation of a hydrocarbon
production system.
[0012] FIG. 2 is a plot of vapor pressure vs. temperature for a
plurality of hydrocarbons.
[0013] FIG. 3 is a histogram depicting a carbon content of
compounds that may be present in a gas plant condensate.
[0014] FIG. 4 is a flowchart depicting disclosure method of
enhancing production of viscous hydrocarbons from a subterranean
formation.
[0015] FIG. 5 is a flowchart depicting disclosure method of
selecting a composition of a hydrocarbon solvent mixture.
[0016] 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
[0017] 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.
[0018] 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 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. 1 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.
[0019] 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.
[0020] 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.
[0021] 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.
[0022] 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.
[0023] 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 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.
[0024] 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.
[0025] 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.
[0026] 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.
[0027] 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.
[0028] 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.
[0029] 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.
[0030] 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.
[0031] 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 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.
[0032] 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.
[0033] 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.
[0034] 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.
[0035] 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 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.
[0036] 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.
[0037] 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%, 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.
[0038] 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.
[0039] 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.degree. C., at least 35.degree. C., at
least 40.degree. C., at least 45.degree. C., at least 50.degree.
C., at least 55.degree. C., at least 60.degree. C., at least
65.degree. C., at least 70.degree. C., at least 75.degree. C., at
least 80.degree. C., at least 85.degree. C., at least 90.degree.
C., at least 95.degree. C., at least 100.degree. C., at least
105.degree. C., at least 110.degree. C., at least 115.degree. C.,
at least 120.degree. C., at least 125.degree. C., at least
130.degree. C., at least 135.degree. C., at least 140.degree. C.,
at least 145.degree. C., at least 150.degree. C., at least
155.degree. C., at least 160.degree. C., at least 165.degree. C.,
at least 170.degree. C., at least 175.degree. C., at least
180.degree. C., at least 185.degree. C., at least 190.degree. C.,
at least 195.degree. C., at least 200.degree. C., at least
205.degree. C., and/or at least 210.degree. C. Additionally or
alternatively, the stream temperature also may be less than or
equal to 250.degree. C., less than or equal to 240.degree. C., less
than or equal to 230.degree. C., less than or equal to 220.degree.
C., less than or equal to 210.degree. C., less than or equal to
200.degree. C., less than or equal to 190.degree. C., less than or
equal to 180.degree. C., less than or equal to 170.degree. C., less
than or equal to 160.degree. C., less than or equal to 150.degree.
C., less than or equal to 140.degree. C., less than or equal to
130.degree. C., less than or equal to 120.degree. C., less than or
equal to 110.degree. C., less than or equal to 100.degree. C., less
than or equal to 90.degree. C., less than or equal to 80.degree.
C., less than or equal to 70.degree. C., less than or equal to
60.degree. C., less than or equal to 50.degree. C., and/or less
than or equal to 40.degree. 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.
[0040] 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.degree.
C., at least 15.degree. C., at least 20.degree. C., at least
25.degree. C., at least 30.degree. C., at least 35.degree. C., at
least 40.degree. C., at least 45.degree. C., at least 50.degree.
C., at least 55.degree. C., at least 60.degree. C., at least
65.degree. C., at least 70.degree. C., at least 75.degree. C., at
least 80.degree. C., at least 85.degree. C., at least 90.degree.
C., at least 95.degree. C., or at least 100.degree. 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.
[0041] 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.
[0042] 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 and/or
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.
[0043] 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).
[0044] 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.
[0045] 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 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.
[0046] 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.
[0047] 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.
[0048] 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 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.
[0049] 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.
[0050] 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).
[0051] 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 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.
[0052] 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.
[0053] 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.
[0054] 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
herein. Additionally or alternatively, the selecting at 110 also
may include selecting using any of the subsequently described
methods 200.
[0055] 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.
[0056] 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.
[0057] 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.
[0058] 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.
[0059] 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.
[0060] 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.
[0061] 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.
[0062] 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.
[0063] 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 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.
[0064] 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.
[0065] 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.
[0066] 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.
[0067] Determining the threshold maximum pressure for the
subterranean formation at 210 may include determining any suitable
threshold maximum pressure for the subterranean formation.
Illustrative, non-exclusive examples of the threshold maximum
pressure are discussed in more detail herein.
[0068] 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 a viscosity, or average viscosity, of the
viscous hydrocarbons. 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.
[0069] 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.
[0070] 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 maximum threshold
pressure of the subterranean formation. Illustrative, non-exclusive
examples of the stream temperature are disclosed herein.
[0071] 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.
[0072] 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.
[0073] 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.
[0074] 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.
[0075] 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.
[0076] 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.
[0077] 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.
[0078] 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.
[0079] 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.
[0080] 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.
[0081] 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.
INDUSTRIAL APPLICABILITY
[0082] The systems and methods disclosed herein are applicable to
the oil and gas industry.
[0083] 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.
[0084] 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.
* * * * *