U.S. patent application number 14/086747 was filed with the patent office on 2014-06-26 for systems and methods for pressure-cycled stimulation during gravity drainage operations.
The applicant listed for this patent is Thomas J. Boone, Nima Saber. Invention is credited to Thomas J. Boone, Nima Saber.
Application Number | 20140174744 14/086747 |
Document ID | / |
Family ID | 50972877 |
Filed Date | 2014-06-26 |
United States Patent
Application |
20140174744 |
Kind Code |
A1 |
Boone; Thomas J. ; et
al. |
June 26, 2014 |
Systems and Methods For Pressure-Cycled Stimulation During Gravity
Drainage Operations
Abstract
Systems and methods for pressure-cycled stimulation during
gravity drainage operations. These systems and methods include
increasing a pressure within a stimulation well that extends within
a subterranean formation and subsequently decreasing the pressure
within the stimulation well to increase production of viscous
hydrocarbons from a production well. The systems and methods
include repeating the increasing and the decreasing for a plurality
of stimulation cycles and producing viscous hydrocarbons from the
subterranean formation during the increasing, the decreasing, and
the repeating. The increasing may include increasing a reservoir
pressure within the subterranean formation to a pressure that is
greater than a bubble point pressure of the viscous hydrocarbons,
and the decreasing may include decreasing the reservoir pressure to
a pressure that is less than the bubble point pressure of the
viscous hydrocarbons.
Inventors: |
Boone; Thomas J.; (Calgary,
CA) ; Saber; Nima; (Calgary, CA) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Boone; Thomas J.
Saber; Nima |
Calgary
Calgary |
|
CA
CA |
|
|
Family ID: |
50972877 |
Appl. No.: |
14/086747 |
Filed: |
November 21, 2013 |
Current U.S.
Class: |
166/303 ;
166/53 |
Current CPC
Class: |
E21B 43/2408 20130101;
E21B 43/16 20130101; E21B 44/00 20130101; E21B 43/2406
20130101 |
Class at
Publication: |
166/303 ;
166/53 |
International
Class: |
E21B 43/24 20060101
E21B043/24; E21B 44/00 20060101 E21B044/00 |
Foreign Application Data
Date |
Code |
Application Number |
Dec 21, 2012 |
CA |
2800443 |
Claims
1. A method of stimulating and producing viscous hydrocarbons from
a subterranean formation that includes the viscous hydrocarbons,
the method comprising: increasing a pressure within a stimulation
well that extends within the subterranean formation to increase a
reservoir pressure to a pressure that is above an upper pressure
threshold that is greater than a bubble point pressure of the
viscous hydrocarbons; decreasing the pressure within the
stimulation well to decrease the reservoir pressure to a pressure
that is below a lower pressure threshold that is less than the
bubble point pressure of the viscous hydrocarbons; repeating the
increasing the pressure and the decreasing the pressure for a
plurality of stimulation cycles; and producing, as a reduced
viscosity hydrocarbon stream, the viscous hydrocarbons from a
production well that extends within the subterranean formation and
is spaced apart from the stimulation well, wherein the producing
includes producing during the increasing the pressure, the
decreasing the pressure, and the repeating, and wherein the
production well is spaced-apart from the stimulation well.
2. The method of claim 1, wherein the increasing the pressure
includes providing a stimulant fluid stream to the stimulation
well.
3. The method of claim 2, wherein the providing a stimulant fluid
stream includes controlling a flow rate of the stimulant fluid
stream to control a rate of the increasing by at least one of: (i)
increasing the flow rate of the stimulant fluid stream responsive
to the rate of the increasing being less than a threshold lower
increasing rate; and (ii) decreasing the flow rate of the stimulant
fluid stream responsive to the rate of the increasing being greater
than a threshold upper increasing rate.
4. The method of claim 1, wherein, subsequent to the increasing the
pressure and prior to the decreasing the pressure, the method
further comprises maintaining the reservoir pressure above the
upper pressure threshold for at least a threshold pressurized
time.
5. The method of claim 4, wherein the increasing includes providing
a stimulant fluid stream to the stimulation well at a first flow
rate, and wherein the maintaining the reservoir pressure above the
upper pressure threshold includes providing the stimulant fluid
stream to the stimulation well at a second flow rate.
6. The method of claim 4, wherein the maintaining includes
controlling a flow rate of a stimulant fluid stream to maintain the
reservoir pressure above the upper pressure threshold.
7. The method of claim 4, wherein the threshold pressurized time is
at least 1 day and less than 500 days.
8. The method of claim 4, further comprising preserving a fluid
temperature difference between a stimulant fluid stream and the
reduced viscosity hydrocarbon stream below a threshold fluid
temperature difference during the maintaining.
9. The method of claim 1, wherein the decreasing the pressure
includes at least one of ceasing providing a stimulant fluid stream
to the stimulation well and decreasing a flow rate of the stimulant
fluid stream to the stimulation well.
10. The method of claim 1, wherein the decreasing the pressure
includes liberating a solution gas from the viscous hydrocarbon
while the viscous hydrocarbon is present within the subterranean
formation.
11. The method of claim 1, wherein, subsequent to the decreasing
the pressure, the method further comprises maintaining the
reservoir pressure below the lower pressure threshold for at least
a threshold depressurized time, wherein the threshold depressurized
time is at least 1 day and less than 250 days.
12. The method of claim 1, wherein the repeating includes repeating
the increasing and the decreasing for at least 10 stimulation
cycles.
13. The method of claim 1, wherein the repeating includes
performing the increasing the pressure and subsequently performing
the decreasing the pressure in each stimulation cycle of the
plurality of stimulation cycles.
14. The method of claim 1, wherein the producing includes
continuously producing the viscous hydrocarbons during at least 90%
of a time period during which the increasing the pressure, the
decreasing the pressure, and the repeating occurs.
15. The method of claim 1, further comprising monitoring the
reservoir pressure.
16. The method of claim 15, wherein the decreasing the pressure
includes decreasing the pressure based, at least in part, on
determining that the reservoir pressure is greater than the upper
pressure threshold.
17. The method of claim 15, wherein the increasing the pressure
includes increasing the pressure based, at least in part, on
determining that the reservoir pressure is less than the lower
pressure threshold.
18. The method of claim 15, wherein the monitoring the reservoir
pressure includes calculating the reservoir pressure.
19. The method of claim 1, wherein the producing further comprises
producing the viscous hydrocarbons from the production well for a
pre-production time prior to at least the decreasing the pressure
and the repeating.
20. The method of claim 1, further comprising performing the method
as part of at least one of a steam-assisted gravity drainage
process, a solvent-assisted steam-assisted gravity drainage
process, and a vapor extraction process.
21. A system configured to produce viscous hydrocarbons from a
subterranean formation, the system comprising: a stimulation well
that extends within the subterranean formation; a stimulant fluid
supply system that is configured to provide a stimulant fluid
stream to the subterranean formation via the stimulation well; a
production well that is spaced-apart from the stimulation well,
extends within the subterranean formation, and is configured to
produce a reduced viscosity hydrocarbon stream from the
subterranean formation; and a controller that is programmed to
control the operation of the system using the method of claim 1.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application claims priority from Canadian Patent
Application No. 2,800,443 filed Dec. 21, 2012 entitled SYSTEMS AND
METHODS FOR PRESSURE-CYCLED STIMULATION DURING GRAVITY DRAINAGE
OPERATIONS, the entirety of which are incorporated by reference
herein.
FIELD OF THE DISCLOSURE
[0002] The present disclosure is directed generally to systems and
methods for stimulating a subterranean formation during gravity
drainage operations, and more specifically to systems and methods
that include pressure-cycling a stimulation well during gravity
drainage operations.
BACKGROUND OF THE DISCLOSURE
[0003] Certain subterranean formations may contain viscous
hydrocarbons with a viscosity that is too high to naturally flow
and/or to be produced from the subterranean formation using
traditional primary and/or secondary hydrocarbon recovery
techniques (i.e., natural and/or artificial pressure drive,
respectively) due to the high viscosity thereof. As illustrative,
non-exclusive examples, oil sands formations, tar sands formations,
and/or bituminous sands formations may include high-viscosity
bitumen, tar, and/or oil that will not flow under native reservoir
conditions (or will not flow at a rate that is sufficient to
provide for economic production of the viscous hydrocarbons).
[0004] Under these conditions, one or more traditional stimulation
processes may be utilized to decrease the viscosity of the
high-viscosity hydrocarbons, thereby permitting flow thereof and/or
permitting flow at a rate that is sufficient for economic
production of the viscous hydrocarbons. As an illustrative,
non-exclusive example, gravity drainage operations, such as
steam-assisted gravity drainage (SAGD), solvent-assisted
steam-assisted gravity drainage (SA-SAGD), and/or vapor extraction
(VAPEX) may be utilized to decrease the viscosity of the viscous
hydrocarbons.
[0005] While these traditional stimulation processes may permit
production of a portion of the viscous hydrocarbons from the
subterranean formation, a rate at which the viscous hydrocarbons
may be produced from the subterranean formation may be relatively
low. Thus, there exists a need for improved systems and methods for
stimulating and producing viscous hydrocarbons from a subterranean
formation that includes the viscous hydrocarbons.
SUMMARY OF THE DISCLOSURE
[0006] Systems and methods for pressure-cycled stimulation during
gravity drainage operations. The systems and methods include
increasing a pressure within a stimulation well that extends within
a subterranean formation and subsequently decreasing the pressure
within the stimulation well to increase the production of viscous
hydrocarbons from a production well. The systems and methods
further include repeating the increasing and the decreasing for a
plurality of stimulation cycles and producing viscous hydrocarbons
from the subterranean formation via the production well during the
increasing, the decreasing, and the repeating. The increasing may
include increasing a reservoir pressure within the subterranean
formation to a pressure that is greater than a bubble point
pressure of the viscous hydrocarbons and/or an initial reservoir
pressure, and the decreasing may include decreasing the reservoir
pressure to a pressure that is less than the bubble point pressure
of the viscous hydrocarbons.
[0007] In some embodiments, the increasing may include providing a
stimulant fluid stream to the stimulation well. In some
embodiments, the systems and methods further may include
maintaining the reservoir pressure above an upper pressure
threshold that is greater than the bubble point pressure and/or the
initial reservoir pressure for at least a threshold pressurized
time. In some embodiments, the maintaining may include controlling
a flow rate of the stimulant fluid stream to the stimulation
well.
[0008] In some embodiments, the decreasing may include ceasing the
provision of the stimulant fluid stream to the stimulation well
and/or decreasing the flow rate of the stimulant fluid stream to
the stimulation well. In some embodiments, the decreasing may
include maintaining the reservoir pressure below a lower pressure
threshold that is less than the bubble point pressure for at least
a threshold depressurized time.
[0009] In some embodiments, the systems and methods further may
include monitoring the reservoir pressure. In some embodiments, the
systems and methods may include initiating the increasing and/or
the decreasing based, at least in part, on the monitoring.
BRIEF DESCRIPTION OF THE DRAWINGS
[0010] FIG. 1 is a schematic representation of illustrative,
non-exclusive examples of a viscous hydrocarbon production system
that may be utilized with and/or include the systems and methods
according to the present disclosure.
[0011] FIG. 2 is a plot of reservoir pressure vs. time that may be
experienced within a subterranean formation that is utilized with
and/or included in the systems and methods according to the present
disclosure.
[0012] FIG. 3 is a flowchart depicting methods according to the
present disclosure of stimulating and producing viscous
hydrocarbons from a subterranean formation that includes the
viscous hydrocarbons.
DETAILED DESCRIPTION AND BEST MODE OF THE DISCLOSURE
[0013] FIG. 1 is a schematic representation of illustrative,
non-exclusive examples of a viscous hydrocarbon production system
10 that may be utilized with and/or include the systems and methods
according to the present disclosure. Viscous hydrocarbon production
system 10 also may be referred to herein as hydrocarbon production
system 10. The viscous hydrocarbon production system includes a
stimulation well 40 and a production well 20 that both extend
within a subterranean formation 16 that is present within a
subsurface region 14.
[0014] Subterranean formation 16 may be any suitable structure that
contains viscous hydrocarbons 18 therein. As illustrative,
non-exclusive examples, the subterranean formation may be an oil
sands formation, a tar sands formation, and/or a bituminous sands
formation. Illustrative, non-exclusive examples of viscous
hydrocarbons 18 include bitumen, tar, an unconventional hydrocarbon
reserve, and/or a hydrocarbon reserve with a viscosity that is too
high to be produced from the subterranean formation using primary
and/or secondary hydrocarbon recovery operations.
[0015] Another illustrative, non-exclusive example of viscous
hydrocarbons 18 according to the present disclosure include viscous
hydrocarbons that contain solution gas adsorbed therein. This may
include solution gas that is adsorbed within the viscous
hydrocarbons and has a bubble point pressure of greater than 100
kilopascals (kPa), greater than 200 kPa, greater than 300 kPa,
greater than 400 kPa, greater than 500 kPa, greater than 750 kPa,
greater than 1000 kPa, greater than 1250 kPa, greater than 1500
kPa, greater than 2000 kPa, greater than 2500 kPa, or greater than
3000 kPa. Additionally or alternatively, this also may include
solution gas that is adsorbed within the viscous hydrocarbons and
has a bubble point pressure of less than 5000 kPa, less than 4500
kPa, less than 4000 kPa, less than 3500 kPa, less than 3000 kPa,
less than 2500 kPa, less than 2000 kPa, less than 1500 kPa, or less
than 1000 kPa.
[0016] It is within the scope of the present disclosure that, as
discussed, subterranean formation 16 and/or viscous hydrocarbons 18
also may include, contain, and/or be mixed with one or more
non-condensable gasses. Illustrative, non-exclusive examples of
non-condensable gasses include methane, nitrogen gas and carbon
dioxide.
[0017] As schematically illustrated in FIG. 1, production well 20
and stimulation well 40 may be defined by respective, spaced-apart,
wellbores 22 and 42 that may extend from surface region 12, through
subsurface region 14, and/or within subterranean formation 16. It
is within the scope of the present disclosure that wellbores 22 and
42 may include and/or define any suitable individual and/or
relative orientation. As illustrative, non-exclusive examples,
wellbores 22 and 42 and/or portions thereof may include and/or be
vertical wellbores, horizontal wellbores, and/or deviated
wellbores. As another illustrative, non-exclusive example, and as
shown in FIG. 1, a horizontal portion 43 of stimulation well 40 (or
wellbore 42 thereof) may extend within subterranean formation 16
and vertically above a horizontal portion 23 of production well 20
(or wellbore 22 thereof).
[0018] Additionally or alternatively, at least a parallel portion
of stimulation well 40 may be parallel to, or at least
substantially parallel to, a respective parallel portion of
production well 20 (such as horizontal portions 43 and 23,
respectively, in FIG. 1). As discussed in more detail herein, this
relative orientation of production well 20 with respect to
stimulation well 40 may permit reduced viscosity hydrocarbon stream
26 to flow into production well 20 under the influence of gravity.
Illustrative, non-exclusive examples of the parallel portion of
production well 20 and/or the parallel portion of stimulation well
40 include portions that comprise at least 25%, at least 30%, at
least 40%, at least 50%, at least 60%, at least 70%, at least 80%,
or at least 90% of a length of the production well and/or the
stimulation well.
[0019] Stimulation well 40 may be associated with, proximal to, at
least partially coextensive with, and/or in fluid communication
with a stimulation chamber 60. Stimulation chamber 60 may include
any suitable portion of subterranean formation 16 and/or wellbore
42 of stimulation well 40 and also may be referred to herein as a
steam chamber 60 and/or a vapor chamber 60. As illustrated in FIG.
1, at least a portion of stimulation chamber 60 may be coextensive
with, or at least partially coextensive with, at least a portion of
stimulation well 40 and/or wellbore 42 thereof. As an illustrative,
non-exclusive example, stimulation chamber 60 may surround and/or
be at least partially concentric with at least a portion of
wellbore 42.
[0020] The viscous hydrocarbon production system also includes a
stimulant fluid supply system 44, which is configured to provide a
stimulant fluid stream 46 to subterranean formation 16 via the
stimulation well. Stimulant fluid supply system 44 may include any
suitable structure that may be adapted, configured, and/or designed
to supply stimulant fluid stream 46 to subterranean formation 16
via stimulation well 40. As illustrative, non-exclusive examples,
stimulant fluid supply system 44 may include any suitable pump 47,
valve 48, compressor 49, pipe and/or fluid conduit 50, and/or
source 51 of stimulant fluid for stimulant fluid stream 46.
[0021] The stimulant fluid stream 46 that is provided to the
subterranean formation by the stimulant fluid supply system via
stimulation well 40 may physically, chemically, and/or thermally
contact viscous hydrocarbons 18 that are within, associated with,
and/or proximal to stimulation chamber 60 to decrease the viscosity
of the viscous hydrocarbons, thereby generating a reduced viscosity
hydrocarbon stream 26 therefrom. The reduced viscosity hydrocarbon
stream may flow through subterranean formation 16 to production
well 20, and the production well may convey the reduced viscosity
hydrocarbon stream from the subterranean formation to and/or
proximal to a surface region 12, thereby producing the reduced
viscosity hydrocarbon stream from the subterranean formation.
[0022] Viscous hydrocarbon production system 10 optionally may
further include a controller 80, which is programmed or otherwise
configured to control the operation of at least a portion of the
viscous hydrocarbon production system. Controller 80 may include
any suitable structure that is adapted, configured, and/or
programmed to control the operation of at least a portion of
viscous hydrocarbon production assembly 10. As illustrative,
non-exclusive examples, controller 80 may include and/or be a
computer, a personal computer, and/or a dedicated control device,
and controller 80 may control the operation of viscous hydrocarbon
production assembly 10 in any suitable manner. This may include
controlling the operation of the viscous hydrocarbon production
assembly according to methods 200 that are discussed in more detail
herein with reference to FIG. 3.
[0023] As an illustrative, non-exclusive example, stimulation well
40 and/or stimulant fluid supply system 44 may include one or more
pumps 47 and/or valves 48, and controller 80 may control the
operation of pumps 47 and/or valves 48 to control a flow rate of
stimulant fluid stream 46 to the subterranean formation. As another
illustrative, non-exclusive example, production well 20 may include
one or more pumps 27 and/or valves 28, and controller 80 may
control the operation of pumps 27 and/or valves 28 to control a
flow rate of reduced viscosity hydrocarbon stream 26 therethrough.
This may include increasing a rotational frequency, or output, of
pumps 27 and/or pumps 47 to increase a flow rate of reduced
viscosity hydrocarbon stream 26 and/or stimulant fluid stream 46,
respectively, decreasing a rotational frequency of pumps 27 and/or
pumps 47 to decrease the flow rate of stream 26 and/or stream 46,
opening valves 28 and/or valves 48 to increase the flow rate of
stream 26 and/or stream 46, and/or closing valves 28 and/or valves
48 to decrease the flow rate of stream 26 and/or stream 46.
[0024] As a further optional feature, and as indicated in dashed
lines in FIG. 1, viscous hydrocarbon production system 10 may
include one or more detectors 90 that may be configured to detect
one or more properties, which also may be referred to herein as
reservoir properties, of subterranean formation 16, stimulation
well 40, stimulant fluid supply system 44, and/or production well
20. As illustrative, non-exclusive examples, detectors 90 may
detect a pressure, a temperature, and/or a fluid flow rate within
subterranean formation 16, stimulation well 40, stimulant fluid
supply system 44, and/or production well 20. As more specific but
still illustrative, non-exclusive examples, detectors 90 may detect
a reservoir pressure within the subterranean formation, a bottom
hole pressure within the stimulation well, a wellhead pressure of
the production well, and/or a wellhead temperature of the
production well. When viscous hydrocarbon production system 10
includes both controller 80 and one or more detectors 90, the
controller may be configured to control and/or otherwise regulate
at least a portion of the system, such as the pressure within the
stimulation well and/or the flow of stream 26 and/or stream 46,
responsive to properties detected by the one or more detectors.
[0025] It is within the scope of the present disclosure that
stimulant fluid stream 46 may reduce the viscosity of viscous
hydrocarbons 18 that are present within subterranean formation 16
to generate reduced viscosity hydrocarbon stream 26 in any suitable
manner. As an illustrative, non-exclusive example, stimulant fluid
stream 46 may include and/or be a diluent and/or a solvent for
viscous hydrocarbons 18, and the viscous hydrocarbons may mix with,
absorb, and/or be diluted by stimulant fluid stream 46, thereby
generating reduced viscosity hydrocarbon stream 26. Additionally or
alternatively, and as another illustrative, non-exclusive example,
stimulant fluid stream 46 may have an elevated temperature and may
transfer thermal energy to viscous hydrocarbons 18, thereby
increasing a temperature of the viscous hydrocarbons, decreasing
the viscosity thereof, and generating the reduced viscosity
hydrocarbon stream. Illustrative, non-exclusive examples of
stimulant fluid stream 46 include fluid streams that include and/or
contain water, steam, a solvent for the viscous hydrocarbons,
and/or a diluent for the viscous hydrocarbons, and these fluid
streams may be supplied to the subterranean formation at an
elevated temperature (i.e., a temperature that is greater than a
temperature of the subterranean formation).
[0026] As discussed, reduced viscosity hydrocarbon stream 26 may
include viscous hydrocarbons 18 that were present within
subterranean formation 16 prior to formation of viscous hydrocarbon
production assembly 10. However, and as also discussed, a viscosity
of reduced viscosity hydrocarbon stream 26 may be less than a
viscosity of viscous hydrocarbons 18 due to one or more
interactions between viscous hydrocarbons 18 and stimulant fluid
stream 46. As an illustrative, non-exclusive example, the reduced
viscosity hydrocarbon stream may include at least a portion of the
stimulant fluid stream, with the portion of the stimulant fluid
stream reducing the viscosity of the viscous hydrocarbons that are
present within the reduced viscosity hydrocarbon stream. As another
illustrative, non-exclusive example, a temperature of the reduced
viscosity hydrocarbon stream may be greater than an ambient
temperature within the subterranean formation and/or a temperature
of the viscous hydrocarbons prior to stimulant fluid stream 46
being supplied to the subterranean formation.
[0027] The systems and methods disclosed herein may be utilized to
increase, relative to more traditional stimulation and/or
production strategies, a rate of production of viscous hydrocarbons
18 from subterranean formation 16. As an illustrative,
non-exclusive example, traditional gravity drainage processes, such
as stream-assisted gravity drainage (SAGD), solvent-assisted
steam-assisted gravity drainage (SA-SAGD), and/or vapor extraction
(VAPEX) may utilize a stimulation well and a production well that
may define a relative orientation that is similar to the relative
orientation of stimulation well 40 and production well 20 of FIG.
1. However, the operation and/or control of the stimulation well
and the production well during the traditional gravity drainage
processes are distinctly different from the operation and/or
control of viscous hydrocarbon production system 10 of FIG. 1.
[0028] In a traditional gravity drainage process, a stimulant fluid
stream may be provided continuously, or at least substantially
continuously, to a subterranean formation via a stimulation well.
The stimulant fluid stream may contact viscous hydrocarbons that
are present within the subterranean formation, thereby decreasing a
viscosity thereof, to produce a reduced viscosity hydrocarbon
stream that may flow through the subterranean formation to a
production well. The production well may convey the reduced
viscosity hydrocarbon stream from the subterranean formation to a
surface region.
[0029] While such a traditional gravity drainage process may
produce viscous hydrocarbons from the subterranean formation, it
suffers from several limitations. As an illustrative, non-exclusive
example, a non-condensable gas may evolve from viscous hydrocarbons
and/or may otherwise be present within the subterranean formation,
and this non-condensable gas may separate and/or insulate the
viscous hydrocarbons that are present within the subterranean
formation from the stimulant fluid stream, thereby decreasing an
effectiveness of the stimulant fluid stream at decreasing the
viscosity of the viscous hydrocarbons.
[0030] In contrast to these traditional gravity drainage processes,
the systems and methods disclosed herein include periodically
cycling a reservoir pressure within subterranean formation 16. This
is discussed in more detail herein with reference to FIGS. 2-3 and
may include cycling the reservoir pressure between an upper
pressure threshold that is greater than a bubble point pressure of
viscous hydrocarbons 18 and a lower pressure threshold that is less
than the bubble point pressure of the viscous hydrocarbons.
[0031] As used herein, the phrase "reservoir pressure" may refer to
a pressure that exists within the subterranean formation and/or a
pressure of the viscous hydrocarbons that are present within the
subterranean formation. The reservoir pressure also may be referred
to herein as the pressure within subterranean formation 16 and/or
the pressure of the subterranean formation 16. This reservoir
pressure may be different from a "bottom hole pressure" that may be
measured within a well (such as production well 20 and/or
stimulation well 40) that extends within the subterranean
formation. The well may be in direct, or at least substantially
direct, fluid communication with surface region 12 via a wellbore
(such as wellbore 22 and/or 42) thereof, thus permitting
substantial fluctuations in the bottom hole pressure thereof, such
as by providing a fluid to and/or removing a fluid from the
wellbore. In contrast, viscous hydrocarbons 18, together with a
matrix material 19 (such as rock, gravel, and/or sand) that may be
present within subterranean formation 16, may resist fluid flow
therethrough. Thus, the pressure within the subterranean formation
may differ significantly from the bottom hole pressure.
[0032] With this in mind, the systems and methods disclosed herein
may include increasing and/or decreasing the reservoir pressure to
pressures that are above and/or below the bubble point pressure of
the viscous hydrocarbons. When the reservoir pressure is lowered to
a pressure that is less than the bubble point pressure of viscous
hydrocarbons 18 (such as the lower pressure threshold), one or more
gasses and/or volatile hydrocarbons that are included within
viscous hydrocarbon 18 may evolve and/or be liberated from the
viscous hydrocarbons. These gasses and/or volatile hydrocarbons may
be referred to herein as solution gas. When this solution gas is
evolved or otherwise released or discharged from the viscous
hydrocarbons, it produces bubbles of the liberated solution gas in
viscous hydrocarbons. These bubbles of liberated solution gas may
cause the viscous hydrocarbons to swell and/or otherwise may
increase a volume and/or decrease a density thereof. This swelling
may provide a motive force for flow of the viscous hydrocarbons
within subterranean formation 18 and may increase a flow rate of
reduced viscosity hydrocarbon stream 26 into production well
20.
[0033] The liberated solution gas may provide an additional motive
force for the production of reduced viscosity hydrocarbon stream 26
from production well 20. In addition, decreasing the reservoir
pressure may permit non-condensable gas to mix with stimulant fluid
stream 46, mix with reduced viscosity hydrocarbon stream 26, and/or
be produced from the subterranean formation via production well 20.
This may decrease a potential for the non-condensable gas to
separate and/or otherwise insulate viscous hydrocarbons 14 from
stimulant fluid stream 26.
[0034] The periodic cycling of the reservoir pressure according to
the systems and methods disclosed herein may cause, contribute to,
and/or otherwise generate a corresponding cyclic, staged,
sequential, and/or stepped growth of stimulation chamber 60 (and/or
a volume thereof). As an illustrative, non-exclusive example, and
during a given (i.e., a particular or illustrative) pressure cycle,
which also may be referred to herein as a stimulation cycle, the
reservoir pressure may be increased to a value that is greater than
the upper pressure threshold for a first period of time, before
being decreased (and/or permitted to decrease) to a value that is
less than the lower pressure threshold for a second period of time.
The first period of time also may be referred to herein as a
threshold pressurized time, and the second period of time, which
also may be referred to herein as a threshold pressurized time,
also may be referred to herein as a threshold depressurized
time.
[0035] Referring again to FIG. 1, a volume, outer perimeter, or
other outer boundary of stimulation chamber 60 is schematically
indicated at 62 and represents the outer boundary of the
stimulation chamber subsequent to the given pressure cycle. As
additional pressure cycles are performed, the volume of the
stimulation chamber may continue to increase, as indicated at 64
and 66, with each successive cycle. The pressure cycles may be
repeated any suitable number of times and/or with any suitable
frequency and may produce a corresponding growth in the volume of
stimulation chamber 60 with each pressure cycle.
[0036] FIG. 2 is a plot 100 of reservoir pressure vs. time that may
be experienced within a subterranean formation that is utilized
with the systems and methods according to the present disclosure.
In FIG. 2, the lower pressure threshold is indicated at 122, the
upper pressure threshold is indicated at 124, and the bubble point
pressure is indicated at 126, with each of these pressures being
discussed in more detail herein with reference to FIG. 1.
[0037] In the illustrative, non-exclusive example of FIG. 2, the
reservoir pressure is relatively constant, as indicated at 120,
during a period of time 102 that is prior to the formation of
stimulation and/or production wells within the subterranean
formation and/or prior to stimulation of and/or production from the
subterranean formation. This pressure 120 will generally be greater
than bubble point pressure 126 due to chemical equilibration within
the subterranean formation that may take place over thousands of
years.
[0038] However, and subsequent to formation of at least one
stimulation well and at least one production well within the
subterranean formation to generate a viscous hydrocarbon production
assembly that may be at least substantially similar to assembly 10
of FIG. 1, the reservoir pressure may be increased through supply
of a stimulant fluid stream to the subterranean formation via the
stimulation well. This increased pressure may be maintained for a
pre-production time period 104, as illustrated in FIG. 2.
[0039] After the pre-production time period, the reservoir pressure
may be cycled a plurality of times using the systems and methods
according to the present disclosure in a plurality of pressure
cycles 105, which also may be referred to herein as a plurality of
stimulation cycles 105. In FIG. 2, stimulation cycles 105 occur
during first cycle time 106, second cycle time 108, third cycle
time 110, fourth cycle time 112, and fifth cycle time 114. In each
of these stimulation cycles, and as discussed, the reservoir
pressure is decreased to, near, and/or below, lower pressure
threshold 122, which is less than bubble point pressure 126, before
being increased to, near, and/or above upper pressure threshold
124, which is greater than bubble point pressure 126.
[0040] As discussed herein with reference to FIG. 1, a volume of a
stimulation chamber that may be associated with the stimulation
well may increase during each stimulation cycle 105, such as due to
the removal of viscous hydrocarbons from the subterranean
formation. As illustrated in FIG. 2, this increase in the volume of
the stimulation chamber may produce a corresponding increase in the
time that is needed for the reservoir pressure to transition
between lower pressure threshold 122 and upper pressure threshold
124 (as shown by the increased width of the pressure drop that is
associated with each stimulation cycle 105). This may be due to an
increased volume of stimulant fluid that must be supplied to the
stimulation chamber to increase the reservoir pressure from the
lower pressure threshold to the upper pressure threshold, an
increased volume of stimulant fluid that must flow from the
stimulation chamber to decrease the reservoir pressure from the
upper pressure threshold to the lower pressure threshold, and/or an
increase in solution gas liberation due to a greater contact area
between the stimulation chamber and the viscous hydrocarbons.
[0041] As discussed in more detail herein, the systems and methods
according to the present disclosure also may include maintaining
the reservoir pressure at, near, and/or above upper pressure
threshold 124 for at least a threshold pressurized time. This is
illustrated in FIG. 2 at 128. As illustrated in FIG. 2, the
threshold pressurized time may be increased with each successive
stimulation cycle 105. However, it is within the scope of the
present disclosure that the threshold pressurized time may be
constant and/or the same for at least a portion of the plurality of
stimulation cycles 105 and/or that the threshold pressurized time
may decrease from a given stimulation cycle to a subsequent
stimulation cycle.
[0042] In addition, and as indicated in dashed-dot lines in FIG. 2
at 130 and discussed in more detail herein, the systems and methods
according to the present disclosure also may include maintaining
the reservoir pressure at, near, and/or below lower pressure
threshold 122 for at least a threshold depressurized time. Similar
to the threshold pressurized time, it is within the scope of the
present disclosure that the threshold depressurized time may be at
least substantially constant for each of the plurality of
stimulation cycles, may increase from a given stimulation cycle to
a subsequent stimulation cycle, and/or may decrease from a given
stimulation cycle to a subsequent stimulation cycle.
[0043] In FIG. 2, each stimulation cycle 105 is indicated as being
maintained at the same, or at least substantially the same, upper
pressure threshold 124 and/or as being decreased to and/or
maintained at the same, or at least substantially the same, lower
pressure threshold 122. However, it is within the scope of the
present disclosure that the upper pressure threshold and/or the
lower pressure threshold may vary from one stimulation cycle 105 to
the next stimulation cycle 105 and/or across the plurality of
stimulation cycles 105. Regardless, the upper pressure threshold
will be greater than bubble point pressure 126 and the lower
pressure threshold will be less than the bubble point pressure.
[0044] FIG. 3 is a flowchart depicting methods 200 according to the
present disclosure of stimulating and producing viscous
hydrocarbons from a subterranean formation that includes the
viscous hydrocarbons. Methods 200 may include pre-producing viscous
hydrocarbons from the subterranean formation at 205 and/or
monitoring a reservoir pressure within the subterranean formation
at 210. Methods 200 also include increasing a pressure within a
stimulation well at 215 and may include maintaining the reservoir
pressure above an upper pressure threshold at 225. Methods 200
further include decreasing the pressure within the stimulation well
at 230 and may include maintaining the reservoir pressure below a
lower pressure threshold at 240. Methods 200 also include repeating
the increasing at 215 and the decreasing at 230 for a plurality of
stimulation cycles at 245, may include decreasing the viscosity of
the viscous hydrocarbons at 250, and include producing viscous
hydrocarbons from the subterranean formation as a reduced viscosity
hydrocarbon stream at 255.
[0045] Pre-producing viscous hydrocarbons from the subterranean
formation at 205 may include the use of any suitable systems and/or
methods to produce, or otherwise remove, a portion of the viscous
hydrocarbons from the subterranean formation. As an illustrative,
non-exclusive example, the pre-producing may include pre-producing
the viscous hydrocarbons from a production well that extends within
the subterranean formation. It is within the scope of the present
disclosure that the pre-producing at 205 may include pre-producing
the viscous hydrocarbons for any suitable pre-production time prior
to the increasing at 215, the decreasing at 230, and/or the
repeating at 245. As illustrative, non-exclusive examples, the
pre-producing may include pre-producing for at least 50, at least
100, at least 150, at least 200, at least 250, at least 300, at
least 350, at least 400, at least 500, at least 600, at least 700,
at least 800, at least 900, or at least 1000 days. As additional
illustrative, non-exclusive examples, the pre-producing may include
pre-producing using any suitable gravity draining process, such as
SAGD, SA-SAGD, and/or VAPEX.
[0046] Monitoring the reservoir pressure at 210 may include the use
of any suitable systems and/or methods to monitor, detect,
determine, and/or calculate the reservoir pressure within the
subterranean formation and/or to estimate and/or calculate the
reservoir pressure from any suitable reservoir property that is
related thereto. As an illustrative, non-exclusive example, the
monitoring at 210 may include detecting the reservoir pressure.
This detecting may include detecting the reservoir pressure by
utilizing a suitable detector, such as the previously discussed
detector 90. As another illustrative, non-exclusive example, the
monitoring at 210 may include monitoring a reservoir property,
illustrative, non-exclusive examples of which include a bottom hole
pressure of the stimulation well, a bottom hole pressure of the
production well, a wellhead pressure of the production well, a
bottom hole temperature of the production well, and/or a wellhead
temperature of the production well.
[0047] It is within the scope of the present disclosure that the
monitoring at 210 also may, additionally or alternatively, include
calculating the reservoir pressure. This may include calculating
the reservoir pressure in any suitable manner, such as based upon
one or more of the reservoir properties that are discussed herein.
As an illustrative, non-exclusive example the reservoir pressure
may be correlated to the bottom hole pressure of the production
well and/or the bottom hole pressure of the stimulation well.
Subsequently, the reservoir pressure may be calculated based upon a
measured bottom hole pressure.
[0048] Increasing the pressure within the stimulation well at 215
may include increasing the pressure within the stimulation well to
increase a reservoir pressure within the subterranean formation.
This may include increasing the reservoir pressure to a pressure
that is above an upper pressure threshold that is greater than a
bubble point pressure of the viscous hydrocarbons that are present
within the subterranean formation. This increasing may be
accomplished by increasing any suitable pressure within the
stimulation well, such as the bottom hole pressure, in any suitable
manner.
[0049] Illustrative, non-exclusive examples of upper pressure
thresholds according to the present disclosure include upper
pressure thresholds that are greater than the bubble point pressure
of the viscous hydrocarbons and/or greater than a pressure that
existed in the subterranean formation prior to performing methods
200 by at least 10 kilopascals (kPa), at least 25 kPa, at least 50
kPa, at least 75 kPa, at least 100 kPa, at least 200 kPa, at least
300 kPa, at least 400 kPa, at least 500 kPa, at least 600 kPa, at
least 700 kPa, at least 800 kPa, at least 900 kPa, or at least 1000
kPa. Additionally or alternatively, the upper pressure threshold
may be greater than the bubble point pressure of the viscous
hydrocarbons and/or greater than the pressure that existed in the
subterranean formation prior to performing methods 200 by less than
1500 kPa, less than 1400 kPa, less than 1300 kPa, less than 1200
kPa, less than 1100 kPa, less than 1000 kPa, less than 900 kPa,
less than 800 kPa, less than 700 kPa, less than 600 kPa, less than
500 kPa, less than 400 kPa, less than 300 kPa, less than 200 kPa,
or less than 100 kPa.
[0050] As an illustrative, non-exclusive example, the increasing at
215 may include providing a stimulant fluid stream at 220,
illustrative, non-exclusive examples of which are discussed in more
detail herein, to the stimulation well and/or to a stimulation
chamber thereof. The providing at 220 may increase the pressure
within the stimulation well, thereby increasing the reservoir
pressure through fluid communication therewith.
[0051] It is within the scope of the present disclosure that
providing the stimulant fluid stream at 220 may include providing a
total volume of the stimulant fluid stream for each stimulation
cycle of the plurality of stimulation cycles. It is also within the
scope of the present disclosure that the total volume of the
stimulant fluid stream for a given stimulation cycle of the
plurality of stimulation cycles may be less than a total volume of
the stimulant fluid stream for a subsequent stimulation cycle of
the plurality of stimulation cycles and/or that the total volume of
the stimulant fluid stream may increase monotonically with each
stimulation cycle of the plurality of stimulation cycles.
[0052] In addition, it is also within the scope of the present
disclosure that the providing at 220 further may include
controlling a flow rate of the stimulant fluid stream that is
provided to the stimulation well to control a rate of the
increasing at 215 (i.e., to control a rate of the increase in the
pressure within the stimulation well and/or to control a rate of
the increase in the reservoir pressure). As an illustrative,
non-exclusive example, the controlling may include increasing the
flow rate of the stimulant fluid stream responsive to the rate of
the increasing at 215 being less than a threshold lower increasing
rate. Additionally or alternatively, the controlling also may
include decreasing the flow rate of the stimulant fluid stream
responsive to the rate of the increasing at 215 being greater than
a threshold upper increasing rate.
[0053] Maintaining the reservoir pressure above the upper pressure
threshold at 225 may include maintaining the reservoir pressure
above the upper pressure threshold for at least a threshold
pressurized time using any suitable system and/or method.
Illustrative, non-exclusive examples of threshold pressurized times
according to the present disclosure include threshold pressurized
times of at least 1 day, at least 2 days, at least 3 days, at least
4 days, at least 5 days, at least 10 days, at least 15 days, at
least 20 days, at least 25 days, at least 30 days, at least 40
days, at least 50 days, at least 75 days, at least 100 days, at
least 150 days, at least 200 days, at least 300 days, at least 400
days, at least 500 days, at least 600 days, at least 700 days, or
at least 800 days. Additionally or alternatively, the threshold
pressurized time may be less than 1500 days, less than 1250 days,
less than 1000 days, less than 900 days, less than 800 days, less
than 700 days, less than 600 days, less than 500 days, less than
400 days, less than 300 days, less than 250 days, less than 200
days, less than 190 days, less than 180 days, less than 170 days,
less than 160 days, less than 150 days, less than 140 days, less
than 130 days, less than 120 days, less than 110 days, or less than
100 days.
[0054] As an illustrative, non-exclusive example, the increasing at
215 may include providing the stimulant fluid stream to the
stimulation well at a first flow rate and the maintaining at 225
may include providing the stimulant fluid stream to the stimulation
well at a second flow rate that is less than the first flow rate.
This may permit the reservoir pressure to be maintained above the
upper pressure threshold despite flow of the stimulant fluid within
the subterranean formation, production of the stimulant fluid via
the production well, and/or condensation of the stimulant fluid
within the subterranean formation.
[0055] As another illustrative, non-exclusive example, the
maintaining at 225 also may include controlling the flow rate of
the stimulant fluid stream that is provided to the stimulation well
to maintain the reservoir pressure above the upper pressure
threshold. This may include increasing the flow rate of the
stimulant fluid stream responsive to the reservoir pressure being
less than a lower maintaining pressure and/or decreasing the flow
rate of the stimulant fluid stream responsive to the reservoir
pressure being greater than an upper maintaining pressure.
[0056] As yet another illustrative, non-exclusive example, and when
the stimulant fluid stream has a temperature that is greater than a
temperature within the subterranean formation, the method also may
include preserving a fluid temperature difference during the
maintaining at 225. The fluid temperature difference may be defined
as a difference between a stimulant fluid stream temperature and a
reduced viscosity hydrocarbon stream temperature below a threshold
fluid temperature difference. An illustrative, non-exclusive
example of the stimulant fluid stream temperature includes a
saturation temperature of the stimulant fluid stream at an
injection pressure of the stimulant fluid stream. An illustrative,
non-exclusive example of the reduced viscosity hydrocarbon stream
temperature includes a temperature of the reduced viscosity
hydrocarbon stream that is produced from the production well.
[0057] Illustrative, non-exclusive examples of threshold fluid
temperature differences according to the present disclosure include
threshold fluid temperature differences of less than 200.degree.
C., less than 190.degree. C., less than 180.degree. C., less than
170.degree. C., less than 160.degree. C., less than 150.degree. C.,
less than 140.degree. C., less than 130.degree. C., less than
120.degree. C., less than 110.degree. C., less than 100.degree. C.,
less than 90.degree. C., less than 80.degree. C., less than
70.degree. C., less than 60.degree. C., less than 50.degree. C.,
less than 40.degree. C., less than 30.degree. C., less than
20.degree. C., or less than 10.degree. C. As used herein,
preserving a temperature difference or preserving a temperature to
be below a reference temperature and/or within a reference
temperature range additionally or alternatively may be referred to
as buffering, supplementing, sustaining, augmenting, and/or
otherwise maintaining the temperature difference to be at or within
the reference temperature or temperature range.
[0058] Preserving the fluid temperature difference below a
threshold fluid temperature difference may include selectively
changing a flow rate of the reduced viscosity hydrocarbon stream
responsive to the temperature difference, such as to permit and/or
provide for retention of at least a threshold quantity of thermal
energy within the subterranean formation. This may include
selectively increasing the flow rate of the reduced viscosity
hydrocarbon stream responsive to determining that the fluid
temperature difference is greater than the threshold fluid
temperature difference and/or selectively decreasing the flow rate
of the reduced viscosity hydrocarbon stream responsive to
determining that the fluid temperature difference is less than the
threshold fluid temperature difference.
[0059] Additionally or alternatively, preserving the fluid
temperature difference below a threshold fluid temperature
difference also may include selectively changing the flow rate of
the stimulant fluid stream responsive to the fluid temperature
difference, such as to permit and/or provide for supply of at least
a threshold quantity of thermal energy to the subterranean
formation. As illustrative, non-exclusive examples, the selectively
changing may include selectively increasing the flow rate of the
stimulant fluid stream responsive to determining that the
temperature difference is greater than the threshold temperature
difference and/or selectively decreasing the flow rate of the
stimulant fluid stream responsive to determining that the fluid
temperature difference is less than the threshold fluid temperature
difference.
[0060] Decreasing the pressure within the stimulation well at 230
may include decreasing the pressure within the stimulation well to
decrease the reservoir pressure. This may include decreasing the
reservoir pressure to a pressure that is below a lower pressure
threshold that is less than the bubble point pressure of the
viscous hydrocarbons and may include increasing any suitable
pressure within the stimulation well, such as the bottom hole
pressure, in any suitable manner.
[0061] Illustrative, non-exclusive examples of lower pressure
thresholds according to the present disclosure include lower
pressure thresholds that are less than the bubble point pressure of
the viscous hydrocarbons and/or less than the pressure that existed
in the subterranean formation prior to performing methods 200 by at
least 10 kilopascals (kPa), at least 25 kPa, at least 50 kPa, at
least 75 kPa, at least 100 kPa, at least 200 kPa, at least 300 kPa,
at least 400 kPa, at least 500 kPa, at least 600 kPa, at least 700
kPa, at least 800 kPa, at least 900 kPa, or at least 1000 kPa.
Additionally or alternatively, the lower pressure threshold also
may be less than the bubble point pressure of the viscous
hydrocarbons and/or less than the pressure that existed in the
subterranean formation prior to performing methods 200 by less than
1500 kPa, less than 1400 kPa, less than 1300 kPa, less than 1200
kPa, less than 1100 kPa, less than 1000 kPa, less than 900 kPa,
less than 800 kPa, less than 700 kPa, less than 600 kPa, less than
500 kPa, less than 400 kPa, less than 300 kPa, less than 200 kPa,
or less than 100 kPa.
[0062] As an illustrative, non-exclusive example, the decreasing at
230 may include decreasing the flow rate of the stimulant fluid
that is supplied to the stimulation well, as indicated in FIG. 3 at
235. The decreasing at 235 may include ceasing the supplying at 220
and/or decreasing a magnitude of the flow rate of the stimulant
fluid stream.
[0063] As discussed in more detail herein, the viscous hydrocarbons
that are present within the subterranean formation may evolve, or
liberate, a solution gas when the pressure within the subterranean
formation is decreased below the bubble point pressure of the
viscous hydrocarbons. As also discussed in more detail herein, the
liberated solution gas may generate gas bubbles within the viscous
hydrocarbons, thereby increasing a volume of the viscous
hydrocarbons. This may provide a motive force for flow of the
viscous hydrocarbons within the subterranean formation and/or may
convey at least a portion of the viscous hydrocarbons into the
stimulation chamber that is associated with the stimulation
well.
[0064] Maintaining the reservoir pressure below the lower pressure
threshold at 240 may include maintaining the reservoir pressure
below the lower pressure threshold for at least a threshold
depressurized time using any suitable system and/or method.
Illustrative, non-exclusive examples of threshold depressurized
times according to the present disclosure include threshold
depressurized times of at least 1, at least 2, at least 3, at least
4, at least 5, at least 10, at least 15, at least 20, at least 25,
at least 30, at least 40, at least 50, at least 75, at least 100,
at least 150, or at least 200 days. Additionally or alternatively,
the threshold depressurized time may be less than 300, less than
250, less than 200, less than 190, less than 180, less than 170,
less than 160, less than 150, less than 140, less than 130, less
than 120, less than 110, or less than 100 days.
[0065] It is within the scope of the present disclosure that the
threshold depressurized time may be constant, or at least
substantially constant, for each stimulation cycle. Alternatively,
it is also within the scope of the present disclosure that the
threshold depressurized time may be different for at least one
stimulation cycle relative to at least one other stimulation cycle.
As an illustrative, non-exclusive example, the threshold
depressurized time may increase with each stimulation cycle
relative to a previous stimulation cycle.
[0066] The repeating at 245 may include repeating the increasing at
215 and the decreasing at 230 for the plurality of stimulation
cycles. The repeating may include performing the increasing at 215
and subsequently performing the decreasing at 230 in each
stimulation cycle of the plurality of stimulation cycles and may
include repeating any suitable number of times and/or based on any
suitable criteria. In addition, the repeating at 245 also may
include performing any suitable traditional gravity drainage
process, illustrative, non-exclusive examples of which are
discussed in more detail herein, prior to the plurality of
stimulation cycles, between at least a portion of the plurality of
stimulation cycles, and/or between each of the plurality of
stimulation cycles.
[0067] As an illustrative, non-exclusive example, the repeating may
include repeating at least 2, at least 3, at least 4, at least 6,
at least 8, at least 10, at least 15, at least 20, at least 25, or
at least 30 times during a corresponding number of stimulation
cycles. As another illustrative, non-exclusive example, the
repeating may include repeating at least once every 25 days, every
30 days, every 40 days, every 50 days, every 60 days, every 70
days, every 80 days, every 90 days, every 100 days, every 110 days,
every 120 days, every 130 days, every 140 days, every 150 days,
every 200 days, every 250 days, every 300 days, or every 350
days.
[0068] It is within the scope of the present disclosure that the
repeating at 245 may be based, at least in part, on any suitable
criteria. As illustrative, non-exclusive examples, the repeating
may include repeating the decreasing at 230 based, at least in
part, on determining that the reservoir pressure is greater than
the upper pressure threshold and/or has been greater than the upper
pressure threshold for at least the threshold pressurized time. As
another illustrative, non-exclusive example, the repeating at 245
also may include repeating the increasing at 215 based, at least in
part, on determining that the reservoir pressure is less than the
lower pressure threshold and/or that the reservoir pressure has
been less than the lower pressure threshold for at least the
threshold depressurized time.
[0069] Decreasing the viscosity of the viscous hydrocarbons at 250
may include decreasing the viscosity of at least a portion of the
viscous hydrocarbons in any suitable manner, with the portion of
the viscous hydrocarbons forming and/or contributing to the reduced
viscosity hydrocarbon stream. It is within the scope of the present
disclosure that the decreasing at 250 may be performed concurrently
with and/or be a result of any suitable portion of methods 200.
[0070] As an illustrative, non-exclusive example, and when the
stimulant fluid stream has a temperature that is greater than a
temperature within the subterranean formation, the decreasing at
250 may include heating the viscous hydrocarbons to decrease the
viscosity of the viscous hydrocarbons. As another illustrative,
non-exclusive example, and when the stimulant fluid stream is a
diluent and/or solvent for the viscous hydrocarbons, the decreasing
at 250 may include diluting the viscous hydrocarbons with the
stimulant fluid stream to decrease the viscosity of the viscous
hydrocarbons.
[0071] Producing the viscous hydrocarbons from the subterranean
formation at 255 may include producing the viscous hydrocarbons as
a reduced viscosity hydrocarbon stream, from a production well that
extends within the subterranean formation and is spaced apart from
the stimulation well. It is within the scope of the present
disclosure that the producing at 255 may include producing during,
in parallel with, and/or concurrently with a remainder of methods
200, including at least the increasing at 215, the decreasing at
230, and the repeating at 245. This may include continuously
producing the viscous hydrocarbons and/or producing the viscous
hydrocarbons during at least 75%, at least 80%, at least 85%, at
least 90%, at least 95%, at least 97.5%, at least 99%, or all of a
time period during which the increasing at 215, the decreasing at
230, and/or the repeating at 245 are performed.
[0072] It is within the scope of the present disclosure that the
producing at 255 may include maintaining a constant, or an at least
substantially constant, rate of production of the reduced viscosity
hydrocarbon stream during each stimulation cycle of methods 200
and/or during a majority, a substantial majority, or all of a time
period during which methods 200 are performed.
[0073] However, it is also within the scope of the present
disclosure that the producing at 255 may include varying the rate
of production of the reduced viscosity hydrocarbon stream within a
given stimulation cycle and/or from stimulation cycle to
stimulation cycle. In addition, it is also within the scope of the
present disclosure that the producing at 255 may include
maintaining at least a threshold production rate of the reduced
viscosity hydrocarbon stream during an entirety of the time period
during which methods 200 are performed.
[0074] In the present disclosure, several of the illustrative,
non-exclusive examples have been discussed and/or presented in the
context of flow diagrams, or flow charts, in which the methods are
shown and described as a series of blocks, or steps. Unless
specifically set forth in the accompanying description, it is
within the scope of the present disclosure that the order of the
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. It is also within the scope of
the present disclosure that the blocks, or steps, may be
implemented as logic, which also may be described as implementing
the blocks, or steps, as logics. In some applications, the blocks,
or steps, may represent expressions and/or actions to be performed
by functionally equivalent circuits or other logic devices. The
illustrated blocks may, but are not required to, represent
executable instructions that cause a computer, processor, and/or
other logic device to respond, to perform an action, to change
states, to generate an output or display, and/or to make
decisions.
[0075] As used herein, the term "and/or" placed between a first
entity and a second entity means one of (1) the first entity, (2)
the second entity, and (3) the first entity and the second entity.
Multiple entities listed with "and/or" should be construed in the
same manner, i.e., "one or more" of the entities so conjoined.
Other entities may optionally be present other than the entities
specifically identified by the "and/or" clause, whether related or
unrelated to those entities specifically identified. Thus, as a
non-limiting example, a reference to "A and/or B," when used in
conjunction with open-ended language such as "comprising" may
refer, in one embodiment, to A only (optionally including entities
other than B); in another embodiment, to B only (optionally
including entities other than A); in yet another embodiment, to
both A and B (optionally including other entities). These entities
may refer to elements, actions, structures, steps, operations,
values, and the like.
[0076] As used herein, the phrase "at least one," in reference to a
list of one or more entities should be understood to mean at least
one entity selected from any one or more of the entity in the list
of entities, but not necessarily including at least one of each and
every entity specifically listed within the list of entities and
not excluding any combinations of entities in the list of entities.
This definition also allows that entities may optionally be present
other than the entities specifically identified within the list of
entities to which the phrase "at least one" refers, whether related
or unrelated to those entities specifically identified. Thus, as a
non-limiting example, "at least one of A and B" (or, equivalently,
"at least one of A or B," or, equivalently "at least one of A
and/or B") may refer, in one embodiment, to at least one,
optionally including more than one, A, with no B present (and
optionally including entities other than B); in another embodiment,
to at least one, optionally including more than one, B, with no A
present (and optionally including entities other than A); in yet
another embodiment, to at least one, optionally including more than
one, A, and at least one, optionally including more than one, B
(and optionally including other entities). In other words, the
phrases "at least one," "one or more," and "and/or" are open-ended
expressions that are both conjunctive and disjunctive in operation.
For example, each of the expressions "at least one of A, B and C,"
"at least one of A, B, or C," "one or more of A, B, and C," "one or
more of A, B, or C" and "A, B, and/or C" may mean A alone, B alone,
C alone, A and B together, A and C together, B and C together, A, B
and C together, and optionally any of the above in combination with
at least one other entity.
[0077] In the event that any patents, patent applications, or other
references are incorporated by reference herein and define a term
in a manner or are otherwise inconsistent with either the
non-incorporated portion of the present disclosure or with 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
originally present.
[0078] 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.
[0079] Illustrative, non-exclusive examples of systems and methods
according to the present disclosure are presented in the following
enumerated paragraphs. It is within the scope of the present
disclosure that an individual step of a method recited herein,
including in the following enumerated paragraphs, may additionally
or alternatively be referred to as a "step for" performing the
recited action.
[0080] A1. A method of stimulating and producing viscous
hydrocarbons from a subterranean formation that includes the
viscous hydrocarbons, the method comprising:
[0081] increasing a pressure within a stimulation well that extends
within the subterranean formation to increase a reservoir pressure
to a pressure that is above an upper pressure threshold that is
greater than a bubble point pressure of the viscous
hydrocarbons;
[0082] decreasing the pressure within the stimulation well to
decrease the reservoir pressure to a pressure that is below a lower
pressure threshold that is less than the bubble point pressure of
the viscous hydrocarbons;
[0083] repeating the increasing the pressure and the decreasing the
pressure for a plurality of stimulation cycles; and
[0084] producing, as a reduced viscosity hydrocarbon stream, the
viscous hydrocarbons from a production well that extends within the
subterranean formation and is spaced apart from the stimulation
well, wherein the producing includes producing during the
increasing the pressure, the decreasing the pressure, and the
repeating.
[0085] A2. The method of paragraph A1, wherein the increasing the
pressure includes providing a stimulant fluid stream to the
stimulation well, and optionally wherein the stimulant fluid stream
includes at least one, optionally at least two, optionally at least
three, or optionally at least four of water, steam, a solvent for
the viscous hydrocarbon, and a diluent for the viscous
hydrocarbon.
[0086] A3. The method of paragraph A2, wherein the providing a
stimulant fluid stream includes providing the stimulant fluid
stream to a stimulation chamber that is associated with the
stimulation well, optionally wherein the stimulation chamber
includes at least one of a steam chamber and a vapor chamber,
optionally wherein the stimulation chamber is at least partially
coextensive with at least a portion of a wellbore that defines the
stimulation well, optionally wherein the stimulation chamber
surrounds at least a portion of the wellbore, and further
optionally wherein the stimulation chamber is at least partially
concentric with at least a portion of the wellbore.
[0087] A4. The method of any of paragraphs A2-A3, wherein the
providing a stimulant fluid stream includes providing a total
volume of the stimulant fluid stream for each stimulation cycle of
the plurality of stimulation cycles, wherein a total volume of the
stimulant fluid stream for a given stimulation cycle of the
plurality of stimulation cycles is less than a total volume of the
stimulant fluid stream for a subsequent stimulation cycle of the
plurality of stimulation cycles, and optionally wherein the total
volume of the stimulant fluid stream increases monotonically with
each stimulation cycle of the plurality of stimulation cycles.
[0088] A5. The method of any of paragraphs A2-A4, wherein the
providing a stimulant fluid stream includes controlling a flow rate
of the stimulant fluid stream to control a rate of the increasing,
and optionally wherein the controlling a flow rate of the stimulant
fluid stream to control a rate of the increasing includes at least
one of: [0089] (i) increasing the flow rate of the stimulant fluid
stream responsive to the rate of the increasing being less than a
threshold lower increasing rate; and [0090] (ii) decreasing the
flow rate of the stimulant fluid stream responsive to the rate of
the increasing being greater than a threshold upper increasing
rate.
[0091] A6. The method of any of paragraphs A1-A5, wherein,
subsequent to the increasing the pressure and prior to the
decreasing the pressure, the method further includes maintaining
the reservoir pressure above the upper pressure threshold for at
least a threshold pressurized time.
[0092] A7. The method of paragraph A6, wherein the increasing
includes providing a/the stimulant fluid stream to the stimulation
well at a first flow rate, and further wherein the maintaining the
reservoir pressure above the upper pressure threshold includes
providing the stimulant fluid stream to the stimulation well at a
second flow rate that optionally is less than the first flow
rate.
[0093] A8. The method of any of paragraphs A6-A7, wherein the
maintaining includes controlling a/the flow rate of the stimulant
fluid stream to maintain the reservoir pressure above the upper
pressure threshold, and optionally wherein the controlling the flow
rate of the stimulant fluid stream to maintain the reservoir
pressure above the upper pressure threshold includes at least one
of: [0094] (i) increasing the flow rate of the stimulant fluid
stream responsive to the reservoir pressure being less than a lower
maintaining pressure; and [0095] (ii) decreasing the flow rate of
the stimulant fluid stream responsive to the reservoir pressure
being greater than an upper maintaining pressure.
[0096] A9. The method of any of paragraphs A6-A8, wherein the
threshold pressurized time is at least one of: [0097] (i) at least
1, at least 2, at least 3, at least 4, at least 5, at least 10, at
least 15, at least 20, at least 25, at least 30, at least 40, at
least 50, at least 75, at least 100, at least 150, at least 200, at
least 300, at least 400, at least 500, at least 600, at least 700,
or at least 800 days; and [0098] (ii) less than 1500 days, less
than 1250 days, less than 1000 days, less than 900 days, less than
800 days, less than 700 days, less than 600 days, less than 500
days, less than 400 days, less than 300, less than 250, less than
200, less than 190, less than 180, less than 170, less than 160,
less than 150, less than 140, less than 130, less than 120, less
than 110, or less than 100 days.
[0099] A10. The method of any of paragraphs A6-A9, wherein the
method further includes preserving a fluid temperature difference
between a/the stimulant fluid stream and the reduced viscosity
hydrocarbon stream below a threshold fluid temperature difference
during the maintaining.
[0100] A11. The method of paragraph A10, wherein the threshold
fluid temperature difference is less than 200.degree. C., less than
190.degree. C., less than 180.degree. C., less than 170.degree. C.,
less than 160.degree. C., less than 150.degree. C., less than
140.degree. C., less than 130.degree. C., less than 120.degree. C.,
less than 110.degree. C., less than 100.degree. C., less than
90.degree. C., less than 80.degree. C., less than 70.degree. C.,
less than 60.degree. C., less than 50.degree. C., less than
40.degree. C., less than 30.degree. C., less than 20.degree. C., or
less than 10.degree. C.
[0101] A12. The method of any of paragraphs A10-A11, wherein the
preserving the fluid temperature difference includes at least one
of: [0102] (i) selectively changing a flow rate of the reduced
viscosity hydrocarbon stream responsive to the fluid temperature
difference; [0103] (ii) selectively increasing the flow rate of the
reduced viscosity hydrocarbon stream responsive to determining that
the fluid temperature difference is greater than the threshold
fluid temperature difference; and [0104] (iii) selectively
decreasing the flow rate of the reduced viscosity hydrocarbon
stream responsive to determining that the fluid temperature
difference is less than the threshold fluid temperature difference.
[0105] (iv) selectively changing a flow rate of the stimulant fluid
stream responsive to the fluid temperature difference; [0106] (v)
selectively increasing the flow rate of the stimulant fluid stream
responsive to determining that the fluid temperature difference is
greater than the threshold fluid temperature difference; [0107]
(vi) selectively decreasing the flow rate of the stimulant fluid
stream responsive to determining that the fluid temperature
difference is less than the threshold fluid temperature
difference;
[0108] A13. The method of any of paragraphs A1-A12, wherein the
decreasing the pressure includes at least one of ceasing providing
a/the stimulant fluid stream to the stimulation well and decreasing
a flow rate of the stimulant fluid stream to the stimulation
well.
[0109] A14. The method of any of paragraphs A1-A13, wherein the
decreasing the pressure includes liberating a solution gas from the
viscous hydrocarbon while the viscous hydrocarbon is present within
the subterranean formation.
[0110] A15. The method of any of paragraphs A13-A14, wherein the
liberating includes generating a motive force for the
producing.
[0111] A16. The method of any of paragraphs A14-A15, wherein the
liberating includes increasing a volume of the viscous
hydrocarbons.
[0112] A17. The method of any of paragraphs A14-A16, wherein the
liberating includes conveying a portion of the viscous hydrocarbons
into a/the stimulation chamber that is associated with the
stimulation well.
[0113] A18. The method of any of paragraphs A1-A17, wherein the
decreasing the pressure further includes producing a
non-condensable gas from the subterranean formation.
[0114] A19. The method of any of paragraphs A1-A18, wherein,
subsequent to the decreasing the pressure, the method further
includes maintaining the reservoir pressure below the lower
pressure threshold for at least a threshold depressurized time.
[0115] A20. The method of paragraph A19, wherein the threshold
depressurized time is at least one of: [0116] (i) at least 1, at
least 2, at least 3, at least 4, at least 5, at least 10, at least
15, at least 20, at least 25, at least 30, at least 40, at least
50, at least 75, at least 100, at least 150, or at least 200 days;
and [0117] (ii) less than 300, less than 250, less than 200, less
than 190, less than 180, less than 170, less than 160, less than
150, less than 140, less than 130, less than 120, less than 110, or
less than 100 days.
[0118] A21. The method of any of paragraphs A19-A20, wherein the
threshold depressurized time at least one of: [0119] (i) is
constant for each stimulation cycle of the plurality of stimulation
cycles; [0120] (ii) increases with each stimulation cycle of the
plurality of stimulation cycles; and [0121] (iii) is different for
at least one stimulation cycle of the plurality of stimulation
cycles relative to at least one other stimulation cycle of the
plurality of stimulation cycles.
[0122] A22. The method of any of paragraphs A1-A21, wherein the
repeating includes repeating the increasing and the decreasing for
at least 2, at least 3, at least 4, at least 6, at least 8, at
least 10, at least 15, at least 20, at least 25, or at least 30
stimulation cycles.
[0123] A23. The method of any of paragraphs A1-A22, wherein the
repeating includes repeating at least once every 25 days, every 30
days, every 40 days, every 50 days, every 60 days, every 70 days,
every 80 days, every 90 days, every 100 days, every 110 days, every
120 days, every 130 days, every 140 days, every 150 days, every 200
days, every 250 days, every 300 days, or every 350 days.
[0124] A24. The method of any of paragraphs A1-A23, wherein the
repeating includes performing the increasing the pressure and
subsequently performing the decreasing the pressure in each
stimulation cycle of the plurality of stimulation cycles.
[0125] A25. The method of any of paragraphs A1-A24, wherein the
increasing the pressure includes providing a motive force for the
producing.
[0126] A26. The method of any of paragraphs A1-A25, wherein the
method further includes decreasing a viscosity of the viscous
hydrocarbons prior to the producing.
[0127] A27. The method of any of paragraphs A1-A26, wherein the
producing includes continuously producing the viscous hydrocarbons
during at least 75%, at least 80%, at least 85%, at least 90%, at
least 95%, at least 97.5%, at least 99%, or all of a time period
during which the increasing the pressure, the decreasing the
pressure, and the repeating occurs.
[0128] A28. The method of any of paragraphs A1-A27, wherein the
producing further includes maintaining an at least substantially
constant production rate during the producing.
[0129] A29. The method of any of paragraphs A1-A28, wherein the
method further includes monitoring the reservoir pressure.
[0130] A30. The method of paragraph A29, wherein the decreasing the
pressure includes decreasing the pressure based, at least in part,
on determining that the reservoir pressure is greater than the
upper pressure threshold.
[0131] A31. The method of paragraph A30, wherein the decreasing the
pressure further includes decreasing the pressure based, at least
in part, on determining that the reservoir pressure has been
greater than the upper pressure threshold for at least a/the
threshold pressurized time.
[0132] A32. The method of any of paragraphs A29-A31, wherein the
increasing the pressure includes increasing the pressure based, at
least in part, on determining that the reservoir pressure is less
than the lower pressure threshold.
[0133] A33. The method of paragraph A32, wherein the increasing the
pressure further includes increasing the pressure based, at least
in part, on determining that the reservoir pressure has been less
than the lower pressure threshold for at least a/the threshold
depressurized time.
[0134] A34. The method of any of paragraphs A29-A33, wherein the
monitoring the reservoir pressure includes monitoring a reservoir
property, and optionally wherein the reservoir property includes at
least one of the stimulation well bottom hole pressure, the
production well bottom hole pressure, the production wellhead
pressure, the production well bottom hole temperature, and the
production wellhead temperature.
[0135] A35. The method of any of paragraphs A29-A34, wherein the
monitoring the reservoir pressure includes calculating the
reservoir pressure.
[0136] A36. The method of paragraph A35 when dependent from A34,
wherein the calculating is based, at least in part, on the
reservoir property.
[0137] A37. The method of any of paragraphs A1-A36, wherein the
method further includes heating the viscous hydrocarbons to
decrease a/the viscosity of a portion of the viscous hydrocarbons
that forms the reduced viscosity hydrocarbon stream, optionally
wherein the heating includes heating the viscous hydrocarbons with
a/the stimulant fluid stream.
[0138] A38. The method of any of paragraphs A1-A37, wherein the
method further includes diluting the viscous hydrocarbons to
decrease a/the viscosity of a portion of the viscous hydrocarbons
that forms the reduced viscosity hydrocarbon stream, optionally
wherein the diluting includes diluting the viscous hydrocarbons
with a/the stimulant fluid stream.
[0139] A39. The method of any of paragraphs A1-A38, wherein the
producing further includes producing the viscous hydrocarbons from
the production well for a pre-production time prior to at least the
decreasing the pressure and the repeating, optionally using at
least one of a steam-assisted gravity drainage process, a
solvent-assisted steam-assisted gravity drainage process, and a
vapor extraction process.
[0140] A40. The method of paragraph A39, wherein the pre-production
time is at least 50, at least 100, at least 150, at least 200, at
least 250, at least 300, at least 350, at least 400, at least 500,
at least 600, at least 700, at least 800, at least 900, or at least
1000 days.
[0141] A41. The method of any of paragraphs A1-A40, wherein the
method includes performing the method as part of at least one of a
steam-assisted gravity drainage process, a solvent-assisted
steam-assisted gravity drainage process, and a vapor extraction
process.
[0142] A42. The method of any of paragraphs A1-A41, wherein the
pressure within the stimulation well is a bottom hole pressure
within the stimulation well.
[0143] A43. The method of any of paragraphs A1-A42, wherein the
upper pressure threshold is at least one of: [0144] (i) greater
than the bubble point pressure of the viscous hydrocarbons by at
least 10 kilopascals (kPa), at least 25 kPa, at least 50 kPa, at
least 75 kPa, at least 100 kPa, at least 200 kPa, at least 300 kPa,
at least 400 kPa, at least 500 kPa, at least 600 kPa, at least 700
kPa, at least 800 kPa, at least 900 kPa, or at least 1000 kPa; and
[0145] (ii) greater than the bubble point pressure of the viscous
hydrocarbons by less than 1500 kPa, less than 1400 kPa, less than
1300 kPa, less than 1200 kPa, less than 1100 kPa, less than 1000
kPa, less than 900 kPa, less than 800 kPa, less than 700 kPa, less
than 600 kPa, less than 500 kPa, less than 400 kPa, less than 300
kPa, less than 200 kPa, or less than 100 kPa.
[0146] A44. The method of any of paragraphs A1-A43, wherein the
upper pressure threshold is at least one of: [0147] (i) greater
than a reservoir pressure prior to performing the method by at
least 10 kilopascals (kPa), at least 25 kPa, at least 50 kPa, at
least 75 kPa, at least 100 kPa, at least 200 kPa, at least 300 kPa,
at least 400 kPa, at least 500 kPa, at least 600 kPa, at least 700
kPa, at least 800 kPa, at least 900 kPa, or at least 1000 kPa; and
[0148] (ii) greater than the reservoir pressure prior to performing
the method by less than 1500 kPa, less than 1400 kPa, less than
1300 kPa, less than 1200 kPa, less than 1100 kPa, less than 1000
kPa, less than 900 kPa, less than 800 kPa, less than 700 kPa, less
than 600 kPa, less than 500 kPa, less than 400 kPa, less than 300
kPa, less than 200 kPa, or less than 100 kPa.
[0149] A45. The method of any of paragraphs A1-A44, wherein the
lower pressure threshold is at least one of: [0150] (i) lower than
the bubble point pressure of the viscous hydrocarbons by at least
10 kilopascals (kPa), at least 25 kPa, at least 50 kPa, at least 75
kPa, at least 100 kPa, at least 200 kPa, at least 300 kPa, at least
400 kPa, at least 500 kPa, at least 600 kPa, at least 700 kPa, at
least 800 kPa, at least 900 kPa, or at least 1000 kPa; and [0151]
(ii) lower than the bubble point pressure of the viscous
hydrocarbons by less than 1500 kPa, less than 1400 kPa, less than
1300 kPa, less than 1200 kPa, less than 1100 kPa, less than 1000
kPa, less than 900 kPa, less than 800 kPa, less than 700 kPa, less
than 600 kPa, less than 500 kPa, less than 400 kPa, less than 300
kPa, less than 200 kPa, or less than 100 kPa.
[0152] A46. The method of any of paragraphs A1-A45, wherein the
lower pressure threshold is at least one of: [0153] (i) lower than
a/the reservoir pressure prior to performing the method by at least
10 kilopascals (kPa), at least 25 kPa, at least 50 kPa, at least 75
kPa, at least 100 kPa, at least 200 kPa, at least 300 kPa, at least
400 kPa, at least 500 kPa, at least 600 kPa, at least 700 kPa, at
least 800 kPa, at least 900 kPa, or at least 1000 kPa; and [0154]
(ii) lower than the reservoir pressure prior to performing the
method by less than 1500 kPa, less than 1400 kPa, less than 1300
kPa, less than 1200 kPa, less than 1100 kPa, less than 1000 kPa,
less than 900 kPa, less than 800 kPa, less than 700 kPa, less than
600 kPa, less than 500 kPa, less than 400 kPa, less than 300 kPa,
less than 200 kPa, or less than 100 kPa.
[0155] A47. The method of any of paragraphs A1-A46, wherein the
bubble point pressure of the viscous hydrocarbons is a pressure at
which a/the solution gas begins to evolve from the viscous
hydrocarbons that are present within the subterranean
formation.
[0156] A48. The method of any of paragraphs A1-A47, wherein the
bubble point pressure of the viscous hydrocarbons is at least one
of: [0157] (i) greater than 100 kilopascals (kPa), greater than 200
kPa, greater than 300 kPa, greater than 400 kPa, greater than 500
kPa, greater than 750 kPa, greater than 1000 kPa, greater than 1250
kPa, greater than 1500 kPa, greater than 2000 kPa, greater than
2500 kPa, or greater than 3000 kPa; and [0158] (ii) less than 5000
kPa, less than 4500 kPa, less than 4000 kPa, less than 3500 kPa,
less than 3000 kPa, less than 2500 kPa, less than 2000 kPa, less
than 1500 kPa, or less than 1000 kPa.
[0159] A49. The method of any of paragraphs A1-A48, wherein at
least a parallel portion of the stimulation well is at least
substantially parallel to at least a parallel portion of the
production well.
[0160] A50. The method of paragraph A49, wherein the parallel
portion of the stimulation well includes at least 25%, at least
30%, at least 40%, at least 50%, at least 60%, at least 70%, at
least 80%, or at least 90% of a length of the stimulation well.
[0161] A51. The method of any of paragraphs A1-A50, wherein at
least a horizontal portion of the stimulation well is at least
substantially horizontal.
[0162] A52. The method of any of paragraphs A1-A51, wherein at
least a horizontal portion of the production well is at least
substantially horizontal.
[0163] A53. The method of any of paragraphs A1-A52, wherein the
viscous hydrocarbons include at least one of bitumen, tar, an
unconventional hydrocarbon reserve, and a hydrocarbon reserve with
a viscosity that is too high to be produced from the subterranean
formation using primary hydrocarbon recovery operations or
secondary hydrocarbon recovery operations.
[0164] A54. The method of any of paragraphs A1-A53, wherein the
subterranean formation includes at least one of an oil sands
formation, a tar sands formation, and a bituminous sands
formation.
[0165] B1. A system configured to produce viscous hydrocarbons from
a subterranean formation, the system comprising:
[0166] a stimulation well that extends within the subterranean
formation;
[0167] a stimulant fluid supply system that is configured to
provide a stimulant fluid stream to the subterranean formation via
the stimulation well;
[0168] a production well that is spaced-apart from the stimulation
well, extends within the subterranean formation and is configured
to produce a reduced viscosity hydrocarbon stream from the
subterranean formation; and
[0169] a controller that is programmed to control the operation of
the system using the method of any of paragraphs A1-A54.
[0170] B2. The system of paragraph B1, wherein the system includes
the subterranean formation.
[0171] B3. The system of any of paragraphs B1-B2, wherein the
system further includes a detector configured to detect a property
of at least one of the subterranean formation, the stimulation
well, and the production well.
[0172] B4. The system of paragraph B3, wherein the property
includes at least one of a pressure, a temperature, and a flow
rate.
[0173] B5. The system of paragraph B3, wherein the property
includes at least one of a reservoir pressure within the
subterranean formation, a bottom hole pressure within the
stimulation well, a wellhead pressure of the production well, and a
wellhead temperature of the production well.
[0174] C1. The use of any of the methods of any of paragraphs
A1-A54 with any of the systems of any of paragraphs B1-B5.
[0175] C2. The use of any of the systems of any of paragraphs B1-B5
with any of the methods of any of paragraphs A1-A54.
[0176] C3. The use of any of the methods of any of paragraphs
A1-A54 or any of the systems of any of paragraphs B1-B5 to produce
a viscous hydrocarbon from a subterranean formation.
[0177] C4. The use of any of the methods of any of paragraphs
A1-A54 or any of the systems of any of paragraphs B1-B5 to
stimulate production of a viscous hydrocarbon from a subterranean
formation.
[0178] C5. Viscous hydrocarbons produced using the method of any of
paragraphs A1-A54 or the system of any of paragraphs B1-B5.
[0179] C6. The use of a pressure-cycling stimulation process in a
stimulation well to increase production of a viscous hydrocarbon
from a production well.
[0180] PCT1. A method of stimulating and producing viscous
hydrocarbons from a subterranean formation that includes the
viscous hydrocarbons, the method comprising:
[0181] increasing a pressure within a stimulation well that extends
within the subterranean formation to increase a reservoir pressure
to a pressure that is above an upper pressure threshold that is
greater than a bubble point pressure of the viscous
hydrocarbons;
[0182] decreasing the pressure within the stimulation well to
decrease the reservoir pressure to a pressure that is below a lower
pressure threshold that is less than the bubble point pressure of
the viscous hydrocarbons;
[0183] repeating the increasing the pressure and the decreasing the
pressure for a plurality of stimulation cycles; and
[0184] producing, as a reduced viscosity hydrocarbon stream, the
viscous hydrocarbons from a production well that extends within the
subterranean formation and is spaced apart from the stimulation
well, wherein the producing includes producing during the
increasing the pressure, the decreasing the pressure, and the
repeating.
[0185] PCT2. The method of paragraph PCT1, wherein the increasing
the pressure includes providing a stimulant fluid stream to the
stimulation well.
[0186] PCT3. The method of paragraph PCT2, wherein the providing a
stimulant fluid stream includes controlling a flow rate of the
stimulant fluid stream to control a rate of the increasing by at
least one of: [0187] (i) increasing the flow rate of the stimulant
fluid stream responsive to the rate of the increasing being less
than a threshold lower increasing rate; and [0188] (ii) decreasing
the flow rate of the stimulant fluid stream responsive to the rate
of the increasing being greater than a threshold upper increasing
rate.
[0189] PCT4. The method of any of paragraphs PCT1-PCT3, wherein,
subsequent to the increasing the pressure and prior to the
decreasing the pressure, the method further includes maintaining
the reservoir pressure above the upper pressure threshold for at
least a threshold pressurized time.
[0190] PCT5. The method of paragraph PCT4, wherein the increasing
includes providing a stimulant fluid stream to the stimulation well
at a first flow rate, and further wherein the maintaining the
reservoir pressure above the upper pressure threshold includes
providing the stimulant fluid stream to the stimulation well at a
second flow rate.
[0191] PCT6. The method of any of paragraphs PCT4-PCT5, wherein the
threshold pressurized time is at least 1 day and less than 500
days.
[0192] PCT7. The method of any of paragraphs PCT4-PCT6, wherein the
method further includes preserving a fluid temperature difference
between a stimulant fluid stream and the reduced viscosity
hydrocarbon stream below a threshold fluid temperature difference
during the maintaining.
[0193] PCT8. The method of any of paragraphs PCT1-PCT7, wherein the
decreasing the pressure includes at least one of ceasing providing
a stimulant fluid stream to the stimulation well and decreasing a
flow rate of the stimulant fluid stream to the stimulation
well.
[0194] PCT9. The method of any of paragraphs PCT1-PCT8, wherein the
decreasing the pressure includes liberating a solution gas from the
viscous hydrocarbon while the viscous hydrocarbon is present within
the subterranean formation.
[0195] PCT10. The method of any of paragraphs PCT1-PCT9, wherein,
subsequent to the decreasing the pressure, the method further
includes maintaining the reservoir pressure below the lower
pressure threshold for at least a threshold depressurized time,
wherein the threshold depressurized time is at least 1 day and less
than 250 days.
[0196] PCT11. The method of any of paragraphs PCT1-PCT10, wherein
the producing includes continuously producing the viscous
hydrocarbons during at least 90% of a time period during which the
increasing the pressure, the decreasing the pressure, and the
repeating occurs.
[0197] PCT12. The method of any of paragraphs PCT1-PCT11, wherein
the method further includes monitoring the reservoir pressure,
wherein the decreasing the pressure includes decreasing the
pressure based, at least in part, on determining that the reservoir
pressure is greater than the upper pressure threshold, and further
wherein the increasing the pressure includes increasing the
pressure based, at least in part, on determining that the reservoir
pressure is less than the lower pressure threshold.
[0198] PCT13. The method of any of paragraphs PCT1-PCT12, wherein
the producing further includes producing the viscous hydrocarbons
from the production well for a pre-production time prior to at
least the decreasing the pressure and the repeating.
[0199] PCT14. The method of any of paragraphs PCT1-PCT13, wherein
the method includes performing the method as part of at least one
of a steam-assisted gravity drainage process, a solvent-assisted
steam-assisted gravity drainage process, and a vapor extraction
process.
[0200] PCT15. A system configured to produce viscous hydrocarbons
from a subterranean formation, the system comprising:
[0201] a stimulation well that extends within the subterranean
formation;
[0202] a stimulant fluid supply system that is configured to
provide a stimulant fluid stream to the subterranean formation via
the stimulation well;
[0203] a production well that extends within the subterranean
formation and is configured to produce a reduced viscosity
hydrocarbon stream from the subterranean formation; and
[0204] a controller that is programmed to control the operation of
the system using the method of any of paragraphs PCT1-PCT14.
INDUSTRIAL APPLICABILITY
[0205] The systems and methods disclosed herein are applicable to
the oil and gas industry.
[0206] It is believed that the disclosure set forth above
encompasses multiple distinct inventions with independent utility.
While each of these inventions has been disclosed in its preferred
form, the specific embodiments thereof as disclosed and illustrated
herein are not to be considered in a limiting sense as numerous
variations are possible. The subject matter of the inventions
includes all novel and non-obvious combinations and subcombinations
of the various elements, features, functions and/or properties
disclosed herein. Similarly, where the claims recite "a" or "a
first" element or the equivalent thereof, such claims should be
understood to include incorporation of one or more such elements,
neither requiring nor excluding two or more such elements.
[0207] It is believed that the following claims particularly point
out certain combinations and subcombinations that are directed to
one of the disclosed inventions and are novel and non-obvious.
Inventions embodied in other combinations and subcombinations of
features, functions, elements and/or properties may be claimed
through amendment of the present claims or presentation of new
claims in this or a related application. Such amended or new
claims, whether they are directed to a different invention or
directed to the same invention, whether different, broader,
narrower, or equal in scope to the original claims, are also
regarded as included within the subject matter of the inventions of
the present disclosure.
* * * * *