Note: Descriptions are shown in the official language in which they were submitted.
CA 02956771 2017-01-31
METHODS OF RECOVERING HEAVY HYDROCARBONS
BY HYBRID STEAM-SOLVENT PROCESSES
TECHNICAL FIELD
[001] This invention relates generally to in situ processes for recovering
hydrocarbons from reservoirs of heavy hydrocarbons, and more particularly to
hybrid
steam-solvent-assisted in situ recovery processes.
BACKGROUND
[002] Some subterranean deposits of heavy hydrocarbons can be extracted in
situ (in-situ) by increasing the mobility of the heavy hydrocarbons so that
they can be
moved to, and recovered from, a production well penetrating a formation of the
hydrocarbons. Reservoirs of such deposits may be referred to as reservoirs of
heavy
hydrocarbons, heavy oil, bitumen, tar sands, bituminous sands, or oil sands.
For
example, such reservoirs include deposits as may be found in Canada's
Athabasca oil
sands.
[003] The in situ processes for recovering oil from heavy hydrocarbon
reservoirs typically involve the use of multiple wells drilled into the
reservoir, and are
assisted or aided by injecting a heated fluid such as steam into the reservoir
formation
from an injection well.
[004] For example, a known process for recovering viscous hydrocarbons is
the
steam-assisted gravity drainage (SAGD) process. A typical (conventional) SAGD
process utilizes one or more pairs of vertically spaced horizontal wells. For
example,
various embodiments of the SAGD process are described in Canadian Patent No.
1,304,287 and corresponding U.S. Patent No. 4,344,485. In a SAGD process,
steam is
pumped through an upper, horizontal, injection well into a viscous hydrocarbon
reservoir while hydrocarbons are produced from a lower, parallel, horizontal,
production
well vertically spaced proximate to the injection well. The injection and
production wells
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are typically located near, but some distance above, the bottom of a pay zone
in the
hydrocarbon deposit. The injected steam initially heats and mobilizes the in-
situ
hydrocarbons in the reservoir around the injection well. Mobilized
hydrocarbons will
drain downward due to gravity, leaving a volume of the formation at least
partially
depleted of the hydrocarbons. The pores in the depleted volume of the
formation, from
which mobilized oil has at least partially drained, are then filled with
mainly injected
steam, and the deleted volume is thus commonly referred to as the "steam
chamber".
As steam injection and gravity drainage continue, the steam chamber will
continue to
grow, expanding both upwardly and laterally from the injection well. As the
steam
chamber expands upwardly and laterally from the injection well, more and more
viscous hydrocarbons in the reservoir are gradually heated and mobilized,
especially at
the margins of the steam chamber where the steam condenses and heats a layer
of
viscous hydrocarbons by thermal conduction. The mobilized hydrocarbons (and
aqueous condensate) drain under the effects of gravity towards the bottom of
the
steam chamber, where the production well is located. The mobilized
hydrocarbons are
collected and produced from the production well.
[005] Alternative processes aided by fluids other than steam have also
been
proposed. For example, solvent-aided processes (SAP) and a process known as
the
vapor-extraction (VAPEX) process have been proposed. In SAP, both steam and a
solvent may be used to aid recovery. VAPEX utilizes a solvent vapor, instead
of
steam, to reduce the viscosity of viscous hydrocarbons. In a proposed VAPEX
process,
a solvent, such as propane, is injected into the reservoir in the vapor phase,
to form a
vapor-filled chamber within the reservoir. The solvent vapor dissolves in the
oil around
the vapor chamber and the resulting solution drains, driven by gravity, to a
horizontal
production well placed low in the formation. The solvent vapor, at or near its
dew point,
is injected simultaneously with hot water from a horizontal well located at
the top of the
reservoir. The temperature and flow rate of the water are chosen so that the
reservoir
temperature is raised to the range of only 40 C to 80 C. See, Butler et al.,
"A New
Process (VAPEX) for Recovering Heavy Oils Using Hot Water and Hydrocarbon
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Vapour", Journal of Canadian Petroleum Technology, 1991, vol. 30, issue 1,
pages 97-
106.
[006] US 6,662,872 to Gutek et al. discloses a combined steam and vapor
extraction process (SAVEX), where steam is injected until an upper surface of
the
steam chamber has progressed to 25 to 75 percent of the distance from the
bottom of
the injection well to the top of the reservoir, or until the recovery rate of
hydrocarbons is
about 25 to 75 percent of the peak predicted recovery rate using SAGD. When
the
condition is met, steam injection is suspended and replaced with solvent vapor
injection
(the VAPEX process). The cross over in injection from steam to vaporized
solvent
should occur about 4 to 6 months after the initiation of SAGD operations for a
typical
SAGD well pair in Athabasca. One of the goals in modifying existing SAGD and
other
steam-assisted processes is to reduce the steam to oil ratio (SOR) or the
cumulative
SOR (CSOR), as the SOR or CSOR is commonly considered an important metric for
assessing the performance and efficiency of a steam-assisted recovery process.
Replacing steam with solvent vapor and hot water as in the VAPEX or SAVEX
process
is expected to reduce CSOR. However, another important measure of the
performance
of an oil recovery process is the oil production rate, which indicates how
fast oil can be
produced from the reservoir. The proposed VAPEX or SAVEX processes are
expected
to result in significant reduction in peak oil production rate.
[007] Instead of a well pair, one or more single horizontal or vertical
wells may
be utilized for injection and production in in-situ hydrocarbon recovery
processes such
as, but not limited to, SAGD, cyclic steam stimulation (CSS), or SAP. For
example,
Canadian patent application number 2,844,345 to Gittins et al. discloses a
single
vertical or inclined well thermal recovery process. Canadian patent
application number
2,868,560 to Sood et aL discloses a single horizontal well for injection and
production in
thermal or solvent recovery processes. These single well processes may be
preceded
by start-up acceleration techniques to establish communication in the
formation
between openings in the single well that have been configured to allow for
both
injection and production. An assembly for coupling a high-pressure steam
pipeline, a
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produced hydrocarbon emulsion pipeline, and a produced gas pipeline to a
single well
may be employed for facilitating injection and production.
SUMMARY
[008] In one aspect, there is provided a method of recovering heavy
hydrocarbons from a subterranean reservoir by a steam-dominant recovery
process
and a solvent-dominant recovery process, comprising: injecting steam into the
reservoir
to assist recovery of hydrocarbons from the reservoir by the steam-dominant
recovery
process until a peak process threshold has been reached, wherein a vapor
chamber is
developed in the reservoir by steam injection and a dominant vapor in the
vapor
chamber during the steam-dominant recovery process is steam; upon
determination
that the peak process threshold has been reached, co-injecting a solvent and
steam
into the vapor chamber to assist further recovery of hydrocarbons from the
reservoir by
the solvent-dominant recovery process, such that the vapor chamber is further
expanded and the dominant vapor in the expanded vapor chamber is a vapor of
the
injected solvent; and recovering a fluid comprising the solvent and
hydrocarbons from
the reservoir.
[009] The steam-dominant recovery process may comprise a steam-assisted
gravity drainage (SAGD) recovery process. The method may comprise selecting a
solvent for the solvent- dominant process, wherein the solvent is injectable
as a vapor
and dissolves at least one of the hydrocarbons for increasing a mobility of
the heavy
hydrocarbons. The solvent may be heated and vaporized by the co-injected
steam. The
solvent-dominant recovery process may comprise co-injecting steam and the
vapor of
the solvent into the vapor chamber to further expand the vapor chamber
laterally,
wherein the volume of steam injected into the reservoir formation provides
sufficient
heat to the injected solvent to maintain the injected solvent in a vapor
phase, and
wherein the weight ratio of co-injected solvent vapor to co-injected steam is
higher than
3/2. The method may comprise selecting a transition condition for
transitioning from the
steam-dominant recovery process to the solvent-dominant recovery process,
wherein
the transition condition occurs after the peak process threshold has been
reached,
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determining when the condition has been met, and upon determination that the
condition has been met, transitioning from the steam-dominant recovery process
to the
solvent-dominant recovery process. The reservoir may have an overburden above
a
formation of the reservoir that contains heavy hydrocarbons, the steam-
dominant
process may create a vapor chamber in the formation below the overburden, and
the
transition condition may be that the injected steam has reached the
overburden. The
reservoir may have an overburden above a formation of the reservoir that
contains
heavy hydrocarbons, the SAGD process may form a vapor chamber in the formation
below the overburden, and the transition condition may be that vertical growth
of the
vapor chamber has reached a limit such that further vapor chamber growth will
be
substantially lateral. The transition condition may be that a peak hydrocarbon
production rate has been reached in the SAGD process. The transition condition
may
be that the reservoir has been subjected to the steam-dominant recovery
process for at
least two years. The transition condition may be that the hydrocarbon
production rate
has reached a peak value and then decreased by less than about 20 percent of
the
peak value, such as decreased by about 10% of the peak production rate, in the
steam-
dominant recovery process. The transition condition may be that hydrocarbon
production in the steam-dominant recovery process has declined for a selected
period
of time. The transition condition may be that a current cumulative steam to
oil ratio
(CSOR) is higher than a previous CSOR in the steam-dominant recovery process.
The
reservoir may have an overburden above a formation of the reservoir that
contains
heavy hydrocarbons, and steam injection in the steam-dominant recovery process
may
cause a temperature at an interface region between the overburden and the
formation
to increase, and the transition condition may be that the temperature has
increased to
at least 20 C due to heating by steam injection. The solvent may comprise at
least one
of propane, butane, pentane, hexane, heptane, and octane. The solvent may
comprise
a C3 to C5 hydrocarbon. The solvent may comprise propane. The solvent-dominant
process may comprise co-injecting a mixture of steam and the solvent, the
mixture
comprising less than 40 wt% of steam. The solvent may comprise propane and the
solvent-dominant process may comprise co-injecting a mixture of steam and the
CA 02956771 2017-01-31
solvent, the mixture comprising about 10 wt% of steam and about 90 wt% of the
solvent. The solvent may comprise propane, and steam and the solvent may be co-
injected at a temperature of about 75 C to about 100 C in the solvent-
dominant
process. Steam may be injected at a pressure of about 3 MPa in the steam-
dominant
recovery process, and steam and the solvent may be co-injected at a pressure
of about
2 MPa to about 3.5 MPa in the solvent-dominant process. The co-injection of a
solvent
and steam into the vapor chamber may comprise gradually increasing the weight
ratio
of the solvent in the co-injected solvent and steam, and gradually decreasing
the
weight ratio of steam in the co-injected solvent and steam. The method may
further
comprise gradually decreasing a solvent content in the co-injected solvent and
steam,
and gradually increasing a steam content in the co-injected solvent and steam.
The
solvent-dominant process may comprise co-injecting a mixture of about 20 wt%
of
steam and about 80 wt% of propane. Steam injection may be reduced from about
100
wt% to about 20 wt% of the injected fluid (mixture) over a period of about
three weeks.
In the solvent-dominant process, the steam and solvent may be co-injected as a
mixture at a selected temperature, and a ratio of steam to solvent in the
mixture and
the temperature may be selected so that the mixture has sufficient enthalpy to
allow the
solvent to be in the gas phase at the selected temperature. In the steam-
dominant
recovery process, steam may be injected at a temperature sufficient to heat
the solvent
such that the injected solvent has a temperature of between about 50 C and
about 350
C within the vapor chamber.
[010] Other aspects and features will become apparent to those of ordinary
skill
in the art upon review of the following description of specific embodiments of
the
invention in conjunction with the accompanying figures.
BRIEF DESCRIPTION OF THE DRAWINGS
[011] Selected illustrative embodiments are described in detail below, with
reference to the following drawings.
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[012] FIG. 1 is a schematic side view of a hydrocarbon reservoir and a pair
of
wells penetrating the reservoir for recovery of hydrocarbons.
[013] FIG. 2 is a schematic partial end view of the reservoir and wells of
FIG. 1.
[014] FIG. 3 is a schematic perspective view of the reservoir and wells of
FIG. 1
during operation after a vapor chamber has formed in the reservoir.
[015] FIG. 4 is a flowchart illustrating a process for recovery of
hydrocarbons
from the reservoir of FIG. 1, illustrative of an embodiment.
[016] FIG. 5 is a simulated two-dimensional phase diagram for selected
solvents.
[017] FIG. 6 is a schematic partial end view of the reservoir and wells of
FIG. 3
where the vapor chamber has expanded upward to reach the overburden above the
wells.
[018] FIG. 7 is a schematic partial end view of the reservoir and wells of
FIG. 3
where the vapor chamber has ceased upward vertical expansion and has further
expanded laterally.
[019] FIGS. 8, 9, 10 and 11 are line graphs illustrating expected change in
oil
production rate over time in a SAGD process and possible transition times.
[020] FIG. 12 is a line graph illustrating time dependency of the
cumulative
steam to oil ratio in a SAGD process.
[021] FIG. 13 is a data graph of representative expected temperature
changes
at an interface region between a pay zone formation and an overburden in the
reservoir
of FIG. 1 over time during a SAGD process.
[022] FIG. 14 is a line graph showing representative expected heavy
hydrocarbon recovery factors for selected solvents at various injection
temperatures.
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[023] FIG. 15 is a data graph showing representative expected oil
production
rates for a hybrid steam-solvent process as compared to a conventional SAGD
process.
[024] FIG. 16 is a data graph comparing expected production rates for a
hybrid
process and a comparison SAGD process, illustrating the effects of the solvent-
dominant process at later stages of oil production.
[025] FIG. 17 shows a screen capture of a computer display illustrating
representative simulation results of vapor chamber development in the process
of
FIG. 4.
[026] FIG. 18 is a line graph showing cumulative oil production over time
in
different simulated recovery processes.
[027] FIG. 19 is a line graph showing oil production rate over time in
different
simulated processes.
[028] FIG. 20 is a line graph showing cumulative solvent injection over
time in
different simulated recovery processes.
DETAILED DESCRIPTION
[029] In overview, it has been recognized by the Applicant that effective
and
efficient recovery of heavy hydrocarbons from a subterranean hydrocarbon
reservoir
can be provided by a hybrid recovery process where a steam-dominant recovery
process (steam-dominant process) is followed by a solvent-dominant recovery
process
(solvent-dominant process) after the steam-dominant recovery process has
reached a
peak production threshold. The Applicant has found that the peak production
threshold
may be reached when the steam chamber has ceased substantial vertical growth
or
expansion (e.g. has reached the overburden above the steam chamber), when the
oil
production rate by the steam-dominant process has peaked, when the cumulative
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steam to oil ratio (CSOR) has started to increase, or when the temperature in
the
interface region between the reservoir formation and the overburden has
started to
significantly increase. It is expected that an embodiment of such a hybrid
recovery
process can significantly accelerate hydrocarbon recovery, reduce the overall
CSOR,
and still achieve satisfactory peak oil production rate, or satisfactory
overall average oil
production rate over the entire recovery period.
[030] In the steam-dominant recovery process, the injected steam plays the
dominant role for the vertical vapor chamber development in the reservoir. The
vapor
chamber developed in the steam-dominant process is a steam chamber, as the
dominant vapor in the vapor chamber is steam. In selected embodiments, the
steam-
dominant recovery process may be a steam-assisted gravity drainage (SAGD)
process.
In a SAGD process, pure steam may be injected to assist hydrocarbon recovery.
In a
modified SAGD process, one or more additives may be co-injected with steam, or
separately injected, but the weight ratio of the additive to steam in the
injection fluid is
relatively small, such as less than about 20 to 30 wt%.
[031] In the solvent-dominant recovery process, the injected solvent plays
the
dominant role for further expansion, particularly lateral or horizontal
expansion of the
vapor chamber in the reservoir. While the vapor chamber is initially dominated
by
steam, after a period of operation under the solvent-dominant process, the
dominant
vapor in the vapor chamber becomes the solvent vapor, as the dominant
component in
the injection fluid is now the solvent. In selected embodiments, the solvent
may be co-
injected with a small amount of steam in the solvent-dominant process. In such
a case,
the amount of the injected steam is selected to be sufficient to heat and
vaporize the
injected solvent, and maintain the solvent in the vapor phase in the vapor
chamber to
allow the solvent to travel to the chamber front (edges or margins of the
vapor
chamber). However, the weight ratio of co-injected steam to co-injected
solvent is
relatively small, such as less than about 20 to 30 wt%, so that steam plays
only a minor
role in further expansion the vapor chamber and further oil production. The
amount of
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injected steam is thus substantially reduced or minimized in the solvent-
dominant
process, as compared to steam use in the steam-dominant process.
[032] As can be appreciated, the solvent used in the solvent-dominant
process
is vaporizable at the operational pressure and temperature near the injection
well and
in the central region of the vapor chamber, which has been heated by steam to
an
elevated temperature, so that the solvent can enter the reservoir in the vapor
phase
and can remain in the vapor phase until the solvent vapor reaches the vapor
chamber
front. The solvent is also substantially condensable at the edges, margins or
boundaries of the vapor chamber, where the local temperature is significantly
lower
than the temperature in the central region of the vapor chamber. The condensed
solvent is capable of dissolving hydrocarbons such that the condensed solvent
(liquid
solvent) can reduce the viscosity of the hydrocarbons, or increase the
mobility of the
hydrocarbons, which will assist to improve the hydrocarbon drainage rate and
therefore
hydrocarbon production rate. There are a number of underlying mechanisms for
increasing mobility of hydrocarbons in the reservoir formation as can be
understood by
those skilled in the art. A suitable solvent may be selected to assist
drainage of
hydrocarbons based on any of these mechanisms or a combination of such
mechanisms.
[033] For example, a solvent may be selected based on its ability to reduce
the
viscosity of hydrocarbons, to dissolve in the reservoir fluid, or to reduce
surface and
interfacial tension between hydrocarbons and sands or other solid or liquid
materials
present in the reservoir formation. The solvent may act as a wetting agent or
surfactant.
When oil attachment to sand or other immobile solid materials in the reservoir
is
reduced, the oil mobility can be increased. The solvent may function as an
emulsifier
for forming hydrocarbon-water emulsions, which may help to improve oil
mobility with
water in the reservoir. Suitable solvents may include volatile hydrocarbon
solvents such
as butane or propane, as will be further described below.
[034] In the hybrid steam-solvent process described herein, the timing for
the
transition from the steam-dominant process to the solvent-dominant process is
selected
CA 02956771 2017-01-31
to maintain satisfactory production performance while significantly reducing
the overall
CSOR. One factor for considering if a recovery process has satisfactory
production
performance is if the overall recovery process is practical and economically
viable. The
factors to be considered include the overall production time (to reach a given
recovery
factor), the overall production cost, the overall (amount of) oil recovery for
a given
reservoir, the potential environmental impact, and the like. It is generally
desirable to
minimize production cost while increasing production yield and production
rate, and
shortening recovery time. If the transition from the steam-dominant process to
the
solvent-dominant process occurs too early, such as before the oil production
rate by
steam injection has reached the peak rate, the overall production performance
will be
negatively affected. Transition after a properly selected peak production
threshold,
such as the peak oil production rate, has been reached is expected provide a
balanced
result, i.e., reducing the overall CSOR while maintaining satisfactory overall
production
performance.
[035] In some embodiments, a solvent-dominant process is introduced to
improve production performance of an existing SAGD operation, particularly
after the
SAGD operation has continued for at least two years, or after the SAGD
production
rate has peaked and is declining or after the CSOR of the SAGD operation has
reached a minimum and is increasing with continued steam injection. At such
later
'stages of the SAGD operation, replacing steam with solvent vapor as the
dominant fluid
for vapor chamber development and for hydrocarbon mobilization can
conveniently
have a number of benefits, some of which will be discussed below. As can be
appreciated, in some applications, the transition from a steam-dominant
process to a
solvent-dominant process may occur earlier than two years from initial SAGD
production, or may be later than two years.
[036] Without being limited to any particular theory, it is expected that
steam is
more efficient or effective for vertical growth of the vapor chamber and a
suitable
solvent may be more efficient or effective for lateral growth of the vapor
chamber. Thus,
transitioning from a steam-dominant process to a solvent-dominant process
after the
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vapor chamber has reached the overburden (or vertical expansion limit) and
thus
ceased vertical growth may provide better overall efficiency and more cost-
effective
recovery of hydrocarbons from the reservoir, as compared to a conventional
SAGD
process or a conventional SAVEX process. The residual heat and aqueous
condensate
in the vapor chamber after steam injection can also help the injected solvent
to remain
in the vapor phase and to disperse through the vapor chamber, which will
improve the
effectiveness and efficiency of the solvent recovery process. The improvement
or
synergistic effect may be particularly significant for hydrocarbon recovery
from a
reservoir formation which has a pay zone depth that requires, for example,
many
months to two years for the vapor chamber to fully develop vertically by the
steam-
dominant recovery process.
[037] Also without being limited to any particular theory, it is further
expected
that steam utilization may become less efficient or effective after the vapor
chamber
(steam chamber) has reached the overburden due to significant heat loss
through the
overburden by thermal conduction. As a solvent vapor may be injected at a
substantially lower temperature as compared to steam, further production
operation at
the lower temperature can reduce inefficiency due to heat loss.
[038] Selected illustrative embodiments are described in more detail below
with
reference to the drawings.
[039] FIG. 1 schematically illustrates a typical SAGD well pair in a
hydrocarbon
reservoir, which can be operated to implement an embodiment of the hybrid
process.
[040] As illustrated, a reservoir formation 100 containing heavy
hydrocarbons is
below an overburden 110. Under natural conditions, reservoir formation 100 is
at a
relatively low temperature, such as about 12 C, and the formation pressure
may be
from about 0.1 to about 4 MPa (1 MPa = 106 Pa), depending on the location and
other
characteristics of the reservoir.
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[041] A pair of SAGD wells, including an injection well 120 and a
production
well 130, is drilled into and extends substantially horizontally in reservoir
formation 100,
for producing hydrocarbons from reservoir formation 100. The well pair is
typically
positioned away from the top of the reservoir formation 100, which as depicted
in FIG.
1 is defined by the lower edge of overburden 110, and positioned near the
bottom of a
pay zone or geological stratum in formation 100, as can be appreciated by
those skilled
in the art.
[042] As is typical, injection well 120 may be vertically spaced from
production
well 130, such as at a distance of about 5 m. The distance between the
injection well
and the production well in a SAGD well pair may vary and may be selected to
optimize
the SAGD operation performance, as can be understood by those skilled in the
art. In
some embodiments, the horizontal sections of wells 120 and 130 may have a
length of
about 800 m. In other embodiments, the length may be varied as can be
understood
and selected by those skilled in the art. Wells 120 and 130 may be configured
and
completed according to any suitable techniques for configuring and completing
horizontal in-situ wells known to those skilled in the art. Injection well 120
and
production well 130 may also be referred to as the "injector" and "producer",
respectively.
[043] As depicted, formation 100 underlies overburden 110, which may also
be
referred to as a cap layer or cap rock. Overburden 110 is formed of a layer of
impermeable material such as clay or shale. A region in the formation 100 just
below
and near overburden 110 may be considered as an interface region 115.
[044] As illustrated, wells 120 and 130 are connected to respective
corresponding surface facilities, which typically include an injection surface
facility 140
and a production surface facility 150. Surface facility 140 is configured and
operated to
supply injection fluids, such as steam and solvent, into injection well 120.
Surface
facility 150 is configured and operated to produce fluids collected in
production well 130
to the surface. Each of surface facilities 140, 150 includes one or more fluid
pipes or
tubing for fluid communication with the respective well 120 or 130. As
depicted for
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illustration, surface facility 140 may have a supply line connected to a steam
generation
plant for supplying steam for injection, and a supply connected to a solvent
source for
supplying the solvent for injection. Optionally, one or more additional supply
lines may
be provided for supplying other fluids, additives or the like for co-injection
with steam or
the solvent. Each supply line may be connected to an appropriate source of
supply,
which may include, for example, a steam generation plant, a boiler, a fluid
mixing plant,
a fluid treatment plant, a truck, a fluid tank, or the like. In some
embodiments, co-
injected fluids or materials may be pre-mixed before injection. In other
embodiments,
co-injected fluids may be separately supplied into injection well 120. In
particular,
surface facility 140 is used to supply steam and a selected solvent into
injection well
120. The solvent may be pre-mixed with steam at surface before co-injection.
Alternatively, the solvent and steam may be separately fed into injection well
120 for
injection into formation 100. Optionally, surface facility 140 may include a
heating
facility (not separately shown) for pre-heating the solvent before injection.
[045] As illustrated, surface facility 150 includes a fluid transport
pipeline for
conveying produced fluids to a downstream facility (not shown) for processing
or
treatment. Surface facility 150 includes necessary and optional equipment for
producing fluids from production well 130, as can be understood by those
skilled in the
art.
[046] Other necessary or optional surface facilities 160 may also be
provided,
as can be understood by those skilled in the art. For example, surface
facilities 160
may include one or more of a pre-injection treatment facility for treating a
material to be
injected into the formation, a post-production treatment facility for treating
a produced
material, a control or data processing system for controlling the production
operation or
for processing collected operational data.
[047] Injection well 120 and production well 130 may be configured and
completed in any suitable manner as can be understood or is known to those
skilled in
the art, so long as the wells are compatible with injection and recovery of
the selectable
solvent to be used in the solvent-dominant process as will be disclosed below.
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[048] FIG. 2 shows a schematic cross-sectional view of wells 120, 130 in
formation 100, and FIG. 3 is a schematic perspective view of wells 120, 130 in
formation 100 during a recovery process where a vapor chamber has formed.
[049] As illustrated, injection well 120 and production well 130, each have
a
casing 220, 230 (respectively). An injector tubing 225 is positioned in
injector casing
220, the use of which can be understood by those skilled in the art and will
be
described below. For simplicity, other necessary or optional components, tools
or
equipment that are installed in the wells are not shown in the drawings as
they are not
particularly relevant to the present disclosure.
[050] As depicted in FIG. 3, injector casing 220 includes a slotted liner
along
the horizontal section of well 120 for injecting fluids into reservoir
formation 100.
[051] Production casing 230 is also completed with a slotted liner along
the
horizontal section of well 130 for collecting fluids drained from reservoir
formation 100
by gravity. In some embodiments, production well 130 may be configured and
completed similarly to injection well 120.
[052] In some embodiments, each well 120, 130 may be configured and
completed for both injection and production, which can be useful in some
applications
as can be understood by those skilled in the art.
[053] In operation according to an embodiment of the hybrid process, wells
120
and 130 may be initially operated to produce hydrocarbons from reservoir
formation
100 according to a conventional SAGD process, or a suitable variation thereof,
as can
be understood by those skilled in the art. In this initial process, steam is
the only or the
dominant injection fluid.
[054] FIG. 4 illustrates an example hybrid process.
[055] At S400, reservoir formation 100 is subjected to an initial phase of
the
SAGD process, referred to as the "start-up" phase or stage, in which fluid
CA 02956771 2017-01-31
communication between wells 120 and 130 is established. To permit drainage of
mobilized hydrocarbons and condensate to production well 130, fluid
communication
between wells 120, 130 must be established. Fluid communication refers to
fluid flow
between the injection and production wells. Establishment of such fluid
communication
typically involves mobilizing viscous hydrocarbons in the reservoir to form a
reservoir
fluid and removing the reservoir fluid to create a porous pathway between the
wells.
Viscous hydrocarbons may be mobilized by heating such as by injecting or
circulating
pressurized steam or hot water through injection well 120 or production well
130. In
some cases, steam may be injected into, or circulated in, both injection well
120 and
production well 130 for faster start-up. For example, the start-up phase may
include
circulation of steam or hot water by way of injector casing 220 and injector
tubing 225
in combination. A pressure differential may be applied between injection well
120 and
production well 130 to promote steam/hot water penetration into the porous
geological
formation that lies between the wells of the well pair. The pressure
differential promotes
fluid flow and convective heat transfer to facilitate communication between
the wells.
[056] Additionally or alternatively, other techniques may be employed
during
the start-up phase. For example, to facilitate fluid communication, a solvent
may be
injected into the reservoir region around and between the injection and
production wells
120, 130. The region may be soaked with a solvent before or after steam
injection. An
example of start-up using solvent injection is disclosed in CA2,698,898. In
further
examples, the start-up phase may include one or more start-up processes or
techniques disclosed in CA2,886,934, CA2,757,125, or CA2,831,928.
[057] Once fluid communication between injection well 120 and production
well
130 has been achieved, oil production or recovery may commence, at S410. As
the oil
production rate is typically low initially and will increase as the vapor
chamber
develops, the early production phase is known as the "ramp-up" phase or stage.
During
the ramp-up phase, steam is typically injected continuously into injection
well 120, at
constant or varying injection pressure and temperature. At the same time,
mobilized
heavy hydrocarbons and aqueous condensate are continuously removed from
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production well 130. During ramp-up, the zone of communication between
injection well
120 and production well 130 may continue to expand axially along the full
length of the
horizontal portions of wells 120, 130.
[058] As injected steam heats up formation 100, heavy hydrocarbons in the
heated region are softened, resulting in reduced viscosity. Further, as heat
is
transferred from steam to formation 100, steam condenses. The aqueous
condensate
and mobilized hydrocarbons will drain downward due to gravity. As a result of
depletion
of the heavy hydrocarbons, a porous region 360 is formed in formation 100,
which is
referred to as the "vapor chamber." When the vapor chamber is filled with
mainly
steam, it is commonly referred to as the "steam chamber." The aqueous
condensate
and hydrocarbons drained towards production well 130 and collected in
production well
130 are then produced (transferred to the surface), such as by gas lifting or
through
pumping as is known to those skilled in the art.
[059] As alluded to above, vapor chamber 360 is formed and expands due to
depletion of hydrocarbons and other in situ materials from regions of
formation 100
above the injection well 120. Injected steam tends to rise up to reach the top
of vapor
chamber 360 before it condenses, and steam can also spread laterally as it
travels
upward. Therefore, during early stages of chamber development, vapor chamber
360
expands upwardly and laterally from injection well 120. During the ramp-up
phase and
the early conventional SAGD production phase, vapor chamber 360 can grow
vertically
towards overburden 110.
[060] Depending on the size of formation 100 and the pay therein and the
distance between injection well 120 and overburden 110, it can take a long
time, such
as many months and up to two years, for vapor chamber 360 to reach overburden
110,
when the pay zone is relative thick as is typically found in some operating
oil sands
reservoirs. However, it will be appreciated that in a thinner pay zone, the
vapor
chamber can reach the overburden sooner. The time to reach the vertical
expansion
limit can also be longer in cases where the pay zone is higher or highly
heterogeneous,
17
CA 02956771 2017-01-31
or the formation has complex overburden geologies such as with inclined
heterolithic
stratification (HIS), top water, top gas, or the like.
[061] At S420, reservoir formation 100 is subject to a conventional SAGD
production process, where the oil production rate is sufficiently high for
economic
recovery of hydrocarbons and the CSOR continues to decrease or remain
relatively
stable.
[062] During SAGD production or a similar but modified steam-dominant
recovery process, one or more chemical additives may be added to steam or co-
injected with steam to enhance hydrocarbon recovery. For example, a
surfactant, which
lowers the surface tension of a liquid, the interfacial tension (IFT) between
two liquids,
or the IFT between a liquid and a solid, may be added. The surfactant may act,
for
example, as a detergent, wetting agent, emulsifier, foaming agent, or
dispersant, to
facilitate the drainage of the softened hydrocarbons to the production well.
An organic
solvent, such as an alkane or alkene, may also be added to dilute the
mobilized
hydrocarbons so as to increase the mobility and flow of the diluted
hydrocarbon fluid to
production well 130 for improved recovery. Other materials in liquid or gas
form may
also be added to enhance recovery performance. However, steam still plays the
dominant role in chamber development during such modified SAGD processes and
the
weight ratio of such other agents or additives in the injection stream is
relatively low. In
some embodiments, the injection stream may include a mixture of steam and
another
vapor, where the partial pressure of the other vapor is about 0.25% to about
20% of the
total pressure.
[063] When vapor chamber 360 grows vertically, oil production rate normally
continue to increase, and the CSOR normally continue to decrease. Steam
utilization
during such chamber growth is efficient. However, when the top front of vapor
chamber
360 approaches or reaches overburden 110 or transition region 115 near
overburden
110, vertical growth of vapor chamber 360 will slow down and eventually stop.
While
vapor chamber 360 may continue to grow or expand laterally, which may be at a
slower
pace, steam utilization during slow lateral growth is less efficient. As a
result, oil
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CA 02956771 2017-01-31
production rate may reach a peak value or plateau, and then starts to decline.
The
CSOR may bottom out and start to increase.
[064] Thus, such changes in chamber growth, oil production rate and CSOR
may be used as a production threshold for transitioning from the steam-
dominant
process to the solvent-dominant process. Without being limited to any
particular theory,
it is expected that a suitable solvent can be more effective or more efficient
than steam
for growing a vapor chamber laterally.
[065] The start-up, ramp-up, and SAGD production phases may be conducted
according to any suitable conventional techniques known to those skilled in
the art, and
will therefore not be detailed herein for brevity.
[066] As an example, during conventional SAGD production, or at the end of
the SAGD production process in the hybrid process, the formation temperature
in the
vapor chamber can reach about 235 C and the pressure in the vapor chamber may
be
about 3 MPa. Of course, depending on the reservoir and the application, the
chamber
temperature and pressure may vary in different embodiments. For example, in
various
embodiments, steam may be injected at a temperature from about 152 C to about
328
C and a pressure from about 0.1 MPa to about 12.5 MPa. In some embodiments,
the
highest temperature in the vapor chamber may be from about 152 C to about 286
C
and the pressure in the vapor chamber may be from about 0.1 MPa to about 7
MPa.
[067] In further embodiments, it may also be possible that in the solvent-
dominant process, steam is injected at a temperature sufficient to heat the
solvent such
that the injected solvent has a maximum temperature of between about 50 C and
about 350 C within the vapor chamber.
[068] It should be noted that the temperature in a vapor chamber varies
from
the injection well towards the front of the vapor chamber, and the temperature
at the
chamber edges (also referred to as the "steam front") is still relatively low,
such as
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CA 02956771 2017-01-31
about 15 C to about 25 C. The reservoir temperature can also vary from about
10 C
to the highest chamber temperature discussed above.
[069] As production continues in conventional SAGD after the oil production
rate has peaked, the rate of oil production will eventually decrease. When the
oil
production rate drops below a certain production performance threshold,
continued
operation under the SAGD production process becomes less economic, which is
expected to occur during the later stages of a conventional SAGD production
process,
as compared to the earlier full production stage.
[070] It is expected that replacing the SAGD production process with a
suitable
solvent-dominant recovery process can improve production efficiency or
performance
and improve the economic outcome of the operation.
[071] To this end, at S430 a suitable solvent and transition condition are
selected according to the various factors and considerations discussed herein,
and as
can be understood by those skilled in the art, at S440 and S450 respectively.
As can be
appreciated, the selection at S440 and S450 may be performed at any time prior
to
solvent injection, and may be performed in any order depending on the
particular
situation and application.
[072] At S440, the solvent for use in the solvent-dominant process is
selected
or determined. A suitable solvent may be selected based on a number of
considerations and factors as discussed herein. The solvent should be
injectable as a
vapor, and can dissolve at least one of the heavy hydrocarbons to be recovered
from
reservoir formation 100 in the solvent-dominant process for increasing
mobility of the
heavy hydrocarbons. The solvent may be a viscosity-reducing solvent, which
reduces
the viscosity of the heavy hydrocarbons in formation 100.
[073] At S450, a transition condition for transitioning to the solvent-
dominant
process is selected or determined. Transition conditions may be selected based
on a
number of considerations and factors as discussed herein. Transition
conditions may
CA 02956771 2017-01-31
be selected such as to, for example, achieve a desirable balance between
various
factors and considerations including engineering trade-offs and economic
considerations, such as vapor chamber growth, production performance, costs,
and
environmental factors. The transition condition may be selected to ensure that
the
performance or production threshold discussed earlier has been reached. The
transition condition may be selected based on operational experience in
similar projects
at other well pads, or projections according to modeling or simulation
calculations, or a
combination thereof. The transition condition may also be adjusted or selected
based
on the market conditions including production costs, material costs, and the
market
values of produced or recovered materials including market oil prices and
solvent
prices.
[074] Transitioning to the solvent-dominant process at an early stage in
the
SAGD process may be possible in some cases, but such early transition before
the
vapor chamber has fully developed vertically may limit the overall chamber
growth or
slow down the initial chamber growth. Further, when the transition occurs too
early, the
reservoir formation contains less heat transferred from steam and the heated
region in
the formation is relatively small. Without being limited to any specific
theory, when the
vapor chamber is fully developed vertically, the amount of heat transferred to
the
reservoir formation and the large region of heated area can be quite
beneficial to the
subsequent solvent-dominant process. The heat, or higher formation temperature
in a
large region in the formation, can help to maintain the solvent in the vapor
phase and
assist dispersion of the solvent to the chamber front or edges. The heat from
steam can
also by itself assist reduction of viscosity of the hydrocarbons. Thus, an
improved
synergistic effect can be achieved in an embodiment as described herein.
[075] At S460, it is determined whether the transition condition selected
at
S450 has been met. This determination may be made based on a pre-set timing or
based on measured and predicted operational parameters and current reservoir
conditions. The determination may involve monitoring certain selected
parameters, for
example, monitoring of injection, production, downhole parameters, or
parameters of
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CA 02956771 2017-01-31
the geological formation. For example, parameters such as CSOR, temperatures,
pressures or the like may be monitored such as, for example, at injection well
120 or
production well 130. Additionally or alternatively, determining a transition
condition has
been met may involve prediction based on indirect indicators that the
condition has
been met, such as based on assumptions derived from a model and informed by
the
aforementioned monitoring.
[076] When the transition condition has been met, the steam-dominant SAGD
process is terminated and the solvent-dominant process is started at S470. The
solvent-dominant process involves injection of the selected solvent in vapor
form into
formation 100 through injection well 120. The solvent is injected into
reservoir formation
100 in a vapor phase. Injection of the solvent in a vapor phase allows the
solvent vapor
to rise in vapor chamber 360 and condense at a region away from injection well
120.
Allowing solvent to rise in vapor chamber 360 before condensing may achieve
beneficial effects. For example, when vapor of the solvent is delivered to
vapor
chamber 360 and then allowed to condense and disperse in the vapor chamber 360
particularly near the edges of vapor chamber 360, oil production performance,
such as
indicated by one or more of oil production rate, cumulative steam to oil ratio
(CSOR),
and overall efficiency, can be improved. Injection of solvent in the gaseous
phase,
rather than a liquid phase, may allow vapor to rise in vapor chamber 360
before
condensing so that condensation occurs away from injection well 120. It is
noted that
injecting solvent vapor into the vapor chamber does not necessarily require
solvent be
fed into the injection well in vapor form. The solvent may be heated downhole
and
vaporized in the injection well in some embodiments.
[077] The total injection pressure for solvent and steam co-injection may
be the
same or different than the injection pressure during the SAGD production
process. For
example, the injection pressure may be maintained at between 2 MPa and 3.5
MPa, or
up to 4 MPa. In another example, steam may be injected at a pressure of about
3 MPa
in the SAGD process, while steam and solvent are co-injected at a pressure of
about 2
MPa to about 3.5 MPa in the solvent-dominant process.
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CA 02956771 2017-01-31
[078] The solvent may be heated to vaporize the solvent. For example, when
the solvent is propane, it may be heated with hot water at a selected
temperature such
as, for example, about 100 C. Additionally or alternatively, solvent may be
mixed or
co-injected with steam to heat the solvent to vaporize it and to maintain the
solvent in
vapor phase. Depending on whether the solvent is pre-heated at surface, the
weight
ratio of steam in the injection stream should be high enough to provide
sufficient heat to
the co-injected solvent to maintain the injected solvent in the vapor phase.
If the feed
solvent from surface is in the liquid phase, more steam may be required to
both
vaporize the solvent and maintain the solvent in the vapor phase as the
solvent travels
through the vapor chamber 360. For example, where the selected solvent is
propane, a
solvent-steam mixture containing about 90 wt% propane and about 10 wt% steam
may
be injected at a suitable temperature, such as about 75 C to about 100 C.
Such a
suitable steam temperature may be determined, for example, through techniques
as
known to persons of skill in the art based on parameters of the mixture
components.
For example, the enthalpy per unit mass of the aforementioned steam-propane
mixture
may be about 557 kJ/kg.
[079] The total volume of the solvent injected during the solvent-dominant
process may be lower than the total volume of steam injected during SAGD.
[080] In different embodiments, co-injection of steam and the solvent may
be
carried out in a number of different ways or manners as can be understood by
those
skilled in the art. For example, co-injection of the solvent and steam into
the vapor
chamber may include gradually increasing the weight ratio of the solvent in
the co-
injected solvent and steam, and gradually decreasing the weight ratio of steam
in the
co-injected solvent and steam. At a later stage, the solvent content in the co-
injected
solvent and steam may be gradually decreased, and the steam content in the co-
injected solvent and steam may be gradually increased. For example, depending
on
market factors, the cost of solvent may change over the life of a hybrid steam-
solvent
process. During or after the solvent-dominant process, it may be of economic
benefit to
gradually decrease the solvent content and gradually increase the steam
content.
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CA 02956771 2017-01-31
[081] Solvent injection is expected to result in increased mobility of at
least
some of the heavy hydrocarbons of reservoir formation 100. For example,
solvent
injection may tend to achieve a heavy hydrocarbon mobility increase by
solubility or
diffusion of solvent into hydrocarbons, or by both solubility and diffusion.
The term
"mobility" is used herein in a broad sense to refer to the ability of a
substance to move
about, and is not limited to the flow rate or permeability of the substance in
the
reservoir. For example, the mobility of heavy hydrocarbons may be increased
when the
heavy hydrocarbons become easier to detach from the sand to which they are
attached, or when the heavy hydrocarbons become mobile, even if the viscosity
or flow
rate remains the same. The mobility of heavy hydrocarbons may also be
increased by
decreasing the viscosity of the heavy hydrocarbons, or when the effective
permeability,
such as through bituminous sands, is increased. Additionally or alternatively,
increasing
heavy hydrocarbon mobility may be achieved by heat transfer from solvent to
heavy
hydrocarbons.
[082] Additionally or alternatively, solvent may otherwise accelerate
production.
For example, a non-condensable gas, such as methane, may propel a solvent,
such as
propane, downwards thereby enhancing lateral growth of the vapor chamber. For
example, such propulsion may be part of, or additionally or alternatively in
addition to, a
blowdown phase.
[083] Conveniently, a solvent-dominant process where solvent is co-injected
with steam requires less steam as compared to the SAGD production phase.
Injection
of less steam may reduce water and water treatment costs required for
production.
Injection of less steam may also reduce the need or costs for steam generation
for an
oil production project. Steam may be produced at a steam generation plant
using
boilers. Boilers may heat water into steam via combustion of hydrocarbons such
as
natural gas. A reduction in steam generation requirement may also reduce
combustion
of hydrocarbons, with reduced emission of greenhouse gases such as, for
example,
carbon dioxide.
24
CA 02956771 2017-01-31
[084] Once the oil production process is completed, the operation may enter
an
ending or winding down phase, at S480, with a process known as the "blowdown"
process. The "blowdown" phase may be performed in a similar manner as in a
conventional SAGD process. During the blowdown phase, a non-condensable gas
may
be injected into the reservoir to replace steam or the solvent. For example,
the non-
condensable gas may be methane. In addition, methane may enhance hydrocarbon
production, for example by about 10% within 1 year, by pushing the already
injected
solvent through the chamber.
[085] Alternatively, in an embodiment, the solvent used for injection in
the
solvent-dominant process may be continuously utilized through a blowdown
phase, in
which case it is possible to eliminate or reduce injection of methane during
blowdown.
In particular, it is not necessary to implement a conventional blowdown phase
with
injected methane gas, when a significant portion of the injected solvent can
be readily
recycled and reused. In some embodiments, as alluded to above, during or at
the end
of the blowdown phase, methane or another non-condensable gas (NCG) may be
used
to enhance solvent recovery, where the injected methane or other non-
condensable
gas may increase solvent condensation and thus improve solvent recovery. For
example, injected methane or other NCG may mobilize gaseous solvent in the
chamber
to facilitate removal of the solvent.
[086] During the blowdown phase, oil recovery or production may continue
with
production operations being maintained. When methane is used for blowdown, oil
production performance will decline over time as the growth of the vapor front
in vapor
chamber 360 slows under methane gas injection.
[087] In an embodiment of the hybrid process, at the end of the production
operation, the injection wells may be shut in but solvent (and some oil)
recovery may
be continued, followed by methane injection to enhance solvent recovery. The
formation fluid may be produced until further recovery of fluids from the
reservoir is no
longer economical, e.g. when the recovered oil no longer justifies the cost
for continued
production, including the cost for solvent recycling and re-injection.
CA 02956771 2017-01-31
[088] In some embodiments, before, during or after the blowdown phase,
production of fluids from the reservoir through production well 130 may
continue.
[089] In some embodiments, a limited steam-dominant process may be started
again after the solvent-dominant process but before the blowdown phase.
[090] The solvent for injection during the solvent-dominant process may be
selected based on a number of selection criteria. As discussed above, the
solvent
should be injectable as a vapor, and can dissolve at least one of the heavy
hydrocarbons to be recovered from reservoir formation 100 in the solvent-
dominant
process for increasing mobility of the heavy hydrocarbons.
[091] Conveniently, increased hydrocarbon mobility can enhance drainage of
the reservoir fluid toward and into production well 130. In a given
application, the
solvent may be selected based on its volatility and solubility in the
reservoir fluid. For
example, in the case of a reservoir with a thinner pay zone (e.g., the pay
zone
thickness is less than about 8 m), or a reservoir having a top gas zone or
water zone,
the solvent may be injected in a liquid phase in the solvent-dominant process.
[092] Suitable solvents may include C3 to C5 hydrocarbons such as, propane,
butane, or pentane. Additionally or alternatively, a C6 hydrocarbon such as
hexane
could be employed.
[093] For selecting a suitable solvent, the properties and characteristics
of
various candidate solvents may be considered and compared. For a given
selected
solvent, the corresponding operating parameters during co-injection of the
solvent with
steam should also be selected or determined in view the properties and
characteristics
of the selected solvent.
[094] For example, the phase diagrams of the solvents may be helpful for
such
selection. FIG. 5 shows 2-dimensional (2D) pressure-temperature phase diagrams
of
propane, butane, pentane, hexane, heptane, and octane. As can be seen, at a
given
pressure, the boiling points of different solvents are different, and at a
given
26
CA 02956771 2017-01-31
temperature the saturation vapor pressures of different solvents are
different. Thus,
suitable operating temperatures and pressures may be selected for a given
solvent in
view of such phase diagrams. In particular, the injection temperature should
be
sufficiently high and the injection pressure should be sufficiently low to
ensure most of
the solvent will be injected in the vapor phase into the vapor chamber. In
this context,
injection temperature and injection pressure refer to injection into the
injection well.
Injection temperature, injection pressure, or both, may be selected to ensure
that the
solvent is in the gas phase upon injection from the injection well into the
vapor
chamber.
[095] Solvents may be selected having regard to reservoir characteristics
such
as, the size and nature of the pay zone in the reservoir, properties of fluids
involved in
the process, and characteristics of the formation within and around the
reservoir. For
example, a relatively light hydrocarbon solvent may be suitable for a
reservoir with a
relatively thick pay zone, as a lighter hydrocarbon solvent in the vapor phase
is typically
more mobile within the heated vapor chamber. For example, propane may be
selected.
[096] Additionally or alternatively, a lighter hydrocarbon solvent such as,
for
example, propane may dissolve in higher and more challenging areas of the
heterogeneous reservoirs as compared to a solvent including heavier
hydrocarbons.
[097] Additionally or alternatively, solvents including heavier
hydrocarbons
such as, for example, pentane or hexane, may be more appropriate in a thinner
pay
reservoir environment. Heavier solvents, even if injected in a liquid phase or
condensed
quickly after injection as a vapor, may serve to drive out (wash) remaining
heavy oil in a
reservoir environment, towards the production well. Further, solvent existence
in the
vapor phase may be less beneficial in a thinner pay reservoir as compared to a
thicker
pay reservoir. For example, in a CSS process, where the initial pressure in a
5-meter
pay zone is about 0.3 MPa, a heavier solvent, such as, for example, liquid
hexane may
be appropriate for use as the solvent. In comparison, in a hybrid process as
described
herein where the reservoir has a 3 MPa initial pressure and a 30-meter pay
zone,
lighter solvents, such as propane in the vapor phase, may be more suitable.
27
CA 02956771 2017-01-31
[098] Additionally or alternatively, solvent selection may include
consideration
of the economics of heating a selected particular solvent to a desired
injection
temperature. For example, following a 3 MPa initial pressure SAGD operation,
propane
will have to be heated to about 80 C whereas pentane will have to heated to
about 190
C so it can be injected in the vapor phase.
[099] As can be appreciated by those skilled in the art, solvents
referenced in
FIG. 5, such as propane and butane, can be efficiently injected in the vapor
phase at
relatively low temperatures at a given injection pressure such as about 3 MPa.
In
comparison, efficient pure steam injection in a SAGD process typically
requires a much
higher injection temperature, such as about steam 200 9C or higher.
[100] For example, at an injection pressure of about 3 MPa, the injection
temperature for propane may be about 75 C to about 100 C.
[101] Different solvents or solvent mixtures may be suitable candidates as
may
be known to those skilled in the art. For example, the solvent may be propane,
butane,
or pentane. A mixture of propane and butane may also be used in an appropriate
application. It is also possible that a selected solvent mixture may include
heavier
hydrocarbons in proportions that are, for example, low enough that the mixture
still
satisfies the above described criteria for selecting solvents.
[102] Conveniently the hybrid process may reduce overall production costs
while improving production performance, as compared to conventional SAGD
processes or combined SAGD and solvent processes. As the overall CSOR is
reduced,
the hybrid process may also result in reduced emission of greenhouse gases,
such as
carbon dioxide due to reduced need for steam generation and water treatment.
[103] The transition condition may be selected to optimize the overall
performance or maximize the above noted benefits. Different techniques for
determining the optimal transition condition have been proposed.
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CA 02956771 2017-01-31
[104] In an embodiment, the vertical growth of vapor chamber 360 is
directly
monitored or estimated based on available data.
[105] FIG. 6 illustrates the stage at which the top front of vapor chamber
360
has just reached the interface region 115 at the lower edge of overburden 110
due to
vertical growth as indicated by the arrows. Such a condition may be detected
by
monitoring a temperature in the interface region 115 change via
instrumentation such
as, for example, using distributed temperature sensing (DTS) (not shown). The
temperature change is significant if it can indicate that steam has reached or
is near the
interface region. A pre-selected temperature or rate of temperature change may
be
used as a threshold for determining if the temperature has changed
significantly. This
threshold may be selected based on a methodology known to those skilled in the
art.
Additionally or alternatively, this condition may be inferred such as, for
example, when
production monitoring indicates that the oil production rate change over time
exhibits a
generally "parabolic" curve. After this stage, overburden 110 will limit
further upward
vertical growth of vapor chamber 360. However, as illustrated in FIG. 7, vapor
chamber
360 may still grow laterally, as indicated by the arrows. A peak production
threshold
may therefore be reached around this time. Thus, the transition time may be
selected
to be some time after this point. In particular, one technique is to monitor
or predict
vertical growth of vapor chamber 360 and select the transition condition to be
the
cessation of upward vertical growth of vapor chamber 360. Another possible
transition
condition is a significant increase in lateral growth of vapor chamber 360.
Such a
condition may be detected by monitoring temperature changes in different
locations in
the formation, such as by DTS. In different embodiments, it is also possible
to
determine the appropriate transition condition by monitoring the change in oil
production rate or the cumulative steam to oil ratio in the SAGD process.
[106] For example, FIG. 8 shows a curve 800 representing hypothetical
expected change in oil production rate over time in a conventional SAGD
process. As
illustrated, it is assumed that curve 800 initially increases and will reach a
peak value
810 at the time denoted as T. In an embodiment, the transition condition (or
transition
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CA 02956771 2017-01-31
time, TT) may be selected be Tp, or sometime thereafter. A delay after Tp may
be
desirable to ascertain that the oil production rate has peaked and is
declining.
[107] Notably, curve 800 may not reflect the oil production rate after
transition
to the solvent-dominant process, as curve 800 represents predicted oil
production rate
for the SAGD process.
[108] Transition time TT may be selected to occur after some period of time
elapses following initial steam injection in the SAGD process as illustrated
in FIG. 9.
Time TT may be selected based on a variety of relevant factors. For example,
the
transition time may be selected based on an a priori determination of when
SAGD
production or the reservoir formation development thereunder is expected to
have
reached peak production, or when the vertical growth of the vapor chamber from
the
injector to overburden is achieved. The time period from initial steam
injection may vary
depending on the thickness of the pay zone. Considerations may also be given
to the
optimal transition time to achieve an optimal economic or cost-effect result.
[109] As an example, for a reservoir with a 20 m thick pay zone and
assuming
the pressure in the formation is 3 MPa, TT may be about 2 years. For a
reservoir with a
different pay zone thickness or reservoir pressure condition, the time period
may be
different. For example, if the pay zone is thinner or the reservoir pressure
is higher, the
time period may be shortened. For example, for a reservoir with a 5 m thick
pay zone,
TT may be about 6 months.
[110] Time TT may also be selected to be at the time when the oil
production
rate has peaked, and in some embodiments, has then declined by about 10%, and
no
more than 20%, of the peak production rate, as illustrated in FIG. 10.
[111] As illustrated in FIG. 11, Time TT may also be selected to be at the
time
after a selected period of time, denoted as AT, has elapsed after Tp (i.e. the
time of
reaching peak production rate). That is, TT = Tp + T. The transition condition
is thus
that the reservoir formation has continued to be subjected to the SAGD process
for a
CA 02956771 2017-01-31
time period of AT after reaching peak production. The time period AT may be
selected
based on one or more of a variety of relevant factors. For example, reservoir
characteristics in a heterogeneous environment such as variations in
overburden height
may be a factor to be considered. The selection may be based on simulation
prediction.
Process economics may also be a factor to be considered. The time period AT
may be
selected to ensure that the oil production rate has indeed peaked. As the oil
production
rate may fluctuate due to various reasons, to ensure the oil production rate
has peaked,
the oil production rate may be monitored until continued and consistent
decline of the
oil production rate has been observed over the time period AT, such as until
the oil
production rate has consistently declined by about 10% of the peak production
rate.
[112] A further possible transition condition is that the CSOR has started
to
increase, which tends to indicate that production performance has started to
decline
after a peak production threshold has been reached. A hypothetical expected
CSOR
curve for a SAGD production process is illustrated in FIG. 12.
[113] As known to skilled persons, CSOR will vary during a SAGD process as
discussed above. Decreases in CSOR are expected during early SAGD production
stages. An increase in CSOR can indicate that steam utilization has become
less
efficient or effective.
[114] As depicted by the CSOR curve 1200 in FIG. 12, the CSOR may
decrease initially until reaching a minimum value (bottom) indicated by dashed
line
1210. The CSOR may then begin to increase, reaching a higher CSOR value as
indicated by dashed line 1220. A transition condition may be selected to be
that the
CSOR has decreased and then increased. For example, the transition condition
may
be that the CSOR has increased by a threshold value, ACSOR. The time to meet
this
condition is indicated as TT in FIG. 12.
[115] In some embodiments, ACSOR may be calculated as a function of the
measured CSOR or based on theoretical predictions.
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[116] In a further embodiment, the transition condition may be selected
based
on an indicator that can be used to predict or indicate that vapor chamber 360
has
reached overburden 110, or reached the interface region 115. For example, the
temperature change in interface region 115, which may be detected, for
example, by
DTS, can be a useful indicator in this regard.
[117] FIG. 13 illustrates expected temperature change at interface region
115
over time during a conventional SAGD process. The curve 1300 in FIG. 13
represents
the expected temperature variation over time in interface region 115, which is
the
interface region between overburden 110 and formation 100. As depicted, the
initial
(natural, prior to a treatment being applied to the reservoir) temperature in
interface
region 115 is assumed to be about 11 C to about 12 C as is typical in many
oil sands
or bitumen reservoirs. The temperature in interface region 115 may gradually
increase
due to steam injection and can reach about 25 C when the steam chamber 360
reaches interface region 115. As such, the transition condition for
transitioning from the
SAGD process to the solvent-dominant process may be selected as when the
temperature in interface region 115 is at a pre-selected value, such as about
20 C to
about 25 C. For example, the transition condition may be selected for a
temperature of
about 20 C as shown by stippled line 1310. The time to meet this condition is
indicated
as TT in FIG. 13. Expressed differently, the transition condition may be that
the
temperature at interface region 115 has increased by about 11 C to about 12
C, or
the temperature as measured in degree Celsius has doubled.
[118] The aforementioned example transition conditions are in no way
limiting
and instead serve to exemplify transition conditions that may be suitable in
some
embodiments.
[119] In some embodiments, it may be appropriate that more than one
transition conditions be met before the transition takes place. For example,
the
conditions that need to be satisfied before the transition may include a
combination of
two or more of the transition conditions described herein. In some
embodiments,
transition may take place as long as one of the selected transition conditions
has been
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satisfied. Alternatively, in some embodiments, transition may take place only
after all
selected transition conditions have been satisfied, or a sub-combination of
transition
conditions have all been satisfied.
[120] Examples
[121] Computer simulations have been conducted to predict expected recovery
performance and vapor chamber development in a hybrid steam-solvent process as
described herein. Representative simulation results are discussed next.
[122] Example I. Computer Simulation of Solvent Recovery Process
[123] The performance and results for hydrocarbon recovery under solvent
injection were studied based on two-dimensional (2D) computer simulation. The
2D
study was conducted for temperatures 100 C and 150 C to compare potential
performance of propane, butane, pentane, and hexane in enhancing heavy
hydrocarbon recovery.
[124] As can be appreciated, each of the studied solvents requires less
energy
to vaporize and to inject at the temperatures of 100 C or 150 C, as compared
to the
energy required to heat water to generate steam at a temperature above 200 C.
[125] FIG. 14 shows representative expected heavy hydrocarbon recovery
factors for selected solvents at different injection temperatures in an
example reservoir
having a relatively thin pay, in this case of 10 m.
[126] As can be seen from FIG. 14, propane provided the best recovery
performance, as injection of propane resulted in the highest recovery factor
in a thin
pay reservoir at both injection temperatures of 100 C and 150 C.
[127] Example II. Phase Diagram Simulation
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[128] Computer simulation was also conducted to provide 2D pressure-
temperature phase diagrams for co-injection of selected solvents with steam.
The
operating pressure in the simulation was near the initial injection pressure
of 3 MPa.
[129] A representative simulated 2D phase diagram is shown in FIG. 5.
[130] The injection temperature was selected to ensure that the solvent is
injected in the vapor (gas) phase, based on enthalpy calculations. That is,
there would
be sufficient energy (enthalpy) available in the mixture to keep the solvent
in the vapor
phase. For example, for injecting propane at 3MPa, the enthalpy calculation
showed
that the injection temperature should be about 75 C to about 100 Co. For
heavier
solvents, a higher injection temperature would be required so the heavier
solvent could
be injected in the vapor phase. The solvent may be delivered to the injection
well at a
higher temperature than required to achieve a gaseous phase so as to offset
possible
heat losses that may occur in the injection well as the solvent travels to the
reservoir.
[131] It is expected that for reservoirs with a typical pay zone height of,
for
example, about 20 m, the solvent would need to be injected as a vapor for
effective
recovery.
[132] Example III. Computer Simulation of Hybrid Steam-Solvent Recovery
Process, and Comparison SAGD Process
[133] The performance of a hybrid steam-solvent process was compared to a
conventional SAGD process based on computer simulation and computer modelling.
[134] The computer simulations modelled components of water, bitumen,
methane, and a selected solvent, which was selected from C3 to C6
hydrocarbons. The
simulated reservoirs had dimensions of 800 m long, 50 m wide, and 10 m or 20 m
high.
A hot fluid communication zone was introduced between the injector and
producer
wells at 200 C and with water saturation of 60% to improve mobility. The
reservoir
conditions were simulated as follows: Temperature (T) =12 C, Pressure (P) = 3
MPa,
Water Saturation (Sw) = 20%, and Oil Saturation (So) = 80%. The permeability
in the x,
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y, and z directions were 6, 6, and 5 Darcy, respectively, and the reservoir
porosity was
assumed to be 33%. Methane content in the oleic phase was assumed to be 16
wt%.
[135] The injection tubing had the following flow control device (FCD)
configuration:
Location: injection tubing section 3, Opening diameter in meters: 20.00e-3;
Discharge coefficient: 0.7;
Location: injection tubing section 7, Opening diameter in meters: 28.28e-3;
Discharge coefficient: 0.73;
Location: injection tubing section 11, Opening diameter in meters: 40.00e-3;
Discharge coefficient: 0.81;
Location: injection tubing section 15, Opening diameter in meters: 56.57e-3;
Discharge coefficient: 0.95.
[136] As noted before, molecularly heavier solvents require higher
temperatures for injection in the gaseous phase at a selected temperature.
Injection in
the gaseous phase may be necessary depending on the pay height of a reservoir.
For
example, solvent injection in the gaseous phase, rather than a liquid phase,
would be
necessary if the pay height in the reservoir formation is approximately 20
metres in
order for the solvent to reach the top of the vapor chamber.
[137] From the operational perspective, injection was controlled at a
pressure
of 3.1 MPa for steam injection, and production was controlled according to a
gas
constraint of 10 tonnes per day (t/d).
[138] FIG. 15 shows representative simulation results for the cumulative
oil
production in a hybrid steam-solvent process, as compared to a SAGD base
(baseline)
case.
CA 02956771 2017-01-31
[139] For the results shown in FIG. 15, the injected solvent was propane.
The
simulation results showed that the cumulative oil production reached the level
of 65% 3
years earlier with the hybrid steam-solvent process than with the SAGD base
case.
This accelerated recovery is a significant improvement in production
performance, as a
shortened recovery operation can provide various benefits including both
technical and
economic advantages.
[140] FIG. 16 compares the predicted oil production rates in a hybrid
process
(labeled as "hybrid") as compared to a baseline SAGD process (labeled as
"SAGD"),
based on half-symmetry simulation. In the simulated solvent-dominant process
of the
hybrid process, propane was injected at about 48 t/d, and the transition from
steam
injection to propane injection was selected to take place at about 1200 days
after
production. In the simulation results, the hybrid steam-solvent recovery
process using
propane increased the oil production rate to 140 t/d after 3.5 years of
operation, up
from 50 t/d in the SAGD base case, for the full simulated reservoir.
[141] The simulation study also considered other solvents. In particular,
in the
simulations injection of selected condensate (see below) and pentane did not
outperform the SAGD base case at an injection rate of 48 t/d, even when the
selected
condensate or pentane (solvent) was injected in the vapor phase. As will be
understood
by a person of skill in the art, "condensate" in this context is a mixture of
hydrocarbons,
for example including C3-C30 hydrocarbons or C4-C20 hydrocarbons. "Condensate"
is
sometimes referred to as diluent. Condensate may primarily include a smaller
range of
hydrocarbons, for example, C3-C6 hydrocarbons. If relatively heavier
hydrocarbons, for
example, C9-C30 hydrocarbons, or a relatively heavier hydrocarbon, for
example,
octane being relatively heavier than heptane, are utilized, a lower quantity
of the
relatively heavier hydrocarbon(s) may be required compared to when relatively
lighter
hydrocarbon(s), for example, propane, are utilized. Simulation suggested that
butane
slightly outperformed the SAGD base case initially but its overall performance
was not
as good as that of propane in the solvent-dominant process. Additionally,
simulation
indicated that the transition timing is important for achieving improved
performance. For
36
CA 02956771 2017-01-31
example, simulation results for transitioning to propane injection immediately
after the
start-up stage (i.e. essentially without any steam-dominant oil production
process) did
not achieve good or improved performance. Instead, the best simulation results
were
obtained when the transition to propane injection took place after 700, 1000,
or 1200
days of production.
[142] Oil saturation distribution and vapor distribution in the vapor
chamber
were also studied by computer simulation. Representative results are shown in
FIG. 17,
which shows a screen shot of a computer display showing simulation results.
[143] FIG. 17 shows three displayed windows 1710, 1720, and 1730.
[144] Window 1710 shows oil saturation ("SO") within the simulated
reservoir in
a SAGD process where no solvent was injected, which was used as the base case.
The darker (cooler) areas indicate oil depleted areas and the lighter (hotter)
areas
indicate oil saturated areas. As can be appreciated, in the vapor chamber oil
was
substantially depleted, and the regions of the reservoir outside the vapor
chamber were
still saturated with oil.
[145] Window 1720 shows oil saturation ("SO") within the simulated
reservoir in
a hybrid process where a solvent was injected after pure steam injection
during the
steam-dominant process. The darker (cooler) areas indicate oil depleted areas
and the
lighter (hotter) areas indicate oil saturated areas. As can be appreciated, in
the vapor
chamber oil was substantially depleted, and the regions of the reservoir
outside the
vapor chamber were still saturated with oil. Window 1730 shows propane
distribution in
the oleic phase at a point of vapor chamber development corresponding to that
of
window 1720. In window 1730, the lighter area indicates higher solvent
concentration in
the oleic phase and the darker areas indicate areas where propane is still in
the
gaseous phase. It can be seen that the injection of propane resulted in
significant
lateral growth of the vapor chamber, particularly at the lower portions of the
reservoir.
Indeed, the computer simulation results of FIG. 17, when considered together,
illustrate
to a skilled person interpreting the results that propane, even though a
lighter and
37
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therefore more buoyant solvent than heavier solvents, such as butane, in the
simulated
reservoir, would still be expected to condense at the bottom of the vapor
chamber and
thus serve to advance oil towards production.
[146] From the simulation results as represented in FIG. 17, it may also be
expected that both heat transfer and diffusion of dissolved solvent in the
hydrocarbons
contribute to the enhanced oil recovery. In comparison, with steam injection,
heat
transfer is helpful for increasing mobility of hydrocarbons but steam does not
dissolve
in the oil phase.
[147] EXAMPLE IV. Simulation Study of Effects of Well Pair Spacing on
Vertical Steam Chamber Development
[148] A simulation study was conducted to evaluate effects of well pair
spacing
on vertical steam chamber development and the optimal timing for initiating a
solvent-
dominant process.
[149] In the study, the formation was modeled with horizontally spaced well
pairs, where the spacing between adjacent pairs of SAGD wells was 50 m, 60 m,
100
m, or 150 m. A hybrid recovery process as described herein was simulated from
the
modeled formation. The temperatures within the steam chambers and the
temperatures
within the volume between the two adjacent well pairs outside the respective
steam
chambers were monitored during a simulated steam-dominant process for each of
the
four well spacing distances. The simulation results showed that the steam
chamber
development was substantially affected by the presence and the spacing of an
adjacent
well pair. With more closely spaced adjacent well pairs, the vertical
development of the
steam chambers was more rapid and reached the vertical expansion limit or peak
production more quickly. For example, in a tested embodiment, the vertical
expansion
of the steam chamber during the steam-dominant process reached its limit
within about
250 days at 50 m spacing, about 300 days at 60 m spacing, about 750 days at
100 m
spacing, and about 4000 days at 150 m spacing. In accordance with an
embodiment of
38
CA 02956771 2017-01-31
the present disclosure, the solvent-dominant process may be initiated after
the steam
chamber has reached its vertical expansion limit or peak production of oil.
[150] While reducing the spacing between the SAGD well pairs might reduce
the time to reach the vertical expansion limit of the steam chamber, shortened
spacing
also requires more wells to be drilled and more steam injection, both of which
result in
higher costs and potentially higher green-house gas emissions. It is expected
that
spacing at about 100 m may provide a practical and balanced result when the
well
pairs have configurations and completions typically found in conventional SAGD
operations.
[151] EXAMPLE V. Simulation Study of Effects of Transition Timing From
Steam-Dominant Recovery Process to Solvent-Dominant Recovery Process
[152] This simulation study focused on the transition timing from the steam-
dominant process to the solvent-dominant process.
[153] Four different simulations were conducted, and representative
simulation
results are shown in FIGS. 18, 19 and 20.
[154] The results labelled as "SAGD base" were obtained from a reference
case with simulation of pure steam injection without any solvent injection.
The results
labelled as "immediate" were obtained by simulating an immediate transition at
950
days from the commencement of pure steam injection, when the production rate
was
already on a decline curve, to co-injection of 80 wt% of propane and 20 wt% of
steam
at once. The results labelled as "15 d interval" were obtained from simulation
of a
stepped transition, in which the proportions of steam and propane in the
injection
mixture were adjusted as shown in Table 1. The results labelled as "20 d
interval" were
obtained from simulation of a stepped transition as shown in Table 2. In the
"15 d
interval" and "20 d interval" cases, the first transition step was a 10 wt%
change from
100 wt% steam to 90 wt% steam and 10 wt% propane, the second transition step
was
a 10 wt% change from 90 wt% steam and 10 wt% propane to 80 wt% steam and 20
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CA 02956771 2017-01-31
wt% propane, and the subsequent transition steps were 20 wt%
decreases/increases
for steam/propane, as shown in Tables 1 and 2, respectively.
[155] The estimated enthalpy per kilogram of the injection mixture
with 20 wt%
steam and 80 wt% propane is 528 kJ/kg, which allows injection of gaseous
propane at
a temperature between 75 C and 100 C.
Table 1. "15 d interval" Transition from Steam-Dominant Process
to Solvent-Dominant Process
Day Steam (wt%) Propane (wt%) Enthalpy/mass (kJ/kg)
950 90 10 2376
965 80 20 2112
980 60 40 1584
995 40 60 1056
1010 20 80 528
Table 2. "20 d interval" Transition from Steam-Dominant Process
to Solvent-Dominant Process
= Day Steam (wt%) Propane (wt%) Enthalpy/mass (kJ/kg)
950 90 10 2376
965 80 20 2112
985 60 40 1584
1005 40 60 1056
1025 20 80 528
[156] As can be seen from FIG. 18, the transition methodology had little
effect
on the overall amount of oil produced (cumulative oil production).
[157] For selecting a suitable injection mixture in the solvent-dominant
process,
the respective percentages of steam and solvent, or a ratio of steam to
solvent, may be
selected based on a selected (desired) injection temperature or pressure and
the
CA 02956771 2017-01-31
enthalpy that is needed to allow the solvent to be in the gas (vapor) phase
during
injection at the selected injection temperature or pressure. As an example for
obtaining
a suitable mixture for injection in the solvent-dominant process, with a
gaseous phase
temperature of propane between about 75 C and about 100 C, about 15-20 t/d
of
steam may be utilized to mix with and heat about 50-75 t/d of propane,
resulting in an
injection mixture containing between about 75 wt% and about 85 wt% of steam
and
about 25 wt% to about 15 wt% of propane in the inject stream.
[158] Without being limited to a particular theory, a desired temperature
of the
solvent may be attained at a certain enthalpy per mass of the mixture of steam
and
solvent. For example, to inject propane at about 75 C and about 3 MPa in the
solvent-
dominant process, about 5.07e5 J/kg of enthalpy/mass (based on the weight of
the
mixture of steam and propane) may need to be in the mixture for the propane to
be in
the gaseous phase (see e.g. Fig. 5). Based on simulation results, it is
expected that the
corresponding rates of injection are about 15 t/d of steam and about 60 t/d of
propane
for a co-injected mixture of about 20 wt% of steam and about 80 wt% of
propane.
[159] At a lower pressure, an injection mixture may contain about 15 t/d of
steam and about 50 t/d of propane, which would yield a co-injected mixture of
about 23
wt% of steam and about 77 wt% of propane.
[160] As a further example, for an injection mixture with about 92 wt% of
propane and about 8 wt% of steam, about 5.28e5 J/kg of enthalpy per unit mass
may
need to be in the mixture for the propane to be in the gaseous phase.
[161] Depending on the solvent selected, a range of enthalpies per unit
mass of
about 4e5 J/kg to about 7e5 J/kg may be applicable to achieve a solvent
temperature
such that the solvent is in the gaseous phase. Solvents other than propane may
have
different enthalpy requirements to achieve temperatures suitable for the
solvent-
dominant process. For example, butane may have higher enthalpy requirements to
achieve temperatures at which butane is in the gaseous phase.
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CA 02956771 2017-01-31
[162] As can be seen from FIG. 19, which shows the change in oil production
rate (t/d) over time (days), within the short period of time during the
transition from the
steam-dominant process to the solvent-dominant process, there was a temporary
decrease in the oil production rate during the switch, followed by a
substantial increase.
In the case of "immediate" transition, the decline in the oil production rate
was more
instantaneous, but the following increase was also earlier as compared to the
two
"interval" cases. In both the "interval" cases, both the decline and following
recovery of
the oil production rate were less sharp than the "immediate" case. After the
transition to
the solvent-dominant process the oil production rate in all cases appeared to
be steady
with low fluctuation and low variance among the different cases.
[163] Given the above results, transitioning with stepped steam reduction
and
propane increase may be selected in some embodiments to reduce risks that may
result from rapid temperature change in the injection mixture. For example,
from a
thermal shock perspective, a fast change in the temperature of the injection
mixture
could cause rapid cooling in the injection well and in the steam chamber.
There is a
potential risk that rapid cooling could cause possible cracking in carbon
steel pipes and
injection skid equipment in the injection well. An "interval" transition may
reduce such
risks.
[164] FIG. 20 shows cumulative solvent injection over time. The result
shown
suggests that the "immediate" transition required more propane injection.
Given that
overall oil production may not be significantly improved by a faster
transition, selecting
a longer transition time frame, such as from about 20 days (or three weeks) to
up to
about 75 days, may be more economical.
[165] EXAMPLE VI. Simulation Study of Batch Solvent Injection
[166] A simulation study was conducted to evaluate the effects of batch
injection of the solvent during either the steam-dominant process or the
solvent-
dominant process. In batch injection, the solvent would be injected in
separate
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CA 02956771 2017-01-31
"batches." For example, each batch might be equivalent to the load of a
shipping truck
for transporting the solvent.
[167] Unlike continuous solvent injection, batch injection allows quick
offloading
of the solvent into the wellbore of the injection well, or into the piping
where the solvent
is mixed with steam to be injected into the formation.
[168] The study results showed that both continuous and batch injection
processes produced similar amounts of oil. For example, both batch and
continuous
injections produced about 140 t/d of oil after 980 days. Batch injection did
not lead to a
drop in the oil production rate that would render batch injection impractical.
Thus, it is
expected that batch injection would be a feasible alternative to continuous
injection.
The pressure in the steam chamber also did not differ significantly between
batch and
continuous injection. In both cases, the average pressure was about 2700 kPa.
[169] As can expected, there was more fluctuation in the oil production
rate and
chamber pressure with batch injection, but such fluctuation was within
acceptable
measurement errors for field measurements.
[170] It is expected that batch injection could be utilized as an
alternative to
continuous injection.
[171] ALTERNATIVES AND VARIATIONS
[172] In some embodiments, injection pressure may be controlled using the
same means in SAGD and in the solvent-dominant process. Alternatively,
different or
additional means may be used for injection pressure control during either SAGD
or the
solvent-dominant process.
[173] In some embodiments, the solvent may be heated at the surface before
injection. Additionally or alternatively, the solvent may be heated by co-
injection with
steam. For example, in an embodiment, the injection fluid may include about 90
wt% of
solvent and about 10 wt% of steam, such as when propane is used as the
solvent. In
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another embodiment, the injection fluid may include about 80 wt% of solvent
and about
20 wt% of steam, such as when butane is used as the solvent. The steam may be
present in a sufficient amount and temperature to heat the mixture, including
propane,
to about 100 C. Additionally or alternatively, the solvent may be heated at
surface or
downhole, such as by way of a heater. In additional embodiments, the relative
amount
of the solvent in the injection fluid may also be higher or lower than the
ranges
previously mentioned. For example, in an embodiment, the injection mixture may
contain about 95 wt % of propane and about 5 wt% of steam, with or without
additional
heating using a heating device.
[174] As discussed above, the solvent is delivered relatively hot to the
reservoir
formation. However, the solvent may be fed into the injection well with or
without pre-
heating at the surface.
[175] In some embodiments, the solvent condensed in the reservoir will be
recovered (produced) in the oleic phase. Additionally or alternatively, vapor
solvent
could remain in the reservoir formation, and may also be recovered with a
reservoir
fluid in the gaseous phase.
[176] In some embodiments, an additive or chemical such as toluene may be
injected during the SAGD production process, during the solvent-dominant
process, or
during a post-production phase. Injection of toluene may help to reduce
asphaltene
precipitation. About 5 wt% of toluene may be co-injected with steam or a
solvent.
[177] In some embodiments, fluids recovered at the surface may be separated
from produced solvent to undergo recycling.
[178] In the above discussed and other embodiments, the injected solvent
may
not be recycled, or the injected solvent may be recovered and recycled.
[179] In some embodiments, a further steam-dominant recovery process may
be performed after the conclusion of the solvent-dominant process. For
example, the
reservoir may be subjected to the steam-dominant process after the solvent-
dominant
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process. For example, the steam-dominant process may be similar to
conventional
SAGD. Such a switch may be made after a prolonged period of solvent-dominant
process production.
[180] In some embodiments, a separate vertical well may be introduced into
the
reservoir for co-injection of some or all of the steam and solvent mixture.
[181] In some embodiments, a barrier or insulation layer may be formed at
the
overburden, which may assist in reducing heat loss through the overburden once
the
vapor chamber has substantially reached full vertical growth. For example, a
barrier
layer may be formed after this condition is reached. Alternatively, a barrier
may be
formed at an earlier or later point in time. In another example, a barrier
layer may be
formed at or about the time that the peak process threshold has been reached
and
detected. The barrier layer may be formed of an insulation composition such as
described in US 201 5/01 59476 to Warren et al. The barrier layer may also be
formed
from an artificial layer such as those disclosed in US 2011/0186295 or CA
2,729,430 to
Kaminski et al..
[182] In some embodiments, non-condensable gases (NCGs) may be
generated in the reservoir such as during heating by steam. Additionally or
alternatively, an NCG may be injected as an additive in some embodiments.
Conveniently, the presence of NCGs in the formation can enhance lateral
dispersion of
the solvent vapor to spread the solvent laterally into the reservoir
formation. Increased
lateral dispersion of the solvent is expected to assist lateral growth of the
vapor
chamber, and hence enhance oil production.
[183] While in some of the above discussed embodiments a pair of wells is
employed for injection and production respectively, it can be appreciated that
a hybrid
steam-solvent process may be implemented with a single well or unpaired wells.
The
single well, or an unpaired well, may be used alternately for injection or
production. The
single well may have a substantially horizontal or vertical section in fluid
communication
with the reservoir. The single well may be a well that is configured and
completed for
CA 02956771 2017-01-31
use in a cyclic steam stimulation (CSS) recovery process. With the use of a
single well
for injection and production, a temperature in the reservoir may be about 234
C to
about 328 C and a pressure in the reservoir may be from about 0.5 MPa or from
about
3.0 MPa to about 12.5 MPa.
[184] There are also alternative methodologies for recognizing or selecting
the
peak process threshold for transitioning from the steam-dominant process to
the
solvent-dominant process in homogeneous or heterogeneous hydrocarbon
reservoirs.
[185] For example, the amount of propane and oil recovery may be estimated
by measuring production rates, composition of the produced fluids, temperature
and
pressure of the produced emulsion and gas streams. Similarly, the oil
production rate
may be estimated from analysis of the produced emulsion flow rate and oil cut
samples. Instantaneous SOR (ISOR) and CSOR may be estimated using a steam flow
meter as well as water cut and total emulsion flow measurements. Compositions
of all
produced streams may be measured using manual sampling, which may be validated
by truck-based large scale samples or by collecting samples from a vessel in
which the
produced stream is stored. In other words, to provide support for the
measurements
obtained from the manual samples, a truck mounted tank may be used including
an on-
demand test separator for additional measurements. One or more of these
produced
fluid measurements may be helpful in determining when to transition from a
steam-
dominant process to a solvent-dominant process.
[186] As an example, a SAGD baseline may be established for two to three
months before commencement of propane injection. While the oil rates may be
used to
estimate steam chamber size, 4D seismic data, for example obtained annually,
may be
used to monitor steam chamber growth.
[187] A post-steam core may be taken within the area swept by the hybrid
steam-solvent process. An analysis of the post-steam core may also be used to
indicate if the steam-dominant process is complete (that is, if it has reached
the peak
process threshold, and the timing is suitable for transitioning to a solvent-
dominant
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process). The core may be used to quantify the amount of asphaltenes (if any)
that are
left in the reservoir. A potential in-situ upgrading benefit of the hybrid
steam-solvent
process may be realized if the solvent helps to retain asphaltenes in-situ.
This could be
monitored by measuring API Gravity at 15 C as well as asphaltene mass % at
various
time periods during the process. The prospective crude upgrading benefit due
to lower
asphaltene production may result in lower diluent requirements prior to
pipeline
transportation and lower refining intensity requirements for separating heavy
hydrocarbons from lighter hydrocarbons. Therefore, lower asphaltene production
may
also contribute to GHG reduction.
[188] Reservoir Saturation Tool (RST) logs may also be obtained for one or
more observations wells. For example, an observation well may be located tens
of
meters, such as about 27 m, from the SAGD well pair of the hybrid steam-
solvent
process. An RST analysis may be performed at the observation well a few (e.g.
two to
three years) before the transition from the steam-dominant process to the
solvent-
dominant process, and annually shortly before the transition, to monitor
relative
changes in residual oil saturation and the rise in steam chamber height during
the
hybrid steam-solvent process. The changes observed from analysis of the RST
logs
may be compared to repeat RST logs of other nearby SAGD well pairs.
[189] In some cases, the pay zone in the formation may have an irregular
ceiling, i.e., the bottom of the overburden above the reservoir may vary in
height. In
such cases, the following methods or metrics may be used, alone or in
combination, to
select and determine the peak process threshold: increase in CSOR; decrease in
oil
production rate; and statistical information from neighboring wells and pads
if the
reservoir is highly heterogeneous; 4D seismic data; and temperature
information (such
as measured by thermal couples).
[190] In some heterogeneous pay zones, the ceiling at some sections of the
reservoir formation may be lower, which may allow an earlier transition to the
solvent-
dominant process.
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[191] In some embodiments, it may be beneficial to use a tracer or NCG
during
the hybrid process to monitor certain performance or process metrics. For
example, in
some cases a chemical tracer or NCG may be injected during the steam-dominant
process or solvent-dominant process and the production of the tracer is
monitored to
understand how quickly or how much of the injected fluid is produced
(recovered) to
surface. The tracer may have a distinctive molecular structure and chain link
within the
mixture for a complete detection. For example, radioactive tracers, or methyl
alcohol or
water-based tracers may also be used.
[192] To deliver a selected solvent to the production site and to implement
a
hybrid steam-solvent process, a modular natural gas liquid (NGL) injection
system may
be used. Such a modular system may be designed to be relocatable to other well
pads.
[193] Solvent, such as propane, may be mixed with steam upstream of a
wellhead and the combined stream of steam and solvent may be injected into the
reservoir through an injection well. An existing NGL injection module may be
modified
to allow the steam-solvent injection point to be in close proximity to the
wellhead.
[194] In an embodiment, a stand-alone hybrid steam-solvent process skid may
be provided. A solvent injection pump driver may be electrically driven with
the
electrical power supplied.
[195] At the surface, the solvent may be delivered by a pipeline or by
trucks. If
trucks are used to deliver the solvent, the trucks may offload the solvent,
for example
propane, to immobile NGL storage bullets, from which the solvent may be
injected into
the reservoir with one or more pumps. While the solvent may also be injected
directly
from mobile trucks into the injection well, quick offloading of the solvent
from trucks
may result in batch injection. Immobile bullets may be used if continuous
injection of
the solvent is desirable and the solvent is initially provided by trucks. For
a medium
scale facility, immobile 50-tonne solvent bullets may be used, which may be
manufactured and configured specifically for propane storage. Additionally,
injection
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pumps may be manufactured following a standard pump manufacture process, or
may
be custom-designed and made to manage propane injection from about 40 t/d to
about
80 t/d. In practice, the amount of solvent delivered may be determined by
measuring
the weight of each truck before and after unloading to monitor the weight
change. For
propane injection at a rate of 50 t/d, two or more trucks may be sufficient.
[196] For maintaining a solvent-dominant process operated with a typical
SAGD well pair at a pressure of about 3 MPa, the steam requirement to heat
propane
to about 75-100 C is expected to be about 10-25 t/d. This steam requirement is
much
less than the steam requirement for steam injection in a conventional SAGD
process,
which requires about 250-300 t/d steam at the in-situ pressure of about 3-3.5
MPa.
[197] In different embodiments, and depending on the desired quality of the
injected propane, the quality of the injected steam, and the temperature of
the propane
in the delivering trucks, the steam injection rate may be between 10% and 30%
of the
propane injection rate.
[198] In some embodiments, solvent injection may be measured to avoid risks
of short circuiting the solvent and thermal shock. Short circuiting of
injected solvent
may increase the load on injection and production pump(s) due to increased GOR
(gas
to oil ratio). To mitigate this potential problem, solvent injection rate may
be increased
with careful control and pump performance may be monitored (e.g., through
monitoring
amperage fluctuations) for anomalies. Rapid cooling at the wellhead and upper
reaches
of the wellbore due to injection of a cooler injection mixture may cause a
thermal shock
effect. The wellbore heat capacity may be sufficient to mitigate this effect
in some
cases. However, to reduce the risk, steam may be provided between 10 wt% and
30
wt% with the solvent, to target 100 C at the wellhead. The amount of steam may
be
controlled based on a wellhead temperature reading.
[199] In an embodiment, after the initial transition to the solvent-
dominant
process, a steady injection ratio of 80 wt% propane and 20 wt% steam may be
achieved within three weeks. In some cases, 20 wt% steam in the injection
mixture
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may be needed for increasing the enthalpy of the mixture for the solvent to be
injected
in the gaseous phase and for later condensation of the solvent in the steam
chamber.
Co-injection of steam and solvent at a steady ratio of 20 wt% of steam and 80
wt% of
solvent may be maintained for about 18 months. It is expected that seasonal
environmental temperature changes should not affect the injection process.
Some
fluctuation in the wt% of steam, the wt% of solvent, or both, may be observed
during
the steam-dominant process, the solvent-dominant process, or both, for
example,
fluctuation of about 10 wt%.
[200] CONCLUDING REMARKS
[201] It will be understood that any range of values herein is intended to
specifically include any intermediate value or sub-range within the given
range, and all
such intermediate values and sub-ranges are individually and specifically
disclosed.
[202] It will also be understood that the word "a" or "an" is intended to
mean
"one or more" or "at least one", and any singular form is intended to include
plurals
herein.
[203] It will be further understood that the term "comprise", including any
variation thereof, is intended to be open-ended and means "include, but not
limited to,"
unless otherwise specifically indicated to the contrary.
[204] When a list of items is given herein with an "or" before the last
item, any
one of the listed items or any suitable combination of two or more of the
listed items
may be selected and used.
[205] Of course, the above described embodiments are intended to be
illustrative only and in no way limiting. The described embodiments are
susceptible to
many modifications of form, arrangement of parts, details and order of
operation. The
invention is intended to encompass all such modification within its scope, as
defined by
the claims.
