Note: Descriptions are shown in the official language in which they were submitted.
DIMETHYL ETHER-BASED METHOD FOR RECOVERING VISCOUS OIL FROM A
WATER-WET RESERVOIR
RELATED APPLICATION:
[0001] The present disclosure claims priority to U.S. Provisional Patent
Application No. 62/927,847, filed October 30, 2019, the entire contents of
which are
incorporated by reference herein.
TECHNICAL FIELD:
[0002] The present disclosure relates to oil recovery methods. More
particularly,
the present disclosure relates to solvent-based in situ thermal oil recovery
methods.
BACKGROUND:
[0003] Steam-based thermal oil recovery processes, including steam
flooding,
cyclic steam stimulation (CSS) and steam-assisted gravity drainage (SAGD) are
commercially well-established processes. In these processes, the temperature
of the
reservoir is typically raised to 200 C or more by injection of steam to reduce
the
viscosity of crude oil therein. Steam consumption in these processes is high,
ranging
from about two to six volumes of steam on a liquid (water) equivalent basis
per volume
of produced oil. High steam demand creates both economic and environmental
performance challenges, including high capital and operating costs for large
capacity
water treatment and steam generation facilities, high water consumption rates,
and high
greenhouse gas emission intensity.
[0004] To improve or replace steam-based processes, much effort has been
devoted to the development of recovery processes that use solvents that are
effective in
reducing the viscosity of crude oil by dilution. Various solvent-dominated or
solvent-
assisted processes have been proposed including processes comprising injecting
solvent alone at ambient reservoir temperature, injecting heated solvent
alone, or co-
injecting solvent as an additive to steam. However, no solvent-dominated
process, i.e.
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Date Recue/Date Received 2020-10-27
where a high partial pressure of steam is not the dominant factor in
mobilizing viscous
oil, has yet been deployed at commercial scale.
[0005] The viability of solvent-dominated processes is challenged by
comparatively low oil production rates, which are typically significantly less
than what
can be achieved with competing steam-dominated processes. This results from
the fact
that, under reservoir conditions and typical operating pressure constraints,
molecular
diffusion (of hydrocarbon solvent into oil) is significantly lower than
thermal diffusivity.
Solvent-dominated processes may also be challenged by high costs associated
with
accumulation or loss of solvent in the depleted reservoir.
[0006] Dimethyl ether (DME) has been suggested as a potential candidate
solvent for use in viscous oil recovery processes. DME has significant
solubility in
bitumen and heavy oils, is relatively inexpensive, and is not associated with
any known
health or environmental concerns. Canadian Patent No. 2,652,930 discloses an
example of a DME-based oil recovery process in which heated DME alone (in
vapor or
liquid form) is injected into a SAGD-type well configuration. However, DME-
only
processes may face similar challenges as other solvent-dominated processes
including
relatively low oil production performance compared to steam-dominated
processes.
[0007] DME has also been proposed as an additive in steam-dominated
processes including variations on SAGD as described, for example, in U.S.
Patent No.
10,125,591 and Canadian Patent Application No. 2,936,649. However, in a study
by
Haddadnia et al., a steam-dominated process with about 5% DME on a liquid
volume
basis was found to provide a higher oil production rate than steam alone but a
lower oil
production rate than steam combined with a hydrocarbon solvent additive (i.e.
butane)
(Haddadnia et a/., "Dimethylether ¨ A promising solvent for ES-SAGD", Society
of
Petroleum Engineers 2018 SPE-189741-MS). In addition, steam-dominated
processes
that include DME as an additive still require high steam consumption and high
operating
temperatures.
2
Date Recue/Date Received 2020-10-27
SUMMARY:
[0008] In one aspect, there is provided a method of recovering viscous
oil from a
subterranean reservoir having at least one injection well and at least one
production
well installed therein, the method comprising: establishing flow communication
between
the at least one injection well and the at least one production well;
injecting a heated
vapor-phase working fluid comprising vapor-phase dimethyl ether (DME) and
vapor-
phase water via the at least one injection well and producing a production
fluid via the at
least one production well; wherein the vapor-phase water is about 5% or lower
of a total
volume of the heated vapor-phase working fluid by liquid volume equivalent.
[0009] In some embodiments, a ratio of vapor-phase DME to vapor-phase
water
is between about 20:1 and about 250:1 by liquid volume equivalent.
[0010] In some embodiments, injecting the heated vapor-phase working
fluid
comprises co-injecting a first fluid stream comprising heated vapor-phase DME
and a
second fluid stream comprising heated vapor-phase water such that the first
fluid
stream and second fluid stream combine in the at least one injection well to
form the
heated vapor-phase working fluid.
[0011] In some embodiments, the first fluid stream is injected at a first
temperature and the second fluid stream is injected at a second temperature.
[0012] In some embodiments, the first temperature and the second
temperature
are each between about 50 C and about 250 C.
[0013] In some embodiments, the method further comprises forming the
heated
vapor-phase working fluid prior to injection.
[0014] In some embodiments, the heated vapor-phase working fluid is
injected at
a temperature of between about 50 C to about 250 C.
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Date Recue/Date Received 2020-10-27
[0015] In some embodiments, the method further comprises maintaining a
vapor
chamber operating temperature of between about 50 C and about 100 C during
injection of the heated vapor-phase working fluid.
[0016] In some embodiments, at least one heater is installed in the at
least one
injection well and/or the at least one production well and wherein maintaining
the
operating temperature comprises heating the at least one injection well and/or
the at
least one production well via the at least one heater.
[0017] In some embodiments, the heated vapor-phase working fluid further
comprises at least one volatile hydrocarbon solvent.
[0018] In some embodiments, the method further comprises adjusting a
concentration of the at least one volatile hydrocarbon solvent based on a
desired
degree of asphaltene precipitation.
[0019] In some embodiments, the heated vapor-phase working fluid further
comprises at least one non-condensable gas.
[0020] In some embodiments, the method further comprises separating at
least a
portion of produced DME from the production fluid.
[0021] In some embodiments, the method further comprises recycling the
produced DME to form new heated vapor-phase working fluid.
[0022] In some embodiments, establishing flow communication comprises
injecting a liquid-phase initialization fluid via the at least one injection
well, the at least
one production well, or both the at least one injection well and the at least
one
production well.
[0023] In some embodiments, the liquid-phase initialization fluid
comprises liquid-
phase DME.
4
Date Recue/Date Received 2020-10-27
[0024] In some embodiments, the liquid-phase initialization fluid further
comprises at least one liquid-phase hydrocarbon solvent.
[0025] In some embodiments, establishing flow communication further
comprises: ceasing injection of the liquid-phase initialization fluid; and
injecting a heated
vapor-phase initialization fluid and producing an initial production fluid via
the at least
one injection well, the at least one production well, or both the at least one
injection well
and the at least one production well.
[0026] In some embodiments, the heated vapor-phase initialization fluid
comprises vapor-phase DME and vapor-phase water and wherein the vapor-phase
water is about 5% or lower of a total volume of the heated vapor-phase
initialization fluid
by liquid volume equivalent.
[0027] In some embodiments, the heated vapor-phase initialization fluid
further
comprises at least one vapor-phase hydrocarbon solvent.
[0028] In some embodiments, the method further comprises ceasing
injection of
the heated vapor-phase working fluid and injecting a non-condensable gas via
the at
least one injection well and producing at least a portion of remaining DME in
the
reservoir via the at least one production well.
[0029] In another aspect, there is provided a system for recovering
viscous oil
from a subterranean water-wet reservoir, comprising: at least one injection
well and at
least one production well installed in the subterranean water-wet reservoir;
at least one
heating system; a control system operatively connected to the at least one
heating
system and configured to implement embodiments of the methods described
herein.
[0030] In some embodiments, the at least one injection well and the at
least one
production well comprise a plurality of well pairs and a ratio of inter-well-
pair spacing to
pay interval thickness is about 4:1 or lower.
[0031] In some embodiments, the at least one injection well and the at
least one
production well are each non-thermally completed.
Date Recue/Date Received 2020-10-27
[0032] In some embodiments, the system further comprises at least one
heater
installed in the at least one injection well and/or the at least one
production well.
[0033] Other aspects and features of the present disclosure will become
apparent, to those ordinarily skilled in the art, upon review of the following
description of
the specific embodiments of the disclosure.
BRIEF DESCRIPTION OF THE DRAWINGS:
[0034] Some aspects of the disclosure will now be described in greater
detail with
reference to the accompanying drawings. In the drawings:
[0035] Figure 1 is a side view diagram of a system for implementing
embodiments of the methods disclosed herein, including a well pair in a
subterranean
reservoir;
[0036] Figure 2A is a cross-sectional view of the well pair of Figure 1;
[0037] Figure 2B is a cross-sectional view of the well pair of Figure 1,
shown with
an adjacent well pair;
[0038] Figure 3 is a flowchart of an example method for recovering
viscous oil
from a subterranean reservoir, according to some embodiments;
[0039] Figure 4 is a flowchart of another example method showing
additional
steps for recycling at least a portion of produced DME, according to some
embodiments;
[0040] Figure 5 is a flowchart of another example method showing
additional
details regarding how flow communication may be established between an
injection well
and a production well, according to some embodiments;
[0041] Figure 6 is a flowchart of another example method showing
additional
steps for recovering DME from the reservoir, according to some embodiments;
6
Date Recue/Date Received 2020-10-27
[0042] Figure 7 is a phase envelope diagram for a multi-component
(condensable) vapor-phase working fluid;
[0043] Figure 8 is a graph showing DME and water vapor injection rates by
liquid
volume equivalent for a laboratory test of DME-water vapor injection in a 2D
high
pressure-high temperature test cell with Athabasca bitumen;
[0044] Figure 9 is a graph showing cumulative bitumen production for the
DME-
water vapor test of Figure 8;
[0045] Figure 10 is a graph showing cumulative DME injection and
production for
the DME-water vapor test of Figure 8;
[0046] Figure 11 is a graph showing cumulative bitumen production for the
DME-
water vapor test of Figure 8 in comparison to a steam-only test and a DME-only
test;
[0047] Figure 12 is a graph showing cumulative DME and steam injection
for the
DME-water vapor test of Figure 8 and the DME-only test of Figure 11;
[0048] Figure 13 shows residual oil saturation for a DME-water vapor test
(left)
compared to a DME-water-butane test (right).
DETAILED DESCRIPTION:
[0049] Generally, the present disclosure provides a method for recovering
viscous oil from a water-wet subterranean reservoir having at least one
injection well
and at least one production well installed therein. The method may comprise
establishing flow communication between the at least one injection well and
the at least
one production well; and injecting a heated vapor-phase working fluid
comprising vapor-
phase dimethyl ether (DME) and vapor-phase water via the at least one
injection well
and producing a production fluid via the at least one production well. The
vapor-phase
water may be about 5% or lower of a total volume of the heated vapor-phase
working
fluid by liquid volume equivalent.
7
Date Recue/Date Received 2020-10-27
[0050] As used herein the terms "a," "an," and "the" may include plural
referents
unless the context clearly dictates otherwise.
[0051] As used herein, "viscous oil" refers to a hydrocarbon material
having a
high viscosity and a high specific gravity. In some embodiments, viscous oil
comprises
heavy oil and/or bitumen. As used herein, "heavy oil" refers to a hydrocarbon
material
having a viscosity greater than 100 centipoise under virgin reservoir
conditions and an
API gravity of about 20 API or lower. Bitumen may be defined as a hydrocarbon
material having a viscosity greater than 10,000 centipoise under virgin
reservoir
conditions and an API gravity of about 100 API or lower.
[0052] As used herein, "reservoir" refers to any subterranean region, in
an earth
formation, including at least one pool or deposit of hydrocarbons such as
viscous oil
therein. A portion of the reservoir containing viscous oil therein may be
referred to as a
"pay interval" or "pay zone".
[0053] Within the pay interval, heavy oil or bitumen exists in the pore
space
between reservoir sand particles. In a "water-wet" reservoir, in the virgin
state, there
may be an approximately continuous film of water attached to the solid
surfaces of the
reservoir sand particles. The oil residing in the interconnected pore space
may be
substantially surrounded by and in contact with this film of water. As a
result, the
interfacial area of contact between the film of water and the oil may be very
large.
[0054] As used herein, "thermal oil recovery process" refers to a process
that
involves in situ heating of the reservoir to mobilize the viscous oil therein
such that the
mobilized oil may be displaced to a production well and produced to surface.
In some
embodiments, the in situ heating of the reservoir is provided by injection of
a heated
working fluid. As used herein, a "working fluid" refers to any fluid injected
into the
reservoir. In some embodiments, the heated working fluid is a heated vapor-
phase
working fluid. In some embodiments, the heated vapor-phase working fluid may
comprise steam, one or more solvents, or a combination thereof. The heat of
the heated
vapor-phase working fluid may reduce the viscosity of the viscous oil and
thereby
8
Date Recue/Date Received 2020-10-27
mobilize the viscous oil within the reservoir. In processes that employ
solvents, the oil
may be mobilized by a combination of heating and dissolution of the solvent
into the oil.
In some embodiments, the displacement mechanism of the thermal oil recovery
process
is gravity drainage such that mobilized oil flows to the production well under
the force of
gravity while the voided pore space from which the oil is displaced is filled
with injected
working fluid.
[0055] Thermal gravity drainage oil recovery processes may be implemented
using a variety of different well configurations. In some embodiments, the
well
configuration comprises at least one injection well and at least one
production well. The
injection well is used to inject a working fluid into the reservoir. The
production well is
used to collect drained mobilized oil and condensed working fluid and convey a
production fluid to the surface. As used herein, "production fluid" refers to
the fluid
produced from the production well which may include oil, condensed working
fluid, and
any other fluids flowing into the production well from the reservoir. In other
embodiments, a single well may function as both the injection well and the
production
well.
[0056] In some embodiments, one or both of the injection well and the
production
well are vertical wells. As used herein, a "vertical" well refers to a well
that extends
substantially directly downward from the surface of the reservoir into the
target pay
interval. In some embodiments, one or both of the injection well and the
production well
are horizontal wells. As used herein, a "horizontal" well refers to a well
having a
substantially vertical section that extends downward into the pay interval
followed by a
substantially horizontal section that extends approximately parallel to the
bottom of the
pay interval. In some embodiments, the horizontal section of the horizontal
well may be
at least 80 from vertical.
[0057] Figure 1 shows an example system 100, according to some
embodiments,
that may implement one or more of the methods described herein. The example
system
100 may comprise a well pair 101. The well pair 101 is similar to the well
pairs typically
used in SAGD operations.
9
Date Recue/Date Received 2020-10-27
[0058] The well pair 101 in this embodiment is installed in an earth
formation 102
having subterranean reservoir 103 with pay interval 105. The earth formation
102 may
have a water-saturated zone 114 below the reservoir 103. In this embodiment,
the
reservoir 103 is a water-wet reservoir.
[0059] The well pair 101 may comprise an injection well 104 and a
production
well 106. In this embodiment, the injection well 104 and the production well
106 are both
horizontal wells. The production well 106 may be located at or near the bottom
of the
pay interval 105. The injection well 104 may be vertically spaced above the
production
well 106 and substantially parallel with the production well 106. In some
embodiments,
the injection well 104 is approximately five meters above the production well
106.
[0060] In some embodiments, the injection well 104 and the production
well 106
are thermally completed. As used herein, "thermally completed" refers to a
well that has
been completed with production casing and cement that are selected or
configured to
withstand high temperatures. The thermally completed wells may therefore
operate at a
maximum steam temperature of about 300 C or higher. In other embodiments, the
injection well 104 and the production well 106 are not thermally completed. As
used
herein, "not thermally completed" or "non-thermally completed" refers to a
well that has
been completed with production casing and cement that are not selected or
configured
to withstand high temperatures. The non-thermally completed wells may have a
maximum operating temperature based on the rating of the conventional cement
used.
For example, the non-thermally completed wells may be limited to a maximum
operating
temperature of about 120 C in some embodiments. The temperature rating of the
injection and production wells 104 and 106 completions may determine the
maximum
operating temperature of the thermal oil recovery process, as described in
more detail
below.
[0061] The injection well 104 and the production well 106 may be in flow
communication via the reservoir 103, as described in more detail below. Once
flow
communication is established between the injection well 104 and the production
well
106, a heated vapor-phase working fluid may be injected via the injection well
104 and
Date Recue/Date Received 2020-10-27
flow into the reservoir 103. The heated vapor-phase working fluid may comprise
vapor-
phase DME and vapor-phase water as described in more detail below. As used
herein,
the terms "vapor-phase water" and "steam" may each refer to water in a vapor
state.
Mobilized, DME-diluted oil in the reservoir 103, along with liquid-phase water
containing
dissolved DME and any other condensed components of the working fluid, may
flow to
the production well 106 via gravity drainage. Production fluid may then be
produced to
surface via the production well 106. In some embodiments, a pump 107 may be
installed in the production well 106 to lift the production fluid to surface.
[0062] As shown in Figure 2A, as the heated vapor-phase working fluid is
injected into the reservoir 103 via the injection well 104, a vapor chamber
110 may be
formed in the reservoir 103. As used herein, "vapor chamber" refers to a
volume of the
reservoir that is at least partially filled with heated vapor-phase working
fluid and at least
partially depleted of oil. In this embodiment, the vapor-chamber 110 may be at
least
partially filled with vapor-phase DME, vapor-phase water, and any other vapor-
phase
components of the heated vapor-phase working fluid.
[0063] The vapor chamber 110 may grow upward and outward from the
injection
well 104 as indicated by arrows A. Mobilized DME-diluted oil and water
containing
dissolved DME may drain downward within or along the periphery of the vapor
chamber
110 towards the production well 106 as indicated by arrows B. Within the vapor
chamber 110, the mobilized oil may be displaced from the pore space within the
reservoir 103 and the voided pore space may be filled with the DME, water
vapor, and
any other vapor-phase components of the heated vapor-phase working fluid.
[0064] In some embodiments, a liquid pool 112 of drained, DME-diluted oil
and
water containing dissolved DME may be maintained around and above the
production
well 106. The liquid pool 112 may act as a barrier to prevent vapor
breakthrough into
the production well 106. As used herein "vapor breakthrough" refers to heated
vapor-
phase working fluid entering the production well 106 such that vapor-phase
fluid may be
produced to the surface.
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Date Recue/Date Received 2020-10-27
[0065] Referring again to Figure 1, in some embodiments, the production
fluid
produced from the production well 106 may be received at an optional treatment
facility
109 where at least a portion of the DME and water may be separated from the
oil in the
production fluid. In some embodiments, the separated DME and water may be
treated
at the treatment facility 109 to remove residual contaminants such that the
treated DME
and water may be recycled and used to generate new heated vapor-phase working
fluid
for injection. In some embodiments, the treated working fluid is received in a
working
fluid storage facility 111, where the treated working fluid may be combined
with make-
up working fluid. In some embodiments, the treated working fluid is primarily
in liquid
phase and the working fluid storage facility 111 is pressurized to maintain
the treated
working fluid in liquid-phase. In other embodiments, the working fluid storage
facility 111
may comprise separate storage components for DME and water. In some
embodiments, a pressurized storage component is provided for the DME and an
atmospheric-pressure storage component is provided for the water. In some
embodiments, separate supplies of make-up DME and make-up water may also be
provided.
[0066] The system 100 may further comprise at least one heating system
116 to
heat the working fluid to provide the heated vapor-phase working fluid for
injection via
the injection well 104. In some embodiments, the heating system 116 comprises
an
electrical heating system. The electrical heating system may comprise an
electrical
boiler or any other suitable type of electrical heating system. In other
embodiments, the
heating system 116 comprises a fired heating system. The fired heating system
may be
used to directly or indirectly heat the working fluid. In some embodiments,
the fired
heating system comprises a natural gas fired boiler that directly heats and
vaporizes the
working fluid. In other embodiments, the fired heating system comprises a
natural gas
fired boiler operatively connected to a condensing heat exchanger such that
the boiler
generates steam to provide heat input to the condensing heat exchanger in
which the
working fluid is heated and vaporized. In some embodiments, the heating system
116
comprises two or more electrical or fired boilers. In other embodiments, the
heating
12
Date Recue/Date Received 2020-10-27
system 116 comprises any other suitable heating system or combination of
heating
systems.
[0067] In some embodiments, the heating system 116 receives working fluid
from
the working fluid storage facility 111. In other embodiments, the heating
system 116
receives separate fluid streams of DME and water from separate DME and water
storage components of the working fluid storage facility 111. In some
embodiments, the
separate fluid streams are combined in a single boiler of the heating system
116. In
other embodiments, the heating system 116 comprises a first boiler to heat the
fluid
stream of DME and a second boiler to heat the fluid stream of water. As
discussed in
more detail below, as the heated vapor-phase working fluid may comprise a
relatively
small proportion of vapor-phase water, the second boiler may have a smaller
capacity
than the first boiler. In some embodiments, the second boiler may have a much
smaller
capacity than conventional boilers used in SAGD operations.
[0068] In some embodiments, the system 100 further comprises one or more
sensors installed in the injection and/or production wells 104 and 106. As
shown in
Figure 1, in some embodiments, at least one pressure sensor 113 and at least
one
temperature sensor 115 may be installed in the injection and/or production
wells 104
and 106. In Figure 1, pressure sensors 113 are shown as triangles and
temperature
sensors 115 are shown are circles. It is to be understood that the number and
arrangement of the pressure and temperature sensors 113 and 115 in Figure 1
are
shown for example purposes only and embodiments are not limited to any
specific
number and arrangement of sensors.
[0069] In some embodiments, at least one pressure sensor 113 is installed
in the
injection well 104 to provide a means to monitor pressure within the vapor
chamber 110.
In some embodiments, at least one pressure sensor 113 is installed in the
horizontal
section of the production well 106, to provide a measurement of bottom-hole
pressure.
Each of the pressure sensors 113 may comprise a piezometer, bubble tube-type
system, or any other suitable pressure sensing means. In some embodiments, at
least
one temperature sensor 115 is installed in the injection well 104 to monitor
the
13
Date Recue/Date Received 2020-10-27
temperature of the heated vapor-phase working fluid. In some embodiments, at
least
one temperature sensor 115 is installed in the production well 106 to monitor
the
temperature of the production fluid. Each of the temperature sensors 115 may
comprise
a thermocouple, a fiber optic array, or any other suitable temperature sensing
means.
[0070] Optionally, at least one heater (not shown) may be installed in
the injection
well 104 and/or the production well 106. In some embodiments, the heater is an
electrical heater. As one example, the electrical heater may comprise a Hot-
TubeTm
downhole electrical heating system supplied by PetroSpec Engineering Ltd.TM.
In other
embodiments, the heater may comprise any other suitable type of heater.
[0071] The system 100 may further comprise a control system 118. The
control
system 118 may be configured to implement embodiments of the methods described
herein. The control system 118 may be operatively connected to the heating
system
116 to control operation thereof. In some embodiments, the control system 118
may
also be operatively connected to the optional pressure and/or temperature
sensors 113
and 115. In some embodiments, the control system 118 may receive input from
the
pressure and temperature sensors 113 and 115 and may control the operation of
the
heating system 116 based on such input. In some embodiments, the control
system 118
may also be operatively connected to the optional heater in the injection well
104 and/or
the production well 106. The control system 118 may control the operation of
the
heater(s) as required to maintain the temperature in the injection well 104
and/or
production well 106 within a desired range.
[0072] In some embodiments, the system 100 may comprise a plurality of
well
pairs 101 within the reservoir 103. In some embodiments, the plurality of well
pairs 101
may be installed in the same pay interval 105. In other embodiments, the
reservoir 103
may comprise a plurality of pay intervals 105 and at least one well pair 101
may be
installed in each pay interval 105. In some embodiments, the plurality of well
pairs 101
may be arranged in at least one parallel array known as pad (not shown).
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Date Recue/Date Received 2020-10-27
[0073] Figure 2B shows the well pair 101 with an adjacent well pair 101B.
It will
be understood that although only two well pairs 101, 101B are shown in Figure
2B, any
suitable number of well pairs can be arranged in a similar manner. Hereafter,
the well
pair 101 is also referred to as the first well pair 101 and the adjacent well
pair 101B is
also referred to as the second well pair 101B. The second well pair 101B may
comprise
an injection well 104B and a production well 106B which may be approximately
parallel
to the injection well 104 and production well 106 of the first well pair 101.
Injection of
heated vapor-phase working fluid via the injection well 104B may lead to the
formation
of a vapor chamber 110B, similar to the vapor chamber 110 of the first well
pair 101. A
liquid pool 112B may act as a barrier to prevent vapor breakthrough into the
production
well 106B.
[0074] As shown in Figure 2B, the first well pair 101 and the second well
pair
101B may have an inter-well-pair spacing 120. As used herein, "inter-well-pair
spacing"
refers to the lateral distance between adjacent well pairs within the same
reservoir 103.
In some embodiments, inter-well-pair spacing may be expressed as a multiple of
the
pay interval thickness since the ratio of pay interval thickness to inter-well-
pair spacing
provides an approximate proxy for the average slope of the vapor chamber
boundary
along which the mobilized oil drains when the vapor chamber is fully developed
laterally.
In some embodiments, the inter-well-pair spacing 120 may be similar to that of
conventional SAGD operations. In these embodiments, the ratio of inter-well-
pair
spacing 120 to pay interval 105 thickness may range from between about 4:1 and
about
5:1 to correspond to that of conventional SAGD operations. In other
embodiments, the
inter-well-pair spacing 120 may be less than that of conventional SAGD
operations. In
some embodiments, the ratio of inter-well-pair spacing 120 to pay interval 105
thickness
may be about 4:1 or less. In some embodiments, the ratio of inter-well-pair
spacing 120
to pay interval 105 thickness may be between about 1.5:1 and about 3:1.
[0075] As discussed in more detail below, one advantage of embodiments of
the
thermal oil recovery processes described herein is the ability to operate at
lower
operating temperatures than conventional SAGD processes. SAGD processes are
Date Recue/Date Received 2020-10-27
typically implemented in thick reservoirs with a pay interval 105 thickness of
about 20m
and above. However, the processes described herein can also be applied to thin
reservoirs with a pay interval 105 thickness less than that of SAGD processes.
To offset
the lower oil production rate expected due to the thinner pay interval 105, a
smaller
inter-well-pair spacing 120 can be used to achieve an acceptable oil
production rate.
[0076] Figure 3 is a flowchart of an example method 300 for recovering
viscous
oil from a water-wet subterranean reservoir that may be implemented using the
system
100 of Figure 1.
[0077] At block 302, flow communication between the at least one
injection well
and the at least one production well is established. As used herein, "flow
communication" refers to fluid communication between the injection well 104
and the
production well 106, via the reservoir 103, such that viscous oil in the
reservoir 103,
mobilized by fluids injected through the injection well 104, may flow to the
production
well 106.
[0078] In some embodiments, flow communication between the injection well
104
and the production well 106 may be established through a process known as
"initialization". Initialization may comprise mobilizing oil in an inter-well
zone 108,
between the injection well 104 and the production well 106 such that mobilized
oil in the
inter-well zone 108 can flow to the production well 106.
[0079] Initialization may be achieved by any suitable mechanism. Non-
limiting
examples of initialization mechanisms include conductive heating and solvent
dissolution, which may be enhanced by inter-well differential pressure
modulation
and/or geomechanical dilation effects. In some embodiments, any suitable
sequential or
concurrent combination of the initialization mechanisms described herein may
be used
to establish flow communication between the injection well 104 and the
production well
106.
[0080] In some embodiments, where the injection and production wells 104
and
106 of the well pair 101 are thermally completed, initialization may be based
solely or
16
Date Recue/Date Received 2020-10-27
predominantly on conductive heating of the inter-well zone 108 by heating the
injection
and production wells 104 and 106.
[0081] In some embodiments, the injection and production wells 104 and
106 are
heated by injecting steam through both the injection well 104 and the
production well
106 in a process known as "steam circulation". In other embodiments,
initialization may
be achieved or assisted by an extended period of a heated vapor-phase solvent
injection, either alone or in combination with steam. The solvent may be
injected
through the injection well 104 or through both the injection and production
wells 104 and
106. The solvent may be any solvent that is effective in reducing the
viscosity of viscous
oil by dilution. Non-limiting examples of suitable solvents include: single-
component
solvents including DME, propane, butane, pentane, hexane, heptane, octane,
nonane,
decane, undecane, dodecane, tridecane, and tetradecane; multicomponent
solvents
including diluent, natural gas condensate, kerosene, and naptha; and
combinations
thereof.
[0082] During initialization of a thermally completed well pair 101, the
temperature at the injection well 104 and production well 106 may range from
about
50 C to 250 C, depending on the temperature rating of the well completion. In
some
embodiments, the overall duration of the initialization period may be
approximately two
to six months.
[0083] In other embodiments, where the injection and production wells 104
and
106 of the well pair 101 are not thermally completed, the maximum temperature
at the
injection and production wells 104 and 106 during initialization may be
limited, for
example to less than 100 C. This temperature limitation may lengthen the time
required
for the initialization period if initialization is based solely or
predominantly on a
conductive heating mechanism. Therefore, in some embodiments, initialization
may
instead be based solely or predominantly on a solvent dissolution mechanism.
In these
embodiments, DME may be particularly useful as a solvent due to its relatively
high
effective rate of diffusion into oil under water-wet reservoir conditions.
17
Date Recue/Date Received 2020-10-27
[0084]
In some embodiments, liquid-phase DME may be injected, at or above
reservoir pressure, through the injection well 104 or through both the
injection and
production wells 104 and 106. Liquid-phase DME may be injected for a suitable
"solvent
soaking" period during which no production fluids are produced via the
production well
106 to surface. In some embodiments, the duration of the solvent soaking
period may
be about two to nine months.
[0085]
In some embodiments, to limit the potential loss of DME to the water-
saturated zone 114 below the reservoir 103, DME may be injected through the
injection
well 104 but not through the production well 106. In some embodiments, a
liquid-phase
hydrocarbon solvent may be injected through the production well 106 in place
of DME.
Non-limiting examples of suitable liquid-phase hydrocarbon solvents include:
single-
component solvents including propane, butane, pentane, hexane, heptane,
octane,
nonane, decane, undecane, dodecane, tridecane, and tetradecane; multicomponent
solvents including diluent, natural gas condensate, kerosene, and naptha, and
combinations thereof.
[0086]
The liquid-phase DME and optional hydrocarbon solvent injected during
the solvent soaking period may be heated or unheated. If heated, the DME and
optional
hydrocarbon solvent may be injected at a temperature of about 50 C to about
250 C, to
maintain the temperature at the injection and production wells 104 and 106
between
about 50 C and about 100 C. In some embodiments, the temperature at the
injection
and production wells 104 and 106 is between about 80 C and 100 C. In some
embodiments, the liquid-phase DME and optional hydrocarbon solvent may be
heated
at surface e.g. by the heating system 116. In other embodiments, the optional
heater
(not shown) installed in at least one of the injection well 104 and the
production well 106
may be operated to maintain the temperature at the injection and production
wells 104
and 106 within the desired range.
[0087]
In other embodiments, any other suitable initialization method may be
used to establish flow communication between injection well 104 and production
well
18
Date Recue/Date Received 2020-10-27
106. An alternative DME-based initialization method for non-thermally
completed wells
will be described in more detail below with reference to Figure 5.
[0088] In some embodiments, to determine if adequate flow communication
has
been established between the injection well 104 and the production well 106 by
any of
the initialization methods described herein, periodic testing may be performed
comprising monitoring a response in the production well 106 to an increase in
pressure
in the injection well 104, or vice versa. In some embodiments, the response is
monitored by measuring pressure in the production well 106 or injection well
104 via at
least one pressure sensor 113 installed therein.
[0089] At block 304, a heated vapor-phase working fluid comprising vapor-
phase
DME and vapor-phase water is injected via the at least one injection well 104.
As the
heated vapor-phase working fluid is injected via the injection well 104, a
production fluid
may be produced via the production well 106 to surface.
[0090] The vapor-phase water may only be a small portion of the heated
vapor-
phase working fluid. In some embodiments, the vapor-phase water may be about
5% or
lower of a total volume of the heated vapor-phase working fluid by liquid
volume
equivalent. In some embodiments, the vapor-phase water is about 3% or lower of
the
total volume of the heated vapor-phase working fluid by liquid volume
equivalent.
[0091] In some embodiments, the ratio of vapor-phase DME to vapor-phase
water is between about 20:1 and about 250:1 by liquid volume equivalent. In
some
embodiments, the ratio of vapor-phase DME to vapor-phase water is about 20:1,
about
25:1, about 35: 1, about 187:1, about 200:1, or about 233:1. In some
embodiments, the
ratio of vapor-phase DME to vapor-phase water remains approximately the same
over
time. In other embodiments, the ratio may be adjusted over time. For example,
in some
embodiments the ratio of vapor-phase DME to vapor-phase water may be increased
during the later stages of operation of well pair 101.
[0092] In some embodiments, injecting the heated vapor-phase working
fluid
comprises co-injecting a first fluid stream comprising heated vapor-phase DME
and a
19
Date Recue/Date Received 2020-10-27
second fluid stream comprising heated vapor-phase water such that the first
fluid
stream and second fluid stream combine in the injection well 104 to form the
heated
vapor-phase working fluid.
[0093] In some embodiments, the first fluid stream is injected at a first
temperature and the second fluid stream is injected at a second temperature.
The first
and second temperature may each be in the range of about 50 C to about 250 C.
In
some embodiments, the first and second temperatures are selected to achieve an
operating temperature in the range of about 50 C to about 100 C (e.g. about 80
C), as
described in more detail below. In some embodiments, the first and second
temperatures are approximately the same. In other embodiments, the second
temperature may be higher than the first temperature (or vice versa). In some
embodiments, the first and/or second temperatures may be adjusted as needed to
maintain the operating temperature in the desired range. In other embodiments,
the first
and second fluid streams are injected at any other suitable temperature. In
some
embodiments, the injection pressure may range from about 500kPa to about
5,000kPa.
[0094] In other embodiments, the heated vapor-phase working fluid is
formed
prior to injection via the injection well 104. In some embodiments, the heated
vapor-
phase working fluid is formed by combining heated vapor-phase DME and vapor-
phase
water. In other embodiments, the heated vapor-phase working fluid is formed by
combining unheated liquid or vapor-phase DME and liquid water, and heating the
combination of DME and water to form the heated vapor-phase working fluid. In
other
embodiments, the heated vapor-phase working fluid may be formed by bubbling
heated
vapor-phase DME through liquid water. In other embodiments, the heated vapor-
phase
working fluid may be formed by any other suitable means.
[0095] In embodiments in which the heated vapor-phase working fluid is
formed
prior to injection, the heated vapor-phase working fluid may be injected at a
temperature
of between about 50 C to about 250 C. In some embodiments, the temperature is
selected to achieve an operating temperature in the range of about 50 C to
about 100 C
Date Recue/Date Received 2020-10-27
(e.g. about 80 C), as described in more detail below. In some embodiments, the
injection pressure may range from about 500kPa to about 5,000kPa.
[0096] In some embodiments, the heated vapor-phase working fluid is
superheated. As used herein, "superheated" refers to heating a fluid to beyond
its
saturation temperature at a given pressure. In some embodiments, the vapor-
phase
working fluid is superheated before or during injection. In some embodiments,
the
vapor-phase working fluid has a degree of superheat of between about 0 C to
about
25 C above the saturation temperature of the working fluid at a given
pressure. In some
embodiments, the vapor-phase working fluid has a degree of superheat of about
20 C.
In some embodiments, superheating the vapor-phase working fluid may ensure
that all
components therein are injected in the vapor phase. In these embodiments, the
superheated vapor-phase working fluid may thereby take greater advantage of
the
working fluid's heat transport capacity than a heated vapor-phase working
fluid that is
not superheated.
[0097] As the heated vapor-phase fluid is injected via the injection well
104, the
vapor chamber 110 may form as shown in Figure 2A and described above. Without
being limited by theory, it is believed that the combination of vapor-phase
DME and a
small amount of vapor-phase water in the injected heated vapor-phase working
fluid
may act synergistically to accelerate mobilization of viscous oil at the
boundary of and
within the vapor chamber 110 as the vapor chamber 110 expands into the
surrounding
oil-saturated, water-wet reservoir 103. Briefly, when heated DME vapor is
injected into
the water-wet reservoir 103, it may diffuse quickly into the water films on
the surface of
the water-wet solids at the vapor chamber 110 boundary, thereby achieving an
expanded area of contact with the oil in the pore space bounded by these water
films.
The heated DME vapor may thereby dissolve into the oil in these pore spaces
and
reduce the viscosity of the oil by both heat and dissolution. If DME is
injected alone,
without vapor-phase water, the water-wet reservoir may eventually become
desiccated,
resulting in an oil-wet condition that limits the further dissolution of DME
beyond the
vapor chamber 110 boundary. However, in the methods described herein, the
small
21
Date Recue/Date Received 2020-10-27
amount of vapor-phase water in the heated vapor-phase working fluid may
condense to
liquid-phase water at the vapor chamber 110 boundary and the liquid-phase
water may
dissolve DME therein to facilitate transfer of DME to the water film of the
water-wet
solids beyond the vapor chamber 110 boundary. By this mechanism, the DME may
achieve expanded contact with the oil in the pore space beyond the vapor
chamber 110
boundary as well as accelerated mass transfer into such oil. The net effect
may thereby
be accelerated dilution and mobilization of the oil by the DME. Condensation
of the
vapor-phase water at the colder boundary of the vapor chamber 110 may also
provide
additional heat, thereby increasing the rate at which oil beyond the vapor
chamber 110
boundary is heated.
[0098]
In some embodiments, the method 300 further comprises determining a
suitable operating temperature. In some embodiments, a suitable operating
temperature
may be determined by first selecting a suitable total pressure at which to
operate the
vapor chamber 110. The total operating pressure may have an upper limit that
is
determined with respect to avoiding geomechanical failure of the confining
reservoir
caprock (seal). Then, for a given total operating pressure, the operating
temperature
may be determined based on the composition of the heated vapor-phase working
fluid,
i.e. the thermodynamic properties and partial pressure for each of its
constituents (such
as DME vapor, water vapor, vapor-phase hydrocarbon solvent species, etc.). As
shown
in Figure 7, the vapor-liquid equilibrium behaviour of a mixture is defined as
an
envelope rather than as a single curve, such that for a given total pressure,
a specific
vapor mixture condenses to liquid over a temperature range rather than at a
single
temperature. Therefore, the relationship between total operating pressure and
temperature for a multi-component vapor-phase working fluid is more
complicated than
for a single component vapor-phase working fluid. For example, measured
operating
pressure and temperature data for a subset of the conditions explored in the
Examples
below are presented in Table 1, showing that for the same operating pressure,
operating temperature varies with the composition of the working fluid.
TABLE 1
22
Date Recue/Date Received 2020-10-27
Total Operating Operating
Composition Injection Temperature
Pressure Temperature
180:1, DME:water 2,200 kPa 82 C 20 C superheat
35:1, DME:water 2,200 kPa 96 C 20 C superheat
Steam only 2,200 kPa 215 C 225 C (10 C
superheat)
[0099] Therefore, in some embodiments, a combination of experimental
measurements and fluid system modelling may be used to define, at least
approximately, the relationship between total operating pressure, the partial
pressure of
various components in a multi-component vapor-phase working fluid, and
operating
temperature.
[00100] In some embodiments, the operating temperature of the vapor
chamber
110 ranges from about 50 C to about 100 C. In some embodiments, the operating
temperature of the vapor chamber 110 is between about 80 C and about 100 C. In
some embodiments, the operating temperature is about 80 C. Therefore, in some
embodiments, the operating temperature may be considerably lower than that of
conventional steam-based thermal oil recovery processes, such as SAGD, that
typically
operate at or above 200 C.
[00101] In some embodiments, the method 300 further comprises maintaining
the
operating temperature within a desired or target range, for example, within
any of the
ranges described above. In some embodiments, the total pressure and
temperature in
the vapor chamber 110 may be monitored to determine if the operating
temperature is
outside of the desired range and, if so, the operating temperature may be
adjusted as
needed.
[00102] In some embodiments, either or both of the total injection
pressure or the
composition of the injected vapor-phase working fluid may be adjusted to
maintain the
operating temperature within the desired range. For a fixed vapor-phase fluid
composition, operating temperature is directly related to total operating
pressure which
23
Date Recue/Date Received 2020-10-27
may be manipulated by changing the injection pressure. For a fixed total
operating
pressure, operating temperature may be increased by increasing the
concentration of
higher boiling point constituents within the injected vapor-phase working
fluid.
Conversely, for a fixed total operating pressure, operating temperature may be
decreased by decreasing the concentration of higher boiling point constituents
within
the injected vapor-phase working fluid.
[00103] In other embodiments, the optional heater in the injection well
104 and/or
the production well 106 may be used to maintain the operating temperature in
the
desired range. For example, if the operating temperature falls below the
desired range,
the heater may be operated to heat the injection well 104 and/or production
well 106 to
raise the operating temperature as desired. In some embodiments, the operating
temperature may be maintained by operation of the heater alone. In other
embodiments, the operating temperature may be maintained by a combination of
operation of the heater and by adjusting the total injection pressure and/or
composition
of the injected vapor-phase working fluid as described above.
[00104] As the heated vapor-phase working fluid is injected via the
injection well
104, DME-diluted oil and water containing dissolved DME (and any other
condensed
components of the working fluid) may drain to the production well 106 by
gravity
drainage to be produced to surface. In some embodiments, the liquids draining
to the
production well 106 may comprise a relatively large oil phase comprising the
DME-
diluted oil. Compared to steam-dominated processes such as SAGD, the volume of
the
draining oil phase may comprise a significantly larger percentage of the total
volume of
draining liquids, which may increase the relative permeability of the draining
oil phase,
thereby facilitating its transport to the production well 106.
[00105] In some embodiments, the method 300 may further comprise
maintaining
the level of the drained liquid pool 112 around the production well 106 or
above a
threshold level to prevent vapor break-through. In some embodiments an
instantaneous
production rate of the production fluid may be adjusted to maintain the level
of the
drained liquid pool 112 at or above the threshold. As used herein,
"instantaneous
24
Date Recue/Date Received 2020-10-27
production rate" refers to the produced volume of production fluid over a
short time
period, for example, the volume of produced fluid per hour, as opposed to the
cumulative production rate over time. In other embodiments, the level of the
liquid pool
112 may be maintained at or above a threshold level by any other suitable
means.
[00106] As demonstrated in the Examples below, in some embodiments, a
cumulative production rate of the production fluid may be similar to or
approximately the
same as that of a steam-only process operating at over 200 C and may be better
than
that of a DME-only process operating at less than 100 C. As used herein,
"cumulative
oil production rate" refers to the cumulative volume of production fluid
produced over
time.
[00107] Therefore, in some embodiments, the method 300 may allow for lower
operating temperatures compared to typical steam-based processes without
sacrificing
oil production performance as in typical solvent-dominated processes. Lower
operating
temperatures may provide a number of economic and/or environmental advantages
including at least one of: reducing the overall energy intensity; reducing or
eliminating
the need for expensive thermal well completions for at least a portion of the
injection
well and/or the production well; and reducing or eliminating the need for
large-capacity,
high-pressure steam generation and related boiler feedwater treatment
facilities typically
associated with steam-dominated processes such as SAGD.
[00108] A major challenge to the economic viability of conventional
solvent-
dominated oil recovery processes is the accumulation of valuable solvent
within the
reservoir, both within the oil-depleted vapor chamber and in the reservoir
just beyond
the vapor chamber boundary. Moreover, this solvent inventory build-up problem
may
worsen if operation the solvent-dominated process continues after the oil rate
has
plateaued, since the bulk of the solvent produced back to surface is dissolved
in
produced oil. In the thermal oil recovery processes described herein, if the
inter-well-
pair spacing is similar to that of conventional SAGD operations, the oil rate
may be
expected to plateau and decline after about three years of operation, by which
time
Date Recue/Date Received 2020-10-27
about 30-40% of the target oil recovery factor may be achieved. In some
embodiments,
the target oil recovery factor is approximately 60 to 70% of original oil in
place (00IP).
[00109] As a result, in some embodiments, the method 300 may be
implemented
in an embodiment of the system 100 in which the inter-well-pair spacing is
less than that
of conventional SAGD operations. The lower operating temperatures of the
heated
vapor chamber 110 as described above may allow lower cost well completions to
be
used that may offset increased costs for the greater number of well pairs 101
required
to achieve smaller inter-well-pair spacing. In some embodiments, the inter-
well-pair
spacing may be small enough to achieve 100% of the designed oil recovery
factor
within about five to seven years. The reduced inter-well-pair spacing may
therefore
allow the target oil recovery factor to be achieved faster and may eliminate
or reduce
the need for continued DME injection past the oil rate plateau. Therefore, the
reduced
inter-well-pair spacing may help to reduce the accumulation of DME in the
reservoir
103.
[00110] Furthermore, in some embodiments, additional steps may be taken to
recover injected DME from the reservoir 103. An example method 600 with steps
to
recover injected DME is shown in Figure 6 and discussed in more detail below.
[00111] Variations of the method 300 are also possible. In some
embodiments, the
heated vapor-phase working fluid further comprises at least one volatile
hydrocarbon
solvent that is effective in reducing the viscosity of viscous oil by
dilution. As used
herein, "volatile", when used in reference to a solvent, refers to a solvent
for which the
boiling point is less than that of water. Non-limiting examples of volatile
hydrocarbon
solvents include propane, butane, and combinations thereof. The volatile
hydrocarbon
solvent may function to diffuse into and further mobilize the oil at the vapor
chamber
110 boundary that has already been partially mobilized by the combined effects
of the
mild heating and dilution by vapor-phase DME.
[00112] In some embodiments, the volatile hydrocarbon solvent is added to
the
heated vapor-phase working fluid in addition to the DME component. In other
26
Date Recue/Date Received 2020-10-27
embodiments, the volatile hydrocarbon solvent replaces a portion of the DME
component in the heated vapor-phase working fluid. In some embodiments, the
ratio of
DME to DME plus volatile hydrocarbon solvent may range from between about 1.0
to
about 0Ø In some embodiments, the ratio of DME to DME plus volatile
hydrocarbon
solvent decreases with time and increasing recovery factor. In some
embodiments, the
ratio of total solvent (DME plus volatile hydrocarbon solvent) to vapor-phase
water in
the heated vapor-phase working fluid is about 20:1 to about 250:1. The vapor-
phase
water may therefore remain at about 5% or lower of the total volume of the
heated
vapor-phase working fluid by liquid volume equivalent.
[00113] As described in the Examples below, substitution of a portion of
the DME
in the heated vapor-phase working fluid with a volatile hydrocarbon solvent
may reduce
asphaltene precipitation in the reservoir 103. Therefore, in some embodiments,
a
concentration of volatile hydrocarbon solvent in the heated vapor-phase
working fluid
may be selected based on a desired degree of asphaltene precipitation. In some
embodiments, the concentration of the volatile hydrocarbon solvent may be
selected
such that the degree of asphaltene precipitation is controlled to be
approximately
constant during the operating life of the recovery process. In other
embodiments, the
concentration of the volatile hydrocarbon solvent may be adjusted over time
such that
the degree of asphaltene precipitation varies over the operating life of the
recovery
process.
[00114] In some embodiments, the volatile hydrocarbon solvent is combined
with
vapor-phase DME and vapor-phase water prior to injection to form the heated
vapor-
phase working fluid. In other embodiments, the volatile hydrocarbon solvent is
combined with heated vapor-phase DME in the first fluid stream and the first
fluid
stream is co-injected with the second fluid stream comprising heated vapor-
phase
water. In other embodiments, the hydrocarbon solvent is co-injected as a third
fluid
stream, separate from the first and second fluid streams.
[00115] Within the operating temperature of the vapor chamber 110,
different
solvents may exhibit differing temperature-dependent solubility in oil. For
example, the
27
Date Recue/Date Received 2020-10-27
solubility of DME and other volatile hydrocarbon solvents may decline with
increasing
temperature. Therefore, in some embodiments, the composition of the volatile
hydrocarbon solvent may be adjusted to optimize oil production at a given
operating
temperature. As one example, the volatile hydrocarbon solvent may comprise a
mixture
of butane and propane and the ratio of butane to propane may be adjusted based
on
the desired operating temperature. For example, a high butane to propane ratio
may be
used at higher operating temperatures (e.g. about 80 C to about 100 C) and a
low
butane to propane ratio may be used at lower operating temperatures (e.g.
about 50 C
to about 79 C).
[00116] In some embodiments, the heated vapor-phase working fluid may
further
comprise a non-condensable gas (NCG). As used herein, a "non-condensable" gas
refers a gas that does not condense nor readily dissolve into oil under
reservoir
conditions. Examples of suitable non-condensable gases include, but are not
limited to,
natural gas, carbon dioxide, nitrogen, carbon monoxide, flue gas, methane,
ethane, and
combinations thereof.
[00117] In some embodiments, the NCG is combined with vapor-phase DME and
vapor-phase water prior to injection to form the heated vapor-phase working
fluid. In
other embodiments, the NCG is co-injected as a third fluid stream, separate
from the
first and second fluid streams. In other embodiments, the NCG may comprise
methane
or carbon dioxide that already exist in the reservoir 103 and therefore form
part of the
recycled DME and hydrocarbon solvent (if used) that is recycled for re-
injection, as
described in more detail below.
[00118] In some embodiments, the amount of NCG is relatively minor
compared to
the other components of the heated vapor-phase working fluid. For example, the
NCG
may comprise about 5% or less of the heated vapor-phase working fluid by
liquid
volume equivalent. In some embodiments, injection of NCG is implemented in the
later
stages of the overall operating lifecycle of the well pair 101 such that oil
production
performance during the early and middle stages of the lifecycle is not
detrimentally
affected. In some embodiments, injection of NCG in the later stages of the
operating
28
Date Recue/Date Received 2020-10-27
lifecycle may facilitate recovery of injected DME as described in more detail
below with
respect to the method 600.
[00119] Figure 4 is a flowchart of another example method 400, implemented
using the system 100 of Figure 1. The method 400 may be used to recycle at
least a
portion of the DME from the production fluid for re-injection.
[00120] At block 402, flow communication between the at least one
injection well
and the at least one production well is established. The steps at block 402
may be
similar to the steps at block 302 as described above.
[00121] At block 404, a heated vapor-phase working fluid comprising vapor-
phase
DME and vapor-phase water is injected via the at least one injection well 104.
As the
heated vapor-phase working fluid is injected via the injection well 104, a
production fluid
may be produced via the production well 106 to surface. The steps of block 404
may be
similar to the steps of block 304 as described above.
[00122] At block 406, at least a portion of produced DME is separated from
the
production fluid. As used herein, "produced DME" refers to DME in the oil
phase of the
production fluid as well as the DME dissolved in the water phase of the
production fluid.
In some embodiments, at least a portion of the produced DME is separated from
the
production fluid at the treatment facility 109.
[00123] In some embodiments, at least a portion of the DME in the oil
phase of the
production fluid is separated from the oil. In some embodiments, the water
phase
containing dissolved DME in the production fluid is separated from the oil
phase and at
least a portion of the DME in the water phase is separated from the water. In
other
embodiments, the water phase may be separated from the oil phase without
separating
the dissolved DME from the water.
[00124] In some embodiments, the heated vapor-phase working fluid further
comprises at least one volatile hydrocarbon solvent and at least a portion of
the
hydrocarbon solvent may also be separated from the production fluid.
29
Date Recue/Date Received 2020-10-27
[00125] At block 408, at least a portion of the separated, produced DME is
recycled to form new heated vapor-phase working fluid for injection. In some
embodiments, the separated DME is treated to remove other contaminants and
then the
treated DME may be used to form new heated vapor-phase working fluid. In some
embodiments, the separated DME is treated at the treatment facility 109.
[00126] In some embodiments, the water may also be recycled to form new
heated vapor-phase working fluid for injection. In some embodiments, the water
may
also be treated to remove contaminants and then used to form new heated vapor-
phase
working fluid. In some embodiments, the hydrocarbon solvent may also be
recycled to
form new heated vapor-phase working fluid for injection. In some embodiments,
the
hydrocarbon solvent may also be treated to remove contaminants and then used
to
form new heated vapor-phase working fluid.
[00127] As discussed above, the production fluid may comprise methane
and/or
carbon dioxide that are naturally present in the reservoir 103. In some
embodiments, it
may not be practically or economically feasible to completely remove the
methane or
carbon dioxide from the DME (and the hydrocarbon solvent, if used). Therefore,
in some
embodiments, at least a portion of the methane or carbon dioxide may be
recycled
along with the DME and hydrocarbon solvent to form the new heated vapor-phase
working fluid.
[00128] Figure 5 is a flowchart of an example method 500, implemented
using the
system 100 of Figure 1, with additional steps for establishing flow
communication
between the injection well 104 and the production well 106. The method 500 of
Figure 5
may be used to achieve faster initialization for a non-thermally completed
well pair 101
than the initialization methods described above.
[00129] At block 502, a liquid-phase initialization fluid is injected for
a first time
period. As used herein, the term "initialization fluid" is equivalent to a
working fluid and
is used for ease of reference only to distinguish between a fluid injected
during an
initialization stage and a fluid injected during a production stage. The
liquid-phase
Date Recue/Date Received 2020-10-27
initialization fluid may comprise liquid-phase DME. The first time period may
be similar
to the solvent soaking period described above at block 302 and during the
first time
period, no displaced fluids may be produced via the production well 106 to
surface. In
some embodiments, the duration of the first time period is about two to six
weeks.
[00130] The liquid-phase initialization fluid may be injected through the
injection
well 104 or through both the injection well 104 and the production well 106.
In some
embodiments, the liquid-phase initialization fluid may only be injected
through the
injection well 104 (and not through the production well 106) to limit loss of
DME to the
water-saturated zone 114 below the reservoir 103.
[00131] In some embodiments, the liquid-phase initialization fluid may
further
comprise at least one liquid-phase hydrocarbon solvent. Non-limiting examples
of
suitable liquid-phase hydrocarbon solvents include: single-component solvents
including
propane, butane, pentane, hexane, heptane, octane, nonane, decane, undecane,
dodecane, tridecane, and tetradecane; multicomponent solvents including
diluent,
natural gas condensate, kerosene, and naptha, and combinations thereof.
[00132] In some embodiments, liquid-phase DME may be injected through the
injection well 104 and the liquid-phase hydrocarbon solvent may be injected
through the
production well 106. In some embodiments, the liquid-phase DME and optional
hydrocarbon solvent may be heated at surface prior to injection. In some
embodiments,
the optional heater installed in the injection well 104 and/or the production
well 106 may
be used to maintain the temperature at the injection well 104 and the
production well
106 within a desired range, for example between about 50 C and about 100 C or
between about 80 C and about 100 C.
[00133] At block 504, injection of the liquid-phase initialization fluid
is ceased and
a heated vapor-phase initialization fluid is injected for a second time
period. In some
embodiments, the duration of the second time period may be about two to five
months.
[00134] The heated vapor-phase initialization fluid may comprise vapor-
phase
DME and vapor-phase water. The vapor-phase water may comprise 5% or lower of a
31
Date Recue/Date Received 2020-10-27
total volume of the heated vapor-phase initialization fluid by liquid volume
equivalent.
The heated vapor-phase initialization fluid may be similar to, or the same as,
the heated
vapor-phase working fluid as described above.
[00135] The heated vapor-phase initialization fluid may be injected
through the
injection well 104 or through both the injection well 104 and the production
well 106. In
some embodiments, the heated vapor-phase initialization fluid may only be
injected
through the injection well 104 (and not through the production well 106) to
limit loss of
DME to the water-saturated zone 114 below the reservoir 103.
[00136] In some embodiments, the heated vapor-phase initialization fluid
further
comprises at least one vapor-phase hydrocarbon solvent. The vapor-phase
hydrocarbon solvent may be any of the solvents described above for the liquid-
phase
hydrocarbon solvent. In some embodiments, vapor-phase DME may be injected
through
the injection well 104 and the vapor-phase hydrocarbon solvent may be injected
through
the production well 106.
[00137] During the second time period, an initial production fluid
comprising
mobilized, DME-diluted oil (or DME- and hydrocarbon solvent-diluted oil) may
be
produced to surface via the injection well 104 and/or the production well 106.
In some
embodiments, the initial production fluid is lifted to surface using the pump
107 installed
in the production well 106 and/or a pump installed in the injection well 104
(not shown).
[00138] In some embodiments, production of the initial production fluid
may be
continuous. In other embodiments, the initial production fluid may be produced
intermittently. For example, in some embodiments, there may be alternating
periods of
injection through both the injection well 104 and the production well 106 and
production
through one or both of the injection well 104 and the production well 106.
[00139] Therefore, in some embodiments, by producing a small amount of
mobilized oil to surface, a small amount of heated vapor-phase initialization
fluid may fill
the voided pore space of the reservoir 103 from which the mobilized oil was
displaced.
A "mini" vapor chamber may thereby be created in the reservoir 103 around the
well
32
Date Recue/Date Received 2020-10-27
pair 101 to facilitate subsequent convective heating and solvent mass transfer
to the
boundary of the mini vapor chamber. The overall duration of the initialization
period,
including both the first time period and the second time period, may therefore
be about
three to six months.
[00140] In some embodiments, to determine if adequate flow communication
has
been established between the injection well 104 and the production well 106
during the
second time period, periodic testing may be performed as described above.
[00141] At block 506, injection of the heated vapor-phase initialization
fluid is
ceased and a heated vapor-phase working fluid comprising vapor-phase DME and
vapor-phase water is injected via the injection well 104. A production fluid
may be
produced via the production well 106. The steps at block 506 may be similar to
those of
block 304 of the method 300 as described above.
[00142] Figure 6 is a flowchart of another example method 600, implemented
using the system 100 of Figure 1, with additional steps for recovering
injected DME.
[00143] At block 602, flow communication between the at least one
injection well
and the at least one production well is established. The steps at block 602
may be
similar to block 302 of the method 300 (or blocks 502 and 504 of the method
500) as
described above.
[00144] At block 604, a heated vapor-phase working fluid comprising vapor-
phase
DME and vapor-phase water is injected via the injection well 104. As the
heated vapor-
phase working fluid is injected via the injection well 104, a production fluid
may be
produced via the production well 106 to surface. The steps of block 604 may be
similar
to the steps of block 304 as described above.
[00145] At block 606, following a suitable operating period of the well
pair 101,
injection of the heated vapor-phase working fluid may be ceased and an NCG may
be
injected via the injection well 104. The NCG may be any of the NCG listed
above with
respect to the heated vapor-phase working fluid. The NCG may be heated or
unheated.
33
Date Recue/Date Received 2020-10-27
In some embodiments, the switch to NCG injection occurs as the oil recovery
factor
approaches a target oil recovery factor.
[00146] Injection of NCG may function to maintain the operating pressure
of the oil
depleted vapor chamber 110 at or near the target operating pressure. The NCG
may
thereby displace mobilized oil toward the production well 106 and effectively
sweep at
least a portion of the remaining DME from the vapor chamber 110 and the
reservoir 103
just beyond the vapor chamber 110 boundary to the production well 106. In
embodiments in which the heated vapor-phase working fluid further comprises at
least
one volatile hydrocarbon solvent, the NCG may also effectively sweep at least
a portion
of the remaining hydrocarbon solvent to the production well 106. By displacing
mobilized oil to the production well 106, injection of NCG may also facilitate
incremental
oil recovery.
[00147] Therefore, in some embodiments, at least a portion of the DME (and
other
optional solvents) injected into the reservoir can effectively be recovered
for re-use in
the oil recovery methods described herein and/or for use in other
applications.
EXAMPLES
[00148] Laboratory tests were undertaken to assess the viability of a
thermal
gravity drainage process comprising injection of a heated vapor-phase working
fluid
comprising vapor-phase DME and vapor-phase water, wherein the vapor-phase
water is
less than 5% of the total vapor-phase working fluid volume. Hereafter, the
combination
of heated vapor-phase DME and a small amount of vapor-phase water will be
referred
to as the "DME-vapor water test". For comparison, lab tests for steam-only
injection (the
"steam-only test"; equivalent to conventional SAGD) and heated vapor-phase DME-
only
injection (the "DME-only test") were also conducted. The lab tests were
conducted using
a 2D high pressure-high temperature test cell with Athabasca bitumen.
Example 1 - Laboratory Test Apparatus
34
Date Recue/Date Received 2020-10-27
[00149] The test cell used in the experiments described herein was similar
to that
described in Deng et al., "Simulating the ES-SAGD process with solvent mixture
in
Athabasca reservoirs", 2010, Journal of Canadian Petroleum Technology Vol.
49(1)
SPE-132488-PA, incorporated herein by reference. The test cell was constructed
of
stainless steel and its dimensions were 24 cm x 80 cm x 10 cm. The test cell
was
packed with frac sand resulting in a sandpack of 34.5% porosity and
permeability of
about 120 Darcy. The test cell was insulated and placed into a pressure
vessel. The
sandpack was then saturated with water and thereafter with dead Athabasca
bitumen
before the experiment. The procedure of saturating the sandpack is as follows:
the cell
was first saturated with water by pumping 1.5 pore volume of water through the
test cell,
then the water was displaced with the Athabasca bitumen by pumping about 1.2
pore
volume of oil through the cell. To speed up the bitumen saturating process,
the test cell
was pre-heated to about 55 C before pumping the bitumen. The test cell was
then
cooled to the lab temperature after the saturation process was completed. Data
of the
initial oil saturation and water saturation were recorded.
Example 2 - Initial Conditions
[00150] After the initial water and oil saturation processes, a total of
6218.0 gm of
bitumen and 213.0 gm of water were in the sandpacked test cell, which
corresponded to
an initial oil saturation of 0.927 and an initial water saturation of 0.073.
Other model
parameters are listed in Table 2 and operating parameters are listed in Table
3.
TABLE 2
Permeability (Darcy) 120
Pore Volume (cc) 6689.4
Porosity (%) 34.5
Oil-in-Place (gm) 6218.0
Viscosity of dead -517,000 at 20 C
Athabasca bitumen (cp) -903 at 80 C
-16.8 at 180 C
Date Recue/Date Received 2020-10-27
TABLE 3
Production Pressure -2200 kPa
Steam injection -225 C
temperature
DME injection temperature -125 C
[00151]
For the DME-vapor water test, the experimental operating scheme was as
outlined in Table 4 below. In Table 4, CWE = cold water equivalent and
"liquid" = liquid
volume equivalent.
TABLE 4
Stage Operating Duration (min) Injection Rate
Scheme
1 Initialization 0 - 10 Starting at 33cc/min (CWE) each
= Upper and lower wells
= Produce from upper and lower
2 SAGD 10 - 20 Water at 33cc/min (CWE)
3 DME-water 20 - 240* DME at 28cc/min (liquid)
Water at 0.15cc/min (CWE)
4 DME-water 240 - 250 DME at 20cc/min (liquid)
Water at 1.0cc/min (CWE)
DME-water 250 - 300 DME at 25cc/min (liquid)
Water at 1.0cc/min (CWE)
6 DME-water 300 - 360 DME at 35cc/min (liquid)
Water at 1.0cc/min (CWE)
7 DME-water 360 - 480 DME at 35cc/min (liquid)
Water at 0.15cc/min (CWE)
8 DME-water 480 - 600 DME at 30cc/min (liquid)
Water at 0.15cc/min (CWE)
9 N2 Injection 600 - 610 N2 at - 10L/m in
N2 Injection 610 - 630 N2 at - 5L/min
*There was an minor, unintentional spike in the water injection rate between
36 and 39
minutes due to an operational issue.
[00152]
For the steam-only test, stages 1 and 2 were the same as in Table 4 and
steam injection at an injection rate of about 33 cc/min continued for the rest
of the test.
36
Date Recue/Date Received 2020-10-27
[00153] For the DME-only test, the experimental operating scheme was as
outlined in Table 5 below.
TABLE 5
Stage Operating Duration (min) Injection Rate
Scheme
Starting at 33cc/min (CWE) each
1 Initialization 0 - 10 = Upper and lower wells
= Produce from upper and lower
2 SAGD 10 - 30 Steam at 33cc/min (CWE)
3 Warm DME 30 - 420 DME at 30cc/min (liquid)
4 Warm DME 420 - 500 DME at 15cc/min (liquid)
Warm DME 500 - 600 DME at 30cc/min (liquid)
Example 3 - Experimental Test Results
[00154] Figure 8 shows the DME and vapor water injection rates by liquid
equivalent for the DME-steam test. The density is around 0.635 g/cc. During
stages 1
and 2 (initialization and SAGD), the total steam injection was around 990g.
During
stages 3 to 8, total DME injection was around 11,125g and total water
injection was
around 190g.
[00155] Figure 9 shows the cumulative bitumen production for the DME-vapor
water test. Total bitumen production was 4.522kg (recovery factor of about
72.8%)
which included 0.232kg from stage 1 and 2 (initialization and SAGD), 4.152kg
from
stages 3 to 8 (DME and vapor water injection), and 0.138kg during stages 9 and
10 (N2
injection).
[00156] Figure 10 shows cumulative DME injection and DME production for
the
DME-vapor water test. Net DME injection was about 1.23kg. DME injection was -
11.12
kg, DME production was -9.41kg, and -0.582 of DME was produced with N2
injection.
Total recovery was therefore -90.2%.
[00157] Figure 11 shows a comparison of the cumulative bitumen production
from
the steam-only test (SAGD), the DME-only test (DME - Test #1), and the DME-
vapor
37
Date Recue/Date Received 2020-10-27
water test (DME - Test #2). The DME-only test resulted in total bitumen
production of
about 2981g and the DME-vapor water test resulted in total bitumen production
of about
4152 g.
[00158] Figure 12 shows a comparison of cumulative DME and steam injection
from DME-only test (DME ¨ Test #1), and the DME-vapor water test (DME - Test
#2).
Total DME injection for the DME-only test was about 10,118g. For the DME-vapor
water
test, total DME injection was about 11,125 g and total steam injection was
about 190g.
[00159] The results for the first 300 minutes of each of the three
experimental tests
are summarized in Table 6 below.
TABLE 6
Test Steam Injection DME Injection Bitumen Production
(g) (g) (g)
Steam only (SAGD) 10,230 N/A 2,683
DME-only 1,320 8,100 2,022
DME-vapor water 1,083 7,610 2,479
Example 4 ¨ Preliminary Observations on Asphaltene Precipitation
[00160] In the experimental tests with DME (i.e. DME-only and DME-vapor
water),
it was observed that an appreciable amount of asphaltene precipitation
occurred, as
evidenced by areas were the oil depleted sandpack was darker than in the all-
steam
test and, in such darker areas, some degree of cementing of the sandpack.
Evidently,
at least in some parts of the sandpack, it appeared that the concentration of
DME in the
mobilized bitumen exceeded the asphaltene precipitation threshold. It was
hypothesized that by substituting one or more normal hydrocarbon solvents,
e.g.
propane or butane, for some fraction of the DME, the concentration of each
individual
solvent component (i.e. DME, propane, butane, etc.) dissolved into the bitumen
might
38
Date Recue/Date Received 2020-10-27
be kept below its asphaltene precipitation threshold and therefore less
asphaltene in the
bitumen would be precipitated in the recovery process.
[00161] Consequently, a fourth experimental test was conducted in which
the
heated vapor-phase working fluid comprised DME, water and various ratios of
butane. The fourth experiment was operated using a similar scheme as the DME-
vapor
water test. The DME plus butane liquid volumetric injection rate was the same
as the
DME injection rate in the DME-vapor water test. The DME to butane ratio was
19:11
between 80 to 540 minutes and 11:19 between 540 to 600 minutes. The water
injection
rate was the same as in the DME-vapor water test. Figure 13 shows the residual
oil
saturations in the sandpack after the experiments. It is noted that the
residual oil
saturations in the depleted zone in the DME-water-butane experiment (right)
were lower
than that in the DME-water experiment (left). SARA (Saturate, Aromatic, Resin
and
Asphaltene) analysis of the residual oil showed that asphaltene contents in
the residual
oils was more than 93wtc/o. Therefore the results show that less asphaltene
was left in
the sandpack in the DME-water-butane experiment, which indirectly confirms the
hypothesis that asphaltene precipitation can be reduced by partially
substituting butane,
a normal hydrocarbon, for a portion of the DME. This is a potentially
important finding
since it may provide a means to control the extent of in-situ asphaltene
precipitation by
varying the composition of the injected heated vapor-phase working fluid. For
example,
this capability might be used to achieve a single controlled degree of
asphaltene
precipitation or to vary the degree of asphaltene precipitation over the
operating life of
the recovery process.
[00162] Various modifications besides those already described are possible
without departing from the concepts disclosed herein. Moreover, in
interpreting the
disclosure, all terms should be interpreted in the broadest possible manner
consistent
with the context. In particular, the terms "comprises" and "comprising" should
be
interpreted as referring to elements, components, or steps in a non-exclusive
manner,
indicating that the referenced elements, components, or steps may be present,
or
39
Date Recue/Date Received 2020-10-27
utilized, or combined with other elements, components, or steps that are not
expressly
referenced.
[00163]
Although particular embodiments have been shown and described, it will
be appreciated by those skilled in the art that various changes and
modifications might
be made without departing from the scope of the disclosure. The terms and
expressions
used in the preceding specification have been used herein as terms of
description and
not of limitation, and there is no intention in the use of such terms and
expressions of
excluding equivalents of the features shown and described or portions thereof.
Date Recue/Date Received 2020-10-27
