Note: Descriptions are shown in the official language in which they were submitted.
PROCESS FOR DEVELOPING FRACTURE NETWORK AND
HYDROCARBON RECOVERY METHOD
(00011 This is a divisional application of Canadian Patent
Application Serial
No. 3,108,149 filed on March 20, 2019.
[0002] It is to be understood that the expression "the present invention"
or
the like used in this specification encompasses not only the subject matter of
this
divisional application but that of the parent also.
TECHNICAL FIELD
[0003] The present disclosure generally relates to processes for
developing
fracture networks in hydrocarbon-bearing formations and methods for recovering
hydrocarbons therefrom. In particular, the present disclosure relates to
processes
that utilize wells having longitudinal wellbore sections to develop fracture
networks
in subterranean hydrocarbon-bearing formations and methods that utilize such
wells to recover hydrocarbons from subterranean hydrocarbon-bearing formations
in which fracture networks have been induced.
BACKGROUND
[0004] In situ hydrocarbon recovery involves the production of
hydrocarbons from a subterranean hydrocarbon-bearing formation. In some
cases, in situ hydrocarbon recovery is aided by hydraulic fracture stimulation
¨ a
process that results in the formation of fractures within the subterranean
hydrocarbon-bearing formation. Hydraulic fracture stimulation is commonly
referred to as "fracturing" or "fracking", and it involves injecting a
stimulant fluid
into the hydrocarbon-bearing formation at a pressure that is sufficient to
induce
localized breaking events (fractures) within the hydrocarbon-bearing
formation.
The stimulant fluid typically comprises a propping agent. The propping agent
is
intended to remain in the fractures after the fracturing process is finished.
Ideally,
the propping agent maintains the geometry of the fractures such that they
provide
higher-permeability paths through which injected fluids, hydrocarbons, or
combinations thereof can flow through the hydrocarbon-bearing formation. The
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Date Recue/Date Received 2022-08-11
stimulant fluid is typically injected by way of a wellbore that penetrates the
hydrocarbon-bearing formation. Often, fracturing is induced at multiple points
along the wellbore. As such, the fractures typically form a three-dimensional
network (i.e. a fracture network) that is in fluid communication with the
wellbore
through multiple points. The fracture geometry and fracture complexity of a
fracture network can be quantified by a variety of techniques known to those
skilled in the art.
Fractures are generally characterised by their orientations relative to
vertical and
horizontal axes (e.g. vertical fractures and horizontal fractures). Fractures
are also
characterized by their orientation with respect to the wellbore section from
which
they originate. In the case of a longitudinal wellbore section (i.e. a non-
vertical
wellbore section) that is disposed about a longitudinal wellbore axis, a
fracture is
said to be "transverse" if it is substantially orthogonal to the longitudinal
wellbore
axis. Likewise, a fracture is said to be "longitudinal" if it is not
substantially
orthogonal to the longitudinal wellbore axis. Accordingly, a fracture network
originating from a longitudinal wellbore section can be characterized as
comprising substantially-transverse-vertical fractures, substantially-
longitudinal-
vertical fractures, substantially-horizontal fractures, or a combination
thereof.
[0005] Hydraulic fracture stimulation is often used in low-
permeability
hydrocarbon-bearing formations such as those found in North America's shale
gas
and shale oil formations. Examples of such formations include the Montney
shale
formation, the Bakken formation, the Marcellus shale formation, the Barnett
shale
formation, the Haynesville shale formation, and the Horn River shale
formation.
[0006] Known processes for developing subterranean fracture
networks are
limited by a number of inefficiencies, and there exists an unmet need for
improved
processes for developing fracture networks in hydrocarbon-bearing formations.
Likewise improved methods for recovering hydrocarbons from hydrocarbon-
bearing formations and improved processes for enhancing hydrocarbon recovery
from hydrocarbon-bearing formations are needed. In particular, improved
methods
for recovering hydrocarbons and improved processes for enhancing hydrocarbon
recovery are need for low-permeability hydrocarbon-bearing formations and/or
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high-permeability hydrocarbon-bearing formations that are bordered by,
interbedded with, and/or interposed by low-permeability deposits.
SUMMARY
[0007] Developing a fracture network in a hydrocarbon bearing
formation
allows for increased hydrocarbon-bearing-formation permeability. The fracture
network may comprise horizontal fractures, transverse-vertical fractures,
longitudinal-vertical fractures, or a combination thereof. In the context of
the
present disclosure, it was found that processes for developing such fracture
networks in such hydrocarbon-bearing formations benefit from offsetting at
least
one substantially-longitudinal wellbore section of at least one well relative
to: (i) a
substantially-longitudinal wellbore section of a second well; (ii) a plane
defined by
the maximum horizontal stress and the minimum horizontal stress; (iii) a
lithofacies
surface; or (iv) a combination thereof. Offsetting the at least one
substantially-
longitudinal wellbore section in such a way allows for modification of
fracture
geometry, fracture complexity, or a combination thereof within the fracture
network. As it pertains to methods of recovering hydrocarbons and/or processes
for enhancing hydrocarbon recovery, it was found that offsetting the at least
one
substantially-longitudinal wellbore section in such a way allows for
modification of
heat transfer within the formation, hydrocarbon-flow rate within the
formation,
hydrocarbon capture from the formation, or a combination thereof.
[0008] The present disclosure seeks to address one or more of the
un-met
needs set out herein by way of four discrete technical solutions, each of
which
features a different well configuration.
[0009] The first technical solution features a multi-well
configuration in
which the longitudinal wellbore section of a first well is: (a) laterally
displaced from,
and (b) angularly offset from, the longitudinal wellbore section of a second
well
such that the longitudinal wellbore section of the first well and the
longitudinal
wellbore of the second well form a crossing pattern as viewed from a
longitudinal
elevation view.
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Date Regue/Date Received 2022-08-11
[0010] The second technical solution features a multi-well
configuration in
which the longitudinal wellbore section of at least one of a first well and a
second
well is angularly offset from: (a) a lithofacies surface, 01(b) a plane
defined by the
maximum-horizontal stress and the minimum-horizontal stress.
[0011] The third technical solution features a single-well configuration,
and
the fourth technical solution features an alternate multi-well configuration.
[0012] With respect to the first technical solution, select
embodiments of the
present disclosure relate to a process for developing a fracture network in a
hydrocarbon-bearing formation: (a) that has a stress field defined by a
vertical
stress, a maximum-horizontal stress, and a minimum-horizontal stress, and (b)
that is penetrated by a well pair comprising: (i) a first well having a
substantially-
vertical wellbore section and a substantially-longitudinal wellbore section,
and (ii)
a second well having a substantially-vertical wellbore section and a
substantially-
longitudinal wellbore section, the process comprising: injecting a stimulant
fluid
comprising a propping agent into the hydrocarbon-bearing formation from the
substantially-longitudinal wellbore section of at least one of the first well
and the
second well to form the fracture network, wherein: the vertical stress is less
than
or substantially equal to the maximum-horizontal stress and the fracture
network
comprises substantially-horizontal fractures, substantially-transverse-
vertical
fractures, substantially-longitudinal-vertical fractures, or a combination
thereof,
and the substantially-longitudinal wellbore section of the first well is: (a)
laterally
displaced from, and (b) angularly offset from, the substantially-longitudinal
wellbore section of the second well such that the substantially-longitudinal
wellbore section of the first well and the longitudinal wellbore of the second
well
form a crossing pattern as viewed from a longitudinal elevation view, to
modify
fracture geometry, fracture complexity, or a combination thereof within the
fracture
network.
[0013] Also with respect to the first technical solution, select
embodiments
of the present disclosure relate to a process for developing a fracture
network in
a hydrocarbon-bearing formation: (a) that has a stress field defined by a
vertical
stress, a maximum-horizontal stress, and a minimum-horizontal stress, and (b)
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Date Regue/Date Received 2022-08-11
that is penetrated by a well pair comprising: (i) a first well having a
substantially-
vertical wellbore section and a substantially-longitudinal wellbore section,
and (ii)
a second well having a substantially-vertical wellbore section and a
substantially-
longitudinal wellbore section, the process comprising: injecting a stimulant
fluid
comprising a propping agent into the hydrocarbon-bearing formation from a
substantially-longitudinal wellbore section of at least one of the first well
and the
second well to form the fracture network, wherein: the vertical stress is
significantly
greater than the maximum-horizontal stress and the fracture network comprises
substantially-transverse-vertical fractures, substantially-longitudinal-
vertical
fractures, or a combination thereof, and the substantially-longitudinal
wellbore
section of the first well is: (a) laterally displaced from, and (b) angularly
offset from,
the substantially-longitudinal wellbore section of the second well such that
the
substantially-longitudinal wellbore section of the first well and the
longitudinal
wellbore of the second well form a crossing pattern as viewed from a
longitudinal
elevation view, to modify fracture geometry, fracture complexity, or a
combination
thereof within the fracture network.
[0014] Also with respect to the first technical solution, select
embodiments
of the present disclosure relate to a process for developing a fracture
network in
a hydrocarbon-bearing formation: (a) that comprises a lithofacies surface, (b)
that
has a stress field defined by a vertical stress, a maximum-horizontal stress,
and a
minimum-horizontal stress, and (c) that is penetrated by a well pair
comprising: (i)
a first well having a substantially-vertical wellbore section and a
substantially-
longitudinal wellbore section, and (ii) a second well having a substantially-
vertical
wellbore section and a substantially-longitudinal wellbore section, the
process
comprising: injecting a stimulant fluid comprising a propping agent into the
hydrocarbon-bearing formation from the substantially-longitudinal wellbore
section of at least one of the first well and the second well to form the
fracture
network, wherein: the vertical stress is less than or substantially equal to
the
maximum-horizontal stress and the fracture network comprises substantially-
horizontal fractures, substantially-transverse-vertical fractures,
substantially-
longitudinal-vertical fractures, or a combination thereof, and the
substantially-
longitudinal wellbore section of the first well is: (a) laterally displaced
from the
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Date Regue/Date Received 2022-08-11
substantially-longitudinal wellbore section of the second well, and at least
one of
(b) angularly offset from at least a part of the lithofacies surface, and (c)
angularly
offset from the substantially-longitudinal wellbore section of the second well
such
that the substantially-longitudinal wellbore section of the first well and the
longitudinal wellbore of the second well form a crossing pattern as viewed
from a
longitudinal elevation view, to modify fracture geometry, fracture complexity,
or a
combination thereof within the fracture network.
[0015] Also with respect to the first technical solution, select
embodiments
of the present disclosure relate to a process for developing a fracture
network in
a hydrocarbon-bearing formation: (a) that comprises a lithofacies surface, (b)
that
has a stress field defined by a vertical stress, a maximum-horizontal stress,
and a
minimum-horizontal stress, and (c) that is penetrated by a well pair
comprising: (i)
a first well having a substantially-vertical wellbore section and a
substantially-
longitudinal wellbore section, and (ii) a second well having a substantially-
vertical
wellbore section and a substantially-longitudinal wellbore section, the
process
comprising: injecting a stimulant fluid comprising a propping agent into the
hydrocarbon-bearing formation from the substantially-longitudinal wellbore
section of at least one of the first well and the second well to form the
fracture
network, wherein: the vertical stress is significantly greater than the
maximum-
horizontal stress and the fracture network comprises substantially-transverse-
vertical fractures, substantially-longitudinal-vertical fractures, or a
combination
thereof, and the substantially-longitudinal wellbore section of the first well
is: (a)
laterally displaced from the substantially-longitudinal wellbore section of
the
second well, and at least one of (b) angularly offset from at least a part of
the
lithofacies surface, and (c) angularly offset from the substantially-
longitudinal
wellbore section of the second well such that the substantially-longitudinal
wellbore section of the first well and the longitudinal wellbore of the second
well
form a crossing pattern as viewed from a longitudinal elevation view, to
modify
fracture geometry, fracture complexity, or a combination thereof within the
fracture
network.
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Date Regue/Date Received 2022-08-11
10016] Also with respect to the first technical solution, select
embodiments
of the present disclosure relate to a method for recovering hydrocarbons from
a
hydrocarbon-bearing formation: (a) that has a stress field defined by a
vertical
stress, a maximum-horizontal stress, and a minimum-horizontal stress, and (b)
that is penetrated by a well pair comprising: (i) a first well having a
substantially-
vertical wellbore section and a substantially-longitudinal wellbore section,
and (ii)
a second well having a substantially-vertical wellbore section and a
substantially-
longitudinal wellbore section, the method comprising: injecting a stimulant
fluid
comprising a propping agent into the hydrocarbon-bearing formation via the
substantially-longitudinal wellbore section of at least one of the first well
and the
second well to form a fracture network; modulating the mobility of
hydrocarbons
within the hydrocarbon-bearing formation; and recovering hydrocarbons from the
hydrocarbon-bearing formation, wherein: the vertical stress is less than or
substantially equal to the maximum-horizontal stress and the fracture network
comprises substantially-horizontal fractures, substantially-transverse-
vertical
fractures, substantially-longitudinal-vertical fractures, or a combination
thereof,
and the substantially-longitudinal wellbore section of the first well is: (a)
laterally
displaced from, and (b) angularly offset from, the substantially-longitudinal
wellbore section of the second well such that the substantially-longitudinal
wellbore section of the first well and the longitudinal wellbore of the second
well
form a crossing pattern as viewed from a longitudinal elevation view, to
modify
heat transfer within the formation, hydrocarbon-flow rate within the
formation,
hydrocarbon capture from the formation, or a combination thereof.
10017] Also with respect to the first technical solution, select
embodiments
of the present disclosure relate to a method for recovering hydrocarbons from
a
hydrocarbon-bearing formation: (a) that has a stress field defined by a
vertical
stress, a maximum-horizontal stress, and a minimum-horizontal stress, and (b)
that is penetrated by a well pair comprising: (i) a first well having a
substantially-
vertical wellbore section and a substantially-longitudinal wellbore section,
and (ii)
a second well having a substantially-vertical wellbore section and a
substantially-
longitudinal wellbore section, the method comprising: injecting a stimulant
fluid
comprising a propping agent into the hydrocarbon-bearing formation via the
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Date Recue/Date Received 2022-08-11
substantially-longitudinal wellbore section of at least one of the first well
and the
second well to form a fracture network; modulating the mobility of
hydrocarbons
within the hydrocarbon-bearing formation; and recovering hydrocarbons from the
hydrocarbon-bearing formation, wherein: the vertical stress is significantly
greater
than the maximum-horizontal stress and the fracture network comprises
substantially-transverse-vertical fractures,
substantially-longitudinal-vertical
fractures, or a combination thereof, and the substantially-longitudinal
wellbore
section of the first well is: (a) laterally displaced from, and (b) angularly
offset from,
the substantially-longitudinal wellbore section of the second well such that
the
substantially-longitudinal wellbore section of the first well and the
longitudinal
wellbore of the second well form a crossing pattern as viewed from a
longitudinal
elevation view, to modify heat transfer within the formation, hydrocarbon-flow
rate
within the formation, hydrocarbon capture from the formation, or a combination
thereof.
f0018] Also with
respect to the first technical solution, select embodiments
of the present disclosure relate to a method for recovering hydrocarbons from
a
hydrocarbon-bearing formation: (a) that comprises a lithofacies surface, (b)
that
has a stress field defined by a vertical stress, a maximum-horizontal stress,
and a
minimum-horizontal stress, and (c) that is penetrated by a well pair
comprising: (i)
a first well having a substantially-vertical wellbore section and a
substantially-
longitudinal wellbore section, and (ii) a second well having a substantially-
vertical
wellbore section and a substantially-longitudinal wellbore section, the method
comprising: injecting a stimulant fluid comprising a propping agent into the
hydrocarbon-bearing formation via the substantially-longitudinal wellbore
section
of at least one of the first well and the second well to form a fracture
network;
modulating the mobility of hydrocarbons within the hydrocarbon-bearing
formation; and recovering hydrocarbons from the hydrocarbon-bearing formation,
wherein: the vertical stress is less than or substantially equal to the
maximum-
horizontal stress and the fracture network comprises substantially-horizontal
fractures, substantially-transverse-vertical fractures, substantially-
longitudinal-
vertical fractures, or a combination thereof, and the substantially-
longitudinal
wellbore section of the first well is: (a) laterally displaced from the
substantially-
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Date Regue/Date Received 2022-08-11
longitudinal wellbore section of the second well, and at least one of (b)
angularly
offset from at least a part of the lithofacies surface, and (c) angularly
offset from
the substantially-longitudinal wellbore section of the second well such that
the
substantially-longitudinal wellbore section of the first well and the
longitudinal
wellbore of the second well form a crossing pattern as viewed from a
longitudinal
elevation view, to modify heat transfer within the formation, hydrocarbon-flow
rate
within the formation, hydrocarbon capture from the formation, or a combination
thereof.
[0019] Also with respect to the first technical solution, select
embodiments
of the present disclosure relate to a method for recovering hydrocarbons from
a
hydrocarbon-bearing formation: (a) that comprises a lithofacies surface, (b)
that
has a stress field defined by a vertical stress, a maximum-horizontal stress,
and a
minimum-horizontal stress, and (c) that is penetrated by a well pair
comprising: (i)
a first well having a substantially-vertical wellbore section and a
substantially-
longitudinal wellbore section, and (ii) a second well having a substantially-
vertical
wellbore section and a substantially-longitudinal wellbore section, the method
comprising: injecting a stimulant fluid comprising a propping agent into the
hydrocarbon-bearing formation via the substantially-longitudinal wellbore
section
of at least one of the first well and the second well to form a fracture
network;
modulating the mobility of hydrocarbons within the hydrocarbon-bearing
formation; and recovering hydrocarbons from the hydrocarbon-bearing formation,
wherein: the vertical stress is significantly greater than the maximum-
horizontal
stress and the fracture network comprises substantially-transverse-vertical
fractures, substantially-longitudinal-vertical fractures, or a combination
thereof,
and the substantially-longitudinal wellbore section of the first well is: (a)
laterally
displaced from the substantially-longitudinal wellbore section of the second
well,
and at least one of (b) angularly offset from at least a part of the
lithofacies surface,
and (c) angularly offset from the substantially-longitudinal wellbore section
of the
second well such that the substantially-longitudinal wellbore section of the
first
well and the longitudinal wellbore of the second well form a crossing pattern
as
viewed from a longitudinal elevation view, to modify heat transfer within the
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Date Recue/Date Received 2022-08-11
formation, hydrocarbon-flow rate within the formation, hydrocarbon capture
from
the formation, or a combination thereof.
[0020] Also with respect to the first technical solution, select
embodiments
of the present disclosure relate to a process for enhancing hydrocarbon
recovery
from a hydrocarbon-bearing formation: (a) that has a stress field defined by a
vertical stress, a maximum-horizontal stress, and a minimum-horizontal stress,
and (b) that is penetrated by a well pair comprising: (i) a first well having
a
substantially-vertical wellbore section and a substantially-longitudinal
wellbore
section, and (ii) a second well having a substantially-vertical wellbore
section and
a substantially-longitudinal wellbore section, the method comprising:
injecting a
stimulant fluid comprising a propping agent into the hydrocarbon-bearing
formation via the substantially-longitudinal wellbore section of at least one
of the
first well and the second well to form a fracture network; wherein: the
vertical
stress is less than or substantially equal to the maximum-horizontal stress
and the
fracture network comprises substantially-horizontal fractures, substantially-
transverse-vertical fractures, substantially-longitudinal-vertical fractures,
or a
combination thereof, and the substantially-longitudinal wellbore section of
the first
well is: (a) laterally displaced from, and (b) angularly offset from, the
substantially-
longitudinal wellbore section of the second well such that the substantially-
longitudinal wellbore section of the first well and the longitudinal wellbore
of the
second well form a crossing pattern as viewed from a longitudinal elevation
view,
to modify heat transfer within the formation, hydrocarbon-flow rate within the
formation, hydrocarbon capture from the formation, or a combination thereof.
[0021] Also with respect to the first technical solution, select
embodiments
of the present disclosure relate to a process for enhancing hydrocarbon
recovery
from a hydrocarbon-bearing formation: (a) that has a stress field defined by a
vertical stress, a maximum-horizontal stress, and a minimum-horizontal stress,
and (b) that is penetrated by a well pair comprising: (i) a first well having
a
substantially-vertical wellbore section and a substantially-longitudinal
wellbore
section, and (ii) a second well having a substantially-vertical wellbore
section and
a substantially-longitudinal wellbore section, the process comprising:
injecting a
Date Regue/Date Received 2022-08-11
stimulant fluid comprising a propping agent into the hydrocarbon-bearing
formation via the substantially-longitudinal wellbore section of at least one
of the
first well and the second well to form a fracture network; wherein: the
vertical
stress is significantly greater than the maximum-horizontal stress and the
fracture
network comprises substantially-transverse-vertical fractures, substantially-
longitudinal-vertical fractures, or a combination thereof, and the
substantially-
longitudinal wellbore section of the first well is: (a) laterally displaced
from, and (b)
angularly offset from, the substantially-longitudinal wellbore section of the
second
well such that the substantially-longitudinal wellbore section of the first
well and
the longitudinal wellbore of the second well form a crossing pattern as viewed
from
a longitudinal elevation view, to modify heat transfer within the formation,
hydrocarbon-flow rate within the formation, hydrocarbon capture from the
formation, or a combination thereof.
[0022] Also with respect to the first technical solution, select
embodiments
of the present disclosure relate to a process for enhancing hydrocarbon
recovery
from a hydrocarbon-bearing formation: (a) that comprises a lithofacies
surface, (b)
that has a stress field defined by a vertical stress, a maximum-horizontal
stress,
and a minimum-horizontal stress, and (c) that is penetrated by a well pair
comprising: (i) a first well having a substantially-vertical wellbore section
and a
substantially-longitudinal wellbore section, and (ii) a second well having a
substantially-vertical wellbore section and a substantially-longitudinal
wellbore
section, the process comprising: injecting a stimulant fluid comprising a
propping
agent into the hydrocarbon-bearing formation via the substantially-
longitudinal
wellbore section of at least one of the first well and the second well to form
a
fracture network; wherein: the vertical stress is less than or substantially
equal to
the maximum-horizontal stress and the fracture network comprises substantially-
horizontal fractures, substantially-transverse-vertical fractures,
substantially-
longitudinal-vertical fractures, or a combination thereof, and the
substantially-
longitudinal wellbore section of the first well is: (a) laterally displaced
from the
substantially-longitudinal wellbore section of the second well, and at least
one of
(b) angularly offset from at least a part of the lithofacies surface, and (c)
angularly
offset from the substantially-longitudinal wellbore section of the second well
such
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Date Regue/Date Received 2022-08-11
that the substantially-longitudinal wellbore section of the first well and the
longitudinal wellbore of the second well form a crossing pattern as viewed
from a
longitudinal elevation view, to modify heat transfer within the formation,
hydrocarbon-flow rate within the formation, hydrocarbon capture from the
formation, or a combination thereof.
[0023] Also with respect to the first technical solution, select
embodiments
of the present disclosure relate to a process for enhancing hydrocarbon
recovery
from a hydrocarbon-bearing formation: (a) that comprises a lithofacies
surface, (b)
that has a stress field defined by a vertical stress, a maximum-horizontal
stress,
and a minimum-horizontal stress, and (c) that is penetrated by a well pair
comprising: (i) a first well having a substantially-vertical wellbore section
and a
substantially-longitudinal wellbore section, and (ii) a second well having a
substantially-vertical wellbore section and a substantially-longitudinal
wellbore
section, the process comprising: injecting a stimulant fluid comprising a
propping
agent into the hydrocarbon-bearing formation via the substantially-
longitudinal
wellbore section of at least one of the first well and the second well to form
a
fracture network; wherein: the vertical stress is significantly greater than
the
maximum-horizontal stress and the fracture network comprises substantially-
transverse-vertical fractures, substantially-longitudinal-vertical fractures,
or a
combination thereof, and the substantially-longitudinal wellbore section of
the first
well is: (a) laterally displaced from the substantially-longitudinal wellbore
section
of the second well, and at least one of (b) angularly offset from at least a
part of
the lithofacies surface, and (c) angularly offset from the substantially-
longitudinal
wellbore section of the second well such that the substantially-longitudinal
wellbore section of the first well and the longitudinal wellbore of the second
well
form a crossing pattern as viewed from a longitudinal elevation view, to
modify
heat transfer within the formation, hydrocarbon-flow rate within the
formation,
hydrocarbon capture from the formation, or a combination thereof.
[0024] With respect to the second technical solution, select
embodiments
of the present disclosure relate to a process for developing a fracture
network in
a hydrocarbon-bearing formation: (a) that has a stress field defined by a
vertical
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Date Regue/Date Received 2022-08-11
stress, a maximum-horizontal stress, and a minimum-horizontal stress, and (b)
that is penetrated by a well pair comprising: (i) a first well having a
substantially-
vertical wellbore section and a substantially-longitudinal wellbore section,
and (ii)
a second well having a substantially-vertical wellbore section and a
substantially-
longitudinal wellbore section, the process comprising: injecting a stimulant
fluid
comprising a propping agent into the hydrocarbon-bearing formation from the
substantially-longitudinal wellbore section of at least one of the first well
and the
second well to form the fracture network, wherein: the vertical stress is less
than
or substantially equal to the maximum-horizontal stress and the fracture
network
cornprises substantially-horizontal fractures, substantially-transverse-
vertical
fractures, substantially-longitudinal-vertical fractures, or a combination
thereof,
and the substantially-longitudinal wellbore section of at least one of the
first well
and the second well is angularly offset from a plane defined by the maximum-
horizontal stress and the minimum-horizontal stress to modify fracture
geometry,
fracture complexity, or a combination thereof within the fracture network.
[0025] Also with respect to the second technical solution, select
embodiments of the present disclosure relate to a process for developing a
fracture network in a hydrocarbon-bearing formation: (a) that has a stress
field
defined by a vertical stress, a maximum-horizontal stress, and a minimum-
horizontal stress, and (b) that is penetrated by a well pair comprising: (i) a
first well
having a substantially-vertical wellbore section and a substantially-
longitudinal
wellbore section, and (ii) a second well having a substantially-vertical
wellbore
section and a substantially-longitudinal wellbore section, the process
comprising:
injecting a stimulant fluid comprising a propping agent into the hydrocarbon-
bearing formation from the substantially-longitudinal wellbore section of at
least
one of the first well and the second well to form the fracture network,
wherein: the
vertical stress is significantly greater than the maximum-horizontal stress
and the
fracture network cornprises substantially-transverse-vertical fractures,
substantially-longitudinal-vertical fractures, or a combination thereof, and
the
substantially-longitudinal wellbore section of at least one of the first well
and the
second well is: (a) oriented relative to the maximum-horizontal stress and the
minimum-horizontal stress, and (b) angularly offset from a plane defined by
the
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Date Regue/Date Received 2022-08-11
maximum-horizontal stress and the minimum-horizontal stress, to modify
fracture
geometry, fracture complexity, or a combination thereof within the fracture
network.
[0026] Also with respect to the second technical solution, select
embodiments of the present disclosure relate to a process for developing a
fracture network in a hydrocarbon-bearing formation: (a) that comprises a
lithofacies surface, (b) that has a stress field defined by a vertical stress,
a
maximum-horizontal stress, and a minimum-horizontal stress, and (c) that is
penetrated by a well pair comprising: (i) a first well having a substantially-
vertical
wellbore section and a substantially-longitudinal wellbore section, and (ii) a
second well having a substantially-vertical wellbore section and a
substantially-
longitudinal wellbore section, the process comprising: injecting a stimulant
fluid
comprising a propping agent into the hydrocarbon-bearing formation from the
substantially-longitudinal wellbore section of at least one of the first well
and the
second well to form the fracture network, wherein: the vertical stress is less
than
or substantially equal to the maximum-horizontal stress and the fracture
network
comprises substantially-horizontal fractures, substantially-transverse-
vertical
fractures, substantially-longitudinal-vertical fractures, or a combination
thereof,
and the substantially-longitudinal wellbore section of at least one of the
first well
and the second well is angularly offset from at least a part of the
lithofacies surface
to modify fracture geometry, fracture complexity, or a combination thereof
within
the fracture network.
[0027] Also with respect to the second technical solution, select
embodiments of the present disclosure relate to a process for developing a
fracture network in a hydrocarbon-bearing formation: (a) that comprises a
lithofacies surface, (b) that has a stress field defined by a vertical stress,
a
maximum-horizontal stress, and a minimum-horizontal stress, and (c) that is
penetrated by a well pair comprising: (i) a first well having a substantially-
vertical
wellbore section and a substantially-longitudinal wellbore section, and (ii) a
second well having a substantially-vertical wellbore section and a
substantially-
longitudinal wellbore section, the process comprising: injecting a stimulant
fluid
14
Date Regue/Date Received 2022-08-11
comprising a propping agent into the hydrocarbon-bearing formation from the
substantially-longitudinal wellbore section of at least one of the first well
and the
second well to form the fracture network, wherein: the vertical stress is
significantly
greater than the maximum-horizontal stress and the fracture network comprises
substantially-transverse-vertical fractures, substantially-longitudinal-
vertical
fractures, or a combination thereof, and the substantially-longitudinal
wellbore
section of at least one of the first well and the second well is: (a) oriented
relative
to the maximum-horizontal stress and the minimum-horizontal stress, and (b)
angularly offset from at least a part of the lithofacies surface to modify
fracture
geometry, fracture complexity, or a combination thereof within the fracture
network.
[0028] Also with respect to the second technical solution, select
embodiments of the present disclosure relate to a method for recovering
hydrocarbons from a hydrocarbon-bearing formation: (a) that has a stress field
defined by a vertical stress, a maximum-horizontal stress, and a minimum-
horizontal stress, and (b) that is penetrated by a well pair comprising: (i) a
first well
having a substantially-vertical wellbore section and a substantially-
longitudinal
wellbore section, and (ii) a second well having a substantially-vertical
wellbore
section and a substantially-longitudinal wellbore section, the method
comprising:
injecting a stimulant fluid comprising a propping agent into the hydrocarbon-
bearing formation via the substantially-longitudinal wellbore section of at
least one
of the first well and the second well to form a fracture network; modulating
the
mobility of hydrocarbons within the hydrocarbon-bearing formation; and
recovering hydrocarbons from the hydrocarbon-bearing formation, wherein: the
vertical stress is less than or substantially equal to the maximum-horizontal
stress
and the fracture network comprises substantially-horizontal fractures,
substantially-transverse-vertical fractures, substantially-longitudinal-
vertical
fractures, or a combination thereof, and the substantially-longitudinal
wellbore
section of at least one of the first well and the second well is angularly
offset from
a plane defined by the maximum-horizontal stress and the minimum-horizontal
stress to modify heat transfer within the formation, hydrocarbon-flow rate
within
the formation, hydrocarbon capture from the formation, or a combination
thereof.
Date Regue/Date Received 2022-08-11
10029] Also with respect to the second technical solution, select
embodiments of the present disclosure relate to a method for recovering
hydrocarbons from a hydrocarbon-bearing formation: (a) that has a stress field
defined by a vertical stress, a maximum-horizontal stress, and a minimum-
horizontal stress, and (b) that is penetrated by a well pair comprising: (i) a
first well
having a substantially-vertical wellbore section and a substantially-
longitudinal
wellbore section, and (ii) a second well having a substantially-vertical
wellbore
section and a substantially-longitudinal wellbore section, the method
comprising:
injecting a stimulant fluid comprising a propping agent into the hydrocarbon-
bearing formation via the substantially-longitudinal wellbore section of at
least one
of the first well and the second well to form a fracture network; modulating
the
mobility of hydrocarbons within the hydrocarbon-bearing formation; and
recovering hydrocarbons from the hydrocarbon-bearing formation, wherein: the
vertical stress is significantly greater than the maximum-horizontal stress
and the
fracture network comprises substantially-transverse-vertical fractures,
substantially-longitudinal-vertical fractures, or a combination thereof, and
the
substantially-longitudinal wellbore section of at least one of the first well
and the
second well is angularly offset from a plane defined by the maximum-horizontal
stress and the minimum-horizontal stress to modify heat transfer within the
formation, hydrocarbon-flow rate within the formation, hydrocarbon capture
from
the formation, or a combination thereof.
[0030] Also with respect to the second technical solution, select
embodiments of the present disclosure relate to a method for recovering
hydrocarbons from a hydrocarbon-bearing formation: (a) that comprises a
lithofacies surface, (b) that has a stress field defined by a vertical stress,
a
maximum-horizontal stress, and a minimum-horizontal stress, and (c) that is
penetrated by a well pair comprising: (i) a first well having a substantially-
vertical
wellbore section and a substantially-longitudinal wellbore section, and (ii) a
second well having a substantially-vertical wellbore section and a
substantially-
longitudinal wellbore section, the method comprising: injecting a stimulant
fluid
comprising a propping agent into the hydrocarbon-bearing formation via the
substantially-longitudinal wellbore section of at least one of the first well
and the
16
Date Recue/Date Received 2022-08-11
second well to form a fracture network; modulating the mobility of
hydrocarbons
within the hydrocarbon-bearing formation; and recovering hydrocarbons from the
hydrocarbon-bearing formation, wherein: the vertical stress is less than or
substantially equal to the maximum-horizontal stress and the fracture network
comprises substantially-horizontal fractures, substantially-transverse-
vertical
fractures, substantially-longitudinal-vertical fractures, or a combination
thereof,
and the substantially-longitudinal wellbore section of at least one of the
first well
and the second well is angularly offset from at least a part of the
lithofacies surface
to modify heat transfer within the formation, hydrocarbon-flow rate within the
formation, hydrocarbon capture from the formation, or a combination thereof.
[0031] Also with respect to the second technical solution, select
embodiments of the present disclosure relate to a method for recovering
hydrocarbons from a hydrocarbon-bearing formation: (a) that comprises a
lithofacies surface, (b) that has a stress field defined by a vertical stress,
a
maximum-horizontal stress, and a minimum-horizontal stress, and (c) that is
penetrated by a well pair comprising: (i) a first well having a substantially-
vertical
wellbore section and a substantially-longitudinal wellbore section, and (ii) a
second well having a substantially-vertical wellbore section and a
substantially-
longitudinal wellbore section, the method comprising: injecting a stimulant
fluid
comprising a propping agent into the hydrocarbon-bearing formation via the
substantially-longitudinal wellbore section of at least one of the first well
and the
second well to form a fracture network; modulating the mobility of
hydrocarbons
within the hydrocarbon-bearing formation; and recovering hydrocarbons from the
hydrocarbon-bearing formation, wherein: the vertical stress is significantly
greater
than the maximum-horizontal stress and the fracture network comprises
substantially-transverse-vertical fractures, substantially-longitudinal-
vertical
fractures, or a combination thereof, and the substantially-longitudinal
wellbore
section of at least one of the first well and the second well is angularly
offset from
at least a part of the lithofacies surface to modify heat transfer within the
formation,
hydrocarbon-flow rate within the formation, hydrocarbon capture from the
formation, or a combination thereof.
17
Date Regue/Date Received 2022-08-11
10032] Also
with respect to the second technical solution, select
embodiments of the present disclosure relate to a process for enhancing
hydrocarbon recovery from a hydrocarbon-bearing formation: (a) that has a
stress
field defined by a vertical stress, a maximum-horizontal stress, and a minimum-
horizontal stress, and (b) that is penetrated by a well pair comprising: (i) a
first well
having a substantially-vertical wellbore section and a substantially-
longitudinal
wellbore section, and (ii) a second well having a substantially-vertical
wellbore
section and a substantially-longitudinal wellbore section, the method
comprising:
injecting a stimulant fluid comprising a propping agent into the hydrocarbon-
bearing formation via the substantially-longitudinal wellbore section of at
least one
of the first well and the second well to form a fracture network; wherein: the
vertical
stress is less than or substantially equal to the maximum-horizontal stress
and the
fracture network comprises substantially-horizontal fractures, substantially-
transverse-vertical fractures, substantially-longitudinal-vertical fractures,
or a
combination thereof, and the substantially-longitudinal wellbore section of at
least
one of the first well and the second well is angularly offset from a plane
defined by
the maximum-horizontal stress and the minimum-horizontal stress to modify heat
transfer within the formation, hydrocarbon-flow rate within the formation,
hydrocarbon capture from the formation, or a combination thereof.
[0033] Also
with respect to the second technical solution, select
embodiments of the present disclosure relate to a process for enhancing
hydrocarbon recovery from a hydrocarbon-bearing formation: (a) that has a
stress
field defined by a vertical stress, a maximum-horizontal stress, and a minimum-
horizontal stress, and (b) that is penetrated by a well pair comprising: (i) a
first well
having a substantially-vertical wellbore section and a substantially-
longitudinal
wellbore section, and (ii) a second well having a substantially-vertical
wellbore
section and a substantially-longitudinal wellbore section, the process
comprising:
injecting a stimulant fluid comprising a propping agent into the hydrocarbon-
bearing formation via the substantially-longitudinal wellbore section of at
least one
of the first well and the second well to form a fracture network; wherein: the
vertical
stress is significantly greater than the maximum-horizontal stress and the
fracture
network comprises substantially-transverse-vertical fractures, substantially-
18
Date Recue/Date Received 2022-08-11
longitudinal-vertical fractures, or a combination thereof, and the
substantially-
longitudinal wellbore section of at least one of the first well and the second
well is
angularly offset from a plane defined by the maximum-horizontal stress and the
minimum-horizontal stress to modify heat transfer within the formation,
hydrocarbon-flow rate within the formation, hydrocarbon capture from the
formation, or a combination thereof.
[0034] Also with respect to the second technical solution, select
embodiments of the present disclosure relate to a process for enhancing
hydrocarbon recovery from a hydrocarbon-bearing formation: (a) that comprises
a lithofacies surface, (b) that has a stress field defined by a vertical
stress, a
maximum-horizontal stress, and a minimum-horizontal stress, and (c) that is
penetrated by a well pair comprising: (i) a first well having a substantially-
vertical
wellbore section and a substantially-longitudinal wellbore section, and (ii) a
second well having a substantially-vertical wellbore section and a
substantially-
longitudinal wellbore section, the process comprising: injecting a stimulant
fluid
comprising a propping agent into the hydrocarbon-bearing formation via the
substantially-longitudinal wellbore section of at least one of the first well
and the
second well to form a fracture network; wherein: the vertical stress is less
than or
substantially equal to the maximum-horizontal stress and the fracture network
comprises substantially-horizontal fractures, substantially-transverse-
vertical
fractures, substantially-longitudinal-vertical fractures, or a combination
thereof,
and the substantially-longitudinal wellbore section of at least one of the
first well
and the second well is angularly offset from at least a part of the
lithofacies surface
to modify heat transfer within the formation, hydrocarbon-flow rate within the
formation, hydrocarbon capture from the formation, or a combination thereof.
[0035] Also with respect to the second technical solution, select
embodiments of the present disclosure relate to a process for enhancing
hydrocarbon recovery from a hydrocarbon-bearing formation: (a) that comprises
a lithofacies surface, (b) that has a stress field defined by a vertical
stress, a
maximum-horizontal stress, and a minimum-horizontal stress, and (c) that is
penetrated by a well pair comprising: (i) a first well having a substantially-
vertical
19
Date Regue/Date Received 2022-08-11
wellbore section and a substantially-longitudinal wellbore section, and (ii) a
second well having a substantially-vertical wellbore section and a
substantially-
longitudinal wellbore section, the process comprising: injecting a stimulant
fluid
comprising a propping agent into the hydrocarbon-bearing formation via the
substantially-longitudinal wellbore section of at least one of the first well
and the
second well to form a fracture network; wherein: the vertical stress is
significantly
greater than the maximum-horizontal stress and the fracture network comprises
substantially-transverse-vertical fractures, substantially-longitudinal-
vertical
fractures, or a combination thereof, and the substantially-longitudinal
wellbore
section of at least one of the first well and the second well is angularly
offset from
at least a part of the lithofacies surface to modify heat transfer within the
formation,
hydrocarbon-flow rate within the formation, hydrocarbon capture from the
formation, or a combination thereof.
[0036] With respect to the third technical solution, select
embodiments of
the present disclosure relate to a process for developing a fracture network
in a
hydrocarbon-bearing formation having a stress field defined by a vertical
stress, a
maximum-horizontal stress, and a minimum-horizontal stress, the process
comprising: injecting a stimulant fluid comprising a propping agent into the
hydrocarbon-bearing formation from a substantially-longitudinal wellbore
section
of a well within the hydrocarbon-bearing formation to form the fracture
network,
wherein: the vertical stress is less than or substantially equal to the
maximum-
horizontal stress and the fracture network comprises substantially-horizontal
fractures, substantially-transverse-vertical fractures, substantially-
longitudinal-
vertical fractures, or a combination thereof, and the substantially-
longitudinal
wellbore section is angularly offset from a plane defined by the maximum-
horizontal stress and the minimum-horizontal stress to modify fracture
geometry,
fracture complexity, or a combination thereof within the fracture network.
[0037] Also with respect to the third technical solution, select
embodiments
of the present disclosure relate to a process for developing a fracture
network in
a hydrocarbon-bearing formation having a stress field defined by a vertical
stress,
a maximum-horizontal stress, and a minimum-horizontal stress, the process
Date Recue/Date Received 2022-08-11
comprising: injecting a stimulant fluid comprising a propping agent into the
hydrocarbon-bearing formation from a substantially-longitudinal wellbore
section
of a well within the hydrocarbon-bearing formation to form the fracture
network,
wherein: the vertical stress is significantly greater than the maximum-
horizontal
stress and the fracture network comprises substantially-transverse-vertical
fractures, substantially-longitudinal-vertical fractures, or a combination
thereof,
and the substantially-longitudinal wellbore section is: (a) oriented relative
to the
maximum-horizontal stress and the minimum-horizontal stress, and (b) angularly
offset from a plane defined by the maximum-horizontal stress and the minimum-
horizontal stress, to modify fracture geometry, fracture complexity, or a
combination thereof within the fracture network.
[0038] Also with respect to the third technical solution, select
embodiments
of the present disclosure relate to a process for developing a fracture
network in
a hydrocarbon-bearing formation comprising a lithofacies surface and a stress
field defined by a vertical stress, a maximum-horizontal stress, and a minimum-
horizontal stress, the process comprising: injecting a stimulant fluid
comprising a
propping agent into the hydrocarbon-bearing formation from a substantially-
longitudinal wellbore section of a well within the hydrocarbon-bearing
formation to
form the fracture network, wherein: the vertical stress is less than or
substantially
equal to the maximum-horizontal stress and the fracture network comprises
substantially-horizontal fractures, substantially-transverse-vertical
fractures,
substantially-longitudinal-vertical fractures, or a combination thereof, and
the
substantially-longitudinal wellbore section is angularly offset from at least
a part of
the lithofacies surface to modify fracture geometry, fracture complexity, or a
combination thereof within the fracture network.
[0039] Also with respect to the third technical solution, select
embodiments
of the present disclosure relate to a process for developing a fracture
network in
a hydrocarbon-bearing formation comprising a lithofacies surface and a stress
field defined by a vertical stress, a maximum-horizontal stress, and a minimum-
horizontal stress, the process comprising: injecting a stimulant fluid
comprising a
propping agent into the hydrocarbon-bearing formation from a substantially-
21
Date Regue/Date Received 2022-08-11
longitudinal wellbore section of a well within the hydrocarbon-bearing
formation to
form the fracture network, wherein: the vertical stress is significantly
greater than
the maximum-horizontal stress and the fracture network comprises substantially-
transverse-vertical fractures, substantially-longitudinal-vertical fractures,
or a
combination thereof, and the substantially-longitudinal wellbore section is:
(a)
oriented relative to the maximum-horizontal stress and the minimum-horizontal
stress, and (b) angularly offset from at least a part of the lithofacies
surface to
modify fracture geometry, fracture complexity, or a combination thereof within
the
fracture network.
[0040] Also with respect to the third technical solution, select
embodiments
of the present disclosure relate to a method for recovering hydrocarbons from
a
hydrocarbon-bearing formation: (a) that has a stress field defined by a
vertical
stress, a maximum-horizontal stress, and a minimum-horizontal stress, and (b)
that is penetrated by a well comprising a substantially-vertical wellbore
section
and a substantially-longitudinal wellbore section, the method comprising:
injecting
a stimulant fluid comprising a propping agent into the hydrocarbon-bearing
formation via the substantially-longitudinal wellbore section to form a
fracture
network; modulating the mobility of hydrocarbons within the hydrocarbon-
bearing
formation; and recovering hydrocarbons from the hydrocarbon-bearing formation,
wherein: the vertical stress is less than or substantially equal to the
maximum-
horizontal stress and the fracture network comprises substantially-horizontal
fractures, substantially-transverse-vertical fractures, substantially-
longitudinal-
vertical fractures, or a combination thereof, and the substantially-
longitudinal
wellbore section is angularly offset from a plane defined by the maximum-
horizontal stress and the minimum-horizontal stress to modify heat transfer
within
the formation, hydrocarbon-flow rate within the formation, hydrocarbon capture
from the formation, or a combination thereof.
[0041] Also with respect to the third technical solution, select
embodiments
of the present disclosure relate to a method for recovering hydrocarbons from
a
hydrocarbon-bearing formation: (a) that has a stress field defined by a
vertical
stress, a maximum-horizontal stress, and a minimum-horizontal stress, and (b)
22
Date Recue/Date Received 2022-08-11
that is penetrated by a well comprising a substantially-vertical wellbore
section
and a substantially-longitudinal wellbore section, the method comprising:
injecting
a stimulant fluid comprising a propping agent into the hydrocarbon-bearing
formation via the substantially-longitudinal wellbore section to form a
fracture
network; modulating the mobility of hydrocarbons within the hydrocarbon-
bearing
formation; and recovering hydrocarbons from the hydrocarbon-bearing formation,
wherein: the vertical stress is significantly greater than the maximum-
horizontal
stress and the fracture network comprises substantially-transverse-vertical
fractures, substantially-longitudinal-vertical fractures, or a combination
thereof,
and the substantially-longitudinal wellbore section is: (a) oriented relative
to the
maximum-horizontal stress and the minimum-horizontal stress, and (b) angularly
offset from a plane defined by the maximum-horizontal stress and the minimum-
horizontal stress, to modify heat transfer within the formation, hydrocarbon-
flow
rate within the formation, hydrocarbon capture from the formation, or a
combination thereof.
[0042] Also with respect to the third technical solution, select
embodiments
of the present disclosure relate to a method for recovering hydrocarbons from
a
hydrocarbon-bearing formation: (a) that comprises a lithofacies surface, (b)
that
has a stress field defined by a vertical stress, a maximum-horizontal stress,
and a
minimum-horizontal stress, and (c) that is penetrated by a well comprising a
substantially-vertical wellbore section and a substantially-longitudinal
wellbore
section, the method comprising: injecting a stimulant fluid comprising a
propping
agent into the hydrocarbon-bearing formation via the substantially-
longitudinal
wellbore section to form a fracture network; modulating the mobility of
hydrocarbons within the hydrocarbon-bearing formation; and recovering
hydrocarbons from the hydrocarbon-bearing formation, wherein: the vertical
stress
is less than or substantially equal to the maximum-horizontal stress and the
fracture network cornprises substantially-horizontal fractures, substantially-
transverse-vertical fractures, substantially-longitudinal-vertical fractures,
or a
combination thereof, and the substantially-longitudinal wellbore section is
angularly offset from at least a part of the lithofacies surface to modify
heat transfer
23
Date Regue/Date Received 2022-08-11
within the formation, hydrocarbon-flow rate within the formation, hydrocarbon
capture from the formation, or a combination thereof.
[0043] Also with respect to the third technical solution, select
embodiments
of the present disclosure relate to a method for recovering hydrocarbons from
a
hydrocarbon-bearing formation: (a) that comprises a lithofacies surface, (b)
that
has a stress field defined by a vertical stress, a maximum-horizontal stress,
and a
minimum-horizontal stress, and (c) that is penetrated by a well comprising a
substantially-vertical wellbore section and a substantially-longitudinal
wellbore
section, the method comprising: injecting a stimulant fluid comprising a
propping
agent into the hydrocarbon-bearing formation via the substantially-
longitudinal
wellbore section to form a fracture network; modulating the mobility of
hydrocarbons within the hydrocarbon-bearing formation; and recovering
hydrocarbons from the hydrocarbon-bearing formation, wherein: the vertical
stress
is significantly greater than the maximum-horizontal stress and the fracture
network comprises substantially-transverse-vertical fractures, substantially-
longitudinal-vertical fractures, or a combination thereof, and the
substantially-
longitudinal wellbore section is angularly offset from at least a part of the
lithofacies
surface to modify heat transfer within the formation, hydrocarbon-flow rate
within
the formation, hydrocarbon capture from the formation, or a combination
thereof.
[0044] Also with respect to the third technical solution, select
embodiments
of the present disclosure relate to a process for enhancing hydrocarbon
recovery
from a hydrocarbon-bearing formation: (a) that has a stress field defined by a
vertical stress, a maximum-horizontal stress, and a minimum-horizontal stress,
and (b) that is penetrated by a well comprising a substantially-vertical
wellbore
section and a substantially-longitudinal wellbore section, the method
comprising:
injecting a stimulant fluid comprising a propping agent into the hydrocarbon-
bearing formation via the substantially-longitudinal wellbore section to form
a
fracture network; wherein: the vertical stress is less than or substantially
equal to
the maximum-horizontal stress and the fracture network comprises substantially-
horizontal fractures, substantially-transverse-vertical fractures,
substantially-
longitudinal-vertical fractures, or a combination thereof, and the
substantially-
24
Date Regue/Date Received 2022-08-11
longitudinal wellbore section is angularly offset from a plane defined by the
maximum-horizontal stress and the minimum-horizontal stress to modify heat
transfer within the formation, hydrocarbon-flow rate within the formation,
hydrocarbon capture from the formation, or a combination thereof.
[0045] Also with respect to the third technical solution, select
embodiments
of the present disclosure relate to a process for enhancing hydrocarbon
recovery
from a hydrocarbon-bearing formation: (a) that has a stress field defined by a
vertical stress, a maximum-horizontal stress, and a minimum-horizontal stress,
and (b) that is penetrated by a well comprising a substantially-vertical
wellbore
section and a substantially-longitudinal wellbore section, the process
comprising:
injecting a stimulant fluid comprising a propping agent into the hydrocarbon-
bearing formation via the substantially-longitudinal wellbore section to form
a
fracture network; wherein: the vertical stress is significantly greater than
the
maximum-horizontal stress and the fracture network comprises substantially-
transverse-vertical fractures, substantially-longitudinal-vertical fractures,
or a
combination thereof, and the substantially-longitudinal wellbore section is
angularly offset from a plane defined by the maximum-horizontal stress and the
minimum-horizontal stress to modify heat transfer within the formation,
hydrocarbon-flow rate within the formation, hydrocarbon capture from the
formation, or a combination thereof.
[0046] Also with respect to the third technical solution, select
embodiments
of the present disclosure relate to a process for enhancing hydrocarbon
recovery
from a hydrocarbon-bearing formation: (a) that comprises a lithofacies
surface, (b)
that has a stress field defined by a vertical stress, a maximum-horizontal
stress,
and a minimum-horizontal stress, and (c) that is penetrated by a well
comprising
a substantially-vertical wellbore section and a substantially-longitudinal
wellbore
section, the process comprising: injecting a stimulant fluid comprising a
propping
agent into the hydrocarbon-bearing formation via the substantially-
longitudinal
wellbore section to form a fracture network; wherein: the vertical stress is
less than
or substantially equal to the maximum-horizontal stress and the fracture
network
comprises substantially-horizontal fractures, substantially-transverse-
vertical
Date Recue/Date Received 2022-08-11
fractures, substantially-longitudinal-vertical fractures, or a combination
thereof,
and the substantially-longitudinal wellbore section is angularly offset from
at least
a part of the lithofacies surface to modify heat transfer within the
formation,
hydrocarbon-flow rate within the formation, hydrocarbon capture from the
formation, or a combination thereof.
[0047] Also with respect to the third technical solution, select
embodiments
of the present disclosure relate to a process for enhancing hydrocarbon
recovery
from a hydrocarbon-bearing formation: (a) that comprises a lithofacies
surface, (b)
that has a stress field defined by a vertical stress, a maximum-horizontal
stress,
and a minimum-horizontal stress, and (c) that is penetrated by a well
comprising
a substantially-vertical wellbore section and a substantially-longitudinal
wellbore
section, the process comprising: injecting a stimulant fluid comprising a
propping
agent into the hydrocarbon-bearing formation via the substantially-
longitudinal
wellbore section to form a fracture network; wherein: the vertical stress is
significantly greater than the maximum-horizontal stress and the fracture
network
cornprises substantially-transverse-vertical fractures, substantially-
longitudinal-
vertical fractures, or a combination thereof, and the substantially-
longitudinal
wellbore section is angularly offset from at least a part of the lithofacies
surface to
modify heat transfer within the formation, hydrocarbon-flow rate within the
formation, hydrocarbon capture from the formation, or a combination thereof.
[0048] With respect to the fourth technical solution, select
embodiments of
the present disclosure relate to a process for developing a fracture network
in a
hydrocarbon-bearing formation: (a) that comprises a lithofacies surface, (b)
that
has a stress field defined by a vertical stress, a maximum-horizontal stress,
and a
minimum-horizontal stress, and (c) that is penetrated by a well pair
comprising: (i)
a first well having a substantially-vertical wellbore section and a
substantially-
horizontal wellbore section, and (ii) a second well having a substantially-
vertical
wellbore section and a substantially-horizontal wellbore section, the process
comprising: injecting a stimulant fluid comprising a propping agent into the
hydrocarbon-bearing formation from the substantially-horizontal wellbore
section
of at least one of the first well and the second well to form the fracture
network,
26
Date Regue/Date Received 2022-08-11
wherein: the vertical stress is less than or substantially equal to the
maximum-
horizontal stress and the fracture network comprises substantially-horizontal
fractures, substantially-transverse-vertical fractures, substantially-
longitudinal-
vertical fractures, or a combination thereof, and the substantially-horizontal
wellbore section of at least one of the first well and the second well is
angularly
offset from at least a part of the lithofacies surface to modify fracture
geometry,
fracture complexity, or a combination thereof within the fracture network.
[0049] Also with respect to the fourth technical solution, select
embodiments of the present disclosure relate to a process for developing a
fracture network in a hydrocarbon-bearing formation: (a) that comprises a
lithofacies surface, (b) that has a stress field defined by a vertical stress,
a
maximum-horizontal stress, and a minimum-horizontal stress, and (c) that is
penetrated by a well pair comprising: (i) a first well having a substantially-
vertical
wellbore section and a substantially-horizontal wellbore section, and (ii) a
second
well having a substantially-vertical wellbore section and a substantially-
horizontal
wellbore section, the process comprising: injecting a stimulant fluid
comprising a
propping agent into the hydrocarbon-bearing formation from the substantially-
horizontal wellbore section of at least one of the first well and the second
well to
form the fracture network, wherein: the vertical stress is significantly
greater than
the maximum-horizontal stress and the fracture network comprises substantially-
transverse-vertical fractures, substantially-longitudinal-vertical fractures,
or a
combination thereof, and the substantially-horizontal wellbore section of at
least
one of the first well and the second well is: (a) oriented relative to the
maximum-
horizontal stress and the minimum-horizontal stress, and (b) angularly offset
from
at least a part of the lithofacies surface to modify fracture geometry,
fracture
complexity, or a combination thereof within the fracture network.
[0050] Also with respect to the fourth technical solution, select
embodiments of the present disclosure relate to a method for recovering
hydrocarbons from a hydrocarbon-bearing formation: (a) that comprises a
lithofacies surface, (b) that has a stress field defined by a vertical stress,
a
maximum-horizontal stress, and a minimum-horizontal stress, and (c) that is
27
Date Regue/Date Received 2022-08-11
penetrated by a well pair comprising: (i) a first well having a substantially-
vertical
wellbore section and a substantially-horizontal wellbore section, and (ii) a
second
well having a substantially-vertical wellbore section and a substantially-
horizontal
wellbore section, the method comprising: injecting a stimulant fluid
comprising a
propping agent into the hydrocarbon-bearing formation via the substantially-
horizontal wellbore section of at least one of the first well and the second
well to
form a fracture network; modulating the mobility of hydrocarbons within the
hydrocarbon-bearing formation; and recovering hydrocarbons from the
hydrocarbon-bearing formation, wherein: the vertical stress is less than or
substantially equal to the maximum-horizontal stress and the fracture network
comprises substantially-horizontal fractures, substantially-transverse-
vertical
fractures, substantially-longitudinal-vertical fractures, or a combination
thereof,
and the substantially-horizontal wellbore section of at least one of the first
well and
the second well is angularly offset from at least a part of the lithofacies
surface to
modify heat transfer within the formation, hydrocarbon-flow rate within the
formation, hydrocarbon capture from the formation, or a combination thereof.
[0051] Also with respect to the fourth technical solution, select
embodiments of the present disclosure relate to a method for recovering
hydrocarbons from a hydrocarbon-bearing formation: (a) that comprises a
lithofacies surface, (b) that has a stress field defined by a vertical stress,
a
maximum-horizontal stress, and a minimum-horizontal stress, and (c) that is
penetrated by a well pair comprising: (i) a first well having a substantially-
vertical
wellbore section and a substantially-horizontal wellbore section, and (ii) a
second
well having a substantially-vertical wellbore section and a substantially-
horizontal
wellbore section, the method comprising: injecting a stimulant fluid
comprising a
propping agent into the hydrocarbon-bearing formation via the substantially-
horizontal wellbore section of at least one of the first well and the second
well to
form a fracture network; modulating the mobility of hydrocarbons within the
hydrocarbon-bearing formation; and recovering hydrocarbons from the
hydrocarbon-bearing formation, wherein: the vertical stress is significantly
greater
than the maximum-horizontal stress and the fracture network comprises
substantially-transverse-vertical fractures, substantially-longitudinal-
vertical
28
Date Recue/Date Received 2022-08-11
fractures, or a combination thereof, and the substantially-horizontal wellbore
section of at least one of the first well and the second well is angularly
offset from
at least a part of the lithofacies surface to modify heat transfer within the
formation,
hydrocarbon-flow rate within the formation, hydrocarbon capture from the
formation, or a combination thereof.
[0052] Also with respect to the fourth technical solution, select
embodiments of the present disclosure relate to a process for enhancing
hydrocarbon recovery from a hydrocarbon-bearing formation: (a) that comprises
a lithofacies surface, (b) that has a stress field defined by a vertical
stress, a
maximum-horizontal stress, and a minimum-horizontal stress, and (c) that is
penetrated by a well pair comprising: (i) a first well having a substantially-
vertical
wellbore section and a substantially-horizontal wellbore section, and (ii) a
second
well having a substantially-vertical wellbore section and a substantially-
horizontal
wellbore section, the process comprising: injecting a stimulant fluid
comprising a
propping agent into the hydrocarbon-bearing formation via the substantially-
horizontal wellbore section of at least one of the first well and the second
well to
form a fracture network; wherein: the vertical stress is less than or
substantially
equal to the maximum-horizontal stress and the fracture network comprises
substantially-horizontal fractures, substantially-transverse-vertical
fractures,
substantially-longitudinal-vertical fractures, or a combination thereof, and
the
substantially-horizontal wellbore section of at least one of the first well
and the
second well is angularly offset from at least a part of the lithofacies
surface to
modify heat transfer within the formation, hydrocarbon-flow rate within the
formation, hydrocarbon capture from the formation, or a combination thereof.
[0053] Also with respect to the fourth technical solution, select
embodiments of the present disclosure relate to a process for enhancing
hydrocarbon recovery from a hydrocarbon-bearing formation: (a) that comprises
a lithofacies surface, (b) that has a stress field defined by a vertical
stress, a
maximum-horizontal stress, and a minimum-horizontal stress, and (c) that is
penetrated by a well pair comprising: (i) a first well having a substantially-
vertical
wellbore section and a substantially-horizontal wellbore section, and (ii) a
second
29
Date Regue/Date Received 2022-08-11
well having a substantially-vertical wellbore section and a substantially-
horizontal
wellbore section, the process comprising: injecting a stimulant fluid
comprising a
propping agent into the hydrocarbon-bearing formation via the substantially-
horizontal wellbore section of at least one of the first well and the second
well to
form a fracture network; wherein: the vertical stress is significantly greater
than
the maximum-horizontal stress and the fracture network comprises substantially-
transverse-vertical fractures, substantially-longitudinal-vertical fractures,
or a
combination thereof, and the substantially-horizontal wellbore section of at
least
one of the first well and the second well is angularly offset from at least a
part of
the lithofacies surface to modify heat transfer within the formation,
hydrocarbon-
flow rate within the formation, hydrocarbon capture from the formation, or a
combination thereof.
BRIEF DESCRIPTION OF THE DRAWINGS
[0054] These and other features of the present disclosure will
become more
apparent in the following brief description in which reference is made to the
appended drawings. The appended drawings illustrate one or more embodiments
of the present disclosure by way of example only and are not to be construed
as
limiting the scope of the present disclosure.
[0055] FIG. 1 shows a schematic rectangular-prismatic section of a
hydrocarbon-bearing formation 100 that comprises a fracture network
originating
from a longitudinal wellbore section 102.
[0056] FIGS. 2A ¨ 2H provide schematic representations of a series
of well
configurations in various archetypal lithological environments. The well
configurations may be suitable for developing fracture networks in hydrocarbon-
bearing formations by processes according to the present disclosure. The well
configurations may also be suitable for recovering hydrocarbons from
hydrocarbon-bearing formations by methods according to the present disclosure.
The well configurations may also be suitable for enhancing hydrocarbon
recovery
from hydrocarbon-bearing formations by processes according to the present
disclosure.
Date Regue/Date Received 2022-08-11
[0057] FIGS. 3A ¨ 3D provide schematic representations of a series
of well
configurations. The well configurations may be suitable for developing
fracture
networks in hydrocarbon-bearing formations by processes according to the
present disclosure. The well configurations may also be suitable for
recovering
hydrocarbons from hydrocarbon-bearing formations by methods according to the
present disclosure. The well configurations may also be suitable for enhancing
hydrocarbon recovery from hydrocarbon-bearing formations by processes
according to the present disclosure. Lithological environments are not
provided in
FIG. 3A ¨ FIG. 3D for clarity.
[0058] FIGS. 4A and 4B provide schematic longitudinal-elevation and
horizontal-plan views, respectively, of a hydrocarbon-bearing formation that
comprises a fracture network in communication with a well pair having a
configuration similar to that of FIG. 2A.
[0059] FIGS. 6A and 6B provide archetypal image logs obtained
(static and
dynamic images, respectively) with a drilling-induced fracture occurring in a
substantially T-shape in a shallow-depth cap-rock formation of an oil sands
reservoir in Northern Alberta. The image logs indicate the presence of a pair
of
fractures.
[0060] FIG. 6 shows a core computed tomography (CT) scan obtained
at
approximately the same depth as the fractures identified in the image logs of
FIGS.
5A/ 6B.
[0061] FIG. 7 provides results of G-function analysis performed on
a
diagnostic fracture injection test (DFIT) pumped at approximately the same
depth
as the fractures identified in the image logs of FIGS. 5A / 5B.
[0062] FIG. 8A provides another DFIT pumped in a viscous hydrocarbon-
containing formation in cold conditions the G-function analysis of FIG. 7.
FIG. 8B
provides results from an after closure analysis (ACA radial analysis) of the
same
data set.
31
Date Recue/Date Received 2022-08-11
10063] FIG. 9 provides an archetypal model of stress anisotropy in
a
computer-based lithological representation of the formation discussed in
FIGS. 8A and 8B. The formation is penetrated by a well comprising a
longitudinal
wellbore section that is angularly offset from a plane defined by the maximum-
horizontal stress and the minimum horizontal stress.
[0064] FIGS. 10A¨ 10C show longitudinal-elevation, transverse-
elevation,
and perspective views, respectively, of a simulated fracture network that is
induced from the longitudinal wellbore section of FIG. 9.
10065] FIGS. 11A¨ 11C provide archetypal simulation results that
contrast
production-related metrics for a typical SAGD well pair in the presence and
absence of the fracture network discussed in FIGS. 10A¨ 10C. Simulation
results
on water (steam) rates as a function of time are shown in FIG. 11A. Simulation
results on oil rates as a function of time are shown in FIG. 11B. Simulation
results
on cumulative oil production and cumulative steam-to-oil ratios (SOR) are
shown
in FIG. 11C.
[0066] FIGS. 12A¨ 12C provide archetypal simulation results that
contrast
production-related metrics for a typical SAGD well pair in the presence and
absence of the fracture network discussed in FIGS. 10A ¨ 10C, wherein the
formation further comprises a shale barrier that overlies the well pair.
Simulation
results on water (steam) rates as a function of time are shown in FIG. 12A.
Simulation results on oil rates as a function of time are shown in FIG. 12B.
Simulation results on cumulative oil production and cumulative SOR are shown
in
FIG. 12C.
DETAILED DESCRIPTION
[0067] In the present disclosure, all terms referred to in singular form
are
meant to encompass plural forms of the same. Likewise, all terms referred to
in
plural form are meant to encompass singular forms of the same. Unless defined
otherwise, all technical and scientific terms used herein have the same
meaning
as commonly understood by one of ordinary skill in the art to which this
disclosure
pertains.
32
Date Recue/Date Received 2022-08-11
Concepts and definitions
[0068] In situ processes for recovering hydrocarbons from low-
permeability
formations or high-permeability hydrocarbon-bearing formations that are
bordered
by, interbedded with, and/or interposed by low-permeability deposits often
involve
the use of one or more wells having longitudinal wellbore sections. Hydraulic
fracture stimulation can be induced from such longitudinal wellbore sections
to aid
in hydrocarbon recovery from low-permeability formations. Low-permeability
formations ¨ those having permeabilities of less than about 10 mD ¨ include
but
are not limited to shale formations, tight sandstone formations, and coal bed
formations. Low-permeability formations may be naturally fractured, or not.
"Shale" is a fine-grained sedimentary rock that forms from the compaction of
silt
and clay-size mineral particles.
10069] Hydraulic fracture stimulation can also be used in high-
permeability
formations to aid in hydrocarbon recovery. High-permeability formations ¨
those
having permeabilities of greater than about 10 mD ¨ include but are not
limited to
those that are sand-dominated and that have sand facies. High-permeability
formations may be naturally fractured, or not. Sand-dominated formations may
have permeabilities ranging from 1,000 mD to 10,000 mD (1 to 10 D). The
hydrocarbons contained in high-permeability formations may be viscous
hydrocarbon. Viscous hydrocarbons may be referred to as reservoirs of heavy
hydrocarbons, heavy oil, bitumen, or oil sands. In situ processes for
recovering
hydrocarbons from oil sands typically involve the use of multiple wells. Such
processes are often assisted or aided by injecting a fluid (e.g. steam,
solvent, or
a combination thereof) through an injection well to mobilize the viscous
hydrocarbons for recovery through a production well. Steam-assisted gravity
drainage (SAGD) and cyclic steam stimulation (CSS) are two such processes
(see, e.g.: Butler, Roger (1991), Thermal Recovery of Oil and Bitumen,
Englewood
Cliffs: Prentice-Hall).
[0070] A typical SAGD process is disclosed in Canadian Patent No.
1,130,201, in which two wells are drilled into a hydrocarbon-bearing
formation.
One of the wells is configured for steam (i.e. an injection well) and the
other is
33
Date Recue/Date Received 2022-08-11
configured for the production of oil and water (i.e. a production well). In
operation,
steam injected via the injection well heats formation and condenses to an
aqueous
condensate. The transfer of latent heat from the steam to the formation heats
the
viscous hydrocarbons which increases their mobility. After sufficient heat
transfer,
the viscous hydrocarbons are sufficiently-mobilized to drain under the
influence of
gravity toward the production well along with an aqueous condensate. In this
way,
the injected steam creates a "steam chamber" in the formation around and above
the injection well. The term "steam chamber" accordingly refers to a volume of
the
reservoir from which mobilized hydrocarbons have at least partially drained.
Mobilized hydrocarbons are recovered continuously through the production well.
The conditions of steam injection and of hydrocarbon production may be
modulated to control the growth of the steam chamber.
[0071] The SAGD process has a number of shortcomings. For example,
SAGD is water-use and water-treatment intensive. Accordingly, alternative
processes for in situ hydrocarbon recovery have been proposed. Some
alternative
processes are aided by one or more solvents and are referred to as "solvent-
aided
processes" (SAPs). In some SAPs, the injection fluid may include less than
about
% solvent and greater than about 80 % steam on a mass basis. Such
processes are referred to as "steam-driven solvent-aided processes". In some
20 SAPs, the injection fluid may include between about 20 % and about 80 %
solvent
on a mass basis. Such processes are referred to as "hybrid solvent-assisted
processes". In some SAPs, the injection fluid may include greater than about
80
% solvent and less than about 20 % steam on a mass basis. Such processes are
referred to as "substantially solvent driven" or in some cases "solvent-only /
solvent-based processes".
[0072] CSS generally involves injecting steam into a formation,
permitting
the injected fluids to soak, and then producing fluids including mobilized
hydrocarbons. A variation of CSS is described for example in Canadian Patent
No. 1,144,064, wherein a hydrocarbon solvent is injected into the formation as
part of the CSS process. For example, solvent-assisted processes characterized
as Liquid Assisted Steam Enhanced Recovery (LASER) have been described, in
34
Date Recue/Date Received 2022-08-11
which solvents are used in conjunction with steam to enhance performance of
CSS.
[0073] In the context of the present disclosure, "thermal recovery"
or
"thermal stimulation" refers to enhanced oil recovery techniques that involve
delivering thermal energy to a petroleum resource, for example to a heavy oil
reservoir. There are a significant number of thermal recovery techniques other
than SAGD and CSS, such as in-situ combustion, hot water flooding, steam
flooding, and electrical heating. In general, thermal energy is provided to
reduce
the viscosity of the petroleum to facilitate production in thermal recovery
processes.
[0074] In the context of the present disclosure, "petroleum" is a
naturally
occurring mixture consisting predominantly of hydrocarbons in the gaseous,
liquid
or solid phase, which include various oxygen-, nitrogen- and sulfur-containing
compounds and typically trace amounts of metal-containing compounds. In the
context of the present application, the words "petroleum", "oil", and
"hydrocarbon"
are generally used interchangeably to refer to mixtures of widely varying
composition, as will be evident from the context in which the word is used.
The
production of petroleum from a reservoir necessarily involves the production
of
hydrocarbons, but is not limited to hydrocarbon production. Similarly,
processes
that produce hydrocarbons from a well will generally also produce petroleum
fluids
that are not hydrocarbons. In accordance with this usage, a process for
producing
petroleum or hydrocarbons is not necessarily a process that produces
exclusively
petroleum or hydrocarbons, respectively.
[0075] In the context of the present disclosure "fluids", such as
petroleum
fluids or reservoir fluids, include both liquids and gases. Natural gas is the
portion
of petroleum that exists either in the gaseous phase or is in solution in
crude oil in
natural underground reservoirs, and which is gaseous at atmospheric conditions
of pressure and temperature. Natural gas may include amounts of non-
hydrocarbons.
Date Regue/Date Received 2022-08-11
[0076] It is common practice to categorize petroleum substances of
high
viscosity and density into two categories, "heavy oil" and "bitumen". For
example,
some sources define "heavy oil" as a petroleum that has a mass density of
greater
than about 900 kg/m3. Bitumen is sometimes described as that portion of
petroleum that exists in the semi-solid or solid phase in natural deposits,
with a
mass density greater than about 1000 kg/m3 and a viscosity greater than about
10,000 centipoise (cP; or 10 Pa-s) measured at original temperature in the
deposit
and atmospheric pressure, on a gas-free basis. Although these terms are in
common use, references to heavy oil and bitumen represent categories of
convenience, and there is a continuum of properties between heavy oil and
bitumen.
[0077] Accordingly, references to heavy oil and/or bitumen herein
include
the continuum of such substances, and do not imply the existence of some fixed
and universally recognized boundary between the two substances. In particular,
the term "heavy oil" includes within its scope all "bitumen" including
hydrocarbons
that are present in semi-solid or solid form.
10078] In the context of the present disclosure, a "reservoir" or
"hydrocarbon-bearing formation" is a subsurface formation containing one or
more
natural accumulations of moveable hydrocarbons, which are generally confined
by relatively impermeable rock. An "oil sand" reservoir is generally comprised
of
strata of sand or sandstone containing viscous hydrocarbons, such as bitumen.
Viscous petroleum, such as bitumen, may also be found in reservoirs whose
solid
structure consists of carbonate material rather than sand material. Such
reservoirs
are sometimes referred to as "bituminous carbonates". A "zone" or "hydrocarbon-
bearing zone" in a reservoir is merely an arbitrarily defined volume of the
reservoir,
typically characterised by some distinctive property. In various embodiments,
a
zone may or may not contain hydrocarbons. Different zones in a reservoir may
have different permeabilities.
[0079] In the context of the present disclosure, a reservoir, a
hydrocarbon-
bearing formation, an oil sand reservoir, or a zone is said to be at "native
reservoir
temperature" when the temperature of the reservoir, the hydrocarbon-bearing
36
Date Regue/Date Received 2022-08-11
formation, the oil sand reservoir, or the zone has not been substantially
influenced
by a thermal process.
[0080] In the context of the present disclosure, the permeability
of the
hydrocarbon-bearing formation refers to the degree to which hydrocarbons can
flow through the hydrocarbon-bearing formation. High-permeability hydrocarbon-
bearing formations are often bordered by, interbedded with, and/or interposed
by
low-permeability deposits such as shale lamina and mud clasts. Inclined
heterolithic strata (IHS) ¨ heterogeneous deposits that include layers of high-
permeability material and low-permeability material and that offset from their
depositional plane ¨ are one such example. INS typically consist of repeating
cycles of interbedded sand-dominated layers and mud-dominated layers. Those
skilled in the art will recognize that mud-dominated layers of a wide variety
of
thicknesses are known, and that typical mud-dominated layers have thicknesses
between about 1 cm and about 50 cm (often between about 1 cm and about 10
cm). Likewise, those skilled in the art will recognize that sand-dominated
layers of
a wide variety of thicknesses are known, and that typical sand-dominated
layers
have thicknesses between about 1 cm and about 1 m (often between about 5 cm
and about 50 cm). Geophysical data suggests that, in at least some instances,
INS result from lateral growth of large-scale bedforms such as point bars. INS
are
typically classified based on their volume percentage of mud-dominated
material.
IHS comprising greater than 30 vol.% mud-based materials are said to be mud-
dominated INS, and INS comprising less than 30 vol.% are said to be sand-
dominated IHS.
[0081] The interface between two or more lithological regions of
different
permeabilities is generally referred to as a lithofacies surface. Lithofacies
surfaces
can be identified by a variety of techniques known to those skilled in the
art. In
various embodiments, a hydrocarbon-bearing zone may comprise a low
permeability zone in form of a consolidated rock barrier or another type of
substantially-impermeable zone. Consolidated rock barriers may comprise
clastic
sedimentary rock (for example, a shale barrier), claystone, siltstone,
mudstone, or
combinations thereof. In the context of the present disclosure, a
substantially-
37
Date Recue/Date Received 2022-08-11
impermeable zone is one which permits limited or no transmission of steam,
hydrocarbons, or combinations thereof. Various other facies present within a
hydrocarbon-bearing formation may have a permeabilities from 100 mD to 1,000
mD (various arrangements of sand and mud clasts or breccia), and mud-
dominated facies can have permeabilities below 100 mD and often below 10 mD.
SAGD and SAPs can become impacted when facies below 1,000 mD are present
within the hydrocarbon-bearing formation, and can become considerably impacted
when facies below 100mD are present.
[0082] Subterranean formations, such as subterranean hydrocarbon-
bearing formations, can be characterized by their in situ stress fields, and
it is
known that the orientations of fracture networks are generally dictated by in
situ
stress fields. In situ stress fields are typically defined by three principal
stresses:
a vertical stress and two orthogonal horizontal stresses. Each of the three
principle
stresses has a magnitude, and the principle stress with the greatest magnitude
is
commonly referred to as the maximum principle stress. Likewise, the principle
stress with the smallest magnitude is commonly referred to as the minimum
principle stress. Basic geo-mechanical principles dictate that a fracture will
propagate along a path of least resistance and that the path of least
resistance
tends to be substantially perpendicular to the direction of the minimum
principal
stress.
[0083] In non-shallow formations, the vertical stress is typically
the
maximum principle stress (due to the considerable mass overlying the
subterranean formation), and the minimum principle stress is typically a
horizontal
stress (i.e. a minimum-horizontal stress). Consequently, in non-shallow
formations, fractures tend to form fracture networks that are that are
substantially-
vertically oriented. Fractures that are substantially-horizontally oriented
may also
be formed in non-shallow formations ¨ particularly in instances where bottom-
hole
testing pressures are substantially greater in magnitude than the vertical
stress.
[0084] In shallow formations, the vertical stress may be the
minimum
principles stress. As such, fractures in shallow formations may form fracture
networks that are substantially horizontally oriented. Alternatively, in
shallow
38
Date Recue/Date Received 2022-08-11
formations, the magnitude of the vertical stress may be substantially equal to
that
of the minimum-horizontal stress. In such cases, fractures tend to form
networks
of both vertically-oriented and horizontally-oriented fractures.
[0085] In the context of the present disclosure, the complexity of
a fracture
network is defined by the number of interconnected fractures per unit volume.
In
other words, fracture-network complexity is synonyms with fracture-network
density in the present disclosure. The complexity of a fracture network can be
quantified by a variety of techniques known to those skilled in the art. In
some
instances, the fractures of a fracture network may extend in alternative
directions
or along alternative planes. In the context of the present disclosure, the
geometry
of a fracture can be defined by a variety of metrics including but not limited
to the
physical dimensions of the fracture and the amount of proppant that the
fracture
contains. In the context of the present disclosure, optimizing fracture
geometry,
fracture complexity, or a combination thereof may be characterized by
production
metrics (simulated or field-based) from the recovery hydrocarbons during or
after
the development of the fracture network.
10086] In the context of the present disclosure, fractures may be
characterised by their orientations. A fracture may be considered to be
"vertically
oriented", "substantially vertically oriented", "vertical", or "substantially
vertical" if it
has a dimension that generally aligns with a vertical stress. Likewise, a
fracture
may be considered to be "horizontally oriented", "substantially horizontally
oriented", "horizontal", or "substantially horizontal" if it has a dimension
that
generally aligns with a horizontal stress plane. In the context of the present
disclosure, fractures may also be characterized by their orientation with
respect to
the wellbore section from which they originate or from a wellbore in proximity
to
the fracture network. In the case of a longitudinal wellbore section that is
disposed
about a longitudinal wellbore axis, a fracture may be said to be "transverse"
or
"substantially transverse" if it is substantially orthogonal to the
longitudinal
wellbore axis. Likewise, a fracture may be said to be "longitudinal" "or
substantially-longitudinal" if it is not substantially orthogonal to the
longitudinal
wellbore axis. Accordingly, a fracture network originating from a longitudinal
39
Date Regue/Date Received 2022-08-11
wellbore section can be characterized as comprising substantially-transverse-
vertical fractures, substantially-longitudinal-vertical fractures,
substantially-
horizontal fractures, or a combination thereof. Those skilled in the art will
recognize that the forgoing are terms of convenience and that induced
fractures
often defy such simple characterizations. Accordingly, the orientation of a
fracture
or a fracture network should not be considered to alter the scope of the
present
disclosure.
[0087] In the context of the present disclosure, a stimulant fluid
is "a fluid
that is suitable for inducing fractures in a formation and/or for carrying a
propping
agent into a fracture". Stimulant fluids may comprise additives and/or
propping
agents. Stimulant fluids are typically characterized by their viscosity,
density, and
other fluid characteristics. Categories of simulant fluids include but are not
limited
to, water-based, foam-based, oil-based, acid-based, alcohol-based, emulsion-
based or other-fluid-based stimulant fluids. Categories of additives include
but are
not limited to friction-reducing additives, fluid-loss-preventing additives,
surfactant
additives, clay control additives, and chemical additives. In the context of
the
present disclosure, "a propping agent" is a solid material that is suitable
for
substantially maintaining the fracture geometry of a fracture. Categories of
propping agents include but are not limited to natural propping agents (such
as
frac-sand), synthetic propping agents (such as ceramic proppants), modified
propping agents (such as resin-coated proppants), or combinations thereof.
[0088] In the context of the present disclosure, hydrocarbon-
bearing
formations may be characterized by their in situ stress fields. In situ stress
fields
may be modelled based on field data including but not limited to image-log
data,
core data, acoustic data, diagnostic-fracturing data, seismic data, and
combinations thereof. The modelling may define a vertical stress and two
horizontal stresses. In some instances, the vertical stress may be angularly
off-set
from a strictly vertical axis, and/or the two horizontal stresses may be
angularly
off-set from the horizontal plane.
[0089] In the context of the present disclosure, two or more wells are
"substantially vertically coplanar" when they are substantially disposed about
axes
Date Recue/Date Received 2022-08-11
that generally fall along a single plane that is oriented substantially
vertically. A
typical SAGD well pair is an example of a well pair that is substantially
vertically
coplanar. Those skilled in the art will appreciate that most wells are not
drilled in
a strictly linear fashion, and that wells may still be substantially
vertically coplanar
in spite of typical directional drilling variations.
[0090] As used herein, the term "about" refers to an approximately
+/-10%
variation from a given value. It is to be understood that such a variation is
always
included in any given value provided herein, whether or not it is specifically
referred to.
Processes and methods of the present disclosure
[0091] Developing a fracture network in a hydrocarbon bearing
formation
allows for increased hydrocarbon-bearing-formation permeability. The fracture
network may comprise horizontal fractures, transverse-vertical fractures,
longitudinal-vertical fractures, or a combination thereof. In the context of
the
present disclosure, it was found that processes for developing such fracture
networks in such hydrocarbon-bearing formations benefit from offsetting at
least
one substantially-longitudinal wellbore section of at least one well relative
to: (i) a
substantially-longitudinal wellbore section of a second well; (ii) a plane
defined by
the maximum horizontal stress and the minimum horizontal stress; (iii) a
lithofacies
surface; or (iv) a combination thereof. Offsetting the at least one
substantially-
longitudinal wellbore section in such a way allows for modification of
fracture
geometry, fracture complexity, or a combination thereof within the fracture
network. As it pertains to methods of recovering hydrocarbons and/or processes
for enhancing hydrocarbon recovery, it was found that offsetting the at least
one
substantially-longitudinal wellbore section in such a way allows for
modification of
heat transfer within the formation, hydrocarbon-flow rate within the
formation,
hydrocarbon capture from the formation, or a combination thereof.
[0092] Select embodiments of the present disclosure relate to
generally
shallow hydrocarbon-bearing formations. In the context of the present
disclosure,
shallow hydrocarbon-bearing formations are those in which the vertical stress
is
41
Date Recue/Date Received 2022-08-11
less than or substantially equal to the maximum-horizontal stress. By way of
non-
limiting example, shallow hydrocarbon-bearing formations may reside at depths
of
less than about 600 m below the surface. Fracture networks developed in
shallow
formations by processes in accordance with the present disclosure may comprise
substantially-horizontal fractures, substantially-transverse-vertical
fractures,
substantially-longitudinal-vertical fractures, or a combination thereof. In
particular,
fracture networks developed in shallow formations by processes in accordance
with the present disclosure may comprises substantially-horizontal fractures
and:
(i) substantially-transverse-vertical fractures, (ii) substantially-
longitudinal-vertical
fractures, or (iii) a combination of (i) and (ii). Such fractures may
intersect at a
variety of angles. By way of non-limiting example, a substantially-horizontal
fracture may intersect a substantially-transverse-vertical fracture or a
substantially-longitudinal-vertical fractures at an angle between 0 and about
180
(preferably between about 45 and about 135 , in particular between about 80
and about 100 ). Fractures that intersect at angles between about 80 and
about
100 are referred to herein as "T-shaped fractures" or "substantially T-shaped
fractures". Processes in accordance with the present disclosure that develop T-
shaped fractures may allow for modified heat transfer within the formation,
modified hydrocarbon flow-rate within the formation, modified hydrocarbon
capture from the formation, or a combination thereof during methods of
hydrocarbon recovery in accordance with present disclosure and/or processes
for
enhanced hydrocarbon recovery in accordance with present disclosure.
[0093] Select embodiments of the present disclosure relate to non-
shallow
hydrocarbon-bearing formations. In the context of the present disclosure, non-
shallow hydrocarbon-bearing formations are those in which the vertical stress
is
greater than the maximum-horizontal stress. By way of non-limiting example,
non-
shallow hydrocarbon-bearing formations may reside at depths greater than about
600 m below the surface. Fracture networks developed in non-shallow formations
by processes in accordance with the present disclosure may comprises
substantially-horizontal fractures, substantially-transverse-vertical
fractures,
substantially-longitudinal-vertical fractures, or a combination thereof. In
particular,
fracture networks developed in non-shallow formations by processes in
42
Date Recue/Date Received 2022-08-11
accordance with the present disclosure may comprise substantially-transverse-
vertical fractures and substantially-longitudinal-vertical fractures. Such
fractures
may intersect at a variety of angles. By way of non-limiting example, a
substantially-transverse-vertical fracture may intersect a substantially-
longitudinal-vertical fracture at an angle between 0 and about 180
(preferably
between about 450 and about 135 , in particular between about 80 and about
1000). Likewise, a substantially-horizontal fracture may intersect a
substantially-
transverse-vertical fracture, a substantially-longitudinal-vertical fracture,
or a
combination thereof at an angle between 0 and about 180 (preferably between
about 45 and about 135 , in particular between about 80 and about 100 ).
Fractures that intersect at angles between about 80 and about 100 are
referred
to herein as "T-shaped fractures" or "substantially T-shaped fractures".
Processes
in accordance with the present disclosure that develop T-shaped fractures may
allow for modified heat transfer within the formation, modified hydrocarbon
flow-
rate within the formation, modified hydrocarbon capture from the formation or
a
combination thereof during methods of hydrocarbon recovery in accordance with
present disclosure and/or processes for enhanced hydrocarbon recovery in
accordance with present disclosure.
[0094] Select embodiments of the present disclosure relate to multi-
zone
hydrocarbon-bearing formations. Such multi-zone hydrocarbon-bearing
formations may be shallow, multi-zone hydrocarbon-bearing formations, or they
may be non-shallow, multi-zone hydrocarbon-bearing formations. In the context
of
the present disclosure a "zone" or "hydrocarbon-bearing zone" in a reservoir
is
merely an arbitrarily defined volume of the reservoir, typically characterised
by
some predominant property. A zone may or may not contain hydrocarbons. A zone
may be defined by its permeability. Multi-zone hydrocarbon-bearing formations
may comprise unconsolidated oil sands, and/or they may comprise shales (e.g.
hydrocarbon-bearing shales).
[0095] In the context of the present disclosure, a multi-zone
hydrocarbon-
bearing formation is one that comprises a lithofacies surface. The term
"lithofacies
surface" defines the interface between two or more lithological regions of
different
43
Date Recue/Date Received 2022-08-11
permeabilities. Lithofacies surfaces can be identified by a variety of
techniques
known to those skilled in the art. By way of non-limiting example, an
interface
between a low-permeability zone and a high-permeability zone may form a
lithofacies surface. Lithofacies surfaces may be heterogeneous or homogeneous.
[0096] Select embodiments of the present disclosure relate to multi-zone
hydrocarbon-bearing formations, wherein the lithofacies surface is one in a
plurality of inclined heterolithic strata. Select embodiments relate to multi-
zone
hydrocarbon-bearing formations that are penetrated by a longitudinal wellbore
section of at least one well, wherein the longitudinal wellbore section
intersects a
lithofacies surface at an angle of between about 0 and about 180 . In select
embodiments, the lithofacies surface may be an interface between a first-
hydrocarbon bearing zone and a second hydrocarbon bearing zone. In select
embodiments, the first hydrocarbon bearing zone and the second hydrocarbon
bearing zone may have different permeabilities. In select embodiments, at
least
one of the first hydrocarbon-bearing zone and the second hydrocarbon-bearing
zone may comprise an unconsolidated oil sand. In select embodiments, at least
one of the first hydrocarbon-bearing zone and the second hydrocarbon-bearing
zone comprises a consolidated rock barrier.
[0097] Select embodiments of the present disclosure relate to
single-zone
hydrocarbon-bearing formations. Such single-zone hydrocarbon-bearing
formations may be shallow, single-zone hydrocarbon-bearing formations or they
may be non-shallow, single-zone hydrocarbon-bearing formations. In the context
of the present disclosure, a single-zone hydrocarbon-bearing formation is one
that
does not comprise a lithofacies surface in proximity to a fracture network.
[0098] In select embodiments of the present disclosure, a single-zone
hydrocarbon-bearing formation may comprise an unconsolidated oil sand or shale
(e.g. a hydrocarbon-bearing shale). In select embodiments, a single-zone
hydrocarbon-bearing formation may be penetrated by a longitudinal wellbore
section of at least one well. The longitudinal wellbore section may be
disposed
about an axis that is substantially coplanar with the minimum-horizontal
stress of
the formation. Alternatively, the longitudinal wellbore section may be
disposed
44
Date Recue/Date Received 2022-08-11
about an axis that is substantially coplanar with the maximum-horizontal
stress of
the formation.
10099] In the context of the present disclosure, hydrocarbon-
bearing
formations may be: (i) shallow, single-zone hydrocarbon-bearing formations;
(ii)
shallow, multi-zone hydrocarbon-bearing formations; (iii) non-shallow, single-
zone
hydrocarbon-bearing formations; or (iv) non-shallow, multi-zone hydrocarbon-
bearing formations. Such formations may be penetrated by wells in a variety of
well configurations in accordance with processes and methods of the present
disclosure.
[00100] In select embodiments of the present disclosure, a hydrocarbon-
bearing formation may be penetrated by a well pair comprising: (i) a first
well
having a vertical wellbore section and a longitudinal wellbore section, and
(ii) a
second well having a vertical wellbore section and a longitudinal wellbore
section.
the longitudinal wellbore section of the first well may be: (a) laterally
displaced
from, and (b) angularly offset from, the longitudinal wellbore section of the
second
well such that the longitudinal wellbore section of the first well and the
longitudinal
wellbore of the second well form a crossing pattern as viewed from a
longitudinal
elevation view. In select embodiments, the crossing pattern may consist of two
acute angles that are 900 or less and two obtuse angles that are 900 or
between
900 and about 180 . In select embodiments, the two acute angles may be between
about 30 and about 60 . In select embodiments, the two obtuse angles may be
between about 120 and about 150 .
100101] In select embodiments of the present disclosure, the
longitudinal
wellbore section of at least one of the first well and the second well may be
angularly offset from a plane defined by the maximum-horizontal stress and the
minimum-horizontal stress. For example, the longitudinal wellbore section of
at
least one of the first well and the second well may be angularly offset from
the
plane defined by the maximum-horizontal stress and the minimum-horizontal
stress by between about 0 and about 90 (such as between about 35 and
about
55 ). In select embodiments, the longitudinal wellbore section of at least
one of
the first well and the second well may be angularly offset from a lithofacies
surface
Date Recue/Date Received 2022-08-11
within the hydrocarbon-bearing formation. For example, the longitudinal
wellbore
section of at least one of the first well and the second well may be angularly
offset
from the lithofacies surface by between about 0 and about 180 (such as
between about 45 and about 135 0).
[00102] In select embodiments of the present disclosure, the first well may
comprise a plurality of toe-up wells and the second well may comprise a
plurality
of toe-down wells. In select embodiments, the plurality of toe-up wells and
the
plurality of toe-down wells may be arranged in an alternating configuration.
In
select embodiments, the first well and the second well may comprise a well
pair
that is one of a plurality of well pairs. Such well pairs may originate from
one well
pad, or they may originate from a plurality of well pads.
[00103] In select embodiments of the present disclosure, the
vertical
wellbore section of the first well may be laterally displaced and
longitudinally
displaced from the vertical wellbore section of the second well.
[00104] In select embodiments of the present disclosure, a hydrocarbon-
bearing formation may be penetrated by a well pair comprising: (i) a first
well
having a vertical wellbore section and a longitudinal wellbore section, and
(ii) a
second well having a vertical wellbore section and a longitudinal wellbore
section.
In select embodiments, the longitudinal wellbore section of at least one of
the first
well and the second well may be angularly offset from a plane defined by the
maximum-horizontal stress and the minimum-horizontal stress. For example, the
longitudinal wellbore section of at least one of the first well and the second
well
may be angularly offset from the plane defined by the maximum-horizontal
stress
and the minimum-horizontal stress by between about 0 and about 90 (such as
between about 35 and about 55 0). In select embodiments, the longitudinal
wellbore section of at least one of the first well and the second well may be
angularly offset from a lithofacies surface within the hydrocarbon-bearing
formation. For example, the longitudinal wellbore section of at least one of
the first
well and the second well may be angularly offset from the lithofacies surface
by
between about 0 and about 180 (such as between about 45 and about 135
0).
46
Date Recue/Date Received 2022-08-11
100105] In select embodiments of the present disclosure, the
longitudinal
wellbore section of the first well may be laterally displaced from the
longitudinal
wellbore section of the second well. In select embodiments, the first well and
the
second well may comprise a well pair that is one of a plurality of well pairs
originating from one or more well pads. In select embodiments, the
longitudinal
wellbore section of the first well and the longitudinal section of the second
well
may be vertically displaced and coplanar.
[00106] In select embodiments of the present disclosure, a
hydrocarbon-
bearing formation may be penetrated by a single well having a longitudinal
wellbore section. In select embodiments, the longitudinal wellbore section may
be
angularly offset from a plane defined by the maximum-horizontal stress and the
minimum-horizontal stress. For example, the longitudinal wellbore section of
the
well may be angularly offset from the plane defined by the maximum-horizontal
stress and the minimum-horizontal stress by between about 0 and about 90
(such as between about 35 and about 55 ). In select embodiments, the
longitudinal wellbore section may be angularly offset from a lithofacies
surface
within the hydrocarbon-bearing formation. For example, the longitudinal
wellbore
section of the well may be angularly offset from the lithofacies surface by
between
about 0 and about 180 (such as between about 35 and about 55 ).
[00107] In select embodiments of the present disclosure, the longitudinal
wellbore section may be in a toe-up configuration. In select embodiments, the
longitudinal wellbore section may be in a toe-down configuration. In select
embodiments, the longitudinal wellbore section may be provided as an
additional
leg to an existing well. The existing well may be an existing SAGD well pair.
In
select embodiments the longitudinal wellbore section may be provided in an
inter-
well region between an existing set of wells (such as in an inter-well region
between an existing pair of SAGD well pairs).
[00108] In select embodiments of the present disclosure, a
hydrocarbon-
bearing formation may be penetrated by a well pair comprising: (i) a first
well
having a vertical wellbore section and a horizontal wellbore section, and (ii)
a
second well having a vertical wellbore section and a horizontal wellbore
section.
47
Date Recue/Date Received 2022-08-11
In select embodiments, at least one of the horizontal wellbore section of the
first
well and the horizontal section of the second well may be angularly offset
from a
lithofacies surface. For example, the longitudinal wellbore section of at
least one
of the first well and the second well may be angularly offset from the
lithofacies
surface by between about 0 and about 180 (such as between about 45 and
about 1350)
[00109] In select embodiments of the present disclosure, the
horizontal
wellbore section of the first well and the horizontal section of the second
well may
be vertically displaced and coplanar.
[00110] Select embodiments of the present disclosure relate to processes
for developing fracture networks in hydrocarbon-bearing formations. Such
embodiments utilize one or more wells in a well configuration that modifies
fracture
geometry and fracture complexity within the fracture network. Such hydrocarbon-
bearing formations may be: (i) shallow, single-zone hydrocarbon-bearing
formations; (ii) shallow, multi-zone hydrocarbon-bearing formations; (iii) non-
shallow, single-zone hydrocarbon-bearing formations; or (iv) non-shallow,
multi-
zone hydrocarbon-bearing formations. Such hydrocarbon-bearing formations may
be at native reservoir temperature or within about 20 C of native reservoir
temperature prior to the injecting of the stimulant fluid. Such hydrocarbon-
bearing
formations may also be at higher temperatures, as processes for developing
fracture networks in accordance with the present disclosure may be employed
after, concurrent with, or in proximity to thermal recovery processes. Those
skilled
in the art will recognize that thermal recovery processes are associated with
temperatures up to about 260 C (e.g. steam injection) which can increase
formations more than 20 C above the native reservoir temperature.
[00111] Processes for developing fracture networks in accordance
with the
present disclosure may comprise injecting a stimulant fluid comprising a
propping
agent into the formation. In select embodiments, the stimulant fluid may be a
water-based stimulant fluid, a foam-based stimulant fluid, an oil-based
stimulant
fluid, an acid-based stimulant fluid, an alcohol-based stimulant fluid, an
emulsion-
based stimulant fluid or a combination thereof. In select embodiments, the
48
Date Regue/Date Received 2022-08-11
propping agent may be a natural propping agent (such as frac-sand), a
synthetic
propping agent (such as a ceramic proppants), a modified propping agent (such
as a resin-coated proppant), or a combination thereof. In select embodiments,
the
stimulant fluid may further comprise an additive. The additive may be a
friction-
reducing additive, a fluid-loss-preventing additive, a surfactant additive, a
clay
control additive, a chemical additive, or a combination thereof. Those skilled
in the
art will recognize stimulant fluids and/or propping agents that are not
explicitly set
out herein, but that fall within the scope of the present disclosure.
[00112] Select embodiments of the present disclosure relate to
methods for
recovering hydrocarbons from hydrocarbon-bearing formations. Such
embodiments utilize one or more wells in a well configuration that is selected
to
modify heat transfer within the formation, hydrocarbon-flow rate within the
formation, hydrocarbon capture from the formation, or combinations thereof.
Such
hydrocarbon-bearing formations may be: (i) shallow, single-zone hydrocarbon-
bearing formations; (ii) shallow, multi-zone hydrocarbon-bearing formations;
(iii)
non-shallow, single-zone hydrocarbon-bearing formations; or (iv) non-shallow,
multi-zone hydrocarbon-bearing formations. Such hydrocarbon-bearing
formations may be at native reservoir temperature prior to application of a
thermal
process or within about 20 C of native reservoir temperature prior to
application
of a thermal process.
[00113] Methods for recovering hydrocarbons in accordance with the
present disclosure may comprise injecting a stimulant fluid comprising a
propping
agent into the formation. In select embodiments, the stimulant fluid may be a
water-based stimulant fluid, a foam-based stimulant fluid, an oil-based
stimulant
fluid, an acid-based stimulant fluid, an alcohol-based stimulant fluid, an
emulsion-
based stimulant fluid or a combination thereof. In select embodiments, the
propping agent may be a natural propping agent (such as frac-sand), a
synthetic
propping agent (such as a ceramic proppants), a modified propping agent (such
as a resin-coated proppant), or a combination thereof. In select embodiments,
the
stimulant fluid may further comprise an additive. The additive may be a
friction-
reducing additive, a fluid-loss-preventing additive, a surfactant additive, a
clay
49
Date Recue/Date Received 2022-08-11
control additive, a chemical additive, or a combination thereof. In select
embodiments, hydrocarbons may have been recovered from the hydrocarbon-
bearing formation prior to the injecting of the stimulant fluid. Those skilled
in the
art will recognize additives that are not explicitly set out herein, but that
fall within
the scope of the present disclosure.
[00114] Methods for recovering hydrocarbons in accordance with the
present disclosure may further comprise modulating the mobility of
hydrocarbons
within hydrocarbon-bearing formation. The modulating of the mobility of the
hydrocarbons may precede ¨ or be concurrent with ¨ the injecting of the
stimulant
fluid. Alternatively, the injecting of the stimulant fluid may precede the
modulating
of the mobility of the hydrocarbons.
[00115] In select embodiments of the present disclosure, modulating
the
mobility of the hydrocarbons may comprise injecting an injecting fluid into
the
formation. The injection fluid may be steam, solvent, or a combination
thereof. In
select embodiments, the solvent may be a Cl-C12 hydrocarbon. In select
embodiments, the recovering of the hydrocarbons from the hydrocarbon-bearing
formation may comprise a gravity dominated recovery process. In select
embodiments, the recovering of the hydrocarbons from the hydrocarbon-bearing
formation may comprise SAGD, CSS, SAP, or a solvent-based process.
[00116] In select embodiments of the present disclosure, the injecting of
the
stimulant fluid may precede the modulating of the mobility of the
hydrocarbons. In
select embodiments, the modulating of the mobility of the hydrocarbons may
precede the injecting of the stimulant fluid..
[00117] Select embodiments of the present disclosure relate to
processes
for enhancing hydrocarbon recovery from hydrocarbon-bearing formations. Such
embodiments utilize one or more wells in a well configuration that is selected
to
modify heat transfer within the formation, hydrocarbon-flow rate within the
formation, hydrocarbon capture from the formation, or a combination thereof.
Such
hydrocarbon-bearing formations may be: (i) shallow, single-zone hydrocarbon-
bearing formations; (ii) shallow, multi-zone hydrocarbon-bearing formations;
(iii)
Date Regue/Date Received 2022-08-11
non-shallow, single-zone hydrocarbon-bearing formations; or (iv) non-shallow,
multi-zone hydrocarbon-bearing formations. Such hydrocarbon-bearing
formations may be at native reservoir temperature or within about 20 C of
native
reservoir temperature prior to the injecting of the stimulant fluid.
[00118] Processes for enhancing hydrocarbon recovery in accordance with
the present disclosure may comprise injecting a stimulant fluid comprising a
propping agent into the formation. In select embodiments, the stimulant fluid
may
be a water-based stimulant fluid, a foam-based stimulant fluid, an oil-based
stimulant fluid, an acid-based stimulant fluid, an alcohol-based stimulant
fluid, an
emulsion-based stimulant fluid or a combination thereof. In select
embodiments,
the propping agent may be a natural propping agent (such as frac-sand), a
synthetic propping agent (such as a ceramic proppants), a modified propping
agent (such as a resin-coated proppant), or a combination thereof. In select
embodiments, the stimulant fluid may further comprise an additive. The
additive
may be a friction-reducing additive, a fluid-loss-preventing additive, a
surfactant
additive, a clay control additive, a chemical additive, or a combination
thereof. In
select embodiments, hydrocarbons may have been recovered from the
hydrocarbon-bearing formation prior to the injecting of the stimulant fluid.
[00119] Embodiments of the present disclosure will now be described
by
reference to FIGS. 1 ¨ 13.
[00120] FIG. 1 shows a schematic rectangular-prismatic section of a
hydrocarbon-bearing formation 100 that comprises a fracture network
originating
from a longitudinal wellbore section 102. The longitudinal wellbore section
102 is
disposed about a longitudinal wellbore axis 104. The rectangular-prismatic
section
is defined in part by a pair of transverse-vertical planes 106 / 106' that
intersect
the longitudinal wellbore axis 104. The rectangular-prismatic section is
further
defined by a pair of horizontal planes 108 /108' that are orthogonal to
transverse-
vertical planes 106 / 106' and that are parallel to the longitudinal wellbore
axis 104.
The rectangular-prismatic section is further defined by a pair of longitudinal-
vertical planes 110 / 110' that are orthogonal to both the transverse-vertical
planes
106 / 106' and the horizontal planes 108 / 108'. The fracture network
comprises a
51
Date Recue/Date Received 2022-08-11
transverse-vertical fracture 112 that is substantially parallel to the
transverse-
vertical planes 106/ 106'. The network also comprises a horizontal fracture
114
that is substantially parallel to the horizontal planes 108 / 108'. The
fracture
network also comprises a longitudinal-vertical fracture 116 that is
substantially
parallel to the longitudinal-vertical planes 110 / 110'.
[00121] FIG. 2A ¨ FIG. 2H provide schematic representations of a
series of
well configurations in various lithological environments. The well
configurations
may be suitable for developing fracture networks in hydrocarbon-bearing
formations by processes according to the present disclosure. The well
configurations may also be suitable for recovering hydrocarbons from
hydrocarbon-bearing formations by methods according to the present disclosure.
The well configurations may also be suitable for enhancing hydrocarbon
recovery
from hydrocarbon-bearing formations by processes according to the present
disclosure.
[00122] FIG. 2A shows a schematic perspective view of a hydrocarbon-
bearing formation 200 that comprises a first high-permeability zone 202, a
second
high-permeability zone 204, and a low-permeability zone 206 interlayered
therebetween. The low-permeability zone 206 may be substantially impermeable
to steam, hydrocarbons, or a combination thereof. The interface between the
first
high-permeability zone 202 and the low-permeability zone 206 defines a first
lithofacies surface 208. The interface between the second high-permeability
zone
204 and the low-permeability zone 206 defines a second lithofacies surface
210.
The first high-permeability zone 202 may have substantially the same
permeability
of the second high-permeability zone 204. Alternatively, the permeabilities of
the
first high-permeability zone 202 and the second high-permeability zone 204 may
be different. The hydrocarbon-bearing formation 200 is penetrated by a first
well
212 and a second well 214 which is laterally displaced from the first well
212. A
fracture network may be induced from the first well 212, the second well 214,
or a
combination thereof. Accordingly, a stimulant fluid comprising a proppant may
be
injected from the first well 212, the second well 214, or a combination
thereof.
Moreover, the first well 212, the second well 214, or a combination thereof
may
52
Date Recue/Date Received 2022-08-11
be equipped as an injection well, a production well, or a combination thereof.
The
first well 212 has a vertical wellbore section 216 and a longitudinal wellbore
section
218. The second well 214 has a vertical wellbore section 220 and a
longitudinal
wellbore section 222. The longitudinal wellbore section 218 of the first well
212 is
oriented in a toe-up configuration, and the longitudinal wellbore section 222
of the
second well 214 is oriented in a toe-down configuration. Accordingly, the
longitudinal wellbore section 218 of the first well 212 is angularly offset
from the
longitudinal wellbore section 222 of the second well 214 such that they form a
crossing pattern when viewed from a longitudinal elevation view. The
longitudinal
wellbore sections 218 / 222 are also angularly offset from at least a part of
the
lithofacies surfaces 208 /210.
[00123] FIG. 2B shows a schematic perspective view of a hydrocarbon-
bearing formation 224 that comprises a series of low-permeability zones 226
that
are interlayered with a series of high-permeability zones 228. One or more of
the
low-permeability zones 226 may be substantially impermeable to steam,
hydrocarbons, or a combination thereof. Each of the low-permeability zones 226
may have substantially the same permeability. Alternatively, two or more of
the
low-permeability zones 226 may have different permeabilities. Likewise, each
of
the high-permeability zones 228 may have substantially the same permeability.
Alternatively, two or more of the high-permeability zones 228 may have
different
permeabilities. The interfaces between the low-permeability zones 226 and the
high-permeability zones 228 define a series of lithofacies surfaces 230. The
low-
permeability zones 226, the high-permeability zones 228, and the lithofacies
surfaces 230 are inclined relative their depositional plane such that they
form an
inclined heterolithic strata (IHS). To provide greater clarity, the dimensions
of at
least some of the low-permeability zones 226 and/or the high-permeability
zones
228 are shown at exaggerated scale in FIG. 2B. Those skilled in the art will
recognize that INS comprising low-permeability zones of a wide variety of
thicknesses are known, and that typical IHS have low-permeability zones with
thicknesses between about 1 cm and about 50 cm (often between about 1 cm and
about 10 cm). Likewise, those skilled in the art will recognize that INS
comprising
high-permeability zones of a wide variety of thicknesses are known, and that
53
Date Recue/Date Received 2022-08-11
typical IHS have high-permeability zones with thicknesses between about 1 cm
and about 1 m (often between about 5 cm and about 50 cm). The hydrocarbon-
bearing formation 224 is penetrated by a first well 232 and a second well 234
which is substantially vertically coplanar with the first well 232. A fracture
network
may be induced from the first well 232, the second well 234, or a combination
thereof. Accordingly, a stimulant fluid comprising a proppant may be injected
from
the first well 232, the second well 234, or a combination thereof. Moreover,
the
first well 232 may be equipped as an injection well, and the second well 234
may
be equipped as a production well. The first well 232 has a vertical wellbore
section
236 and a longitudinal wellbore section 238. The second well 234 has a
vertical
wellbore section 240 and a longitudinal wellbore section 242. The longitudinal
wellbore section 238 of the first well 232 is oriented in a toe-up
configuration, and
the longitudinal wellbore section 242 of the second well 234 is oriented in a
horizontal configuration. Accordingly, the longitudinal wellbore section 238
of the
first well 232 is angularly offset from the longitudinal wellbore section 242
of the
second well 234. The longitudinal wellbore sections 238 / 242 are also
angularly
offset from at least a part of the lithofacies surfaces 230.
[00124] FIG. 2C shows a schematic perspective view of a hydrocarbon-
bearing formation 244 that comprises a high-permeability zone 246. The high-
permeability zone 246 has a stress field defined by a vertical stress 248, a
maximum-horizontal stress 250, and a minimum-horizontal stress 252. The
stresses 246/248/252 are schematic in that they do not represent particular
(or
relative) magnitudes. The hydrocarbon-bearing formation 244 is penetrated by a
first well 254 and a second well 256. A fracture network may be induced from
the
first well 254, the second well 256, or a combination thereof. Accordingly, a
stimulant fluid comprising a proppant may be injected from the first well 254,
the
second well 256, or a combination thereof. Moreover, the first well 254 may be
equipped as an injection well, and the second well 256 may be equipped as a
production well. The first well 254 is substantially vertically coplanar with
the
second well 256. The first well 254 has a vertical wellbore section 258 and a
longitudinal wellbore section 260. The second well 256 has a vertical wellbore
section 262 and a longitudinal wellbore section 264. The longitudinal wellbore
54
Date Regue/Date Received 2022-08-11
section 260 of the first well 254 is oriented in a toe-up configuration, and
the
longitudinal wellbore section 264 of the second well 256 is oriented in a
horizontal
configuration. Accordingly, the longitudinal wellbore section 260 of the first
well
254 is angularly offset from the longitudinal wellbore section 264 of the
second
well 256. The longitudinal wellbore section 260 of the first well 254 is also
angularly
offset from a plane defined by the maximum-horizontal stress 250 and the
minimum horizontal stress 252.
[00125] FIG. 2D shows a schematic perspective view of a hydrocarbon-
bearing formation 268 that comprises a series of low-permeability zones 270
that
are interlayered by a series of high-permeability zones 272. One or more of
the
low-permeability zones 270 may be substantially impermeable to steam,
hydrocarbons, or a combination thereof. Each of the low-permeability zones 270
may have substantially the same permeability. Alternatively, two or more of
the
low-permeability zones 270 may have different permeabilities. Likewise, each
of
the high-permeability zones 272 may have substantially the same permeability.
Alternatively, two or more of the high-permeability zones 272 may have
different
permeabilities. The interfaces between the low-permeability zones 270 and the
high-permeability zones 272 define a series of lithofacies surfaces 274. Some
of
the low-permeability zones 270, the high-permeability zones 272, and the
lithofacies surfaces 274 are inclined relative their depositional plane such
that they
form an IHS. To provide greater clarity, the dimensions of at least some of
the low-
permeability zones 270 and the high-permeability zones 272 are shown at
exaggerated scale in FIG. 2D. Those skilled in the art will recognize that IHS
comprising low-permeability zones of a wide variety of thicknesses are known,
and that typical IHS have low-permeability zones with thicknesses between
about
1 cm and about 50 cm (often between about 1 cm and about 10 cm). Likewise,
those skilled in the art will recognize that INS comprising high-permeability
zones
of a wide variety of thicknesses are known, and that typical IHS have high-
permeability zones with thicknesses between about 1 cm and about 1 m (often
between about 5 cm and about 50 cm). The hydrocarbon-bearing formation 268
further comprises a high-permeability zone 276 which underlies the IHS. The
hydrocarbon-bearing formation 268 is penetrated by a first well 278 and a
second
Date Recue/Date Received 2022-08-11
well 280 which is substantially vertically coplanar with the first well 278. A
fracture
network may be induced from the first well 278, the second well 280, or a
combination thereof. Accordingly, a stimulant fluid comprising a proppant may
be
injected from the first well 278, the second well 280, or a combination
thereof.
Moreover, the first well 278 may be equipped as an injection well, and the
second
well 280 may be equipped as a production well. The first well 278 has a
vertical
wellbore section 282 and a longitudinal wellbore section 284. The second well
280
has a vertical wellbore section 286 and a longitudinal wellbore section 288.
The
longitudinal wellbore section 284 of the first well 278 is oriented in a toe-
up
configuration, and the longitudinal wellbore section 288 of the second well
280 is
oriented in a horizontal configuration. Accordingly, the longitudinal wellbore
section 284 of the first well 278 is angularly offset from the longitudinal
wellbore
section 288 of the second well 280. The longitudinal wellbore section 284 of
the
first well 278 penetrates the IHS and is angularly offset from at least a part
of the
lithofacies surfaces 274.
[00126] FIG. 2E shows a schematic perspective view of a hydrocarbon-
bearing formation 290 that comprises a high-permeability zone 292. The high-
permeability zone 292 has a stress field defined by a vertical stress 294, a
maximum-horizontal stress 296, and a minimum-horizontal stress 298. The
stresses 294/296/298 are schematic in that they do not represent particular
(or
relative) magnitudes. The hydrocarbon-bearing formation 290 is penetrated by a
first well 201, a second well 203, and a third well 205. The second well 203
and
the third well 205 are each substantially vertically coplanar with the first
well 201.
A fracture network may be induced from the first well 201, the second well
203,
the third well 205, or a combination thereof. Accordingly, a stimulant fluid
comprising a proppant may be injected from the first well 201, the second well
203, the third well 205, or a combination thereof. Moreover, the first well
201, the
second well 203, or a combination thereof may be equipped as an injection
well,
and the third well 205 may be equipped as a production well. The first well
201
has a vertical wellbore section 207 and a longitudinal wellbore section 209.
The
second well 203 has a vertical wellbore section 211 and a longitudinal
wellbore
section 213. The third well 205 has a vertical wellbore section 215 and a
56
Date Regue/Date Received 2022-08-11
longitudinal wellbore section 217. The longitudinal wellbore section 209 of
the first
well 201 is oriented in a toe-up configuration. The longitudinal wellbore
sections
213 / 217 of the wells 203 / 205 are oriented in a horizontal configuration as
is
typical of a SAGD well configuration. The longitudinal wellbore section 209 of
the
first well 201 is angularly offset from the longitudinal wellbore sections 213
/ 217
of the wells 203/ 205. The longitudinal wellbore section 209 of the first well
201 is
also angularly offset from a plane defined by the maximum-horizontal stress
296
and the minimum-horizontal stress 298.
[00127] FIG. 2F shows a schematic perspective view of a hydrocarbon-
bearing formation 219 that comprises a series of low-permeability zones 221
that
are interlayered with a series of high-permeability zones 223. One or more of
the
low-permeability zones 221 may be substantially impermeable to steam,
hydrocarbons, or a combination thereof. Each of the low-permeability zones 221
may have substantially the same permeability. Alternatively, two or more of
the
low-permeability zones 221 may have different permeabilities. Likewise, each
of
the high-permeability zones 223 may have substantially the same permeability.
Alternatively, two or more of the high-permeability zones 223 may have
different
permeabilities. The interfaces between the low-permeability zones 221 and the
high-permeability zones 223 define a series of lithofacies surfaces 225. Some
of
the low-permeability zones 221, the high-permeability zones 223, and the
lithofacies surfaces 225 are inclined relative their depositional plane such
that they
form an IHS. To provide greater clarity, the dimensions of at least some the
low-
permeability zones 221 and the high-permeability zones 223 are shown at
exaggerated scale in FIG. 2F. Those skilled in the art will recognize that IHS
comprising low-permeability zones of a wide variety of thicknesses are known,
and that typical IHS have low-permeability zones with thicknesses between
about
1 cm and about 50 cm (often between about 1 cm and about 10 cm). Likewise,
those skilled in the art will recognize that IHS comprising high-permeability
zones
of a wide variety of thicknesses are known, and that typical IHS have high-
permeability zones with thicknesses between about 1 cm and about 1 m (often
between about 5 cm and about 50 cm). The hydrocarbon-bearing formation 219
further comprises is a high-permeability zone 227 which underlies the IHS. The
57
Date Recue/Date Received 2022-08-11
hydrocarbon-bearing formation 219 is penetrated by a first well 229, a second
well
231, and a third well 233. The second well 231 and the third well 233 are each
substantially vertically coplanar with the first well 229. A fracture network
may be
induced from the first well 229, the second well 231, the third well 233, or a
combination thereof. Accordingly, a stimulant fluid comprising a proppant may
be
injected from the first well 229, the second well 231, the third well 233, or
a
combination thereof. Moreover, the first well 229, the second well 231, or a
combination thereof may be equipped as an injection well, and the third well
233
may be equipped as a production well. The first well 229 has a vertical
wellbore
section 235 and a longitudinal wellbore section 237. The second well 231 has a
vertical wellbore section 239 and a longitudinal wellbore section 241. The
third
well 233 has a vertical wellbore section 243 and a longitudinal wellbore
section
245. The longitudinal wellbore section 237 of the first well 229 is oriented
in a toe-
up configuration. The longitudinal wellbore sections 241 / 245 of the wells
231 /
233 are oriented in a horizontal configuration as is typical of a SAGD well
configuration. The longitudinal wellbore section 237 of the first well 229 is
angularly offset from the longitudinal wellbore sections 241 / 245 of the
wells 231
/ 233. The longitudinal wellbore section 237 of the first well 229 is also
angularly
offset from at least a part of the lithofacies surfaces 225.
[00128] FIG. 2G shows a schematic perspective view of a hydrocarbon-
bearing formation 247 that comprises a low-permeability zone 249 such as a
shale
gas formation or a shale oil formation. The low-permeability zone 249 may be
naturally fractured, or not. The low-permeability zone 249 has a stress field
defined
by a vertical stress 251, a maximum-horizontal stress 253, and a minimum-
horizontal stress 255. The stresses 251/253/255 are schematic in that they do
not
represent particular (or relative) magnitudes. The hydrocarbon-bearing
formation
247 is penetrated by a first well 257 and a second well 259 which is laterally
displaced from the first well 257. A fracture network may be induced from the
first
well 257, the second well 259, or a combination thereof. Accordingly, a
stimulant
fluid comprising a proppant may be injected from the first well 257, the
second
well 259, or a combination thereof. Moreover, the first well 257, the second
well
259, or a combination thereof may be equipped as an injection well, a
production
58
Date Regue/Date Received 2022-08-11
well, or a combination thereof. The first well 257 has a vertical wellbore
section
261 and a longitudinal wellbore section 263 comprising a toe 265 and a heel
267.
The second well 259 has a vertical wellbore section 269 and a longitudinal
wellbore section 271 comprising a toe 273 and a heel 275. The longitudinal
wellbore section 263 of the first well 257 is oriented in a toe-up
configuration, and
the longitudinal wellbore section 271 of the second well 259 is oriented in a
toe-
down configuration. Accordingly, the longitudinal wellbore section 263 of the
first
well 257 is angularly offset from the longitudinal wellbore section 271 of the
second
well 259 such that they form a crossing pattern when viewed from a
longitudinal
elevation view. The longitudinal wellbore sections 263 / 271 are also
angularly
offset from a plane defined by the maximum-horizontal stress 253 and the
minimum-horizontal stress 255. The longitudinal wellbore sections 263 / 271
are
oriented such that the toes 265 / 273 are in closer proximity than the heels
267 /
275.
f00129] FIG. 2H shows a schematic perspective view of a hydrocarbon-
bearing formation 279 that comprises a first high-permeability zone 283, a
second
high-permeability zone 285, and a low-permeability zone 281 interlayered
therebetween. The low-permeability zone 281 may be substantially impermeable
to steam, hydrocarbons, or a combination thereof. The interface between the
first
high-permeability zone 283 and the low-permeability zone 281 defines a first
lithofacies surface 287. The interface between the second high-permeability
zone
285 and the low-permeability zone 281 defines a second lithofacies surface
289.
The first high-permeability zone 283 may have substantially the same
permeability
of the second high-permeability zone 285. Alternatively, the permeabilities of
the
first high-permeability zone 283 and the second high-permeability zone 285 may
be different. The hydrocarbon-bearing formation 279 is penetrated by a well
291.
A fracture network may be induced from the well 291. Accordingly, a stimulant
fluid comprising a proppant may be injected from the well 291.The well 291 may
be equipped as an injection well and a production well. The well 291 has a
vertical
wellbore section 293 and a longitudinal wellbore section 295. The longitudinal
wellbore section 295 is oriented in a toe-down configuration such that it is
angularly offset from at least a part of the lithofacies surfaces 287 / 289.
59
Date Recue/Date Received 2022-08-11
[001301 FIG. 3A ¨ FIG. 3D provide schematic representations of a
series of
well configurations. The well configurations may be suitable for developing
fracture networks in hydrocarbon-bearing formations by processes according to
the present disclosure. The well configurations may also be suitable for
recovering
hydrocarbons from hydrocarbon-bearing formations by methods according to the
present disclosure. The well configurations may also be suitable for enhancing
hydrocarbon recovery from hydrocarbon-bearing formations by processes
according to the present disclosure. Lithological environments are not
provided in
FIG. 3A ¨ FIG. 3D for clarity.
[001311 FIG. 3A shows a schematic perspective view of a well configuration
300 that comprises a first well 302, a second well 304, and a third well 306.
A
fracture network may be induced from the first well 302, the second well 304,
the
third well 306, or a combination thereof. Moreover, one or more of the first
well
302 and the second well 304 may be equipped as a production well, and the
third
well 306 may be equipped as an injection well. The first well 302 comprises a
vertical wellbore section 308 and a longitudinal wellbore section 310. The
second
well comprises a vertical wellbore section 312 and a longitudinal wellbore
section
314. The third well comprises a vertical wellbore section 316 and a
longitudinal
wellbore section 318. The longitudinal wellbore sections 310 / 314 of the
wells 302
/ 304 are oriented in a horizontal configuration. The longitudinal wellbore
section
318 of the third well 306 is oriented in a toe-up configuration. Accordingly,
the
longitudinal wellbore section 318 of the third well 306 is angularly offset
from the
longitudinal wellbore sections 310 / 314 of the wells 302 / 304.
[001321 FIG. 3B shows a schematic perspective view of a well
configuration
320 that comprises a first well 322, a second well 324, a third well 326, a
fourth
well 328, and a fifth well 330. A fracture network may be induced from the
first well
322, the second well 324, the third well 326, the fourth well 328, the fifth
well 330,
or a combination thereof. Accordingly, a stimulant fluid comprising a proppant
may
be injected from the first well 322, the second well 324, the third well 326,
the
fourth well 328, the fifth well 330, or a combination thereof. The first well
322, the
third well 326, the fifth well 330, or a combination thereof may be equipped
as an
Date Regue/Date Received 2022-08-11
injection well. The second well 324, the fourth well 328, or a combination
thereof
may be equipped as a production well. The wells 322 / 324 / 326 / 328 / 330
comprise vertical wellbore sections 332 / 334 / 336 / 338 / 340, respectively.
The
wells 322 / 324 / 326 / 328 / 330 further comprise longitudinal wellbore
sections
342 / 344 / 346 / 348 / 350, respectively. The longitudinal wellbore sections
342 /
344 are vertically displaced and substantially vertically coplanar, such that
the
wells 322 / 324 comprise a typical SAGD well pair 352. Likewise, the
longitudinal
wellbore sections 346 / 348 are vertically displaced and substantially
vertically
coplanar, such that the wells 326 / 328 comprise a typical SAGD well pair 354.
The well pair 352 is laterally displaced from the well pair 354, and the fifth
well 330
is interposed therebetween. The longitudinal wellbore section 350 of the fifth
well
330 is oriented in a toe-up configuration. Accordingly, the longitudinal
wellbore
section 350 of the fifth well 330 is offset relative to the longitudinal
wellbore
sections 342 / 344 / 346 / 348 of the wells 322 / 324 / 326 / 328. In FIG. 3B,
the
vertical wellbore sections 334, 338, and 340 are shown as aligned along a
transverse-vertical plane, however this is one of many well configurations
that fall
within the scope of the present disclosure. For example, the vertical wellbore
section 340 of the fifth well 330 may be longitudinally off-set from the
transverse-
vertical plane defined by the vertical wellbore sections 334 and 338 (see,
e.g., the
position of vertical wellbore section 376 in FIG. 3C).
[00133] FIG. 3C shows a schematic perspective view of a well
configuration
356 that comprises a first well 358, a second well 360, a third well 362, a
fourth
well 364, and a fifth well 366. A fracture network may be induced from the
first well
358, the second well 360, the third well 362, the fourth well 364, the fifth
well 366,
or a combination thereof. Accordingly, a stimulant fluid comprising a proppant
may
be injected from the first well 358, the second well 360, the third well 362,
the
fourth well 364, the fifth well 366, or a combination thereof. The first well
358, the
third well 362, the fifth well 366, or a combination thereof may be equipped
as an
injection well. The second well 360, the fourth well 364, or a combination
thereof
may be equipped as a production well. The wells 358 / 360 / 362 / 364 / 366
comprise vertical wellbore sections 368 / 370 / 372 / 374 / 376, respectively.
The
wells 358 / 360 / 362 / 364 / 366 further comprise longitudinal wellbore
sections
61
Date Regue/Date Received 2022-08-11
378 / 380 / 382 / 384 / 386, respectively. The longitudinal wellbore sections
378 /
380 are substantially vertically coplanar, and that the wells 358 / 360 form a
well
pair 388. Likewise, the longitudinal wellbore sections 382 / 384 are
substantially
vertically coplanar, and that the wells 362 / 364 form a well pair 390. The
fifth well
366 is interposed between the well pair 388 and the well pair 390. The
longitudinal
wellbore section 378 of the first well 358 is oriented in a toe-up
configuration, and
the longitudinal wellbore section 380 of the second well 360 is oriented in a
horizontal configuration. Likewise, the longitudinal wellbore section 372 of
the third
well 362 is oriented in a toe-up configuration, and the longitudinal wellbore
section
384 of the fourth well 364 is oriented in a horizontal configuration.
Accordingly, the
longitudinal wellbore sections 378 / 382 are angularly offset from the
longitudinal
wellbore sections 380 / 384. The vertical wellbore section 376 of the fifth
well 366
is laterally and longitudinally displaced from the vertical wellbore sections
368 /
370 / 372 / 374. Further, the longitudinal wellbore section 386 of the fifth
well 366
is oriented in a toe-up configuration. As such the longitudinal wellbore
section 386
is angularly offset from the longitudinal wellbore sections 378 / 380 / 382 /
384.
[00134] FIG. 3D shows a schematic perspective view of a well
configuration
392 that comprises a first well 394, a second well 396, a third well 398, a
fourth
well 301, and a fifth well 303. The wells 394 / 396 / 398 / 301 / 303 comprise
vertical wellbore sections 305 / 307 / 309 / 311/ 313, respectively. The wells
394
/ 396 / 398 / 301 / 303 further comprise longitudinal wellbore sections 315 /
317 /
319 / 321 / 323, respectively. The wells 394 / 396 form a well pair 325, and
the
longitudinal wellbore sections 315 / 317 are horizontally oriented, vertically
displaced, and substantially vertically coplanar. Likewise, the wells 398 /
301 form
a well pair 327, and the longitudinal wellbore sections 319 / 321 are
horizontally
oriented, vertically displaced, and substantially vertically coplanar. The
well pair
325 is laterally displaced from the well pair 327, and the fifth well 303 is
interposed
therebetween. A fracture network may be induced from the longitudinal wellbore
sections 329, 323, 331, or a combination thereof. Accordingly, a stimulant
fluid
comprising a proppant may be injected from the longitudinal wellbore sections
329, 323, 331, or a combination thereof. After development of the fracture
network,
one or more of the longitudinal wellbore sections 329 / 331 may be shut off.
One
62
Date Regue/Date Received 2022-08-11
or more of the longitudinal wellbore sections 315 / 319 / 323 may be equipped
as
an injection well. One or more of the longitudinal wellbore sections 317 / 321
may
be equipped as a production well. The longitudinal wellbore section 323 of the
fifth
well 303 is oriented in a toe-up configuration. Accordingly, the longitudinal
wellbore section 323 of the fifth well 303 is offset relative to the
longitudinal
wellbore sections 315 / 317 / 319 / 321 of the wells 394 / 396/ 398 /301. The
first
well 394 further comprises an auxiliary longitudinal wellbore section 329.
Likewise,
the third well 398 further comprises an auxiliary longitudinal wellbore 331.
The
auxiliary longitudinal wellbores 329 / 331 are each oriented in a toe-up
configuration. Accordingly, the auxiliary longitudinal wellbores 329 / 331 are
angularly offset from the longitudinal wellbore sections 315 / 317 / 319 /
321.
[001351 FIG. 4A and FIG. 4B provide schematic longitudinal-elevation
and
horizontal-plan views, respectively, of a hydrocarbon-bearing formation 400
that
comprises a fracture network in communication with a first well 402 and a
second
well 404. The fracture network may be induced from the first well 402, the
second
well 404, or a combination thereof. Accordingly, a stimulant fluid comprising
a
proppant may be injected from the first well 402, the second well 404, or a
combination thereof. Moreover, one or more of the first well 402 and the
second
well 404 may be equipped as an injection well, a production well, or a
combination
thereof. As best seen in FIG. 4A, the hydrocarbon-bearing formation 400
comprises a first high-permeability zone 406, a second high-permeability zone
408, and a low-permeability zone 410 interlayered therebetween. The interface
between the first high-permeability zone 406 and the low-permeability zone 410
defines a first lithofacies surface 412. The interface between the second high-
permeability zone 408 and the low-permeability zone 410 defines a second
lithofacies surface 414.
[001361 As best seen in FIG. 4B, the first well 402 is laterally
displaced from
the second well 404. The first well 402 has a vertical wellbore section 416
(not
shown) and a longitudinal wellbore section 418. The second well 404 has a
vertical
wellbore section 420 (not shown) and a longitudinal wellbore section 422. The
longitudinal wellbore section 418 of the first well 402 is oriented in a toe-
up
63
Date Regue/Date Received 2022-08-11
configuration, and the longitudinal wellbore section 422 of the second well
404 is
oriented in a toe-down configuration. Accordingly, the longitudinal wellbore
section
418 of the first well 402 is angularly offset from the longitudinal wellbore
section
422 of the second well 404 as best seen in FIG. 4A. The longitudinal wellbore
sections 418 /422 are also angularly offset from at least a part of the
lithofacies
surfaces 412 / 414. As best seen in FIG. 4A, the fracture network comprises a
series of transverse-vertical fractures 424 and a series of horizontal
fractures 426.
As best seen in FIG. 4B, the fracture network further comprises a series of
longitudinal-vertical fractures 428.
Example 1: Formation evaluation by diagnostic fracture injection testing
[00137] This example demonstrates how fracture geometry and fracture
complexity of an induced fracture network can be evaluated using diagnostic
fracture injection testing (DFIT) and related methods. The following data was
collected from testing in a shallow-depth cap-rock formation of an oil sands
reservoir in Northern Alberta. Image log data was collected using a Formation
Micro-Imager (FMI). Core computed tomography (CT) data was collected using
CT scanning equipment from Schlumberger. G-function analysis and after closure
analysis (ACA) were performed using grid oriented hydraulic fracture extension
replicator (GOHFER ) software (GOHFER is a registered trade of Barree &
Associates LLC, Lakewood, Colorado, USA). Those skilled in the art will
recognize
that multiple suitable alternatives to the image-logging tool, core CT
scanning tool,
and the DFIT/ACA tool/software noted above exist, and that such alternatives
may
be suitable for conducting the tests / analysis disclosed herein. Moreover,
those
skilled in the art will readily understand how to identify/calculate stress
fields
including vertical stress, maximum-horizontal stress, and minimum-horizontal
stress.
[00138] Drilling-induced fracturing was effected through a series of
core
drillings in the formation. FIG. 6A and FIG. 6B, show archetypal image logs
obtained (static and dynamic images, respectively). The image logs indicate
the
presence of a horizontal fracture 500 and a vertical fracture 502. The
vertical
64
Date Regue/Date Received 2022-08-11
fracture 502 terminates in the horizontal fracture 500, such that they
together form
a substantially T-shaped fracture.
100139] FIG. 6 shows results from a core CT scan at the same depth
as the
horizontal fracture 500 shown in the image logs of FIG. 5A and FIG. 6B. In
FIG.
6, the horizontal fracture is identified by reference number 600. The core CT
scan
indicates that the horizontal fracture 600 is a continuous fracture. The
vertical
fracture 502 identified in the images logs of FIG. 6A and FIG. 6B is not
present on
the core CT scan of FIG. 6, likely because it is a drilling-induced fracture.
100140] G-function analysis, performed at approximately the same
depth as
the horizontal fracture 500 and the vertical fracture 502 shown in the image
logs
of FIG. 5A / FIG. 5B, confirms the presence of two fractures. Results from the
G-
functional analysis are provided in FIG. 7, where the G-function is identified
by
reference number 700 and the two fracture-closure signatures are identified by
reference numbers 702 and 704. FIG. 8A provides another G-function plot in a
bitumen formation from a different DFIT identified by reference number 800 in
FIG.
8A. As identified by reference number 802, the data indicates a final closure
pressure 4.76 MPa for the formation. FIG. 8B provides results from an ACA
radial
analysis of the same data set. From the results of FIG. 8B it was determined
that
the reservoir pressure was 2.76 MPa and the relative permeability to water was
1.56 mD. Additional metrics relating to from the results of FIG. 8B are
provided in
Table 1.
Date Recue/Date Received 2022-08-11
Table 1: Additional metrics relating to the ACA radial-analysis plot of FIG.
8B
ACA radial flow inputs ACA radial flow Outputs
closure found? true radial flow found? true
time at closure (min) 25.0143 begin radial flow time 7253.71
(min)
avg. perforation TVD (m) 479.75 radial pressure gradient 5.6229
(kPa/m)
fluid volume pumped (m3) 2.68925 ACA radial reservoir 2.69759
pressure (MPa)
est. net pay height (m) 5.00 ACA radial Kh/mu 7.80817
(md m/cp)
reservoir fluid visc. (cp) 1.00 ACA radial Kh (md m) 7.80817
ACA radial permeability 1.56163
(md)
Example 2: Stress field and fracture modeling
[00141] This example demonstrates how fracture simulations may be
conducted in a reservoir model to determine how to generate a fracture network
having modified fracture geometry and fracture complexity.
[00142] A computer-based lithological representation of the
formation
discussed in Example 1 was prepared based on data from a variety of sources
including image logs, core CT scanning, geomechanical lab data, DFIT
information, and other reservoir analysis. Data for generating computer-based
lithological representations can be obtained from a variety of methods ¨
details of
which will be understood by those skilled in the art. A grid-oriented
hydraulic
fracture extension replicator was used to model stress fields and simulate
fracturing events in the lithological representation. FIG. 9 shows an
archetypal
model of stress anisotropy in the formation. The orientations and magnitudes
of
the primary stress are identified by reference numerals 900 and 902. Based on
the orientations and magnitudes of the stresses, a well 904 was modelled to
penetrate the formation at the orientation shown. The well 904 was modeled to
include a vertical wellbore section 906 and a longitudinal wellbore section
908. A
series of twelve fracture initiation points were modeled at intervals along
the
66
Date Regue/Date Received 2022-08-11
longitudinal wellbore section 908 (identified by the symbol "x"). The
longitudinal
wellbore section 908 was oriented such that it was offset from a horizontal
plane
910 by an angle 1.6 .
[001431 The development of a fracture network by hydraulic
stimulation from
the longitudinal wellbore section 908 was modeled, and archetypal results from
the simulation are shown in FIG. 10A-C. FIG. 10A and FIG. 10B show transverse-
and longitudinal-elevation views of the fracture network, respectively. As
best
seen in FIG. 10A the fracture network comprises transverse-vertical fractures.
The
transverse-vertical fractures are bi-wing fractures having lengths of about
100 m
to about 200 m and heights of about 40 m to about 47 m. As best seen in FIG.
10B, the fracture network also comprises longitudinal-vertical fractures. The
longitudinal-vertical fractures are bi-wing fractures having lengths of about
50 m
to about 100 m and heights of about 32 m to about 38 m.
Example 3: Reservoir simulations for comparison of production metrics
[001441 This example illustrates how the presence / absence of a fracture
network induced from a longitudinal wellbore section that is angularly offset
from
a plane defined by a maximum horizontal stress and a minimum horizontal stress
impacts typical productions metrics.
[001451 In a first case, the formation discussed in Examples 1 and 2
was
modelled to include a well pair in a typical SAGD configuration. In the first
case,
the formation did not include a fracture network. In a second case, the
formation
discussed in Examples 1 and 2 was modelled to include the same well pair. In
the
second case, the formation included the fracture network discussed in Example
2.
In other words, the formation in the second case was modelled to include a
fracture network induced from a longitudinal wellbore section that is
angularly
offset from a plane defined by a maximum horizontal stress and a minimum
horizontal stress. The fractures were modelled using logarithmic local grid
refinement and non-Darcy flow conditions.
[001461 Archetypal simulation results are shown in FIG. 11A ¨ FIG.
11C. In
FIG 11A, the water (steam) rate as function of time for the first case (no off-
set
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Date Regue/Date Received 2022-08-11
fracturing) is identified by reference number 1100 and the water (steam) rate
as a
function of time for the second case (off-set fracturing) is identified by
reference
number 1102. The results of FIG. 11A indicate that the presence of the
fracture
network increases the water rate by an average of 15 %. This suggests that the
presence of the fracture network increase the formation's ability to
accommodate
higher concentrations of steam.
[00147] In FIG 11B, the oil-production rate as function of time for
the first
case (no off-set fracturing) is identified by reference number 1106 and the
oil-
production rate as a function of time for the second case (off-set fracturing)
is
identified by reference number 1108. The results of FIG. 11B indicate that the
presence of the fracture network leads to a higher rate of oil production and
an
earlier peak production (by approximately 8 months). Accordingly, methods and
processes of the present disclosure may result in hydrocarbon recovery with
shorter start-up and ramp-up times compared with current conventional SAGD
and CSS processes.
[00148] In FIG 11C, cumulative oil production as function of time
for the first
case (no off-set fracturing) is identified by reference number 1112 and the
cumulative oil production as a function of time for the second case (off-set
fracturing) is identified by reference number 1110. The results of FIG. 11C
indicate
that the presence of the fracture network increases the cumulative oil
production
by an approximately 6 %. In FIG 11C, the cumulative steam-to-oil ratio as
function
of time for the first case (no off-set fracturing) is identified by reference
number
1114 and the cumulative steam-to-oil ratio as a function of time for the
second
case (off-set fracturing) is identified by reference number 1116. The results
of FIG.
11C indicate that the presence of the fracture network does not substantially
influence the cumulative steam-to-oil ratio.
Example 4: Reservoir simulations for comparison of production metrics in a
formation comprising a shale barrier
1001491 This example illustrates how the presence / absence of a
fracture
network induced from a longitudinal wellbore section that is angularly offset
from
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Date Regue/Date Received 2022-08-11
a plane defined by a maximum horizontal stress and a minimum horizontal stress
impacts typical productions metrics in a formation comprising a shale barrier.
The
formation discussed in Examples 1 and 2 was modelled to include an injection
well and a production well in a typical SAGD configuration. The formation was
also
modelled to include a shale barrier. The shale barrier was modelled to have a
longitudinal dimension of 400 m, a lateral dimension of 50 m, and a vertical
dimension of 3 m. The shale barrier was modelled to be positioned about 3 m
above the injection well.
[00150] In a first case, the formation was modelled such that it did
not include
a fracture network. In a second case, the formation was modelled to include
the
fracture network discussed in Example 2. In other words, the formation in the
second case was modelled to include a fracture network induced from a
longitudinal wellbore section that is angularly offset from a plane defined by
a
maximum horizontal stress and a minimum horizontal stress. The longitudinal
wellbore section was also modelled to be angularly offset from the shale
barrier
and the lithofacies surfaces defined by the interfaces between the shale
barrier
and the formation. The shale barrier was modelled to overlay five out of eight
fracture initiation points on the longitudinal wellbore section. The fractures
were
modelled using logarithmic local grid refinement and non-Darcy flow
conditions.
[00151] Archetypal simulation results are shown in FIG. 12A¨ FIG. 12C. In
FIG 12A, the water (steam) rate as function of time for the first case (no off-
set
fracturing) is identified by reference number 1200 and the water (steam) rate
as a
function of time for the second case (off-set fracturing) is identified by
reference
number 1202. The results of FIG. 12A indicate that the presence of the
fracture
network increases the water rate by an average of about 200 %. This suggests
that the presence of the fracture network increase the formation's ability to
accommodate higher concentrations of steam in formations partitioned by a
shale
barrier.
[00152] In FIG 12B, the oil-production rate as function of time for
the first
case (no off-set fracturing) is identified by reference number 1206 and the
oil-
production rate as a function of time for the second case (off-set fracturing)
is
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Date Regue/Date Received 2022-08-11
identified by reference number 1208. The results of FIG. 12B indicate that the
presence of the fracture network leads to a higher rate of oil production and
an
earlier peak production (by approximately 400 %). Accordingly, methods and
processes of the present disclosure may result in hydrocarbon recovery with
shorter start-up and ramp-up times compared with current conventional SAGD
and CSS processes in formations portioned by a shale barrier.
[00153] In FIG 12C, the cumulative oil production as function of
time for the
first case (no off-set fracturing) is identified by reference number 1216 and
the
cumulative oil production as a function of time for the second case (off-set
fracturing) is identified by reference number 1214. The results of FIG. 12C
indicate
that the presence of the fracture network increases the cumulative oil
production
about 2.8 fold over five years. In FIG 12C, the cumulative steam-to-oil ratio
as
function of time for the first case (no off-set fracturing) is identified by
reference
number 1212 and the cumulative oil production as a function of time for the
second
case (off-set fracturing) is identified by reference number 1210. The results
of FIG.
12C indicate that the presence of the fracture network decreases to oil
cumulative
steam-to-oil ratio by about 22 % at the end of five years. Accordingly,
various
embodiments of the present disclosure may result in higher production rates
compared with current conventional SAGD and CSS processes due, in part, to
fractures penetrating through zones such as shale barriers.
f00154] Although various embodiments of the disclosure are disclosed
herein, many adaptations and modifications may be made within the scope of the
disclosure in accordance with the common general knowledge of those skilled in
this art. Such modifications include the substitution of known equivalents for
any
aspect of the disclosure in order to achieve the same result in substantially
the
same way. Numeric ranges are inclusive of the numbers defining the range. The
word "comprising" is used herein as an open-ended term, substantially
equivalent
to the phrase "including, but not limited to", and the word "comprises" has a
corresponding meaning. As used herein, the singular forms "a", "an" and "the"
include plural referents unless the context clearly dictates otherwise. Thus,
for
example, reference to "a thing" includes more than one such thing. Citation of
Date Regue/Date Received 2022-08-11
references herein is not an admission that such references are prior art to
the
present disclosure. The disclosure includes all embodiments and variations
substantially as hereinbefore described and with reference to the examples and
drawings.
[00155] It should be understood that the compositions and methods are
described in terms of "comprising," "containing," or "including" various
components or steps, the compositions and methods can also "consist
essentially
of or "consist of the various components and steps.
[00156] For the sake of brevity, only certain ranges are explicitly
disclosed
herein. However, ranges from any lower limit may be combined with any upper
limit to recite a range not explicitly recited, as well as, ranges from any
lower limit
may be combined with any other lower limit to recite a range not explicitly
recited,
in the same way, ranges from any upper limit may be combined with any other
upper limit to recite a range not explicitly recited. Additionally, whenever a
numerical range with a lower limit and an upper limit is disclosed, any number
and
any included range falling within the range are specifically disclosed. In
particular,
every range of values (of the form, "from about a to about b," or,
equivalently,
"from approximately a to b," or, equivalently, "from approximately a-b")
disclosed
herein is to be understood to set forth every number and range encompassed
within the broader range of values even if not explicitly recited. Thus, every
point
or individual value may serve as its own lower or upper limit combined with
any
other point or individual value or any other lower or upper limit, to recite a
range
not explicitly recited.
[00157] Therefore, the present disclosure is well adapted to attain
the ends
and advantages mentioned as well as those that are inherent therein. The
particular embodiments disclosed above are illustrative only, as the present
disclosure may be modified and practiced in different but equivalent manners
apparent to those skilled in the art having the benefit of the teachings
herein.
Although individual embodiments are discussed, the disclosure covers all
combinations of all those embodiments. Also, the terms in the claims have
their
plain, ordinary meaning unless otherwise explicitly and clearly defined by the
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Date Regue/Date Received 2022-08-11
patentee. It is therefore evident that the particular illustrative embodiments
disclosed above may be altered or modified and all such variations are
considered
within the scope and spirit of the present disclosure.
[00158] Many obvious variations of the embodiments set out herein
will
suggest themselves to those skilled in the art in light of the present
disclosure.
Such obvious variations are within the full intended scope of the appended
claims.
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Date Recue/Date Received 2022-08-11
