Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
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1 METHODS OF IMPROVING HEAVY OIL PRODUCTION
2 FIELD OF THE INVENTION
3 [0001] The present invention is directed to oil extraction
processes used in the recovery of
4 hydrocarbons from hydrocarbon deposits.
BACKGROUND OF THE INVENTION
6 [0002] There exist throughout the world deposits or reservoirs of
heavy oils and bitumen
7 which, until recently, have been ignored as sources of petroleum products
since the contents
8 thereof were not recoverable using previously known production
techniques. While those
9 deposits that occur near the surface may be exploited by surface mining,
a significant amount of
heavy oil and bitumen reserves may occur in formations that are too deep for
surface mining,
11 typically referred to as "in situ" reservoirs or deposits because
extraction must occur in situ or
12 from within the reservoir or deposit. The recovery of heavy oil and/or
bitumen in these in situ
13 deposits may be hampered by the physical characteristics of the heavy
oil and bitumen
14 contained therein, particularly the viscosity of the heavy oil and/or
bitumen. While there is no
clear definition, heavy oil typically has a viscosity of greater than 100 mPas
(100 cP), a specific
16 gravity of 10 API to 17 API and tends to be mobile (e.g. capable of flow
under gravity) under
17 reservoir conditions, while bitumen typically has a viscosity of greater
than 10,000 mPas
18 (10,000 cP), a specific gravity of 7 API to 10 API and tends to be
immobile (e.g. incapable of
19 flow under gravity) under reservoir conditions. The above noted physical
characteristics of the
heavy oil and bitumen (collectively referred to as "heavy oil") typically
render these components
21 difficult to recover from in situ deposits and, as such, in situ
processes and/or technologies
22 specific to these types of deposits are needed to efficiently exploit
these resources.
23 [0003] Several techniques have been developed to recover heavy oil
from in situ deposits,
24 such as steam assisted gravity drainage (SAGD), as well as variations
thereof using
hydrocarbon solvents (e.g. VAPEX), steam flooding, cyclic steam stimulation
(CSS) and in situ
26 combustion. These techniques involve attempts to reduce the viscosity of
the heavy oil so that
27 the heavy oil and bitumen can be mobilized toward production wells. One
such method, SAGD,
28 provides for steam injection and oil production to be carried out
through separate wells. The
29 SAGD configuration provides for an injector well which is substantially
parallel to, and situated
above a producer well, which lies horizontally near the bottom of the deposit.
Thermal
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1 communication between the two wells is established, and as oil is
mobilized and produced from
2 the producer or production well, a steam chamber develops. Oil at the
surface of the enlarging
3 steam chamber is constantly mobilized by contact with steam and drains
under the influence of
4 gravity.
[0004] An alternative to SAGD, known as VAPEX, provides for the use of
hydrocarbon
6 solvents rather than steam. A hydrocarbon solvent or mixture of solvents
such as propane,
7 butane, ethane and the like can be injected into the reservoir or deposit
through an injector well.
8 Solvent fluid at the solvent fluid/oil interface dissolves in the heavy
oil thereby decreasing its
9 viscosity, causing the reduced or decreased viscosity heavy oil to flow
under gravity to the
production well. The hydrocarbon vapour forms a solvent fluid chamber,
analogous to the steam
11 chamber of SAGD.
12 [0005] It has been recognized, however, that these prior means used
for the recovery of
13 heavy oil from subterranean deposits need to be optimized.
14 SUMMARY OF THE INVENTION
[0006] An aspect of the present invention includes a method for extracting
hydrocarbons
16 from in a reservoir containing hydrocarbons having an array of wells
disposed therein, the
17 method comprising: (a) injecting a solvent fluid into the reservoir
through a first well in the array;
18 (b) producing reservoir fluid from a second well in the array, the
second well offset from the first
19 well, to drive the formation of a solvent fluid chamber between the
first and the second well; (c)
injecting the solvent fluid into the solvent fluid chamber through at least
one of the first and
21 second wells to expand the solvent fluid chamber within the reservoir;
and (d) producing
22 reservoir fluid from at least one well in the array to direct the
expansion of the solvent fluid
23 chamber within the reservoir.
24 [0007] An aspect of the present invention includes a method for
extracting hydrocarbons
from a reservoir containing hydrocarbons, the method comprising: (a) injecting
a solvent fluid
26 into the reservoir through a first well disposed in the reservoir; (b)
producing reservoir fluid from
27 a second well disposed in the reservoir and offset from the first well
to create a pressure
28 differential between the first and second well, the pressure
differential being sufficient to
29 overcome the gravity force of the solvent fluid so as to drive the
formation of a solvent fluid
chamber towards the second well.
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1 [0008] Another aspect of the present invention includes a method
for extracting
2 hydrocarbons from a reservoir containing hydrocarbons, the method
comprising: (a) injecting a
3 solvent fluid into the reservoir through a first well disposed in the
deposit; (b) producing reservoir
4 fluid from a second well disposed in the reservoir and offset from the
first well so as to drive the
formation of a solvent fluid chamber towards the second well until solvent
fluid breakthrough
6 occurs at the second well; (c) injecting the solvent fluid into the
solvent fluid chamber through
7 the second well to increase the surface area of the solvent fluid
chamber; and (d) producing
8 reservoir fluid in the solvent fluid chamber from the first well.
9 [0009] Another aspect of the present invention includes a method
for extracting
hydrocarbons from a reservoir containing hydrocarbons, the method comprising:
(a) injecting a
11 solvent fluid into the reservoir through a first vertical well disposed
in the deposit; (b) producing
12 reservoir fluid from a second vertical well disposed in the reservoir
offset from the first vertical
13 well so as to drive the formation of a first solvent fluid chamber
towards the second vertical well
14 until solvent fluid breakthrough occurs at the second vertical well; (c)
injecting the solvent fluid
into the reservoir through a first horizontal well disposed in the deposit and
offset from the first
16 and second vertical wells so as to create a second solvent fluid
chamber; and (d) producing
17 reservoir fluid from the horizontal well and injecting solvent fluid
into the first solvent chamber so
18 as to drive the first solvent fluid chamber towards the second solvent
fluid chamber. In a further
19 aspect, the horizontal well may include completion and production
strings. In another aspect,
the completion string may be provided with flow control devices as described
further herein.
21 [0010] Another aspect of the present invention includes a method
for extracting
22 hydrocarbons from a reservoir containing hydrocarbons, the method
comprising: (a) injecting a
23 solvent fluid into the reservoir through a first well disposed in the
reservoir; (b) producing
24 reservoir fluid from a second well disposed in the reservoir and offset
from the first well to create
a direct solvent fluid channel between the first and second well; (c)
injecting solvent fluid into the
26 reservoir from at least one of the first and second wells and producing
reservoir fluid from at
27 least one of the first and second wells to create at least two solvent
fluid chambers, each of the
28 solvent fluid chambers having "oil/solvent fluid" mixing and "solvent
fluid/oil mixing".
29 [0011] In one aspect the present invention provides a method for
extracting hydrocarbons
from a reservoir having at least one well, the method comprising injecting a
solvent fluid into the
31 reservoir through the well and extracting a reservoir fluid from the at
least one well.
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1 [0012] In one aspect the present invention provides a method for
extracting hydrocarbons
2 from a reservoir having at least one well, the at least one well having
at least one completion
3 string disposed therein, the method comprising injecting a solvent fluid
into the reservoir through
4 the at least one completion string and extracting a reservoir fluid from
the at least one well.
[0013] In one aspect the present invention provides a method for extracting
hydrocarbons
6 from a reservoir having at least one well, the at least one well having
at least one completion
7 string disposed therein, the method comprising injecting a solvent fluid
into the reservoir through
8 the at least one completion string and extracting a reservoir fluid from
the at least one well,
9 wherein the at least one completion string includes two or more flow
control devices located on
a portion thereof in the reservoir.
11 [0014] In one aspect the present invention provides a method for
extracting hydrocarbons
12 from a reservoir having at least one well, the at least one well having
at least one completion
13 string and at least one production string disposed therein, the method
comprising injecting a
14 solvent fluid into the reservoir through the at least one completion
string and extracting a
reservoir fluid from the reservoir through the at least one completion string
and extracting the
16 reservoir fluid from the at least one well through the at least one
production string.
17 [0015] In one aspect the present invention provides a method for
extracting hydrocarbons
18 from a reservoir having at least one well, the at least one well having
at least one completion
19 string and at least one production string disposed therein, the method
comprising injecting a
solvent fluid into the reservoir through the at least one completion string
and extracting a
21 reservoir fluid from the reservoir through the at least one completion
string and extracting the
22 reservoir fluid from the at least one well through the at least one
production string, wherein the
23 at least one completion string includes two or more flow control devices
located on a portion
24 thereof in the reservoir.
[0016] In one aspect the present invention provides a method for extracting
hydrocarbons
26 from a reservoir, comprising at least one first well and at least one
second well, the method
27 comprising injecting a solvent fluid into the reservoir through the at
least one first well and
28 extracting a reservoir fluid from the at least one second well.
29 [0017] In one aspect the present invention provides a method for
extracting hydrocarbons
from a reservoir, comprising at least one first well and at least one second
well, the at least one
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1 first well having at least one completion string disposed therein, the
method comprising injecting
2 a solvent fluid into the reservoir through the at least one completion
string and extracting a
3 reservoir fluid from at least one of the wells.
4 [0018] In one aspect the present invention provides a method for
extracting hydrocarbons
from a reservoir, comprising at least one first well and at least one second
well, the at least one
6 first well having at least one completion string disposed therein, the
method comprising injecting
7 a solvent fluid into the reservoir through the at least one completion
string and extracting a
8 reservoir fluid from at least one of the wells, wherein the at least one
completion string includes
9 two or more flow control devices located on a portion thereof in the
reservoir.
[0019] In one aspect the present invention provides a method for extracting
hydrocarbons
11 from a reservoir, comprising at least one first well and at least one
second well, the at least one
12 first well having at least one completion string and at least one
production string disposed
13 therein, the method comprising injecting a solvent fluid into the
reservoir through at least one of
14 the completion strings and the second wells and extracting a reservoir
fluid from at least one of
the completion strings and the second wells and extracting the reservoir fluid
from the at least
16 one first well through the at least one production string.
17 [0020] In one aspect the present invention provides a method for
extracting hydrocarbons
18 from a reservoir, comprising at least one first well and at least one
second well, the at least one
19 first well having at least one completion string and at least one
production string disposed
therein, the method comprising injecting a solvent fluid into the reservoir
through the at least
21 one first completion string and the at least one second well and
extracting a reservoir fluid from
22 the reservoir from at least one of the completion strings and the second
wells and extracting the
23 reservoir fluid from the at least one of the at least one production
string or second well, wherein
24 at least one of the completion strings includes two or more flow control
devices located on a
portion thereof in the reservoir.
26 [0021] In one aspect the present invention provides a method for
extracting hydrocarbons
27 from a reservoir, comprising at least one first well and at least one
second well, the at least one
28 first well having at least one first completion string disposed therein,
the at least one second well
29 having at least one second completion string disposed therein, the
method comprising injecting
a solvent fluid into the reservoir through at least one of the completion
strings and extracting a
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1 reservoir fluid from at least one of the wells, wherein at least one of
the completion strings
2 includes two or more flow control devices located on a portion thereof in
the reservoir.
3 [0022] In one aspect the present invention provides a method for
extracting hydrocarbons
4 from a reservoir, comprising at least one first well and at least one
second well, the at least one
first well having at least one first completion string and at least one first
production string
6 disposed therein, the at least one second well having at least one second
completion string
7 disposed therein, the method comprising injecting a solvent fluid into
the reservoir through at
8 least one of the completion strings and extracting a reservoir fluid from
the reservoir from at
9 least one of the first completion strings and the second wells and
extracting the reservoir fluid
from the at least one first well through the at least one production string or
the at least one
11 second well, wherein at least one of the completion strings includes two
or more flow control
12 devices located on a portion thereof in the reservoir.
13 [0023] In one aspect the present invention provides a method for
extracting hydrocarbons
14 from a reservoir, comprising at least one first well and at least one
second well, the at least one
first well having at least one first completion string and at least one first
production string
16 disposed therein, the at least one second well having at least one
second completion string and
17 at least one second production string disposed therein, the method
comprising injecting a
18 solvent fluid into the reservoir through at least one of the completion
strings and extracting a
19 reservoir fluid from the reservoir from at least one of the completion
strings and extracting the
reservoir fluid from at least one of the first and second wells through at
least one of the first or
21 second production strings, wherein at least one of the completion
strings includes two or more
22 flow control devices located on a portion thereof in the reservoir.
23 [0024] In a further aspect, the present invention includes a
method for extracting
24 hydrocarbons from a reservoir having at least one first well and at
least one second well, the at
least one first well having at least one first completion string and at least
one first production
26 string disposed therein, and the at least one second well having at
least one second completion
27 string and at least one second production string disposed therein, the
method comprising: (a)
28 injecting a solvent fluid into the reservoir through at least one of the
completion strings; (b)
29 extracting reservoir fluid from the reservoir from at least one of the
completion strings, wherein
the at least one second well is offset from the at least one first well, to
drive the formation of a
31 solvent fluid chamber between the at least one first well and the at
least one second well; (c)
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1 injecting the solvent fluid into the solvent fluid chamber through at
least one of the completion
2 strings to expand the solvent fluid chamber within the reservoir; (d)
extracting reservoir fluid
3 from the reservoir from at least one of the completion strings to direct
the expansion of the
4 solvent fluid chamber within the reservoir, and (e) extracting the
reservoir fluid from at least one
of the first and second wells through at least one of the first or second
production strings,
6 wherein at least one of the completion strings includes two or more flow
control devices located
7 on a portion thereof in the reservoir.
8 [0025] In a further aspect, the present invention includes a
method for extracting
9 hydrocarbons from a reservoir having at least one first well and at least
one second well, the at
least one first well having at least one first completion string and at least
one first production
11 string disposed therein, and the second well having at least one second
completion string and at
12 least one second production string disposed therein, the method
comprising: (a) injecting a
13 solvent fluid into the reservoir through the at least one of the
completion strings disposed in the
14 reservoir; (b) extracting reservoir fluid from the at least one of the
completion strings disposed in
the reservoir, the at least one second well being offset from the at least one
first well to create a
16 pressure differential between the at least one first and the at least
one second well, the pressure
17 differential being sufficient to overcome the gravity force of the
solvent fluid so as to drive the
18 formation of a solvent fluid chamber towards the at least one second
well; and (c) extracting the
19 reservoir fluid from at least one of the first and second wells through
at least one of the first or
second production strings, wherein at least one of the completion strings
includes two or more
21 flow control devices located on a portion thereof in the reservoir.
22 [0026] In a further aspect, the present invention includes a
method for extracting
23 hydrocarbons from a reservoir having at least one first well and at
least one second well, the at
24 least one first well having at least one first completion string and at
least one first production
string disposed therein, and the at least one second well having at least one
second completion
26 string and at least one second production string disposed therein, the
method comprising: (a)
27 injecting a solvent fluid into the reservoir through at least one of the
completion strings disposed
28 in the reservoir; (b) extracting reservoir fluid from the reservoir from
at least one of the
29 completion strings disposed in the reservoir, the at least one second
well being offset from the
at least one first well so as to drive the formation of a solvent fluid
chamber towards the at least
31 one second well until solvent fluid breakthrough occurs at the at least
one second well; (c)
32 injecting the solvent fluid into the solvent fluid chamber through at
least one of the completion
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1 strings to increase the surface area of the solvent fluid chamber; (d)
producing reservoir fluid
2 from the solvent fluid chamber in the reservoir using at least one of the
completion strings; and
3 (e) extracting the reservoir fluid from at least one of the first and
second wells through at least
4 one of the first or second production strings, wherein at least one of
the completion strings
includes two or more flow control devices located on a portion thereof in the
reservoir.
6 [0027] In a further aspect the present invention includes a method
for extracting
7 hydrocarbons from a reservoir having at least one first well and at least
one second well, the at
8 least one first well having at least one first completion string and at
least one first production
9 string disposed therein, and the at least one second well having at least
one second completion
string and at least one second production string disposed therein, the method
comprising: (a)
11 injecting a solvent fluid into the reservoir through at least one of the
completion strings disposed
12 in the reservoir; (b) extracting reservoir fluid from the reservoir from
at least one of the
13 completion strings disposed in the reservoir, the at least one second
well being offset from the
14 at least one first well to create a direct solvent fluid channel between
the at least one first and
the at least one second well; (c) injecting solvent fluid into the reservoir
from at least one of the
16 completion strings; (d) producing reservoir fluid from the reservoir
using at least one of the
17 completion strings to create at least two solvent fluid chambers, each
of the solvent fluid
18 chambers having "oil/solvent fluid" mixing and "solvent fluid/oil
mixing", and (e) extracting the
19 reservoir fluid from at least one of the first and second wells through
at least one of the first or
second production strings, wherein at least one of the completion strings
includes two or more
21 flow control devices located on a portion thereof in the reservoir.
22 [0028] In a further aspect, the present invention includes a
method for extracting
23 hydrocarbons from a reservoir having at least one first well and at
least one second well, the at
24 least one first well having at least one first completion string and at
least one first production
string disposed therein, and the at least one second well having at least one
second completion
26 string and at least one second production string disposed therein, the
method comprising: (a)
27 injecting a solvent fluid into the reservoir through at least one of the
completion strings disposed
28 in the reservoir; (b) extracting reservoir fluid from the reservoir from
at least one of the
29 completion strings disposed in the reservoir, the at least one second
well being vertically and
laterally offset from the at least one first well so as to drive the formation
of a solvent fluid
31 chamber towards the at least one second well until solvent fluid
breakthrough occurs at the at
32 least one second well; (c) injecting the solvent fluid into the solvent
fluid chamber through at
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1 least one of the completion strings to increase the surface area of the
solvent fluid chamber; (d)
2 producing reservoir fluid from the solvent fluid chamber in the reservoir
using at least one of the
3 completion strings; and (e) extracting the reservoir fluid from at least
one of the first and second
4 wells through at least one of the first or second production strings,
wherein at least one of the
completion strings includes two or more flow control devices located on a
portion thereof in the
6 reservoir.
7 [0029] In a further aspect the present invention includes a method
for extracting
8 hydrocarbons from a reservoir having at least one first well and at least
one second well, the at
9 least one first well having at least one first completion string and at
least one first production
string disposed therein, and the at least one second well having at least one
second completion
11 string and at least one second production string disposed therein, the
method comprising: (a)
12 injecting a solvent fluid into the reservoir through at least one of the
completion strings disposed
13 in the reservoir; (b) extracting reservoir fluid from the reservoir from
at least one of the
14 completion strings disposed in the reservoir, the at least one second
well being vertically and
laterally offset from the at least one first well to create a direct solvent
fluid channel between the
16 at least one first and the at least one second well; (c) injecting
solvent fluid into the reservoir
17 from at least one of the completion strings; (d) producing reservoir
fluid from the reservoir using
18 at least one of the completion strings to create at least two solvent
fluid chambers, each of the
19 solvent fluid chambers having "oil/solvent fluid" mixing and "solvent
fluid/oil mixing", and (e)
extracting the reservoir fluid from at least one of the first and second wells
through at least one
21 of the first or second production strings, wherein at least one of the
completion strings includes
22 two or more flow control devices located on a portion thereof in the
reservoir.
23 BRIEF DESCRIPTION OF THE DRAWINGS
24 [0030] Various objects, features and attendant advantages of the
present invention will
become more fully appreciated and better understood when considered in
conjunction with the
26 accompanying drawings, in which like reference characters designate the
same or similar parts
27 throughout the several views.
28 [0031] Figure 1(a) and (b) are schematic perspective views of an
array of horizontal wells;
29 [0032] Figure 2 is a schematic side view of a horizontal well,
comprising a completion string
with a plurality of flow control devices;
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1 [0033] Figure 3 is a schematic side view of a horizontal well,
comprising a production string
2 and a completion string having a plurality of flow control devices;
3 [0034] Figures 4 and 5 are schematic perspective views of
horizontal wells for use with
4 embodiments of the present invention;
[0035] Figures 6 and 7 are schematic end views of horizontal wells for use
with
6 embodiments of the present invention;
7 [0036] Figures 8 to 10 are schematic plan views of horizontal and
vertical wells for use with
8 embodiments of the present invention;
9 [0037] Figure 11 is a schematic side view of horizontal and
vertical wells for use with
embodiments of the present invention; and
11 [0038] Figure 12 is a schematic end view of horizontal and
vertical wells for use with
12 embodiments of the present invention.
13 DETAILED DESCRIPTION OF THE INVENTION
14 [0039] In order that the invention may be more fully understood,
it will now be described, by
way of example, with reference to the accompanying drawings in which Figures 1
through 7
16 illustrate embodiments of the present invention.
17 [0040] In the description and drawings herein, and unless noted
otherwise, the terms
18 "vertical", "lateral" and "horizontal", can be references to a Cartesian
co-ordinate system in
19 which the vertical direction generally extends in an "up and down"
orientation from bottom to top
while the lateral direction generally extends in a "left to right" or "side to
side" orientation. In
21 addition, the horizontal direction generally extends in an orientation
that is extending out from or
22 into the page. Alternatively, the terms "horizontal" and "vertical" can
be used to describe the
23 orientation of a well within a reservoir or deposit. "Horizontal" wells
are generally oriented
24 parallel to or along a horizontal axis of a reservoir or deposit. The
horizontal axis and thus the
so-called "horizontal wells" may correspond to or be parallel to the
horizontal, vertical or lateral
26 direction as represented in the description and drawings. "Vertical"
wells are generally oriented
27 perpendicular to horizontal wells and are generally parallel to the
vertical axis of the reservoir.
28 As with the horizontal axis, the vertical axis and thus the so-called
"vertical wells" may
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1 correspond to or be parallel to the horizontal, vertical or lateral
direction as represented in the
2 description and drawings. It will be understood that horizontal wells are
generally 800 to 105
3 relative to the vertical axis of the reservoir or deposit, while vertical
wells are generally
4 perpendicular relative to the horizontal axis of the reservoir or
deposit.
[0041] Many known methods of heavy oil recovery or production employ means
of reducing
6 the viscosity of the heavy oil located in the deposit so that the heavy
oil will more readily flow
7 under reservoir conditions to the production wells. Steam or solvent
fluid flooding of the
8 reservoir to produce a steam or solvent fluid chamber in SAGD and VAPEX
processes may be
9 used to reduce the viscosity of the heavy oil within the deposit. While a
SAGD process reduces
the viscosity of the heavy oil within the deposit through heat transfer, a
VAPEX process reduces
11 the viscosity by dissolution of the solvent into the heavy oil. Such
techniques show potential for
12 stimulating recovery of heavy oil that would otherwise be essentially
unrecoverable. While
13 these processes, particularly VAPEX, may potentially increase heavy oil
production, these
14 known processes may not sufficiently maximize recovery of the heavy oil
so that the in situ
deposit can be produced in an economically or cost efficient or effective
manner. The objective
16 of embodiments of the present invention is to improve recovery of heavy
oil in these in situ
17 deposits so as to effectively, efficiently, and economically maximize
heavy oil recovery. The
18 embodiments of the present invention are directed to the use of a
solvent fluid, which may
19 consist of a solvent in a liquid or gaseous state or a mixture of gas
and liquid, so as to
effectively and efficiently maximize oil recovery by increasing the mixing
process of the solvent
21 fluid (e.g. either a solvent liquid or solvent fluid) with the heavy oil
contained in the formation,
22 thus improving the oil recovery from particular underground hydrocarbon
formations.
23 [0042] The present invention is directed to producing a solvent
fluid chamber having a
24 desired configuration or geometry between at least two wells. In an
aspect of the present
invention, a solvent fluid chamber having a desired configuration or geometry
is formed between
26 one well that may be vertically, horizontally or laterally offset from
another well so as to
27 maximize the recovery of heavy oil from in situ deposits. It will be
understood by a person
28 skilled in the art that the use of the term "offset" herein refers to
wells that can be displaced
29 relative to one another within the reservoir or deposit in a lateral,
horizontal or vertical
orientation. The solvent fluid may comprise steam, methane, butane, ethane,
propane,
31 pentanes, hexanes, heptanes, carbon dioxide (CO2) or other solvent
fluids which are well known
32 in the art, either alone or in combination, as well as these solvent
fluids or mixtures thereof
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1 mixed with other non-condensable gases. The solvent fluid (e.g. solvent
liquid, gas or mixtures
2 thereof) chamber configuration of the present invention provides for an
increase in the surface
3 area of the solvent fluid chamber that is in contact with heavy oil
contained within the deposit.
4 The increased contact between the fluid chamber and the heavy oil leads
to increased mixing
between the fluid (e.g. solvent liquid, gas or mixtures thereof) and the heavy
oil. The increased
6 mixing, in turn, leads to increased production of the heavy oil from a
producing well. The fluid
7 that is "produced" or flows into the producing well, typically in a
liquid state, from within the
8 deposit to the surface or elsewhere where it is collected typically
comprises reduced or
9 decreased viscosity heavy oil, solvent fluid, other components or
mixtures thereof. This mixture
of reduced viscosity heavy oil and other components has a viscosity less than
that of heavy oil,
11 namely 1 to 100 cP, and can be referred to as "decreased viscosity heavy
oil", "reduced
12 viscosity heavy oil" or "production oil". As noted above, heavy oil,
namely heavy oil and bitumen
13 have viscosities of between 100 to 5,000,000 cP.
14 [0043] Figures 1(a) and 1(b) of the present application show an
example of a known
configuration of at least one injector well and one production well in a heavy
oil deposit 1. As
16 shown in Figure 1(a), two vertically offset horizontal wells 5 and 10
are provided. These can be
17 previously existing horizontal wells that may have been drilled for
primary production or newly
18 drilled wells for secondary production processes such as SAGD or VAPEX.
Well Scan be used
19 to inject a solvent fluid, such as steam, propane, methane, etc., into
deposit 1 so as to create a
solvent fluid chamber 15 having an outer edge 20. Outer edge 20 has a given
surface area that
21 is in contact with the heavy oil of the deposit. The fluid along the
surface area of the outer edge
22 20 of the fluid chamber 15 interfaces with the heavy oil contained
within the deposit. If the fluid
23 is a solvent fluid such as methane, propane, etc., the solvent fluid at
the surface area of the
24 solvent fluid chamber will mix with the heavy oil along the surface area
of the fluid chamber
through known mechanisms such as diffusion, dispersion, capillary mixing, etc.
This "fluid over
26 oil" surface area mixing between the solvent fluid and the heavy oil of
the deposit will result in a
27 decrease in the viscosity of the heavy oil located near outer edge 20.
It will be understood that
28 the term "fluid over oil" surface area mixing refers to the type of
mixing that occurs when the
29 fluid of the fluid chamber mixes into the heavy oil of the deposit by
only diffusion, dispersion,
capillary mixing, etc. and is unaided by the effects of gravity, and will be
understood in greater
31 detail below. At some point during the "fluid over oil" surface area
mixing, the viscosity of the
32 heavy oil along the surface area of the solvent fluid chamber will have
been decreased
33 sufficiently to form decreased viscosity heavy oil which will begin to
flow to the production well
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1 10 under the influence of gravity as indicated by the arrows provided in
Figure 1(a). If steam is
2 used as the solvent fluid, it will be understood that while the steam per
se does not mix with the
3 heavy oil along the surface area, the heat of the steam will penetrate
the heavy oil so as to
4 decrease the viscosity of the heavy oil so as to begin or increase its
flow under gravity. As a
result of the mixing (such as, for example, if a solvent fluid is used in a
gaseous state) or the
6 heat transfer (such as, for example, if steam is used as the solvent
fluid), a volume 25 along the
7 horizontal well length of decreased viscosity oil having an outer edge 26
is formed allowing the
8 improved viscosity heavy oil within area 25 to flow by gravity into
production well 10 in the
9 direction provided in the arrows of Figure 1(a). As more solvent fluid or
steam is injected into
chamber 15 from well 5, fluid chamber 15 will begin to expand in the direction
of arrows 26a to
11 mix with the heavy oil contained in the deposit. As such, the outer edge
or border 26 of mixed
12 heavy oil and solvent fluid or steam will migrate or move through the
deposit as the steam or
13 gas mixes with the high viscosity heavy oil. In turn, the lower
viscosity heavy oil and solvent fluid
14 mixture will flow via gravity to the production well 10 thus reducing
the overall amount of heavy
oil in the deposit 1.
16 [0044] Similar to the configuration of Figure 1(a), Figure 1(b)
provides three offset horizontal
17 wells, two of which can be considered upper wells 30 and 35, laterally
offset from one another,
18 while the remaining well could be considered a lower well 40, laterally
and vertically offset from
19 upper wells 30 and 35. Similar to the process discussed in relation to
Figure 1(a), Figure 1(b)
provides that a solvent fluid is injected into the upper wells 30 and 35 to
form a fluid chamber 41
21 such that the heavy oil either mixes with the solvent fluid (e.g. in the
case of the methane, etc.)
22 or receives the heat of the solvent fluid thereby decreasing or reducing
the viscosity of the
23 heavy oil which then flows under the influence of gravity to producing
well 40.
24 [0045] In the prior art examples provided in Figure 1(a) and (b),
it will be understood that the
production of heavy oil from production wells 10 and 40 are limited by (a) the
rate at which the
26 decreased viscosity heavy oil or production oil flows under gravity to
the production well (the
27 "gravity drainage rate"); or (b) the rate of mixing of the solvent fluid
within the solvent fluid
28 chamber and the heavy oil contained within the reservoir or deposit
(hereinafter referred to as
29 the "solvent fluid/oil mixing rate"). Provided that the gravity drainage
rate is not the rate limiting
factor under reservoir conditions, the production of decreased viscosity heavy
oil or production
31 oil will generally be determined by the amount of decreased viscosity
heavy oil or production oil,
32 that has a viscosity sufficiently low to flow under gravity to the
production well. This in turn will
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1 be dependent upon the solvent fluid/oil mixing rate. The solvent
fluid/oil mixing rate is
2 influenced by the surface area of the solvent fluid chamber through which
the heavy oil and the
3 solvent fluid of the solvent fluid chamber can interact and by any
mechanisms which lead to
4 mixing of the heavy oil and the solvent fluid. In other words, if there
is an increase in the
surface area of the solvent fluid chamber so as to increase the solvent
fluid/oil contact area, the
6 solvent fluid/oil mixing rate will increase. In addition, any mechanisms
which can lead to
7 increased oil and solvent fluid mixing will increase the solvent
fluid/oil mixing rate which in turn
8 leads to an increase in the production of decreased viscosity heavy oil
(i.e. production oil) from
9 the reservoir. In order to maximize production from the producing well,
it is desirable, therefore,
to maximize the solvent fluid/oil mixing rate.
11 [0046] The present invention is directed, therefore, to maximizing
the solvent fluid/oil mixing
12 rate by increasing the surface area mixing of the solvent fluid in the
solvent fluid chamber with
13 the heavy oil of the deposit through directing the creation and
maintenance of a solvent fluid
14 chamber having a desired configuration or geometry. The solvent fluid
chamber of the present
invention has an increased surface area over solvent fluid chambers created
using previously
16 known methods of heavy oil production such as SAGD and VAPEX.
Embodiments of the
17 present invention provide for the use of horizontal or vertical
production/injection wells as well
18 as combinations thereof to direct and/or maintain the formation of a
solvent fluid chamber
19 having a geometry or configuration so as to maximize the solvent
fluid/oil mixing rate by
increasing the surface area mixing of the solvent fluid in the solvent fluid
chamber with the
21 heavy oil. The embodiments of the present invention involve directing
and maintaining the
22 creation or development of a solvent fluid chamber having a desired
geometry or configuration
23 between offset horizontal or vertical injection and production wells
through the use of
24 simultaneous solvent fluid injection and reservoir fluid production
between the offset wells and
alternating injection and production between them.
26 [0047] In accordance with the present invention, a solvent fluid
chamber having the desired
27 geometry or configuration can be formed between two vertically,
horizontally or laterally offset
28 wells so as to provide for increased mixing of the solvent fluid and
heavy oil. The wells of the
29 present invention could be either generally vertical or generally
horizontal wells or combinations
thereof. The solvent fluid chamber of the present invention increases the
mixing of the solvent
31 fluid within the solvent fluid chamber and the heavy oil of the deposit
by providing increased
32 surface area of the solvent fluid chamber, which provides for both
"fluid over oil" mixing and "oil
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1 over fluid" mixing. "Fluid over oil" mixing is discussed above in
relation to Figures 1(a) and 1(b).
2 It will be understood that "oil over fluid" mixing refers to the mixing
that occurs when the solvent
3 fluid of the solvent fluid chamber lies underneath the heavy oil of the
deposit. In other words, it
4 will be understood that at least a portion of the surface area of the
solvent fluid chamber is
disposed vertically below the heavy oil in the deposit. As a result of this
configuration, the
6 mixing of the heavy oil and the solvent fluid within the solvent fluid
chamber will be increased
7 relative to those chambers which provide predominately "fluid over oil"
mixing. In "fluid over oil"
8 mixing, the solvent fluid mixes with the heavy oil under known mechanisms
such as diffusion,
9 dispersion, capillary mixing, etc. However, with "oil over fluid" surface
area mixing there is an
additional mixing force at work, namely gravity. As the solvent fluid of the
solvent fluid chamber
11 typically has a lower density or is "lighter" than the heavy oil within
the deposit, the fluid will tend
12 to be influenced to migrate into the heavy oil due to its buoyancy. This
method of mixing could
13 be described as gravity induced counter-flow mixing of upper heavier oil
with a lower lighter
14 solvent fluid. Also, the heavy oil above the solvent fluid will also be
influenced to migrate into
the fluid chamber due to its higher density. In effect, the mixing of the
solvent fluid and the
16 heavy oil is increased due to the effect of the migration tendency of
the solvent fluid into the
17 heavy oil and vice versa. As a result, the solvent fluid chamber of the
present invention
18 increases the fluid/oil mixing rate due to the increases in surface area
and the increases in
19 overall mixing rate due to the additional mixing of oil over fluid
mixing not present in prior art
methods of heavy oil production.
21 Solvent Fluid Chamber Creation Using Horizontal Wells
22 [0048] In one embodiment, a solvent fluid is injected into the
well via the annulus. In a
23 preferred embodiment, the solvent fluid is injected into the reservoir
via a completion string.
24 [0049] In one embodiment, the wells may comprise one or more
completion strings, wherein
the one or more completion strings may include two or more flow control
devices, located on a
26 portion of the completion strings in the reservoir, for a uniform
injection of the solvent fluid into
27 the reservoir and uniform production of reservoir fluid from the
reservoir.
28 [0050] Referring to Figure 2, a capped well 200 is shown
comprising an annulus 300
29 defined by a well casing 400. The well 200 is provided with an annulus
dividing means 500 that
separates a portion of a completion string 202 located in the reservoir from a
portion of the
31 completion string located outside of the reservoir and of the casing
annulus 300. The portion of
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1 the completion string located in the reservoir is provided with at least
two flow control devices
2 203. Annular isolation means 210, 211, 214 and 215 are also provided for
the zonal isolation of
3 a portion of the completion string located in the reservoir. The annular
isolation means are
4 located internally of the horizontal well casing 700. Preferably, the
annular isolation means are
aligned with packers 216, 217, 218 and 219 located externally of the
horizontal well casing 700.
6 [0051] Preferably the horizontal well casing is provided with a
reticulated liner to prevent the
7 ingress of particulate matter from the reservoir. The reticulated liner
may be a slotted liner or a
8 sand screen of the type known to those of skill in the art.
9 [0052] In use, solvent fluid is injected through the completion
string into the reservoir. The
solvent fluid passes through the at least two flow control devices 203. The
solvent fluid enters
11 the reservoir by flowing through the reticulated liner to initiate and
develop a solvent fluid
12 chamber in the reservoir.
13 [0053] The completion string in accordance with the present
invention is also suitable for
14 extracting reservoir fluid from a reservoir. Reservoir fluid flows into
the completion string 202,
through the reticulated liner and at least two flow control devices 203. The
reservoir fluid is then
16 pumped out of the well through the completion string.
17 [0054] Referring to Figure 3, a preferred embodiment of the
present invention is shown.
18 The well 200 further comprises a production string 201. The completion
string further comprises
19 flow means 600 to permit fluid communication between the completion
string 202, the annulus
300 and the production string 201.
21 [0055] Optionally, the production string may be provided with a
pump 301.
22 [0056] In one embodiment, solvent fluid may be injected into the
reservoir through the
23 completion string. During this injection some of the solvent fluid may
escape from the
24 completion string 202 into the annulus 300 via the flow means 600.
However, as the well may
be capped and may be under pressure, such fluid escape may be limited. The
solvent fluid then
26 passes through the flow control devices 203. The solvent fluid enters
the reservoir by flowing
27 through the reticulated liner to initiate and develop a solvent fluid
chamber in the reservoir.
28 [0057] In another embodiment, solvent fluid may be injected
through the annulus 300 of the
29 well 200. When the well 200 is capped, solvent will flow from the
annulus 300 into the injection
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1 string 202 via flow means 600. The solvent fluid then passes through the
flow control devices
2 203. The solvent fluid enters the reservoir by flowing through the
reticulated liner to initiate and
3 develop a solvent fluid chamber in the reservoir.
4 [0058] The completion string in accordance with the present
invention is also suitable for
extracting reservoir fluid from a reservoir. Reservoir fluid flows into the
completion string 202,
6 through the reticulated liner and flow control devices 203. The reservoir
fluid then flows through
7 the portion of the completion string located in the reservoir. The
reservoir fluid then exits the
8 completion string through the flow means 600 into the annulus of the
well. The annulus dividing
9 means prevents the reservoir fluid from re-entering the portion of the
well located in the
reservoir. The reservoir fluid in the annulus in then extracted from the well
through the
11 production string, using pump 301, if required.
12 [0059] This arrangement is advantageous as it permits the uniform
injection of solvent fluid
13 into a reservoir and the uniform production of reservoir fluid from a
reservoir.
14 [0060] As will be understood by persons skilled in the art, the
arrangement in accordance
with the present invention is advantageous as, during fluid injection, when
the injection fluid is
16 flowing through the injection string, the fluid may be subjected to flow
friction, which results in a
17 frictional pressure loss, particularly when flowing through a horizontal
section of an injection
18 string.
19 [0061] This pressure loss normally exhibits a non-linear and
increasing pressure loss along
the injection string. Thus, the outflow rate of the solvent fluid into the
reservoir will also be non-
21 linear and may decrease in the downstream direction of the injection
string. At any position
22 along a horizontal injection string, for example, the driving pressure
difference (differential
23 pressure) between the fluid pressure within the injection string and the
fluid pressure within the
24 reservoir rock may exhibit a non-linear and greatly decreasing pressure
progression. Thereby,
the radial outflow rate of the injection fluid per unit of horizontal length
will be substantially
26 greater at the upstream "heel" portion of the horizontal section than
that of the downstream "toe"
27 portion of the well. Thus, the fluid injection rate along the injection
string thereby becomes
28 irregular. This causes substantially larger amounts of fluid to be
pumped into the reservoir at
29 the "heel" portion of the well than that the "toe" portion of the well.
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1 [0062] Accordingly, the solvent fluid will flow out of the
horizontal section of the well and
2 spread out within the reservoir as an irregular, non-uniform
(inhomogeneous) and partly
3 unpredictable injection front, inasmuch as the injection front drives
reservoir fluids towards one
4 or more production wells.
[0063] An uneven injection rate may also occur as a result of non-
homogeneity within the
6 reservoir. That part of the reservoir having the highest permeability
will receive most fluid. This
7 may also create an irregular flood front, and the fluid injection thus
becomes non-optimal with
8 respect to downstream recovery from production wells.
9 [0064] Thus, the present arrangement of two or more flow control
devices enables a uniform
and relatively straight-line injection front to be achieved, moving through
the reservoir and
11 pushing the reservoir fluid in front of it.
12 [0065] Advantageously, the arrangement of the present invention
also provides for the
13 uniform production of reservoir fluid along the length of a horizontal
well.
14 [0066] As will be appreciated by those of skill in the art, when
reservoir fluid flows
downstream and onwards in the horizontal section of a completion string, said
fluid is subjected
16 to flow friction in the form of a frictional pressure drop. In the
downstream direction, this
17 frictional pressure drop normally exhibits a non-linear and strongly
increasing pressure drop
18 gradient, particularly where this pressure drop gradient occurs largely
as a result of the
19 continual draining of new volumes of reservoir fluid into and along the
production tubing
downstream of said horizontal section. Thus, the flow rate of the fluids
increases in the
21 downstream direction. As a result of said pressure drop gradient, the
internal fluid flow in the
22 completion string will therefore exhibit a non-linear and greatly
decreasing fluid pressure
23 gradient in the downstream direction. When reservoir fluid extraction
from a reservoir is started,
24 the fluid pressure in the surrounding reservoir rock will often be
relatively homogenous and
change very little along the horizontal section. At the same time, the
frictional pressure drop of
26 the fluids when flowing from the reservoir rock and radially into the
completion string is small in
27 comparison with the frictional pressure drop of the fluids in and along
the horizontal section of
28 the well. At any position along this horizontal section, the pressure
difference (differential
29 pressure) that arises between the fluid pressure in the reservoir rock
and the corresponding fluid
pressure inside the production tubing will therefore exhibit a non-linear and
strongly increasing
31 differential pressure gradient. In practice, such a differential
pressure gradient allows the radial
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1 inflow rate of the fluid per unit length of the horizontal section to be
significantly greater at the
2 downstream side (the "heel" portion of the well) than at the upstream
side (the "toe" portion of
3 the well) of the horizontal section.
4 [0067] When producing hydrocarbons via a horizontal well, the
radial inflow rate per unit
length of the horizontal section is significantly greater in some reservoir
zones than in other
6 zones of the same reservoir, and that said former zones are drained
significantly faster than the
7 latter zones. For most horizontal wells, this means that most of the
hydrocarbon production is
8 produced from the reservoir zones at the downstream side of the
horizontal section, i.e. at the
9 "heel" portion of the well, while relatively small volumes of
hydrocarbons are produced from
zones along the remaining part of the horizontal section, and in particular
from the upstream
11 side of the horizontal section, i.e. the "toe" portion of the well. This
leads to some reservoir
12 zones being produced faster than other zones of the reservoir. Fluid
flow produced from the fast
13 draining zones may, at an earlier point than is desired, contain large
unwanted amounts of
14 solvent fluid. This variable production rate from the various zones of
the reservoir also cause
differences in fluid pressure between the reservoir zones, which may also lead
to the formation
16 fluids flowing among other things into and along an annulus between the
outside of the
17 completion string and the borehole wall of the well, instead of flowing
inside said completion
18 string.
19 [0068] Thus, the present arrangement of two or more flow control
devices, together with
annular isolation means advantageously enables a uniform production of
reservoir fluid along
21 the length of the completion string located in the reservoir in addition
to the uniform injection of
22 solvent fluid.
23 [0069] Of course, it will be further appreciated by those of skill
in the art that, in connection
24 with a horizontal well, it may also be desirable to create an injection
front having a geometric
shape that is, for example, curvilinear, arched or askew. Thereby, it is
possible, using the
26 arrangement of the present invention to better adjust, control or shape
the injection front relative
27 to the specific reservoir conditions and to the positions of other
wells.
28 [0070] In one embodiment, the two or more flow control devices may
be disposed in a
29 housing enclosing the completion string.
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1 [0071] In one embodiment, the two or more flow control devices may
have a diameter
2 greater than 1mm. In a further embodiment, the two or more flow control
devices may have a
3 diameter of about 2 to 5mm. It will be appreciated by those of skill in
the art that such diameters
4 are not intended to be construed as limiting the invention in any way.
Various other diameters
may be used depending upon various process and equipment configurations.
6 [0072] In yet a further embodiment, the two or more flow control
devices may be located at
7 varying distances along the portion of the injection string 202 located
in the reservoir. It will be
8 appreciated by those of skill in the art that the location of the flow
control devices will vary
9 considerably from well to well depending on such factors as local geology
and the like. In
another embodiment, the two or more flow control devices may be located at
regular intervals
11 along the portion of the injection string located in the reservoir. In
still a further embodiment,
12 high densities of flow control devices may be located at certain
intervals along the injection
13 string to maximize injection and extraction of fluid into and out of the
well. In still a further
14 embodiment, a flow control device may be provided at every joint of the
injection string.
Preferably, this may be every 13.5 metres. It will be appreciated by those of
skill in the art that
16 such distances are not intended to be construed as limiting the
invention in any way. Various
17 other distances may be used depending upon various process and equipment
configurations.
18 [0073] In another embodiment, the two or more flow control devices
may be arranged to
19 have varying diameters along the length of the well, as is generally
known to those of skill in the
art, in order to provide a uniform distribution of the solvent fluid into the
reservoir. In another
21 embodiment, the two or more flow control devices may be arranged such
that flow control
22 devices of smaller diameter are found upstream of the well, whilst flow
control devices of larger
23 diameter are found downstream of the well. This arrangement provides a
gradient of varying
24 flow control device diameters along the length of the well. In another
embodiment, the density
of the two or more flow control devices may be increased, while at the same
time maintaining a
26 constant diameter of the two or more flow control devices. It will be
appreciated by those skilled
27 in the art that other arrangements of flow control devices are not
excluded from the present
28 invention.
29 [0074] In one embodiment, the flow control devices may be inserts
that are inserted into
bores located in the completion string, that are of complementary
configuration to the inserts.
31 Alternatively, in another embodiment, the flow control devices may
comprise an adjustable
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1 sleeve or ball valve. The sleeves or ball valves may be adjusted
electrically, hydraulically or
2 electro-hydraulically.
3 [0075] In one embodiment, the annulus isolation means may be
provided by packers that
4 are generally known to those of skill in the art. In a further
embodiment, these packers may be
expandable packers. The expandable packers may expand in the presence of
liquid
6 hydrocarbons or water and provide zonal isolation of oil producing zones
in the wells. It will be
7 appreciated, by those of skill in the art, that although four packers are
shown, fewer or greater
8 numbers of these packers may be used. It will be further appreciated that
other packers,
9 generally known to those of skill in the art, may be used.
[0076] It is a further advantage of the present invention that the use of
annulus isolation
11 means enables discrete inflow and outflow zones of solvent fluid from
the completion string.
12 This may prevent unwanted cross- or transverse flows of solvent fluid in
the annulus during
13 injection. Preferably, each outflow zone may be provided with a
configuration of flow control
14 devices immediately prior to lowering and installing the completion
string in the well. This is
advantageous, as much of the reservoir and well information is often acquired
immediately prior
16 to installing a completion string. Thus, an optimal pressure profile for
the solvent fluid along the
17 completion string may be calculated immediately prior to installing the
string in the well. The
18 arrangement of annular isolation means together with the two or more
flow control devices
19 enables uniform injection and production profiles to be obtained.
[0077] Preferably, the completion string may also be used as a logging
string for the
21 collection of data from the well relating to, for example, temperature,
pressure and flow rates.
22 [0078] In a preferred embodiment, the arrangement of the present
invention is particularly
23 useful for extracting reservoir fluid from reservoirs comprising angled
or diagonal solvent fluid
24 chambers, where at least one first well is vertically and laterally
offset from at least one second
well.
26 [0079] As shown in Figures 4 to 7, wells 50 and 51 may comprise a
well arrangement
27 generally known to those of skill in the art. Preferably, wells 50 and
51 may comprise a well
28 arrangement as set forth in Figure 2. Most preferably, wells 50 and 51
may comprise a well
29 arrangement as set forth in Figure 3. Well 52 may comprise an
arrangement as set forth in
Figure 3 described above. One embodiment of the present invention provides for
the creation
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1 of a solvent fluid chamber between horizontal wells vertically and
laterally offset from one
2 another. As provided in figures 6 and 7, horizontal wells 50 and 51 can
be drilled generally
3 parallel to one another and generally parallel to the longitudinal axis
of reservoir or deposit 49 in
4 an upper portion of in situ reservoir or deposit 49 having heavy oil
contained therein. In Figures
4 to 7, the longitudinal axis of deposit 49 would be extending outwardly from
the page, e.g. in a
6 horizontal orientation, towards the viewer. Horizontal well 52 can also
be infill drilled so as to be
7 offset vertically and laterally from horizontal wells 50 and 51. It will
be understood that existing
8 wells from previous production of in situ deposit 49, which may have been
previously drilled,
9 may also be used. For example, horizontal wells 50, 51 or 52 may have
been used in primary
production of deposit 49.
11 [0080] As shown in Figure 5, solvent fluid (such as methane,
propane, etc.) can be injected
12 into horizontal well 52 while "reservoir fluid", which can consist of
one or more of decreased
13 viscosity heavy oil (e.g. production oil), water, pre-existing formation
gas (e.g. natural gas) or
14 solvent fluid is produced from horizontal wells 50 and 51. Production at
horizontal wells 50 and
51 continues until a significant amount (i.e. greater than 50%) of the
reservoir fluid produced at
16 wells 50 and 51 is solvent fluid. In other words, as production proceeds
at wells 50 and 51, the
17 percentage of solvent fluid of the total reservoir fluid produced will
increase, while the
18 percentage of the other components of the reservoir fluid produced will
decrease. When the
19 percentage of the solvent fluid is generally greater than 50% of the
solvent fluid produced
relative to the total reservoir fluid produced, significant solvent fluid
"breakthrough" has
21 occurred. As production proceeds at well 50 while solvent fluid is
simultaneously injected into
22 deposit 49 via well 52, a solvent fluid chamber 53a will be created (see
Figure 5) that is oriented
23 away from well 52 towards well 50. In general, and as shown in Figure 5,
the solvent fluid
24 chamber is delimited by upper and lower upwardly inclined boundaries.
The upper and lower
upwardly inclined boundaries converge towards well 50. Solvent fluid chamber
53a may, for the
26 purposes of illustration in Figure 5 and not to be considered limiting,
have a generally elongated
27 wedge shape with the apex generally oriented towards well 50 and the
elongated base oriented
28 towards and extending along the horizontal length of well 52. The volume
of the elongated
29 wedge base is generally largest nearest the injection well (e.g. well 50
in Figure 5) as this area
tends to have the highest volume of solvent fluid. As the process described
herein proceeds,
31 the solvent fluid chamber will continue to expand as more solvent fluid
is injected. It will be
32 understood however, that the specific configuration or geometry of
solvent fluid chamber 53a
33 will be dictated by reservoir conditions and by the injection and
production procedures as
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1 described herein. Similarly, as production proceeds at well 51 while
solvent fluid is injected into
2 deposit 49 via well 52, a second solvent fluid chamber 53b, similar in
configuration and
3 geometry to solvent fluid chamber 53a as noted above, will be created.
4 [0081] As shown in Figure 5, each of solvent chambers 53a and 53b
are angled or formed
"diagonally" between injection well 52 and each of wells 50 or 51. An aspect
of the present
6 invention is to create an upwardly inclined solvent fluid chamber for
each pair of injection and
7 production wells (e.g. 50 and 52 or 51 and 52), the upwardly inclined
solvent fluid chambers
8 each delimited by upper and lower upwardly inclined boundaries which tend
to converge
9 towards the upper well (e.g. 50).
[0082] The conditions under which this angled or diagonal solvent fluid
chamber is formed
11 between each pair of injection and production wells will depend on the
specific reservoir
12 conditions, such as horizontal and vertical permeability as well as the
viscosity of the heavy oil
13 in the deposit or reservoir. In other words, the reservoir conditions
will determine or dictate the
14 injection or production pressures and rates as well as pressure
gradients through which the
solvent fluid chambers of the present invention are formed and maintained. The
conditions that
16 will likely determine the formation of the solvent fluid chamber in
accordance with the present
17 invention include the rates and pressures at which a solvent fluid may
be injected into a deposit,
18 the horizontal and vertical permeability of a deposit, the rate or
pressure of production at the
19 producing wells and the pressure differential between the injection and
production wells. The
flow rate of fluid through a permeable matrix is proportionate to the
permeability and inversely
21 proportionate to the viscosity of the fluid. Hence, high permeability
and low viscosity oil will
22 result in and require high injection and production rates. In order to
direct the creation,
23 formation or maintenance of the upwardly inclined diagonal fluid
chamber, the injected fluid
24 must be forced or driven towards the production well and should not be
allowed to rise or gravity
override to the top of the reservoir as shown in Figure 1(b). In other words,
the viscous forces
26 created by pressure differentials and high flow rates should overcome or
dominate the gravity or
27 buoyancy force of the lighter injected solvent fluid. It will be
understood that as the horizontal
28 and vertical permeability of the deposit increases and/or the viscosity
of the heavy oil located
29 therein decreases, the ability of the solvent fluid to transverse the
deposit will increase. To
avoid a gravity overriding solvent chamber, as described herein, the creation,
formation or
31 maintenance of the solvent fluid chamber should be directed by
increasing or maximizing the
21632092.3 23
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1 injection rate at the injection well and increasing or maximizing the
production rate at the
2 production wells to accommodate the permeability and viscosity conditions
of the deposit.
3 [0083] In general, the solvent fluid injection rate should be as
much or as fast as possible
4 given the horizontal and vertical permeability of the deposit as well as
the viscosity of the heavy
oil (i.e. heavy oil and bitumen) deposited therein. Injection rates will
generally be high if the
6 horizontal or vertical permeability is high and/or the viscosity of the
heavy oil is low and vice
7 versa. In other words, the higher the permeability, the higher the
injection rate; conversely,
8 solvent fluid injection rates tend to be lower the higher the viscosity
of the heavy oil in the
9 deposit or reservoir. If the horizontal and vertical permeability of the
deposit is high (e.g.
generally exceeding 500 millidarcies (mD)), the injection rate should be
correspondingly high.
11 Similarly, the production rate at the producing wells should be as high
as possible given a
12 particular horizontal and vertical permeability of a given deposit and
the viscosity of the heavy
13 oil deposited therein.
14 [0084] By injecting the solvent fluid at a sufficiently high rate
as noted herein and producing
the reservoir fluid at a sufficiently high rate as noted herein, a pressure
gradient is created so as
16 to direct flow of the solvent fluid towards the production wells away
from the injection wells to
17 create an angled or diagonal solvent fluid chamber of the type or
geometry as described herein.
18 This directed flow arises because the solvent fluid channels through
deposit 49 to create the
19 solvent fluid chamber of the disclosed configuration or geometry. The
solvent fluid channelling
or preference direct flow arises because the solvent fluid, particularly when
it is a gas, will tend
21 to move or "channel" through the deposit due to the pressure
differential created between the
22 injection and production wells.
23 [0085] It will be understood that the actual or specific injection
and production rates may not
24 be a significant factor as each will likely depend on the reservoir
conditions. The directed
formation of the solvent fluid chamber of the desired configuration or
geometry may be more
26 influenced by the creation of a pressure gradient or pressure difference
between the injection
27 and production wells. Subject to equipment tolerances, the injection
rates and/or production
28 rates should be as high as possible under specific reservoir conditions.
29 [0086] As shown in Figures 5 to 7, the solvent fluid injected into
the deposit 49 via well 52
will tend to channel towards wells 51 and 50 to form two angled or diagonal
solvent fluid
31 chambers 53a and 53b. As noted above, the specific conditions under
which the angled or
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1 diagonal solvent fluid chambers can be created will vary for each
reservoir depending on the
2 reservoir conditions. In order to form diagonal solvent fluid chambers,
such as chamber 53a
3 between wells 50 and 52, as well as chamber 53b between wells 51 and 52,
the rate at which
4 the solvent fluid can be injected into well 52 should preferably be as
high as possible so that
injected solvent fluid directly channels through the heavy oil to wells 50 and
51, respectively.
6 Injection of the solvent fluid into well 52 must be at rates sufficiently
high to induce solvent fluid
7 channelling of the injected solvent fluid. Such injection rates may be
greater than 14,000
8 standard cubic meters per day (500,000 standard cubic feet per day). It
is also important to
9 produce wells 50 and 51 at the highest rates as possible so as to produce
the desired pressure
gradient. As such, an embodiment of the present invention provides for a
pressure gradient
11 exceeding 100 kPa up to a maximum not exceeding the fracture pressure of
the formation (e.g.
12 when the deposit or reservoir breaks apart) for heavy oil. It may even
be necessary to exceed
13 the fracture pressure if the viscosity is particularly high, such as for
bitumen.
14 [0087] If injection rates, production rates and pressure gradients
are not sufficiently high for
a given reservoir, the injected solvent fluid will preferentially rise to the
top of the reservoir due
16 to its natural buoyancy and form a solvent fluid chamber as shown in
Figures 1(a) and 1(b).
17 Such a solvent fluid chamber is known as a gravity overriding solvent
chamber. An additional
18 benefit of sufficiently high solvent fluid injection rates, high
production rates and high pressure
19 gradients between the wells is that solvent fluid injection and the
diagonal solvent fluid chamber
should occur along most of the length of the horizontal well. At low rates and
low pressure
21 gradients between the wells, the solvent fluid injection and chamber
formation may only occur
22 along less than 50% of the length of the horizontal well resulting in
low rates of oil production.
23 However, the present invention provides for solvent fluid chamber
formation in greater than 50%
24 the length of the horizontal well.
[0088] As shown in Figure 5, solvent fluid chambers 53a and 53b having the
desired
26 configuration and geometry can be formed between injection well 52 and
production wells 50
27 and 51 upon solvent fluid breakthrough at wells 50 and 51. As such, well
52 is in solvent fluid
28 contact with wells 50 and 51. Once the solvent fluid has reached wells
50 and 51 so as to
29 establish the angled or diagonal fluid chambers 53a and 53b, wells 50
and 51 are switched from
production of reservoir fluid to injection of solvent fluid into deposit 49.
Upon solvent fluid
31 breakthrough, well 52 can be simultaneously switched from injection of
solvent fluid to
32 production of reservoir fluid, including improved viscosity heavy oil
and solvent fluid. As shown
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1 in Figures 6 and 7, solvent fluid can be injected into deposit 49 via
wells 50 and 51 while
2 reservoir fluid is produced at well 52. In doing so, additional solvent
fluid chambers 55 and 54
3 are formed. Reservoir fluid, including decreased viscosity heavy oil or
production oil and
4 solvent fluid is then produced from well 52. As shown in Figures 6 and 7,
solvent fluid is
continuously injected into wells 50 and 51 such that solvent fluid chambers
53a, 53b, 54 and 55
6 expand in the directions of arrows 54a,b,c and 55a,b,c (see Figure 6),
such that reservoir fluid
7 can be produced from well 52. Eventually, continuous solvent fluid
injection into wells 50 and 51
8 and continuous production from well 52 can occur until the deposit has
had a significant portion,
9 such as 20-80%, of the heavy oil extracted.
[0089] It will be understood that some or all these steps can then be
repeated if, for
11 example, (a) if the solvent chamber configuration or geometry is not
achieved or is lost (e.g.
12 converts to a gravity overriding solvent chamber) due to equipment
failure or the process
13 stopped for whatever reason and the solvent fluid chamber needs to be re-
created; or (b) the
14 configuration, geometry or size of the solvent fluid chamber need to be
optimized (e.g. not
extending greater than 50% the length of the horizontal well). It will be
understood that prior to
16 production at wells 50 and 51, solvent fluid injection into these wells
can be done, particularly in
17 the presence of reservoirs with high bitumen content.
18 [0090] Unlike prior art methods, such as those shown in Figures
1(a) and 1(b), the above
19 noted embodiment of the present invention provides for an increase in
the recovery of heavy oil
contained in deposit 49. As noted above, the rate of heavy oil recovery will
be dependent on
21 the mixing of the solvent fluid within the solvent fluid chamber and the
heavy oil, namely the
22 "fluid/oil mixing rate". Unlike the prior art methods noted in Figures
1(a) and 1(b), this
23 embodiment of the present invention provides for both "fluid over oil"
surface area mixing as well
24 as "oil over fluid" surface area mixing. Gravity overriding solvent
fluid chambers 15 and 41 of
Figures 1(a) and 1(b) provide only "fluid over oil" surface area mixing. This
is in contrast to
26 solvent fluid chambers having the desired configuration or geometry
taught herein as shown in
27 Figures 5 to 7. As shown in Figure 7, the diagonal solvent fluid
chambers have two areas of
28 solvent fluid and oil surface area mixing, namely upper surfaces 60, 61
and lower surfaces 62,
29 63 of solvent fluid chambers 53a and 53b. "Fluid over oil" mixing will
occur at lower surfaces 62
and 63 of solvent fluid chambers 53a and 53b, respectively. Similarly, there
will be "fluid over
31 oil" surface area mixing along the lower surfaces 62 and 63 of solvent
fluid chambers 54 and 55.
32 In addition to the "fluid over oil" mixing occurring at those surfaces,
there will also be "oil over
21632092.3 26
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1 fluid" surface area mixing at the upper surfaces 60 and 61 of solvent
chambers 53a and 53b. As
2 such there will be increased mixing in the "diagonal" solvent fluid
chambers of the present
3 invention over the methods known in the prior art. The increased solvent
fluid and oil mixing will
4 result in a higher production at well 52.
[0091] Eventually, continuous solvent fluid injection into horizontal wells
50 and 51 and
6 continuous production from horizontal well 52 can occur until deposit or
reservoir 49 has had a
7 significant portion, such as 20 to 80% of the heavy oil extracted.
Likewise, injection rates into
8 the horizontal wells can be adjusted to maximize the recovery of heavy
oil. If injection and
9 production rates are too low, a gravity overriding chamber could form,
reducing the recovery of
heavy oil. Injection and production rates must be sufficiently high to
maintain the diagonal or
11 directed chamber. If injection rate is too high, more solvent may break
through and may need to
12 be re-injected and re-cycled. It will be understood that as heavy oil is
being extracted from the
13 area surrounding wells 50, 51 and 52, then extracting using the process
noted above can
14 concurrently or subsequently be implemented to other existing or inf ill
drilled horizontal wells
(not shown) within reservoir 49.
16 [0092] As the present invention provides for the creation of an
angled or diagonal solvent
17 fluid chamber between an injection horizontal well and an offset
producing horizontal well, it will
18 be understood that factors that may impact the solvent fluid channelling
through the deposit may
19 have an impact on the process of the invention. For example, in
formations where bottom water
is present, the presence of bottom water may assist in the formation of the
diagonal solvent fluid
21 chamber due to the increased mobility of the solvent fluid through the
water at the top of the oil-
22 water transition zone.
23 Solvent Fluid Chamber Creation Using Horizontal and Vertical Wells
24 [0093] As shown in Figures 8 to 12, another embodiment of the
present invention provides
for the use of horizontal and vertical production and injection wells to
direct the formation of
26 solvent fluid chambers having a desired geometry or configuration.
Instead of using horizontal
27 wells only, this embodiment involves recovery using vertical
injection/production wells as well as
28 horizontal injection/production wells. This embodiment involves
directing and maintaining the
29 creation or development of a solvent fluid chamber having a desired
geometry or configuration
between offset vertical injection and production wells with horizontal
production and injection
31 wells through the use of simultaneous solvent fluid injection and
reservoir fluid production
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1 between the offset vertical and horizontal wells and alternating the
injection and production
2 between them.
3 [0094] As with the other embodiment of the present invention, the
objective of this
4 embodiment is to obtain improved mixing of solvent fluid with heavy oil
so as to reduce the
viscosity of an increased amount of heavy oil allowing decreased viscosity
heavy oil or
6 production oil to be produced. Instead of using horizontal wells only,
this embodiment involves
7 recovery or production using vertical injection or production wells. This
embodiment involves
8 the creation of a solvent fluid chamber between vertical injection and
production wells and with
9 offset horizontal production and injection wells.
[0095] In the heavy oil reservoir with or without existing vertical wells,
the configuration or
11 geometry of the solvent fluid chamber is determined by use of
alternating the injection of solvent
12 fluid and the production of reservoir fluid, containing production oil,
through the use of vertical
13 and horizontal wells. For example, vertical wells can be drilled (if no
existing vertical wells) and,
14 offset to these vertical wells, parallel horizontal producing wells can
be drilled (if no pre-existing
wells) close to the bottom of the formation (e.g. within 1 meter). In this
embodiment, a solvent
16 fluid chamber is first established between the vertical injection wells.
This is accomplished by
17 injecting solvent fluid and producing reservoir fluid simultaneously
between paired vertical wells.
18 For example, solvent fluid can be injected into a first vertical well
while producing a second
19 vertical well until significant solvent fluid breakthrough occurs.
Solvent fluid can also be injected
next into the first and second vertical well while producing from an offset
third vertical well for a
21 desired time. This process is continued until a solvent fluid chamber
has the desired geometry
22 or configuration. Solvent fluid can then be injected into a horizontal
well at pressures higher
23 than at the vertical wells so as create a second solvent fluid chamber,
thus reducing the
24 viscosity of the surrounding heavy oil. Solvent fluid can be injected
into the vertical wells and
reservoir fluid, and then production oil, can be produced from the horizontal
wells until depletion
26 of the reservoir.
27 [0096] As shown in Figures 8 to 12, there are existing or infill
drilled vertical wells 100, 102,
28 104, 106, 108 and 110 in a typical spatial arrangement of vertical
production and injection wells
29 within reservoir or deposit 90. It will be understood that the injection
pattern can be selected
based on the location of existing wells, reservoir size and shape, cost of new
wells and the
31 recovery increase associated with the various possible injection or
production patterns.
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1 Common injection patterns are direct line drive, staggered line drive,
two-spot, three-spot, four-
2 spot, five-spot, seven-spot and nine-spot.
3 [0097] Solvent fluid can be first injected into deposit 90 through
vertical well 108.
4 Simultaneously, reservoir fluid is produced at vertical well 106. For
reasons noted above, this
will induce the formation of solvent fluid chamber 118a, as shown in Figure 8.
As the solvent
6 fluid is injected into reservoir 90 through well 108 while reservoir
fluid is produced at well 106,
7 solvent fluid chamber 118a will expand to 118b and eventually 118c, at
which point solvent fluid
8 breakthrough can occur. As a result, a continuous solvent fluid chamber
118c is created
9 between wells 108 and 106. As noted above with respect to solvent fluid
chamber 53a, solvent
fluid chamber 118c has a generally conical shape preferentially distorted in
the direction of well
11 106. The generally conical shape of solvent fluid chamber 118c is
oriented in the vertical
12 direction with its longitudinal axis parallel to the vertical axis of
well 108. The conical apex of
13 solvent fluid chamber 118c is generally oriented away from the upper
portion of vertical well 108
14 and deposit 90 and points towards the lower portion of vertical well 108
and deposit 90, while
the conical base is generally oriented towards the upper portion of well 108
and deposit 90. The
16 conical base is generally widest nearest the upper portion of injection
well 108 as this area
17 tends to have the highest concentration of solvent fluid. As the process
described herein
18 proceeds, solvent fluid chamber 118c will expand both at the conical
base and the conical apex
19 outwardly from vertical well 108 as more solvent fluid is injected. It
will be understood however,
that the specific configuration or geometry of solvent fluid chamber 118c will
be dictated by
21 reservoir conditions.
22 [0098] As noted previously, the solvent fluid injection rate at
108 and reservoir fluid
23 production rate at well 106 must be sufficiently high for the solvent
fluid to channel as directly as
24 possible from well 108 towards well 106 possibly at solvent fluid
injection rates exceeding 3,000
standard cubic meters per day (100,000 standard cubic feet per day). It is
also important that
26 the pressure gradient between 108 and 106 be very high as possible,
possibly exceeding 100
27 kPa pressure. The solvent fluid breakthrough and flow between these
vertical wells must be
28 enough in volume and time to create a stable and reasonable sized
solvent fluid chamber 118c.
29 The solvent fluid breakthrough and cycling time between these wells
should be one or more
months long. The reservoir conditions (e.g. net oil pay, porosity and
permeability) and field
31 application (e.g. distance between wells and injection and productions
rates) will determine the
32 solvent fluid injection rate, volume and time.
21632092.3 29
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1 [0099] If solvent fluid breakthrough does not occur then one or
more infill vertical wells
2 between wells 106 and 108 can be drilled (not shown). It will be
understood that several
3 reasons could account for the failure of the solvent fluid to break
through, such as reservoir
4 discontinuity, geological barriers, poor permeability or the inter-well
distance is too great due to
the high viscosity of the heavy oil. For example, if an infill vertical well
was made between wells
6 106 and 108, solvent fluid injection could continue at well 108 with
simultaneous reservoir fluid
7 production from newly infill drilled adjacent vertical well until
significant solvent fluid
8 breakthrough occurs at the newly infill drilled adjacent vertical well.
Once solvent breakthrough
9 occurs at the newly infill drilled adjacent vertical well, solvent fluid
injection can cease at vertical
well 108 while the newly infill drilled adjacent vertical well switches from
production to injection
11 of solvent fluid. The solvent fluid can then be injected into the newly
infill drilled adjacent
12 vertical well while producing from next adjacent well such as vertical
well 106 until solvent fluid
13 breakthrough occurs at well 106.
14 [00100] Following solvent fluid breakthrough at well 106, solvent
fluid injection at well 108
continues while well 106 is converted from production to solvent fluid
injection. In other words,
16 vertical well 106 is used to inject solvent fluid into fluid chamber
118c. Production is switched to
17 vertical wells 104 and 110. For the reasons noted above, a pressure
gradient will be created
18 through which the solvent fluid chamber 118c will expand towards wells
110 and 104. As with
19 the solvent fluid chamber development between 106 and 108, solvent fluid
injection rates,
reservoir fluid production rates and the pressure gradient between the
injection and production
21 wells must be sufficiently high for the solvent fluid to channel from
106 towards 104 and from
22 108 towards 110. As shown in Figure 8, solvent fluid chamber 121a is
created by the
23 simultaneous production of reservoir fluid at well 110 and the injection
of solvent fluid at well
24 108. As this simultaneous production and injection proceeds, solvent
chamber 121a expands to
121b. Similarly, solvent fluid chamber 120a is created by the simultaneous
production of
26 reservoir fluid at well 104 and the injection of solvent fluid at well
106. As this simultaneous
27 production and injection proceeds, solvent chamber 120a expands to 120b.
It is not necessary
28 for solvent fluid chambers 121b and 120b to extend to the point of
solvent breakthrough at wells
29 110 and 104 respectively. Typically, the elongated gas chambers around
the vertical wells
should be slightly greater in length than the adjacent horizontal wells.
However, it will be
31 understood that the process could proceed until solvent fluid
breakthrough occurs at wells 110
32 or 104. As shown in Figure 8, simultaneous injection and production at
wells 104, 106, 108 and
33 110 as noted above results in the formation of solvent fluid chamber
122.
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1 [00101] Once the solvent fluid chamber 122 has between established,
injection of solvent
2 fluid into these wells and into the solvent fluid channels and chamber is
similar to injecting
3 solvent fluid into a hypothetical horizontal well extending between these
wells and along the
4 solvent fluid channel. Simply, the vertical wells in conjunction with the
solvent fluid channel and
chamber should act like a horizontal well. Unlike horizontal well injection,
the injection and
6 production rates can be adjusted between the vertical wells providing
some control over the
7 injection profile into the solvent fluid chamber and its composition.
When solvent is injected into
8 a horizontal well, most of the solvent could preferentially enter the
reservoir in certain parts of
9 the horizontal well bore resulting in a poor uneven injection profile. If
2-4 vertical wells act as a
horizontal well, having control over the injection of each vertical well
provides some control over
11 the injection profile into the solvent chamber.
12 [00102] Upon formation of solvent fluid chamber 122 as shown in Figure
9, solvent fluid can
13 then be injected into new or previously existing horizontal wells 112
and 114 either
14 simultaneously or alternately (e.g. inject solvent into 112 and shut in
or produce 114 then inject
into 114 and shut in or produce 112) at injection pressures higher than the
reservoir pressures
16 at vertical wells 106 and 108, and the reservoir pressure of solvent
fluid chamber 122 between
17 106 and 108, as it will be understood that the reservoir pressures at
wells 106 and 108 or in
18 chamber 122 may not be the same. As described above in reference to
Figure 3, it will be
19 understood that the horizontal wells 112 and 114 may include completion
and production
strings. In addition, the completion strings may be provided with flow control
devices as
21 discussed above. The injection pressures and/or rates at horizontal
wells 112 and 114 should
22 be as high as possible as noted above in order to direct the injected
solvent fluid to channel
23 laterally outwards from horizontal wells 112 and 114 towards vertical
wells 106 and 108,
24 respectively and solvent fluid chamber 122, as shown in Figure 9. If
there is no production at
wells 108 and 106, the only pressure forcing the solvent fluid chamber to
expand is the injection
26 pressure from wells 112 and 114. However, there can be injection or
production at wells 106
27 and 108, if needed, depending on reservoir conditions to create the
solvent fluid chamber
28 having the desired configuration. In addition to the pressure or rates
being sufficiently high to
29 direct the formation of horizontal solvent fluid chambers 126 and 127
laterally towards vertical
fluid chamber 122, the solvent fluid injection pressures or rates must also be
sufficient to create
31 these solvent fluid chambers along most (e.g. greater than 50%) of the
longitudinal length of
32 each of horizontal wells 112 and 114. As shown in Figure 9, horizontal
wells 112 and 114 inject
33 solvent fluid into reservoir or deposit 90 to create horizontal solvent
fluid chambers 126 and 127.
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1 Solvent fluid chambers 126 and 127 are generally fusiformed or spindle
shaped but distorted
2 laterally and upwards along the horizontal axis of wells 112 and 114.
3 [00103] Horizontal wells 112 and 114 are then converted to
production of reservoir fluid,
4 while vertical wells 106 and 108 continue to inject solvent fluid into
solvent fluid chamber 122.
For the reasons noted herein, a pressure gradient will be created through
which the solvent fluid
6 chamber 122 will expand laterally towards wells 112 and 114, as shown in
Figures 8 and 9. As
7 with the solvent fluid chamber development between the vertical wells,
fluid injection rates,
8 reservoir fluid production rates and the pressure gradient between the
vertical injection wells
9 106 and 108 as well as the horizontal production wells 114 and 112 must
be sufficiently high for
the solvent fluid to channel from existing solvent fluid chamber 122 towards
horizontal solvent
11 fluid chambers 126 and 127. As shown in Figure 9, solvent fluid chamber
122 expands laterally
12 into 122a due to the simultaneous production of reservoir fluid at wells
112 and 114 and the
13 injection of solvent fluid at wells 106 and 108. As this simultaneous
production and injection
14 proceeds, solvent chambers 122a, 126 and 127 expand to 122b, 126a and
127a, respectively.
This process continues until the expanding solvent fluid chamber 122, 122a and
122b converge
16 with the expanding solvent fluid chambers 126, 126a, 127 and 127a. As
shown in Figure 10,
17 solvent fluid chamber 128 is in solvent fluid connection with fluid
chambers 126 and 127.
18 [00104] Figures 11 and 12 provide cross-sectional views of the
configuration or geometry of
19 the solvent fluid chambers 127 and 128. It will be understood that a
cross-sectional view of fluid
chamber 126 and 128 would be the same as seen in Figure 11; therefore only the
solvent fluid
21 chamber at 127 and 128 will be described. As seen in Figure 11,
elongated solvent fluid
22 chambers in fluid connection are formed at each of vertical wells 106
and 108. While it will be
23 understood that the specific configuration or geometry of solvent fluid
chamber 128 will be
24 dictated by reservoir conditions, it is seen in Figure 11 as two
generally conical shaped solvent
fluid chambers as described above. As noted above, solvent fluid chamber 127
is generally
26 fusiformed or spindle shaped along the horizontal axis of well 112. As
seen in Figure 12, two
27 angled or diagonal solvent fluid chambers in fluid connection are formed
at each of horizontal
28 wells 112 and 114.
29 [00105] It will be understood that some or all these steps can
then be repeated if, for
example, (a) the solvent chamber configuration or geometry is not achieved or
is lost (e.g.
31 converts to a gravity overriding solvent chamber) due to equipment
failure or process stoppage
21632092.3 32
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1 for any reason and the solvent fluid chamber needs to be re-created; or
(b) the configuration,
2 geometry or size of the solvent fluid chamber need to be optimized (e.g.
create more solvent
3 fluid chamber along the horizontal well, creating more of a solvent fluid
chamber between the
4 vertical wells or changing the composition of the solvent).
[00106] Eventually, continuous solvent fluid injection into vertical wells
106 and 108 and
6 continuous production from horizontal wells 112 and 114 can occur until
deposit or reservoir 90
7 has had a significant portion, such as 20-80%, of the heavy oil
extracted. Likewise, injection
8 rates into the vertical wells can be adjusted to maximize the recovery of
heavy oil and bitumen.
9 It will be understood that as the heavy oil is being extracted from the
area surrounding vertical
wells 106 and 108 as well as horizontal wells 112 and 114, then extracting
using the process
11 noted above can concurrently or subsequently be implemented to wells 100
and 102 or others
12 within the area of reservoir 90.
13 [00107] Although the invention has been described with reference to
certain specific
14 embodiments, various modifications thereof will be apparent to those
skilled in the art without
departing from the purpose and scope of the invention as outlined in the
claims appended
16 hereto. Any examples provided herein are included solely for the purpose
of illustrating the
17 invention and are not intended to limit the invention in any way. Any
drawings provided herein
18 are solely for the purpose of illustrating various aspects of the
invention and are not intended to
19 be drawn to scale or to limit the invention in any way. The disclosures
of all prior art recited
herein are incorporated herein by reference in their entirety.
21
21632092.3 33
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Example 1 ¨ Producing Heavy Oil By Creating and Maintaining Diagonal Solvent
Chambers using Horizontal Wells
Step Rate Pressure Duration
Expected Results
la ¨ Inject solvent into well 52 Very high rates, Highest
injection Roughly 1 Significant gas channelling
until significant solvent possibly exceeding pressures in
excess of month occurring from well 52 to 50
breakthrough to wells 50 & 51 28,000 standard
100 kPa above reservoir and from well 52 to 51
m3/d pressure
lb ¨ Simultaneously with step Very high rates Highest
production Roughly Oil production along with
la produce reservoir fluids drawdown at inflow
simultaneously significant gas channelling
from wells 50 & 51 and solvent pressures in excess of
with step la occurring from well 52 to 50
as it channels from well 52 100 kPa below reservoir
and from well 52 to 51 0
pressure
0
1.)
01
0
Step 2a ¨ Inject solvent in wells Very high rates, Highest
injection Roughly 1 Significant gas
channelling 0.
..3
50 & 51 until significant solvent possibly exceeding a pressures in excess of
month occurring from well 50 to 52
1.)
production occurs at well 52 total of 28,000
100 kPa above reservoir and from well 51 to 52 1.)
standard m3/d pressure
0
1-,
w
1
2b ¨ Simultaneously with 2a Very high rates Highest
production Roughly Oil and some solvent
0
I
produce reservoir fluids and drawdown at inflow
simultaneously production along with 0
0.
solvent from well 52 and more pressures in excess of
with step 2a significant gas channelling
solvent as it channels from 100 kPa below reservoir
occurring from well 50 to 52
wells 50 & 51 pressure
and from well 51 to 52
3+ - Repeat steps la, 1 b, 2a Very high rates As above
Roughly 1 Oil and solvent production
and 2b numerous times until month for each
with significant gas
wells 50 & 51 produce less oil step
channelling with diagonal
than well 52 and too much gas
chamber growth in size and
along most of the horizontal
lengths of each well
21632092.3 34
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Step Rate Pressure Duration
Expected Results
4 ¨ Continuously inject solvent At maximum oil
At drawdown pressures Continuously Oil production, solvent
into wells 50 & 51 and production rate and that maximize
oil until depletion of production
continuously produce oil and minimum solvent production and
minimize the reservoir
solvent from well 52 gas recycling gas recycling
Example 2 ¨ Producing Heavy Oil By Creating and Maintaining Solvent Chambers
using Horizontal Producing Wells &
Vertical Injection Wells
0
Step Rate Pressure Duration
Expected Results 0
1.)
01
0
la ¨ Inject solvent into Very high rates,
Highest injection pressures Roughly 1 month Significant gas channelling
0.
..3
vertical (vt.) well 108 until possibly in excess of
100 kPa or until a occurring from well 108 to
1.)
significant solvent exceeding 14,000 above reservoir pressure
significant and 106 and forming a stable gas 1.)
breakthrough to vt. well 106 standard m3/d
stable gas channel with high gas 0
1-,
channel forms
saturation w
1
1-,
0
1
lb ¨ Simultaneously produce Very high rates Highest
production Roughly Oil production along
with 0
0.
reservoir fluids from well 106 drawdown at inflow simultaneously
significant gas channelling
and solvent as it channels pressures in excess of 100 with step
la occurring from well 108 to
from well 108 kPa below reservoir
106 as described above
pressure
2¨ Inject solvent in wells 108 Very high rates,
Highest injection pressures Roughly 0.5-1 Significant gas channelling
& 106 while producing possibly in excess of 100 kPa month.
Injection occurring from well 108
reservoir fluid from wells 110 exceeding a total above reservoir
pressure time to be more towards 110 and from well
and 104 so as to channel gas of 28,000 than half the
106 towards 104. inject for a
towards 110 and 104 standard m3/d breakthrough
time time longer than half the
in step la
breakthrough time measured
in steps la and lb
21632092.3 35
CA 2,584,712
Blakes Ref: 80545/00219
Step Rate Pressure Duration
Expected Results
3 ¨ Inject solvent in Very high rates, Highest injection pressures
Roughly 1 month Significant gas channelling
horizontal (hz.) wells 112 & possibly
in excess of 100 kPa occurring from hz wells 112
114 while wells 108 and 106 exceeding a total
above the reservoir and 114 towards the gas
are preferably shut in but of 28,000
pressures at wells 108, chamber around wells 106
these wells could be standard m3/d 106 and their gas chamber
and 108
producing pressure
4a ¨ Produce reservoir fluids Very high rates Highest
production Roughly 1 month Oil and some solvent
and solvent from hz wells drawdown at inflow
production
112 and 114 pressures in excess of 100
kPa below reservoir
pressure
0
1.)
4b - Inject solvent in wells Very high rates,
Highest injection pressures Roughly Significant gas channelling
108 & 106 while producing possibly in excess of
100 kPa simultaneously occurring from the gas
0
reservoir fluid from wells 112 exceeding a total above reservoir
pressure with step 4a chamber around wells 106
and 114 to channel gas of 28,000
and 108 towards the gas
0
toward 112 and 114 and standard m3/d
chambers around wells 112
0
expand the gas chamber
and 114
around wells 108 &106
5+ - Repeat steps 4a and 4b Very high rates As above
Roughly 1 month Oil and solvent production
numerous times until the gas for each step
from 112 and 114 with
chambers around the hz
significant gas channelling
wells 112 and 114
with growth of the gas
significantly connects with
chamber along most of the
the gas chamber around
horizontal lengths of each
wells 108 & 106
well and also growth of the
gas chamber around wells
108 & 106
21632092.3 36
CA 2,584,712
Blakes Ref: 80545/00219
Step Rate Pressure Duration
Expected Results
6 ¨ Continuously inject At maximum oil At drawdown
pressures Continuously until Oil production, solvent
solvent into wells 106 & 108 production rate that maximize
oil depletion of the production
and continuously produce oil and minimum production and minimize
reservoir
and solvent from hz wells solvent gas gas recycling
112 and 114 recycling
ci
1.)
0
If
0
21632092.3 37
