Note: Descriptions are shown in the official language in which they were submitted.
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REMOVAL OF NON-CONDENSING GAS FROM STEAM CHAMBER WITH CO-
INJECTION OF STEAM AND CONVECTION-ENHANCING AGENT
FIELD
[0001] The present disclosure relates generally to steam-assisted
processes for
hydrocarbon recovery and particularly to removal of non-condensing gas from a
steam
chamber in such a process.
BACKGROUND
[0002] Some subterranean reservoirs (also known as deposits or formations)
of
viscous hydrocarbons can be extracted in situ by lowering the viscosity of the
hydrocarbons to mobilize the hydrocarbons so that they can be moved to, and
recovered from, a production well. Such reservoirs may be referred to as
reservoirs of
heavy hydrocarbons, heavy oil, bitumen, bituminous sands, or oil sands. The in
situ
processes for recovering oil from oil sands typically involve the use of one
or more
wells drilled into the reservoir, and can be assisted or aided by injecting a
heated fluid
such as steam into the reservoir through one or more injection wells. Example
processes include steam-assisted gravity drainage (SAGD) processes and cyclic
steam stimulation (CSS) processes. In these and other processes, a solvent may
also
be used to reduce the viscosity of viscous hydrocarbons in the reservoir.
[0003] In a typical SAGD process, a steam injection well and a hydrocarbon
production well (forming a well pair) penetrate into a reservoir formation of
bituminous
sands. Both wells have generally horizontal, perforated terminal sections. A
perforated
section may have any type of opening in the wellbore for fluid communication
with the
reservoir, and may include slotted casing. The horizontal section of the
injection well
is typically located above the horizontal section of the production well,
normally by a
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few meters. A fluid such as steam is injected into the reservoir through the
injection
well, to soften bitumen in the reservoir and reduce the viscosity of the
bitumen. Heat is
transferred from the injected steam to the reservoir formation, which softens
the
bitumen and results in condensation of steam. The softened bitumen and
condensed
steam (aqueous condensate) can flow and drain downward due to gravity, thus
leaving
behind a porous region, which is permeable to gas and steam and is referred to
as the
steam chamber. Subsequently injected steam rises from the injection well,
permeates
the steam chamber, and condenses at the edge of the steam chamber (often
referred
to as the steam chamber front), which is the interface area of the steam
chamber and
the bitumen in the formation. In the process, more heat is transferred to the
bituminous
sands and the steam chamber expands over time. Mobilized hydrocarbons and
condensate drained downward under gravity are collected by the horizontal
section of
the production well, from which the hydrocarbons are produced or recovered.
Multiple
well pairs may be arranged at a well pad or within the reservoir to form a
well pattern.
Additional injection or production wells, such as a well drilled using Wedge
WellTM
technology, may also be provided.
[0004] In a typical CSS process, a single well may be used to alternately
inject
steam into the reservoir and produce a fluid from the reservoir. The
alternation may be
repeated or cycled, hence known as cyclic steam stimulation. The single well
may
have a substantially horizontal or vertical section in fluid communication
with the
reservoir. A steam chamber may also develop in a CSS process.
[0005] In a SAGD or CSS process, as a steam chamber forms and expands,
non-condensing gases (NCGs), mainly methane, but which may include other gases
such as carbon dioxide or hydrogen sulfide, can be liberated or generated. If
not
removed, the NCGs will accumulate in the steam chamber. In particular, because
the
molar mass of methane is slightly less than the molar mass of water (steam),
methane
tends to rise up and accumulate at the top of the steam chamber. Other aspects
of
fluid dynamics in the steam-assisted process can also influence NCG movement
in the
steam chamber. For example, as injected steam migrates from the injection well
towards the steam chamber front, the steam can in effect drag NCGs with it.
When
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steam transfers heat to the bitumen and condenses, which mainly occurs near
the
steam chamber front, the volume or partial pressure of steam is significantly
reduced.
NGCs generally have higher vapour pressures, as compared to steam, at lower
temperatures. These, and various other factors, contribute to creation of a
region near
the steam chamber front that draws and retains NCGs and the accumulation of
NCGs
at the steam chamber front.
[0006] NCGs accumulated in the steam chamber can be beneficial. For
example, US Patent No. 8,596,357 teaches adding NCGs to injected steam, to
increase accumulation of NCGs at the top of the steam chamber.
[0007] Accumulation of NCGs at the steam chamber front can also present
challenges. For example, the accumulated NCGs may form a "blanket" and act as
an
insulator, which reduces or prevents heat transfer from steam to the bitumen
at the
steam chamber front. The accumulation of NCGs can also result in a lower
partial
pressure of steam at the steam chamber front, and a lower steam saturation
temperature, thus limiting lateral growth of the steam chamber.
[0008] In principle, removal of NCGs from the steam chamber is expected
to
improve heat transfer efficiency and reduce the amount of steam required to
expand
the steam chamber. However, in practice, it has been found to be challenging
to
remove NCGs without incurring substantial equipment and operation costs and to
achieve an overall lower steam to oil ratio (SOR) or cumulative SOR (CSOR) for
the
production process.
[0009] As is well known, SOR (or CSOR) is a benchmark metric for
production
efficiency and performance, as a lower SOR/CSOR generally indicates a more
cost-
effective oil production process. Some positive effects of a lower SOR/CSOR
include,
as graphically illustrated in FIG. 16, reduced water usage for generating
steam,
reduced greenhouse gas GHG) emissions, smaller footprint of surface production
facilities, lower capital expenditures (CAPEX), and increased overall revenue.
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[0010] However, in a conventional SAGD operation, for example, it may be
difficult to remove NCGs through a production well located at the bottom of
the steam
chamber. A number of potential problems can arise from attempting to remove
NCGs
from the reservoir by producing the NCGs through the production well. As an
example,
one proposed technique for moving NCGs downward into the production well is to
apply sufficient fluid drawdown to drive the NCGs towards the production well,
but
such fluid drawdown often also moves a steam phase, or a hot water phase, with
the
NCG phase towards the production well. Hot water can flash to steam when it
approaches the bottom of the steam chamber or the production well, as in the
vicinity
of the production well the pressure is typically lower and the temperature is
typically
higher. In any event, a large amount of steam may be produced through the
production well, which is undesirable as this would increase the steam to oil
ratio
(SOR) for the production process.
[0011] Challenges thus remain in connection with removal of NCGs from
steam
chambers to decrease the overall SOR.
SUMMARY
[0012] Accordingly, in an aspect of the present disclosure, there is
provided a
method of removing non-condensing gas present in a steam chamber in a steam-
assisted process for hydrocarbon recovery from an oil sands reservoir, wherein
the
reservoir is serviced by one or more wells each configurable as an injection
well, a
production well, or both an injection well and a production well, and wherein
each of
the one or more wells mediates fluid communication between a surface
completion
and the reservoir, and wherein steam is injected into the reservoir through at
least one
of the one or more wells configured for injection, resulting in formation and
expansion
of the steam chamber and accumulation of the non-condensing gas in the steam
chamber. The method comprises injecting a convection-enhancing agent with
steam
into the at least one of the one or more wells configured for injection, to
promote
convection of gases in the steam chamber so as to assist removal of the non-
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condensing gas from the steam chamber; removing gases from the reservoir
through
at least one of the one or more wells configured for production of
hydrocarbons
conveyed downward from the steam chamber wherein the removed gases comprise
the non-condensing gas descended from the steam chamber resulting from the
convection of gases.
[0013] In selected embodiments, the one or more wells may comprise a well
pair of an injection well and a production well. The one or more wells may
comprise a
single well configurable for either injection or production, and the method
may
comprise alternately injecting steam with the convection-enhancing agent into
the
steam chamber through the single well and producing a fluid and gases from the
reservoir through the single well. The one or more wells may comprise a well
that is
configurable for injection or production. The one or more wells may comprise a
well
having a substantially horizontal terminal section in fluid communication with
the
reservoir. The one or more wells may comprise a well having a substantially
vertical
section in fluid communication with the reservoir. The steam-assisted process
may be
a steam-assisted gravity drainage (SAGD) process, or a cyclic steam
stimulation
(CSS) process. A mixture of the convection-enhancing agent and steam may be
injected into the at least one well for injection, and wherein a temperature
in the steam
chamber is from about 152 C to about 286 C and a pressure in the steam
chamber is
from about 0.5 MPa to about 7 MPa. A temperature in the reservoir may be from
about
234 C to about 328 C and a pressure in the reservoir may be from about 3 MPa
to
about 12.5 MPa. The convection-enhancing agent may be 0.1% to 10% of the steam
by weight in the mixture, such as 1% to 3%, 1% to 5%, 3% to 5%, 3% to 8%, or
5% to
8%. The non-condensing gas may comprise methane, a carbon oxide such as carbon
dioxide or carbon monoxide, a nitrogen oxide such as nitrogen dioxide, a
sulfur oxide
such as sulfur dioxide, hydrogen sulfide, or a combination thereof. The non-
condensing gas may comprise methane. The convection-enhancing agent may be
selected to increase a gas phase density in the steam chamber. The convection-
enhancing agent may comprise an organic molecule having a moderate volatility
such
that a sufficient proportion of the convection-enhancing agent injected into
the steam
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chamber can remain in the gas phase in the steam chamber for a sufficient
period to
ascend to a steam chamber front and to induce the convection of gases in the
steam
chamber, and can thereafter condense along the steam chamber front. Increasing
gas
phase density in the steam chamber may direct the non-condensing gas away from
the front of the steam chamber and towards at least one of the one or more
wells
configured for production to remove the non-condensing gas. The method may
comprise directing the non-condensing gas towards at least one of the one or
more
wells configured for production to inhibit steam loss, oil loss, or both steam
loss and oil
loss to a thief zone in the reservoir, wherein a thief zone is bottom water, a
gas cap, or
both bottom water and a gas cap. The convection-enhancing agent may comprise
at
least one of propane and butane. The organic molecule may comprise a non-polar
molecule. The molar mass of the non-polar organic molecule may be from about
30
g/mol to about 60 g/mol. The organic molecule may comprise a polar molecule.
The
molar mass of the polar organic molecule may be from about 30 g/mol to about
105
g/mol. The polar organic molecule may comprise formaldehyde. A molar mass of
the
convection-enhancing agent may be higher than a molar mass of the non-
condensing
gas. The convection-enhancing agent may be more volatile than water. The
convection-enhancing agent may be more soluble in oil than in water.
[0014] In some selected embodiments, injection of the convection-
enhancing
agent may commence before the steam chamber has formed, or when hydrocarbon
production from the reservoir through the one or more wells has commenced. In
some
selected embodiments, injection of the convection-enhancing agent may commence
after the steam chamber has formed, or after a period of hydrocarbon
production from
the reservoir through the one or more wells. The period of hydrocarbon
production
may be about 12 months. Injection of the convection-enhancing agent may
terminate
after the steam chamber has coalesced with an adjacent steam chamber.
Injection of
the convection-enhancing agent may terminate after about 36 months of
hydrocarbon
production from the reservoir through the one or more wells. The weight
percentage
of the convection-enhancing agent in the mixture may increase or decrease over
time
during injection of the convection-enhancing agent. The weight percentage of
the
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convection-enhancing agent in the mixture may increase over time during
injection of
the convection-enhancing agent by 1 wt% to 3 wt%.
[0015] Other aspects, features, and embodiments of the present invention
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
[0016] In the figures, which illustrate, by way of example only,
embodiments of
the present invention:
[0017] FIG. 1 is a schematic diagram illustrating a steam-assisted
gravity
drainage (SAGD) arrangement, according to an embodiment of the disclosure;
[0018] FIG. 2 is a three-dimensional (3D) graph showing simulation
results of
steam chamber development in the reservoir along the length of the well in the
x-z
plane after 2.1 years of SAGD operation;
[0019] FIG. 3 is a 3D graph showing simulation results of methane
distribution in
the reservoir after 2.1 years of SAGD operation;
[0020] FIG. 4 is a 3D graph showing simulation results of methane
distribution in
the reservoir after 4.7 years of SAGD operation;
[0021] FIG. 5A is a 3D graph showing simulation results of methane
distribution
in the reservoir after 4.9 years of SAGD operation;
[0022] FIG. 5B is a 3D graph showing simulation results of methane
distribution
in the reservoir after 4.9 years of SAGD operation with injection of propane
at 5 wt% of
steam;
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[0023] FIG. 6 is a line graph showing simulation results of bitumen
production
rates over time for various butane and/or propane injection compositions;
[0024] FIG. 7 is a line graph showing simulation results of bitumen
recovery
factor over time for different injection compositions;
[0025] FIG. 8 is a line graph showing simulation results of methane
removal
rates over time for different injection compositions;
[0026] FIG. 9 is a line graph showing simulation results of methane
removal
factor over time for different injection compositions;
[0027] FIG. 10 is a line graph showing simulation results of cumulative
steam to
oil ratio (CSOR) over time for different injection compositions;
[0028] FIG. 11 is a line graph showing simulation results of bitumen
production
rates over time for various polar and non-polar injection compositions;
[0029] FIG. 12 is a line graph showing simulation results of bitumen
recovery
factor over time for injection of the different compositions of FIG. 11;
[0030] FIG. 13 is a line graph showing simulation results of methane
removal
rates over time for injection of the different compositions of FIG. 11;
[0031] FIG. 14 is a line graph showing simulation results of methane
removal
factor over time for injection of the different compositions of FIG. 11;
[0032] FIG. 15 is a line graph showing simulation results of CSOR over
time for
injection of the different compositions of FIG. 11;
[0033] FIG. 16 is a diagram illustrating the benefits of decreased SOR;
[0034] FIG. 17A is a two-dimensional (2D) simulated representation of a
SAGD
steam chamber;
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[0035] FIG. 17B is a 2D simulated representation of NCG distribution at
the
edges of the steam chamber of FIG. 17A;
[0036] FIG. 17C is a 2D simulated representation of a SAGD with
convection-
enhancing agent steam chamber;
[0037] FIG. 17D is a 2D simulated representation of NCG distribution in
the
steam chamber of FIG. 17C;
[0038] FIG. 17E is a 2D simulated representation of convection-enhancing
agent distribution in the steam chamber of FIG. 17C;
[0039] FIG. 18 is a line graph showing simulation results of CSOR as a
function
of methane removal factor;
[0040] FIG. 19 is a line graph showing simulation results of CSOR as a
function
of bitumen recovery factor.
[0041] FIG. 20 is a line graph showing simulation results of CSOR as a
function
of bitumen recovery factor for various propane injection compositions with
injection
starting after 365 days of SAGD operation;
[0042] FIG. 21 is a line graph showing simulation results of CSOR as a
function
of methane recovery factor for various propane injection compositions with
injection
starting after 365 days of SAGD operation;
[0043] FIG. 22 is a line graph showing simulation results of bitumen
recovery
factor over time for various propane injection compositions with injection
starting after
365 days of SAGD operation;
[0044] FIG. 23 is a line graph showing simulation results of methane
removal
factor over time for various propane injection compositions with injection
starting after
365 days of SAGD operation;
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[0045] FIG. 24A is a 3D graph showing simulation results of methane
distribution in the reservoir along the length of the well in the x-z plane
after 365 days
of SAGD operation;
[0046] FIG. 24B is a 3D graph showing simulation results of methane
distribution in the reservoir along the length of the well in the x-z plane
after 450 days
of SAGD operation;
[0047] FIG. 24C is a 3D graph showing simulation results of methane
distribution in the reservoir along the length of the well in the x-z plane
after 550 days
of SAGD operation;
[0048] FIG. 24D is a 3D graph showing simulation results of methane
distribution in the reservoir along the length of the well in the x-z plane
after 650 days
of SAGD operation;
[0049] FIG. 24E is a 3D graph showing simulation results of methane
distribution in the reservoir along the length of the well in the x-z plane
after 730 days
of SAGD operation;
[0050] FIG. 24F is a 3D graph showing simulation results of methane
distribution in the reservoir along the length of the well in the x-z plane
after 1,096
days of SAGD operation;
[0051] FIG. 25A is a 3D graph showing simulation results of methane
distribution in the reservoir along the length of the well in the x-z plane
after 450 days
of SAGD operation including 85 days with injection of propane at 3 wt% of
steam;
[0052] FIG. 25B is a 3D graph showing simulation results of methane
distribution in the reservoir along the length of the well in the x-z plane
after 550 days
of SAGD operation including 185 days with injection of propane at 3 wt% of
steam;
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[0053] FIG. 25C is a 3D graph showing simulation results of methane
distribution in the reservoir along the length of the well in the x-z plane
after 650 days
of SAGD operation including 285 days with injection of propane at 3 wt% of
steam;
[0054] FIG. 25D is a 3D graph showing simulation results of methane
distribution in the reservoir along the length of the well in the x-z plane
after 730 days
of SAGD operation including 365 days with injection of propane at 3 wt% of
steam;
[0055] FIG. 25E is a 3D graph showing simulation results of methane
distribution in the reservoir along the length of the well in the x-z plane
after 1,096
days of SAGD operation including 730 days with injection of propane at 3 wt%
of
steam;
[0056] FIG. 26A is a 3D graph showing simulation results of methane
distribution in the reservoir along the length of the well in the x-z plane
after 450 days
of SAGD operation including 85 days with injection of propane at 5 wt% of
steam;
[0057] FIG. 26B is a 3D graph showing simulation results of methane
distribution in the reservoir along the length of the well in the x-z plane
after 550 days
of SAGD operation including 185 days with injection of propane at 5 wt% of
steam;
[0058] FIG. 26C is a 3D graph showing simulation results of methane
distribution in the reservoir along the length of the well in the x-z plane
after 650 days
of SAGD operation including 285 days with injection of propane at 5 wt% of
steam;
[0059] FIG. 26D is a 3D graph showing simulation results of methane
distribution in the reservoir along the length of the well in the x-z plane
after 730 days
of SAGD operation including 365 days with injection of propane at 5 wt% of
steam;
[0060] FIG. 26E is a 3D graph showing simulation results of methane
distribution in the reservoir along the length of the well in the x-z plane
after 1,096
days of SAGD operation including 730 days with injection of propane at 5 wt%
of
steam;
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[0061] FIG. 27A is a 3D graph showing simulation results of methane
distribution in the reservoir along the length of the well in the x-z plane
after 450 days
of SAGD operation including 85 days with injection of propane at 10 wt% of
steam;
[0062] FIG. 27B is a 3D graph showing simulation results of methane
distribution in the reservoir along the length of the well in the x-z plane
after 550 days
of SAGD operation including 185 days with injection of propane at 10 wt% of
steam;
[0063] FIG. 27C is a 3D graph showing simulation results of methane
distribution in the reservoir along the length of the well in the x-z plane
after 650 days
of SAGD operation including 285 days with injection of propane at 10 wt% of
steam;
[0064] FIG. 27D is a 3D graph showing simulation results of methane
distribution in the reservoir along the length of the well in the x-z plane
after 730 days
of SAGD operation including 365 days with injection of propane at 10 wt% of
steam;
[0065] FIG. 27E is a 3D graph showing simulation results of methane
distribution in the reservoir along the length of the well in the x-z plane
after 1,096
days of SAGD operation including 730 days with injection of propane at 10 wt%
of
steam;
[0066] FIG. 28A is a 3D graph showing simulation results of methane
distribution in the reservoir along the length of the well in the y-z plane
after 365 days
of SAGD operation;
[0067] FIG. 28B is a 3D graph showing simulation results of methane
distribution in the reservoir along the length of the well in the y-z plane
after 450 days
of SAGD operation;
[0068] FIG. 28C is a 3D graph showing simulation results of methane
distribution in the reservoir along the length of the well in the y-z plane
after 550 days
of SAGD operation;
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[0069] FIG. 28D is a 3D graph showing simulation results of methane
distribution in the reservoir along the length of the well in the y-z plane
after 650 days
of SAGD operation;
[0070] FIG. 28E is a 3D graph showing simulation results of methane
distribution in the reservoir along the length of the well in the y-z plane
after 730 days
of SAGD operation;
[0071] FIG. 28F is a 3D graph showing simulation results of methane
distribution in the reservoir along the length of the well in the y-z plane
after 1,096
days of SAGD operation;
[0072] FIG. 29A is a 3D graph showing simulation results of methane
distribution in the reservoir along the length of the well in the y-z plane
after 450 days
of SAGD operation including 85 days with injection of propane at 3 wt% of
steam;
[0073] FIG. 29B is a 3D graph showing simulation results of methane
distribution in the reservoir along the length of the well in the y-z plane
after 550 days
of SAGD operation including 185 days with injection of propane at 3 wt% of
steam;
[0074] FIG. 29C is a 3D graph showing simulation results of methane
distribution in the reservoir along the length of the well in the y-z plane
after 650 days
of SAGD operation including 285 days with injection of propane at 3 wt% of
steam;
[0075] FIG. 29D is a 3D graph showing simulation results of methane
distribution in the reservoir along the length of the well in the y-z plane
after 730 days
of SAGD operation including 365 days with injection of propane at 3 wt% of
steam;
[0076] FIG. 29E is a 3D graph showing simulation results of methane
distribution in the reservoir along the length of the well in the y-z plane
after 1,096
days of SAGD operation including 730 days with injection of propane at 3 wt%
of
steam;
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[0077] FIG. 30A is a 3D graph showing simulation results of methane
distribution in the reservoir along the length of the well in the y-z plane
after 450 days
of SAGD operation including 85 days with injection of propane at 5 wt% of
steam;
[0078] FIG. 30B is a 3D graph showing simulation results of methane
distribution in the reservoir along the length of the well in the y-z plane
after 550 days
of SAGD operation including 185 days with injection of propane at 5 wt% of
steam;
[0079] FIG. 30C is a 3D graph showing simulation results of methane
distribution in the reservoir along the length of the well in the y-z plane
after 650 days
of SAGD operation including 285 days with injection of propane at 5 wt% of
steam;
[0080] FIG. 30D is a 3D graph showing simulation results of methane
distribution in the reservoir along the length of the well in the y-z plane
after 730 days
of SAGD operation including 365 days with injection of propane at 5 wt% of
steam;
[0081] FIG. 30E is a 3D graph showing simulation results of methane
distribution in the reservoir along the length of the well in the y-z plane
after 1,096
days of SAGD operation including 730 days with injection of propane at 5 wt%
of
steam;
[0082] FIG. 31A is a 3D graph showing simulation results of methane
distribution in the reservoir along the length of the well in the y-z plane
after 450 days
of SAGD operation including 85 days with injection of propane at 10 wt% of
steam;
[0083] FIG. 31B is a 3D graph showing simulation results of methane
distribution in the reservoir along the length of the well in the y-z plane
after 550 days
of SAGD operation including 185 days with injection of propane at 10 wt% of
steam;
[0084] FIG. 31C is a 3D graph showing simulation results of methane
distribution in the reservoir along the length of the well in the y-z plane
after 650 days
of SAGD operation including 285 days with injection of propane at 10 wt% of
steam;
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[0085] FIG. 31D is a 3D graph showing simulation results of methane
distribution in the reservoir along the length of the well in the y-z plane
after 730 days
of SAGD operation including 365 days with injection of propane at 10 wt% of
steam;
[0086] FIG. 31E is a 3D graph showing simulation results of methane
distribution in the reservoir along the length of the well in the y-z plane
after 1,096
days of SAGD operation including 730 days with injection of propane at 10 wt%
of
steam;
[0087] FIG. 32 is a line graph showing simulation results of bitumen
production
rates over time for various propane injection compositions with injection at
the start of
a SAGD operation;
[0088] FIG. 33 is a line graph showing simulation results of bitumen
recovery
factor over time for various propane injection compositions with injection at
the start of
a SAGD operation;
[0089] FIG. 34 is a line graph showing simulation results of methane
production
rates over time for various propane injection compositions with injection at
the start of
a SAGD operation;
[0090] FIG. 35 is a line graph showing simulation results of methane
removal
factor over time for various propane injection compositions with injection at
the start of
a SAGD operation;
[0091] FIG. 36 is a line graph showing simulation results of CSOR as a
function
of bitumen recovery factor for various propane injection compositions with
injection at
the start of a SAGD operation; and
[0092] FIG. 37 is a line graph showing simulation results of CSOR as a
function
of methane removal factor for various propane injection compositions with
injection at
the start of a SAGD operation.
[0093]
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DETAILED DESCRIPTION
[0094] In brief overview, it has now been recognized that co-injecting a
small
amount of a convection-enhancing agent (CEA) with steam into a steam chamber
can
assist removal of non-condensing gases (NCGs) from the steam chamber and
significantly lower steam to oil ratio (SOR). The injected CEA is heated by
steam and
can travel or rise up to the steam front with steam. The CEA, being more
volatile than
steam, progresses ahead of the steam front and comes into contact with NCGs,
which
promotes convection of gases in the steam chamber and along the length of, for
example, the horizontal section of a SAGD well pair, and particularly the
descending
gas flow from the steam chamber front. Without being limited to theory, the
descending
gas flow may carry or drag NCGs towards the bottom of the steam chamber. Thus,
the
NCGs can be conveniently removed from the steam chamber through an existing
production well positioned at or near the bottom of the steam chamber. With
careful
selection of the convection-enhancing agent, the rate of NCG removal and
reduction in
SOR can be optimized. In the context of the present disclosure, convection of
gases or
convection flow of gases refer to the conveying or transport of gases. A
suitable
convection-enhancing agent increases the gas phase density in the steam
chamber,
resulting in descending gas flow towards a production well for removal of NCGs
from
the steam chamber.
[0095] It has also been recognized that a number of factors are expected
to
impact the performance and economics of such a NCG removal technique.
[0096] One of such factors is the molar mass of the CEA. To provide
effective or
optimal NCG removal, the molar mass of the CEA should be higher than the molar
mass of the NCG to be removed, but not too high. If the CEA is too light, it
is expected
to tend to remain above the NCG layer in the steam chamber and will not be
effective
for promoting convection of gases towards the bottom of the steam chamber. If
the
CEA is too heavy, it would be difficult for the injected CEA to rise up in the
steam
chamber to reach the steam front. In other words, when the CEA has a higher
molar
mass than steam and the NCG and is added to the gas phase in the steam
chamber,
16
CA 02953352 2016-12-29
the gas phase density is increased and the gas phase tends to descend, which
helps
removal of the NCG. However, the density factor needs to be balanced with
other
factors such as the volatility. For example, heavier organic molecules tend to
be less
volatile, and if a compound being injected is too heavy it may be less
effective as a
CEA for removing NCGs (see discussion below).
[0097] Another factor that should be considered when selecting the CEA is
the
volatility of the CEA at reservoir conditions. The volatility of the CEA in
the steam
chamber should be moderate such that CEA can remain in the gas phase (as a
vapour) in the steam chamber. It is however beneficial if the CEA is not too
volatile so
that a substantial portion of the CEA can eventually condense in the steam
chamber
and dissolve in oil, which will conveniently have the effect of lowering the
viscosity of
the liquid phase in the steam chamber.
[0098] It is desirable that the CEA is more soluble in oil than in water.
[0099] Generally, it is expected that the vapour pressure of a suitable
CEA is
lower than the vapour pressure of water at the same temperature. Organic
compounds
with such low vapour pressures include ethane, propane, butane, pentane,
hexane, or
the like. However, it is noted that pentane and hexane have relatively high
molar mass
and low volatility. Therefore, these may be less effective for removing NCGs,
as
compared to the other lighter alkanes.
[00100] Simulation results show that butane and propane can meet the above
criteria, and are suitable for use as CEAs in some applications to remove,
e.g.,
methane, from the steam chamber. It is expected other alkanes or hydrocarbon
solvents with 2 to 5 carbon atoms may also be suitable for removing methane,
if they
have molar masses, volatilities and oil solubilities comparable to those of
butane and
propane.
[00101] A liquefied petroleum gas (LPG) is a by-product of petroleum or
natural
gas refining and contains a mixture of hydrocarbon gases including propane and
butane. In some embodiments, LPG may be used as a CEA. In different
embodiments,
17
CA 02953352 2016-12-29
one or more components of LPG may be separated or extracted from the mixture
and
be used as a CEA. Advantageously, using LPG or its components as a CEA may
improve the efficiency of, or reduce the costs of, NCG removal in a steam-
assisted
process for hydrocarbon recovery.
[00102] However, hydrocarbon molecules with 6 or more carbon atoms are
less
likely to be suitable candidates for the CEA as such hydrocarbon molecules
tend to
have low volatility and are expected to dissolve in oil. Methane is itself a
NCG and is
thus not suitable for use as CEA in the present context.
[00103] A suitable CEA may have a molar mass from about 30 g/mol to about
60
g/mol.
[00104] A further factor that can affect the performance and economics of
NCG
removal is the amount of CEA injected into the steam chamber. A lower amount
would
mean lower cost and less post-production processing or treatment. In this
regard, it is
expected that compounds with lower molar masses are typically less expensive,
and
co-injecting a low concentration of CEA may only require limited, if any,
surface
processing or CEA recovery or recycling.
[00105] Computer model simulation results indicated that a small amount of
the
CEA would be sufficient to achieve effective removal of methane from a steam
chamber in a typical steam-assisted gravity drainage (SAGD) process. Effective
removal of NCGs such as methane may be achieved when steam and CEA are co-
injected and the CEA in the injection stream is from about 0.1 % to about 10%
of
steam by weight (i.e. about 0.1 wt% to about 10 wt%), such as about 1 wt% to
about 5
wt%. It is expected that injection of about 1 wt% to about 3 wt% of CEA, for
example,
propane, with steam would be sufficient to significantly increase the rate of
NCG
removal and can be implemented economically at an existing SAGD operation
site.
[00106] Computer model simulation results also indicated that for NCG
removal,
about 1 wt% of CEA (such as propane or butane) co-injection can be effective
in some
tested formation conditions, for example, achieving as high as about 29%
incremental
18
CA 02953352 2016-12-29
NCG removal compared to a baseline case of SAGD. Increasing the CEA
concentration to above about 5 to 8 wt% may not further substantially improve
overall
NCG removal or allow for NCG removal at an economical cost under at least some
formation and operation conditions, although the overall oil recovery and NCG
removal
rate can still increase. Thus, for NCG removal, co-injection of CEA at about 1
to 3 wt%,
about 3 to 5 wt%, or about 5 to 8 wt% may be effective and economical.
[00107] In comparison, a typical conventional solvent aided process (SAP)
often
involves injection of a solvent at much higher concentrations or ratios, such
as above
20 wt% of steam, to achieve significant and economical reduction in SOR or
CSOR.
[00108] Computer model simulation results also indicated that at low
concentrations of CEA, such as about 1 to 3 wt%, about 3 to 5 wt%, or about 5
to 8
wt%, the effect of CEA co-injection and NCG removal after merging (also known
as
coalescence) of the steam chambers of adjacent SAGD well pairs may be
significantly
reduced. Thus, it may be more economical to terminate CEA co-injection once
the
steam chambers have coalesced. For example, depending on the nature of the
reservoir formation and its conditions, steam chambers of SAGD well pairs that
are
spaced apart by about 100 m may coalesce after about 3 years of hydrocarbon
(oil)
production. In such cases, CEA co-injection may terminate after about 3 years
of
hydrocarbon production. Other well spacing may be suitable, for example, about
200
m between SAGD well pairs.
[00109] Without being limited to any particular theory, it is expected
that a low
amount (e.g. about 1 to 8 wt%) of CEA co-injection is more or most effective
during
early stages of oil production as NCG removal during this period is expected
to
significantly improve steam chamber conformance, as compared to only steam
injection. As can be understood by those skilled in the art, better or
improved steam
chamber conformance can improve hydrocarbon production performance, such as
improved oil recovery rates or overall oil recovery factors (oil uplift).
[00110] Further, test results indicated that, while co-injection of CEA at
about 1
wt% to about 8 wt% may be effective for NCG removal, CEA co-injection at the
range
19
CA 02953352 2016-12-29
of about 3 wt% to about 5 wt% can also improve hydrocarbon/oil production, and
CEA
co-injection at the higher end of the range, e.g., about 5 wt% to about 8 wt%,
can
further significantly improve instantaneous steam to oil ration (ISOR) or CSOR
of the
hydrocarbon recovery operation.
[00111] Without being limited to any specific theory, it is expected that
the
increased performance at higher co-injection concentrations of CEA may be due
to
reduction in bitumen fluid viscosity as the CEA condenses and dissolves in the
formation fluid phase, particularly at the steam front. Further, it is
expected that at
lower concentrations of CEA co-injection, the main effect of the injected CEA
may be
NCG removal, which may require additional steam to fill the void space
remaining as
NCGs are removed, and may result in faster steam chamber growth and a higher
oil
production rate. As the concentration of co-injected CEA is increased, more
and more
CEA may condense and dissolve in or mix with the formation fluid to improve
bitumen
mobility or viscosity, thus leading to increased oil production and,
eventually, reduced
ISOR or CSOR.
[00112] Even if the CSOR is not reduced, maintaining the level of CSOR
over a
longer period of time would still provide a benefit as this would extend the
economical
period of oil production, resulting in increased overall production (bitumen
recovery
factor) for a given reservoir.
[00113] As can be understood by those skilled in the art, in practice, the
weight
percentage of an injected material such as CEA may be measured and controlled
within a certain tolerance, in part because the measurement and control of the
injection rate does not need to be absolutely precise, which is also not
always
impractical. For example, it may be sufficient that, at 1 wt% CEA, the error
tolerance
can be about 5%. That is, for a stated injection concentration of 1 wt%, the
actual
measured injection concentration may vary between 0.95 wt% to 1.05 wt%.
[00114] The amount of co-injected CEA may vary during injection. For
example,
the weight percentage of the co-injected CEA in the injection mixture may
increase
during injection, such as by about 1 to 3 wt%. In an embodiment, the initial
weight
CA 02953352 2016-12-29
percentage may be about 3 wt% and may be increased to 4 or 5 wt% by continual
increase or by stepwise increments. In another embodiment, the initial weight
percentage of CEA may be increased by a greater amount, for example, from
about 3
wt% to about 8 wt%. Of course, in some embodiments, the weight percentage of
the
co-injected CEA in the injection mixture may also decrease or fluctuate during
co-
injection.
[001151 In selected embodiments, steam may be injected at a temperature
from
about 100 C to about 330 C and a pressure from about 0.1 MPa to about 12.8
MPa.
The steam may be injected through an injection well, and the fluid may be
produced
through a production well. The injection well and the production well may have
terminal sections that are substantially horizontal, the substantially
horizontal sections
of the wells being substantially parallel. The substantially horizontal
sections of the
wells may be vertically spaced apart. The injection well and the production
well may
form a well pair for a steam-assisted gravity drainage (SAGD) process. A steam
chamber may be formed in the reservoir due to steam injection, and a
temperature in
the steam chamber may be from about 152 C to about 286 C and a pressure in
the
steam chamber may be from about 0.5 MPa to about 7 MPa. A single well may be
used to alternately inject steam into the reservoir and produce the fluid from
the
reservoir. The single well may have a substantially horizontal or vertical
section in fluid
communication with the reservoir. The single well may be used in a cyclic
steam
recovery process. With the use of the 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 about 3.0 MPa to about 12.5 MPa.
[00116] Embodiments disclosed herein relate to a method of hydrocarbon
recovery from a reservoir of bituminous sands assisted by injection of steam
and a
convection-enhancing agent into the reservoir. Steam is injected into the
reservoir to
mobilize or liquefy the native bitumen therein, thus forming a fluid
containing
hydrocarbons and water (including aqueous condensate), which can be produced
from
the reservoir by an in-situ recovery process, such as steam-assisted gravity
drainage
(SAGD), or a cyclic steam recovery process such as cyclic steam stimulation
(CSS).
21
CA 02953352 2016-12-29
As will be further detailed below, when steam is injected into the reservoir
to heat the
reservoir formation, non-condensing gases (NCGs) are liberated within the
reservoir
and can impede heat transfer from the steam to the bitumen. In various
embodiments,
the convection-enhancing agent is co-injected with steam to assist removal of
the
NCGs from the reservoir to permit more effective heat transfer from the steam
to the
bitumen. Advantageously, the convection-enhancing agent may also eventually
dissolve in the oleic phase in the reservoir, thus enhancing mobility of the
oleic phase
in the reservoir by reducing the viscosity, which can result in increased
liquid flow rate.
[00117] In various embodiments of the invention, the term "reservoir"
refers to a
subterranean or underground formation comprising recoverable oil
(hydrocarbons);
and the term "reservoir of bituminous sands" refers to such a formation
wherein at
least some of the hydrocarbons are viscous and immobile and are disposed
between
or attached to sands.
[00118] In various embodiments of the invention, the terms "oil",
"hydrocarbons"
or "hydrocarbon" relate to mixtures of varying compositions comprising
hydrocarbons
in the gaseous, liquid or solid states, which may be in combination with other
fluids
(liquids and gases) that are not hydrocarbons. For example, "heavy oil",
"extra heavy
oil", and "bitumen" refer to hydrocarbons occurring in semi-solid or solid
form and
having a viscosity in the range of about 1,000 to over 1,000,000 centipoise
(mPa.s or
cP) measured at original in-situ reservoir temperature. In this specification,
the terms
"hydrocarbons", "heavy oil", "oil" and "bitumen" are used interchangeably.
Depending
on the in-situ density and viscosity of the hydrocarbons, the hydrocarbons may
comprise, for example, a combination of heavy oil, extra heavy oil and
bitumen. Heavy
crude oil, for example, may be defined as any liquid petroleum hydrocarbon
having an
American Petroleum Institute (API) Gravity of less than about 20 and a
viscosity
greater than 1,000 mPa.s. Oil may be defined, for example, as hydrocarbons
mobile at
typical reservoir conditions. Extra heavy oil, for example, may be defined as
having a
viscosity of over 10,000 mPa-s and about 100 API Gravity. The API Gravity of
bitumen
ranges from about 12 to about 7 and the viscosity is greater than about
1,000,000
mPa.s. Native bitumen is generally non-mobile at native reservoir conditions.
22
CA 02953352 2016-12-29
[00119] A person skilled in the art will appreciate that an immobile
formation or
reservoir at initial (or original) conditions (e.g., temperature or viscosity)
means that the
reservoir has not been treated with heat or other means. Instead, it is in its
original
condition, prior to the recovery of hydrocarbons. Immobile formation means
that the
formation has not been mobilized through the addition of heat or other means.
The
hydrocarbons in a reservoir of bituminous sands occur in a complex mixture
comprising interactions between sand particles, fines (e.g., clay), and water
(e.g.,
interstitial water) which may form complex emulsions during processing. The
hydrocarbons derived from bituminous sands may contain other contaminant
inorganic, organic or organometallic species which may be dissolved, dispersed
or
bound within suspended solid or liquid material. Accordingly, it remains
challenging to
separate hydrocarbons from the bituminous sands in-situ, which may impede
production performance of the in-situ process.
[00120] Production performance may be improved when a higher amount of oil
is
produced within a given period of time, or with a given amount of injected
steam
depending on the particular recovery technique used, or within the lifetime of
a given
production well (overall recovery), or in some other manner as can be
understood by
those skilled in the art. For example, production performance may be improved
by
increasing the amount of hydrocarbons recovered within the steam chamber,
increasing drainage rate of the fluid or hydrocarbon from the steam chamber to
the
production well, or both.
[00121] Faster oil flow or drainage rates can lead to more efficient oil
production,
and the increase in the flow or drainage rate of reservoir fluids within the
formation can
be indirectly indicated or measured by the increase in the rate of oil
production.
Techniques for measurement of oil production rates have been well developed
and are
known to those skilled in the art.
[00122] Conveniently, an embodiment disclosed herein can improve production
performance.
23
CA 02953352 2016-12-29
[00123] The convection-enhancing agent may be used in various in-situ
thermal
recovery processes, such as SAGD or CSS, where steam is used and a steam
chamber has been developed. Selected embodiments disclosed herein may be
applicable to an existing hydrocarbon recovery process, such as after the
hydrocarbon
production rate in the recovery process has peaked.
[00124] For example, the technique disclosed herein may be employed in
typical
SAGD processes, such as those disclosed in Canadian Patent No. 1,130,201
issued
on 24 August 1982. In an example of SAGD, two wells are drilled into the
reservoir,
one for injection of steam and one for production of oil and water. Steam is
injected
via the injection well to heat the formation. The steam condenses and gives up
its
latent heat to the formation, heating a layer of viscous hydrocarbons. The
viscous
hydrocarbons are thereby mobilized, and drain by gravity toward the production
well
with the condensed steam. In this way, the injected steam initially mobilizes
the in-
place hydrocarbon to create the "steam chamber" in the reservoir around and
above
the horizontal injection well. The term "steam chamber" may accordingly refer
to any
volume of the reservoir which is filled with, or saturated with, injected
steam and from
which mobilized oil has at least partially drained. Mobilized viscous
hydrocarbons are
recovered continuously through the production well. The conditions of steam
injection
and of hydrocarbon production may be modulated to control the growth of the
steam
chamber, to ensure that the production well remains located at the bottom of
the
steam chamber in an appropriate position to collect mobilized hydrocarbons.
[00125] The start-up stage of the SAGD process establishes thermal or
hydraulic
communication, or both, between the injection and production wells. At initial
reservoir
conditions, there is typically negligible fluid mobility between wells due to
high bitumen
viscosity. Communication is achieved when bitumen between the injector and
producer is mobilized to allow for bitumen production (also referred to as
bitumen
recovery). A conventional start-up process involves establishing interwell
communication by simultaneously circulating steam through each injector well
and
producer well. High-temperature steam flows through a tubing string that
extends to
the toe of each horizontal well. The steam condenses in the well, releasing
heat and
24
CA 02953352 2016-12-29
resulting in a liquid water phase which flows back up the casing-tubing
annulus.
Alternative start-up techniques involve creating a high mobility inter-well
path by the
use of solvents or by application of pressures so as to dilate the reservoir
sand matrix.
[00126] In the ramp-up stage of the SAGD process, after communication has
been established between the injection and production wells during start-up
(usually
over a limited section of the well pair length), production begins from the
production
well. Steam is continuously injected into the injection well (usually at
constant
pressure) while mobilized bitumen and water are continuously removed from the
production well (usually at constant temperature). During this period the zone
of
communication between the wells is expanded axially along the full well pair
length
and the steam chamber grows vertically up to the top of the reservoir. The
reservoir
top may be a thick shale (overburden) or some lower permeability facies that
causes
the steam chamber to stop rising. When the interwell region over the entire
length of
the well pair has been heated and the steam chamber that develops has reached
the
reservoir top, the bitumen production rate typically peaks and begins to
decline while
the steam injection rate reaches a maximum and levels off.
[00127] In conventional SAGD, after ramp-up, in an operational phase of
production, the steam chamber has generally achieved full height (although it
is
typically still rising slowly through or spreading around lower permeability
zones in
some locations) and lateral or radial growth of the steam chamber along the
longitudinal axis of the well pair becomes the dominant mechanism for
recovering
bitumen. Typically steam injection at the injector well is controlled so as to
maintain a
target steam chamber pressure during this phase. As the reservoir fluids drain
to the
production well, fluid withdrawal rates are controlled to ensure the well
remains
submerged in bitumen and aqueous condensate. Submergence prevents the steam
that overlies the liquid zone from breaking through to the production well,
which can
short-circuit the SAGD process and potentially damage the wellbore. Moreover,
this
can lead to higher SOR and less efficient bitumen recovery. In certain
instances,
submergence is not achieved along the entire of length of the wellbore. This
may be
CA 02953352 2016-12-29
due to reservoir heterogeneity, such as pay, permeability or saturation
differences, and
wellbore hydraulic issues imposed by the trajectory or completion design.
[00128] A person of skill in the art would appreciate that different well
completions (also called a completion design) may be utilized to achieve
similar
results. Well completions in an injection well, a production well, or both an
injection
well and a production well may be modified one or more times during the
lifetime of a
well to improve aspects such as, but not limited to, steam chamber conformance
along
the length of a well (or well pair), NCG production rate, or oil production
rate.
[00129] As discussed above, a concomitant feature of a thermal recovery
process applied to oil sands is that non-condensing (or non-condensable) gases
are
evolved and created. Non-condensing gases (NCGs) refer to gaseous substances
with
relatively low condensation (boiling) points. As examples, under standard
conditions
methane condenses at -161 C and nitrogen condenses at -196 C. NCGs include,
but are not limited to air, nitrogen, nitrogen oxides such as nitrogen
dioxide, carbon
monoxide, carbon dioxide, hydrogen sulfide, sulfur oxides such as sulfur
dioxide,
methane, and other light hydrocarbons.
[00130] In a typical implementation of SAGD, there are a number of sources
of
NCGs within the steam chamber. One source is the evolution of solution gas
dissolved
in the bitumen. As the bitumen is heated, the solubility of the gas decreases
as it
becomes energized, resulting in its evolution from the bitumen into the steam
chamber. A second major source involves the production of NCGs from reactions
taking place between water and organic compounds at elevated temperatures and
pressures. This process can for example include bitumen thermal cracking at
elevated
temperatures or low temperature oxidation. Other minor sources of NCGs may
include
the co-injection of gases with steam, for example as may be undertaken in
order to
prevent steam hammer or for the purpose of using the NCGs to facilitate
measurements of the steam chamber pressure.
[00131] As explained above, NCGs tend to have low molar masses and
therefore
tend to be light and buoyant. As a result, any NCG that is liberated or
generated lower
26
CA 02953352 2016-12-29
in the steam chamber will tend to rise to a higher part of the steam chamber,
and any
NCG produced or released higher in the steam chamber will tend to remain in
the
upper elevations of the steam chamber.
[00132] As steam is continuously injected and flows outwardly toward the
bituminous sands where it condenses, the steam effectively drags the NCGs with
it.
The NCGs generally having much greater vapour pressures compared to steam at
lower temperatures, and being non-condensing, tend to accumulate at the steam
front
along the steam chamber perimeters or walls. Over time, this accumulation of
NCGs
results in the formation of an insulating layer or blanket at the top of the
steam
chamber, reducing efficient contact between the hot steam and the colder
bitumen
surface. The insulating layer thus provides resistance to heat flow from steam
to
reservoir, impeding steam chamber expansion and ultimately jeopardizing
production
performance of the in-situ process.
[00133] FIG. 1 schematically illustrates a typical SAGD arrangement 100 in
a
reservoir 112 of bituminous sands. SAGD arrangement 100 includes a well pair,
injection well 118 and production well 120. It can be understood that
reservoir 112 is
serviced by injection well 118 and production well 120, which mediate fluid
communication between reservoir 112 and a surface completion.
[00134] In a typical SAGD operation, fluid communication between injection
well
118 and production well 120 is established (known as the start-up stage)
before
normal oil production begins. During oil production, in cases where only steam
is used,
steam is injected into reservoir 112 through injection well 118. The injected
steam
heats up the reservoir formation, softens or mobilizes the bitumen in a region
in the
reservoir 112 and lowers bitumen viscosity such that the mobilized bitumen can
flow.
As heat is transferred to the bituminous sands, steam condenses and a fluid
mixture
containing aqueous condensate and mobilized bitumen (oil) forms. The fluid
mixture
drains downward due to gravity, and a porous region 130, referred to as the
"steam
chamber," is formed in reservoir 112.
27
CA 02953352 2016-12-29
[00135] In an embodiment as illustrated in FIG. 1, a convection-enhancing
agent
124 is co-injected with steam 116 into steam chamber 130 through injection
well 118.
The injected steam 116 mobilizes the bitumen in reservoir 112. As a result, a
reservoir
fluid 114 comprising oil 122 and condensed steam (water) is formed in steam
chamber
130. In selected embodiments, at least a portion of the condensed CEA 124 may
dissolve in the reservoir fluid 114, which may also assist in mobilizing the
bitumen.
Fluid 114 is drained by gravity along the edge of steam chamber 130 into
production
well 120 for recovery of oil 122.
[00136] The CEA 124 may be in the form of a solid, liquid, gas, liquid-
vapour
mixture, or an aqueous solution prior to mixing with the steam 116. The heat
from the
steam will vapourize at least a portion of the CEA if it is not already
vapourized. As a
portion of the convection-enhancing agent 124 will remain in the gas phase,
when the
CEA cools near the edge of steam chamber 130 the gas phase density will
increase
and the CEA will descend towards the bottom of steam chamber 130, resulting in
convection of gases and particularly a descending flow of gases. This
descending flow
carries or drags with it some NCGs, such as methane, towards production well
120
and the NCGs can be conveniently removed through production well 120.
[00137] A suitable convection-enhancing agent may comprise at least one
non-
polar organic molecule. The suitable convection-enhancing agent may be
selected to
increase the overall density of the gaseous phase in the reservoir, such that
it may
enhance the removal of NCGs from the reservoir. In selected embodiments, the
convection-enhancing agent has a molar mass higher than the molar mass of
steam
and at least one of the NCGs, such as methane, to be removed.
[00138] A person skilled in the art would appreciate that if, at a given
instant, the
pressure and temperature in a region are constant, then the density of the gas
phase
in the region is directly proportional to the molar mass of the gas molecules
in the gas
phase. According to the ideal gas law, the density (p) of a gas can be
calculated as:
p = p* MM / (RT).
28
CA 02953352 2016-12-29
where P is pressure, MM is molar mass and T is temperature. In some
embodiments,
the NCGs in the steam chamber include mainly methane. Steam and methane have
similar molar masses, being 18 g/mol and 16 g/mol respectively. Thus, at the
same
temperature and pressure, methane has a density similar to that of steam.
[00139] Therefore, a convection-enhancing agent may be selected that has a
molar mass greater than methane to increase the resultant gas phase density.
The
resulting change in the gas density causes NCGs to be displaced away from the
top of
the steam chamber, thereby preventing formation of the insulating layer or
blanket.
Increasing gas phase density in the reservoir also directs the non-condensing
gas
away from the front of the steam chamber and towards a production well, which
may
help prevent steam loss, oil loss, or both steam loss and oil loss to a thief
zone, for
example, bottom water, below the production well.
[00140] A suitable convection-enhancing agent should be sufficiently
volatile so
that the convection-enhancing agent can be vapourized by heating (by steam)
under
reservoir operating conditions and the convection-enhancing agent vapour can
ascend
within a mobile zone of the reservoir. The CEA may be a vapour prior to mixing
with
steam. Upon rising within the mobile zone, the convection-enhancing agent may
cool
and become denser. A suitable CEA also has a low enough volatility so that the
CEA
is condensable at a lower temperature zone in the reservoir, and the condensed
CEA
should be sufficiently miscible with oil or bitumen or sufficiently soluble in
oil. The CEA
may be selected to prevent formation of an insulating blanket by NCGs that
would
hinder heat transfer from the steam to the hydrocarbons in the reservoir. In
some
embodiments, the convection-enhancing agent may have a boiling point that is
less
than the boiling point of water, but significantly higher the boiling point of
methane,
under the steam injection conditions, such that the CEA is sufficiently
volatile to rise up
with the injected steam in vapour form when penetrating the steam chamber, and
can
then condense at the edge or front of the steam chamber.
[00141] The front of the steam chamber is typically at a lower
temperature, such
as at about 12 to 150 C, as compared to the temperature at the center of the
steam
29
CA 02953352 2016-12-29
chamber or near the injection well. The condensed convection-enhancing agent
may
be soluble in or miscible with the hydrocarbons in the reservoir fluid, so as
to increase
the drainage rate of the hydrocarbons in the fluid through the reservoir
formation.
[00142] As is known to those skilled in the art, with a gravity-dominated
process,
such as SAGD, a start-up process is required to establish communication
between the
injector and producer wells. A skilled person is aware of various techniques
for start-up
processes, such as for example hot fluid wellbore circulation, the use of
selected
solvents such as xylene (as for example described in CA 2,698,898 to Pugh, et
al.),
the application of geomechanical techniques such as dilation (as for example
described in CA 2,757,125 to Abbate, etal.), or the use of one or more
microorganisms to increase overall fluid mobility in a near-wellbore region in
an oil
sands reservoir (as for example in CA 2,831,928 to Bracho Dominguez, et al.).
[00143] Even if there is minimal NCG accumulation during SAGD start-up,
CEA
injection may be beneficial during SAGD start-up in some situations due to
other
beneficial effects of the particular CEA used, for example, the effect of
aiding bitumen
viscosity reduction and improving fluid mobility between the injection well
and
production well of a SAGD well pair.
[00144] A suitable convection-enhancing agent may comprise at least one
organic molecule. The organic molecule may be polar or non-polar.
Conveniently, the
aqueous phase of the fluids produced from the reservoir, which may include
aqueous
condensate formed in the reservoir, may contain a suitable polar CEA, and the
polar
CEA may be separated from the aqueous condensate and re-used for co-injection
into
the reservoir. In contrast, while the oil phase of the fluids produced from
the reservoir
may contain a non-polar CEA, it may be more difficult to separate the non-
polar CEA
from the oil phase. A polar CEA may also be useful during treatment of a water-
oil
emulsion in terms of reversing a water-in-oil to an oil-in-water emulsion,
which may be
separated more easily.
[00145] In selected embodiments, the convection-enhancing agent may be
used
to assist removal of NCGs and increase mobility of oil or the reservoir fluid
in the
CA 02953352 2016-12-29
reservoir, thus accelerating heat transfer and fluid flow from the steam
chamber to the
production well, as compared to a typical SAGD operation where only steam is
used.
[00146] A common consideration for selecting the suitable convection-
enhancing
agent is cost versus benefits. When multiple CEAs are potentially suitable
from the
technical perspectives, the final selection may be based on performance,
economic
analysis, and other practical considerations.
[00147] It should be noted that in the context of this disclosure, the
terms "light",
"lighter", "heavy", or "heavier" refer to the relative molar mass of the
compared gas
molecules.
[00148] As is typical, the injection and production wells may have terminal
sections that are substantially horizontal and substantially parallel to one
another. A
person of skill in the art will appreciate that while there may be some
variation in the
vertical or lateral trajectory of the injection or production wells, causing
increased or
decreased separation between the welts, such wells for the purpose of this
application
will still be considered substantially horizontal and substantially parallel
to one another.
Spacing, both vertical and lateral, between injectors and producers may be
optimized
for establishing start-up or based on reservoir conditions.
[00149] At the point of injection into the formation, or in the injection
well 118, the
injected steam may be at a temperature from about 152 C to about 286 C or
about
328 C, and at a pressure from about 0.5 MPa to about 12.5 MPa. These
conditions
may be collectively referred to as steam injection conditions. A person
skilled in the art
will appreciate that steam injection conditions may vary in different
embodiments
depending on, for example, the type of hydrocarbon recovery process
implemented
(e.g., SAGD, CSS) or the convection-enhancing agent selected.
[00150] However, once the steam enters the reservoir, its temperature and
pressure may drop under the reservoir conditions. The reservoir temperature
will
become colder in regions further away from injection well 118. Typically,
during SAGD
operations, the reservoir conditions may vary. For example, the reservoir
temperature
31
CA 02953352 2016-12-29
may vary from about 10 C to about 235 C, or up to 328 C, and the reservoir
pressure may vary from about 0.5 MPa to about 3 MPa, or up to 12.5 MPa,
depending
on the stage of operation. The reservoir conditions may vary in different
embodiments.
[00151] As noted above, steam condenses in the reservoir and mixes with
the
mobilized bitumen to form reservoir fluids. It is expected that in a typical
reservoir
subjected to steam injection, the reservoir fluids include a stream of aqueous
condensate and water originally present in the reservoir (or water, may also
be
referred to as water stream herein). The water stream may flow at a faster
rate
(referred to as the water flow rate herein) than a stream of mobilized bitumen
containing oil (referred to as the oil stream herein), which may flow at a
slower rate
(referred to as the oil flow rate herein). The reservoir fluids can be drained
to the
production well by gravity. The mobilized bitumen may still be substantially
more
viscous than water, and may drain at a relatively low rate if only steam is
injected into
the reservoir.
[00152] A suitable CEA is delivered to the steam chamber 130 in addition
to the
steam, and at least a portion of the CEA will remain in the gas phase to
promote
convection of gases away from the steam front before being condensed,
dispersed,
and mixed with the reservoir fluid. A plurality of CEAs may be co-injected
with steam,
for example, a plurality of CEAs may comprise propane and butane.
[00153] It is expected that delivery of the CEA to steam chamber 130 may
assist
removal of NCGs from the steam chamber, and may optionally result in increased
fluid
flow rate and drainage rate of the oil stream, which may lead to improved oil
production performance, such as increased oil production rate, reduced
cumulative
steam to oil ratio (CSOR), or improved overall hydrocarbon recovery factor.
[00154] The CEA may be heated. The CEA may be heated due to co-injection
with steam, as the injected steam is at a relatively high temperature. As
such, it is not
necessary to separately heat the CEA before injection into the injection well
118. The
CEA may be provided or distributed to one or more well pads or injection wells
from a
central facility, source, or pad, or from various facilities, sources or pads,
for example,
32
CA 02953352 2016-12-29
by way of a pipeline. The CEA may be provided or distributed to one or more
well pads
or injection wells in an aqueous fluid at a concentration higher than the
intended co-
injection concentration, even up to 100% CEA. The CEA fluid may be diluted
with
steam at the one or more well pads or injection wells to provide the CEA at
the desired
concentration of about 0.1 wt% to about 10 wt% of steam for injection into the
reservoir.
[00155] The timing for commencing co-injection of the CEA may depend on
various factors and considerations. Co-injection may start early in the
production stage
such as when the fluid/oil production has commenced or when the steam chamber
has
started to form and grow, but if the benefit of NCG removal at this stage is
not
significant enough to off-set the costs of co-injecting CEA, co-injection may
be delayed
until it becomes more economical.
[00156] For example, in selected embodiments, co-injection of CEA may
commence at the ramp-up stage, coinciding with the start of oil production or
immediately after the steam chamber has formed and started to grow.
[00157] One or more CEAs may be delivered to one or more wells at
different
times. For example, in selected embodiments, co-injection of a first CEA may
commence at an initial time at one or more injection wells at a well pad or in
a well
pattern and then co-injection of the same or a different CEA may commence at a
later
time at one or more other injection wells at the well pad or in the well
pattern. The
difference between the initial and later time may be from days to years
depending on,
for example, the particular well pad, well pattern, reservoir, one or more
CEAs, or a
combination thereof.
[00158] As noted earlier, co-injection of CEA at a low concentration, such
as up
to 3 wt% during an early stage or stages of oil production or steam chamber
growth,
can be expected to effectively remove NCGs or reduce NCG accumulation at the
steam front, which can result in better chamber conformance. When the steam
chamber has grown to a certain extent, such as when the steam chambers at
adjacent
SAGD well pairs have coalesced, further CEA co-injection may become less
effective
33
CA 02953352 2016-12-29
for NCG removal and less economical. As an example, when the adjacent well
pairs
are spaced apart by about 100 m, the adjacent steam chambers may coalesce
after
about 3 years of oil production. However, it should be understood that the
exact timing
of chamber coalescence may vary depending on the well design and other
reservoir
properties or factors.
[00159] After the fluid 114 is removed from the reservoir, produced water,
and
optionally any condensed CEA, may be separated from oil in the produced fluids
by a
method known in the art depending on the particular organic molecule(s) used.
The
separated water and CEA can be further processed by known methods, and
recycled,
heating as needed, to provide steam and CEA at the injection well 118.
[00160] In some embodiments, the CEA may be separated from the produced
water before further treatment, re-injection into the reservoir or disposal.
In some
embodiments, ease of handling and recovery in the liquid phase at surface
conditions
may be a consideration for selecting a suitable CEA.
[00161] In various embodiments, the co-injection of CEA may include a
selected
injection pattern. For example, the co-injection pattern may include
simultaneous
injection with the steam, alternate injection of steam and CEA at different
times (in
which case, the CEA may be separately heated), staged (e.g., sequential)
injection at
selected time intervals, or injection at selected locations within the SAGD
operation
(e.g., across multiple well pairs in a SAGD well pad). The co-injection may be
performed in various regions of a well pad, or at multiple well pads to create
a target
injection pattern to achieve target results at a particular location of the
pad or pads. In
various embodiments, the co-injection may be continuous or periodic. The co-
injection
may be performed through an injection well (e.g., injection well 118), and may
involve
injection at various intervals along a length of the well.
[00162] The CEA should be suitable for use under SAGD operating
conditions,
which include certain temperatures, pressures and chemical environments. For
example, in various embodiments, the CEA may be selected such that it is
chemically
34
CA 02953352 2016-12-29
stable under the reservoir conditions and the steam injection conditions and
therefore
can remain effective after being injected into the steam chamber.
[00163] While some examples herein are discussed with regard to SAGD
operations, it can be appreciated that a CEA may be similarly used in another
steam-
assisted recovery process such as CSS.
[00164] In a CSS operation, a single well may be used to alternately inject
steam
into the reservoir and produce the fluid from the reservoir. The single well
may have a
substantially horizontal or vertical section in fluid communication with the
reservoir.
The single well may be used in a cyclic steam recovery process. With the use
of the
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
about 3.0 MPa to about 12.5 MPa.
[00165] In embodiments of the present disclosure, a single well may be used
to
form and expand the steam chamber and to produce oil and remove NCGs. In such
an
embodiment, and in other embodiments where multiple wells are used, a single
well
may be configured for injection and may be configured for production. The well
may be
reconfigurable repeatedly, to be used alternately as an injection well and a
production
well. The well(s) used in embodiments of the present disclosure may include
horizontal
wells, vertical wells, or directional wells (drilled by directional drilling),
or a combination
thereof. Therefore, it should be understood that a well is configurable for
injection or
production if the well can be alternatively configured to function as an
injection well or
as a production well. In some cases, a well may be completed for only
injection, and
another well may be completed for only production. In some embodiments, a well
may
have a first section completed for injection and a second section completed
for
production. In different well arrangements, three or more wells may be used to
service
one reservoir formation, and may be in fluid communication with the same steam
chamber.
[00166] When selecting the suitable organic molecules, the information and
test
results included in the Examples to this disclosure may be considered. It may
be
CA 02953352 2016-12-29
beneficial to select a compound that not only can enhance convection of gases
in the
steam chamber but also can dissolve in the reservoir fluid to increase the
mobility of oil
in the region. 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 oil may be increased
when the
oil becomes easier to detach from the sand it is attached to, or when the oil
has
become mobile, even if its viscosity or flow rate remains the same. The
mobility of oil
may also be increased when its viscosity is decreased or when its effective
permeability through the bituminous sands is increased.
[00167] A skilled person may appreciate that the gas phase density in the
steam
chamber can continue to increase as the temperature decreases, until the
saturation
point of the CEA is reached, after which, the equilibrium balance favours CEA
being
dissolved in the oleic or aqueous phase.
[00168] Using CEA to assist removal of NCGs from the steam chamber through
a
production well located at or near the bottom of the steam chamber can also
have the
added effect and benefit of mitigating oil loss to a bottom water zone below
the
production well. Density and viscosity reduction can be expected to reduce
heat
penetration ahead of the steam chamber front.
[00169] Some steam might be removed with NCGs and other gases due to
increased convection flow of gases. However, the effect of such loss of steam
would
be off-set by other beneficial effects of a suitable co-injected CEA.
[00170] Other possible modifications and variations to the examples
discussed
above are also possible.
EXAMPLES
[00171] Example 1 ¨ Live Oil Simulations
36
CA 02953352 2016-12-29
[00172] A live oil simulation study was conducted to understand the NCG
behavior with and without CEA co-injection in a SAGD process. A typical
Christina
Lake homogenous simulation was used to model SAGD with CEA injection
processes.
Hot zone was used to simulate a start-up phase, but a blowdown phase was not
considered in the simulations. The term "live oil" refers to bitumen saturated
with
methane at native reservoir conditions.
[00173] The simulation modeled a SAGD well pair in a homogeneous reservoir
using a half element of symmetry along the x-axis. The model included an
overburden
and underburden which allowed for heat losses via conduction.
[00174] In accordance with various aspects of the disclosure, detailed
computational simulations of reservoir behaviour were carried out. For
purposes of
illustrating embodiments described herein, a 'base case' model was
constructed. For
purposes of illustrating alternative embodiments, slight modifications to the
base case
(primarily with respect to the selected CEA and wt% of the CEA with respect to
steam)
were made when constructing the other models.
[00175] The modelled reservoir was divided into a grid of 26 x-axis units,
16 y-
axis units, and 28 z-axis units. Each of the x-axis units 1 and 26 had a
length of 1 m
and each of the x-axis units 2-25 had a length of 2 m for a total x-axis
length of 50 m.
Each of the 16 y-axis units had a length of 50 m. Each of the 28 z-axis units
had a
length of 1 m. The x-axis, y-axis, and z-axis represented directions into the
plane of
the page, along the plane of the page, and parallel to the plane of the page,
respectively.
[00176] The following completion design was used in the simulations: three
steam splitters in the injector: 8-hole at 150 m, 12-hole at 350 m and 32-hole
at 600 m;
injection and production casing with outer and inner diameters of 177.8 mm and
159.4
mm, respectively; injection tubing with outer and inner diameters of 134.3 mm
and
100.5 mm, respectively; no production tubing was used.
37
CA 02953352 2016-12-29
[00177] The oil, methane and reservoir properties used in the simulation
were
typical for Athabasca bitumen and the Christina Lake reservoir located in
Northern
Alberta, Canada, and some of the key properties are listed in Table I.
[00178] Injection pressure was controlled at 2.6 MPa and the producer
(production well) was controlled to have an overall gas production rate of 15
t/d (half-
model) in the simulations. Injection of a low concentration of CEA (1 wt% - 5
wt %)
commenced after six months of standard SAGD operation, which served to provide
the
baseline. The Athabasca reservoir has small amounts of initial gas dissolved
in the
bitumen (¨ 15-20 mole %), and this was simulated in the model.
Table I. Simulation Reservoir Properties
Property Value Units
Solid Sand N/A
Initial reservoir temperature 12 C
Initial reservoir pressure 2.35 MPa
Initial water saturation 0.2 N/A
Initial oil saturation 0.8 N/A
Initial methane fraction in oil 16 Mol%
Horizontal hydraulic permeability (KO 6
Vertical hydraulic permeability (Kv) 4.2
Steam chamber porosity 0.34 N/A
[00179] FIG. 2 shows the steam distribution along the length of the well
in x-z
plane. The gas saturation in the reservoir after 2.1 years of SAGD operation
is shown
to illustrate the steam chamber development. The vertical and horizontal steam
chamber growth in the steam chamber is shown.
38
CA 02953352 2016-12-29
[00180] When steam was injected to heat the formation, some dissolved
methane also came out of the liquid phase.
[00181] FIG. 3 shows methane accumulation along the steam chamber wall
after
2.1 years of SAGD operation. The results indicated that methane, being
lighter, rose to
the top of the steam chamber and tried to achieve equilibrium along the edges
of the
steam chamber ahead of the steam front.
[00182] FIG. 4 shows the increased methane volume along the steam chamber
after 4.7 years of SAGD operation.
[00183] Comparing Figures 3 and 4, it is evident that methane accumulation
increased with time. The accumulated methane, which is non-condensable, would
impede further steam chamber development. It formed a layer of insulation,
which
provided resistance to heat flow from steam to reservoir, eventually
jeopardizing the
ultimate recovery. Overall methane removal (also referred to as methane
production or
methane recovery) at the end of eight years of operation was 38.5%.
[00184] The effect and impact on methane distribution/accumulation by co-
injection of 5 wt% of propane after 4.9 years of SAGD operation is shown in
FIGS. 5A
and 5B. The results indicate that with added propane in the gas phase, the gas
phase
density was increased and this appears to have improved gas removal from the
steam
chamber.
[00185] With even just 1 wt% propane co-injection, the cumulative methane
removal was 68.3 %, much higher than 38.5 % with pure steam injection.
[00186] The test results, including representative results shown in FIGS.
5A and
5B, indicate that propane injection at a lower concentration level can assist
methane
removal. In the case of pure steam injection, methane accumulation along the
lateral
edge of the steam chamber was relatively high, with local methane
concentration in
the range of 5 wt% to 60 wt%. With 5 wt% propane co-injection, the methane
concentration was reduced to about 5 wt % to 8 wt%, which was expected to
39
CA 02953352 2016-12-29
significantly improve heat transfer along the lateral edge of the steam
chamber and
reduce steam usage. Advantageously, propane injection could also improve oil
production rates and the cumulative steam to oil ratio (CSOR) (as illustrated
further
and in Table ll below).
[00187] FIG. 6 is a plot of the oil production rates (half model) for
different
simulation scenarios. Co-injection of butane (at 5 wt%) resulted in the
highest uplift in
the oil rates. FIG. 7 is a plot of bitumen recovery factor (%) versus time for
various
CEA co-injection scenarios. FIG. 8 is a plot of methane removal rates (half-
model) in
t/d versus time for various CEA co-injection scenarios. FIG. 9 is a plot of
methane
removal factor (%) versus time for various CEA co-injection scenarios. FIG. 10
is a
plot of CSOR versus time for various CEA co-injection scenarios.
[00188] The simulation results show that co-injection of propane at 1 wt%
concentration provided a 6 % cumulative uplift in oil production (FIG. 7) and
about
30% uplift in cumulative methane removal (FIG. 9). Co-injection of butane at 3
wt%
resulted in about 5 % incremental original oil in place (00IP) recovery in
comparison
to co-injection of propane at 3 wt%.
[00189] As can be seen from FIG. 8, methane removal can be improved with
CEA co-injection as compared to pure steam injection. This is confirmed by the
impact
on cumulative methane removal factor shown in FIG. 9.
[00190] The simulation results show that CSOR reductions were significant
with
more than 3 wt% CEA injection (see e.g. FIG. 10). CEA injection at 5 wt%
resulted in
about 10 % to 12 % reduction in CSOR for each of propane, butane, or a mixture
of
propane and butane (hybrid CEA).
[00191] Simulation tests show that CEA co-injection can assist in methane
removal by increasing the overall density of the gaseous phase, and hence
descending convection flow of gases in the steam chamber. For a given amount
of
methane recovered, about 98% is expected to be removed in the gaseous phase,
and
the remaining 2% in the liquid phase at bottom hole conditions (P = ¨ 1.8 ¨
2.1 MPa
CA 02953352 2016-12-29
and T = ¨ 160 ¨ 180 C). Under other conditions, all methane may flash and be
produced to surface in the gas phase, for example, via a casing line when
emulsion is
produced from the reservoir using a pump, for example, an electrical
submersible
pump (ESP). Without being limited to any particular theory, it can be expected
that the
injected CEA, which was denser and less volatile than steam, would drag some
of the
methane with it when it descended in the steam chamber and condensed into the
liquid phase. Therefore, with CEA co-injection a small amount of methane was
removed in the liquid phase. Increasing the concentration of co-injected CEA
in the
injection stream (from example from 1 wt% propane to 3 wt% propane) increased
the
cumulative bitumen recovery by 5 % to 7% (see FIG. 7).
[00192] Example 2 ¨ Live Oil Simulations
[00193] Additional simulations were performed with co-injection of the
following
CEAs, each at a concentration of 2, 5, and 10 wt% of steam: n-propylamine,
ammonia,
formaldehyde, dipropyl ether, sodium propanolate, propyl ethyl ether, 1,5-
pentane diol,
dimethyl ether, tetrahydrofuran, toluene, glycerin and butane. SAGD conditions
were
used as a baseline from which to compare the simulations with CEAs. The same
methodology, reservoir properties and conditions were used as described in
Example
1 above.
[00194] Representative simulation results are shown in FIGS. 11, 12, 13,
14, and
15, illustrating the expected impact of various potential CEAs on bitumen
production
rate, bitumen recovery factor, methane removal rate, methane removal factor,
and
CSOR respectively.
[00195] FIG. 11 shows bitumen production rate (half model) vs. time for
different
polar and non-polar compounds at weight fractions of 2 wt%, 5 wt% and 10 wt%.
Acceleration of bitumen production can be seen from the co-injection of CEAs
with
superior performance compared to SAGD.
[00196] FIG. 12 shows cumulative bitumen recovered vs. time for different
polar
and non-polar compounds at weight fractions of 2 wt%, 5 wt% and 10 wt%. FIG.
12
41
CA 02953352 2016-12-29
shows that co-injecting ammonia or glycerin resulted in inferior performance
compared
to SAGD and these molecules may not act as preferred CEAs in comparison to
other
compounds.
[00197] FIG. 13 shows methane production rate (half model) vs. time for
different
polar and non-polar compounds at weight fractions of 2 wt%, 5 wt% and 10 wt%.
Increased methane production can be seen upon CEA injection resulting in
formation
of a dense gas phase.
[00198] FIG. 14 shows cumulative methane recovered vs. time for different
polar
and non-polar compounds at weight fractions of 2 wt%, 5 wt% and 10 wt%. The
higher
the methane recovery, the more efficient the volumetric sweep due to better
convection of gases along the length of the well.
[00199] FIG. 15 shows cumulative steam to oil ratio (CSOR) vs. time for
different
polar and non-polar compounds at weight fractions of 2 wt%, 5 wt% and 10 wt%.
A
lower CSOR is an indicator of a more efficient oil recovery process.
[00200] The effect of the presence of gas phase CEA in the steam chamber
on
CSOR can also be understood based on the fact that less steam would be
required
when a portion of the gas phase volume in the steam chamber is occupied by a
CEA
which has a higher molar mass and gas phase density than steam. For instance,
according to the ideal gas law, the densities of steam, propane and butane at
two
different temperature/pressure conditions are as listed in Table II.
Table II. Density Comparison
Density at Density at
Molecule
101.325 kPa, 15.5 C 2600 kPa, 225 C
Steam 0.76 11.30
Propane 1.86 27.62
Butane 2.45 36.41
42
CA 02953352 2016-12-29
[00201] Assuming a sample pore block with a volume of 1 m3, from Table II
it can
be seen that propane occupies 2.5 times more spatial volume than steam, and
butane
occupies almost 3 times more spatial volume than steam. Thus, injection of
propane,
butane, or propane and butane is expected to improve CSOR.
[00202] From the simulation results it may be expected that the CEA would
be
ahead of the steam front. That is, the gas volume in which gas phase density
is
increased and methane is accumulated is ahead of the steam front.
[00203] FIGS. 17A to 17E show simulated development of gas phase in a SAGD
steam chamber in different situations. FIG. 17A shows the gas phase
distribution in
the steam chamber without any injected CEA. FIG. 17C shows the gas phase in
the
steam chamber with injected CEA. As can be seen, the gas phase in FIG. 17A was
not
as well developed as in FIG.17C. FIG. 17B shows a higher percentage of NCGs
(represented by the darker regions) with no CEA injection, as compared to FIG.
17D
which shows a percentage of NCGs with CEA injection because in the latter case
at
least a portion of NCGs were more readily removed. FIG. 17E indicates that the
gas
phase CEA is positioned ahead of the steam front.
[00204] FIG. 18 is a plot of well performance CSOR as a function of
methane
recovery factor. With CEA injection, methane removal increased and CSOR
decreased
as a higher amount of oil was produced.
[00205] FIG. 19 is a plot of well performance CSOR as a function of
bitumen
recovery factor. With CEA injection, methane recovery increased and CSOR
decreased as a higher amount of oil was produced. With 1 % CEA injection, CSOR
was almost the same as the base case of SAGD and there was about a 6-7%
increase
in bitumen recovery factor. Any weight percentage higher than 1 wt%
contributed more
significantly to CSOR reduction as well as uplift in bitumen recovery factor.
[00206] Example 3 ¨ Live Oil Simulations
43
CA 02953352 2016-12-29
[00207] A further simulation study was conducted that was similar to the
study
discussed in Example 1 and included the following simulation parameters.
[00208] The simulated formation initially had at least 75% oil saturation
(see
Table III for range). A vertical permeability barrier (clasts) was positioned
along the x-
and y-axes. The barrier was varied along the z-axis and positioned 12 m above
the
heel, 9 m above the mid-section, and 16 m above the toe of the injector. The
clast
permeability was 0 D, 0 D and 0.02 D along the x-, y-, and z-axes,
respectively. The
initial formation temperature was 12.0 C and initial formation pressure was
3.0 MPa.
The dissolved solution gas was 16%.
[00209] The modelled reservoir was divided into a grid of 51 x-axis units,
12 y-
axis units, and 32 z-axis units. Each of the x-axis units 1 and 51 had a
length of 0.5 m
and each of the x-axis units 2-50 had a length of 1 m for a total x-axis
length of 50 m.
Each of the 12 y-axis units had a length of 50 m. Each of the 32 z-axis units
had a
length of 1 m.
[00210] A different completion design was used in the simulations. The
injection
pressure was controlled to be at 3.1 MPa. The production rate was controlled
at a gas
rate of 10 t/d (half element of symmetry).
[00211] The oil, methane and reservoir properties used in the simulation
were
typical for Athabasca bitumen and are listed in Table III.
[00212] Injection of different concentrations of CEA (1 wt% - 20 wt %) was
simulated, commencing at different times/stages in a SAGD operation. As in
Example
1, a standard SAGD process without CEA co-injection was used to provide the
baseline reference.
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Table III. Simulation Reservoir Properties
Property Value Units
Solid Sand N/A
Initial Reservoir Temperature 12 C
Initial Reservoir Pressure 3 MPa
Initial Water Saturation 0.20-0.25 N/A
Initial Oil Saturation 0.75-0.80 N/A
Initial Methane Fraction in Oil 16 Mol%
Horizontal hydraulic 0-6
permeability (KH)
Vertical hydraulic permeability 0-5
(Kv)
Porosity 0-0.33 N/A
Solvent injection 3-20 wt%
Pay thickness 15-20
[00213] FIG. 20 shows the effects of propane injection at different
concentrations
on CSOR and oil recovery (indicated by bitumen recovery factor in percentage),
all
with co-injection of propane starting after 365 days of SAGD oil production
and
continuing for 2 years. FIG. 21 shows similar effects on CSOR and methane
removal
(indicated by methane recovery factor in percentage). The reference lines with
no
propane injection are labeled as "SAGD". As can be seen, the CSOR at the same
oil
recovery percentage is lower with increased propane injection. The maximum oil
recovery factor obtainable below CSOR of about 3.2 is significantly higher
with
propane injection, as compared to without propane injection, but is not
substantially
affected by the amount of propane injection within the range of 3 wt% to 20
wt%.
Similarly, the maximum methane recovery factor obtainable below CSOR of about
3.2
CA 02953352 2016-12-29
increases significantly with propane injection, but remains substantially
constant with 5
wt% to 20 wt% of propane injection.
[00214] FIG. 22 shows effects of propane injection at different
concentrations on
oil recovery (indicated by bitumen recovery factor in percentage), all with co-
injection
of propane starting after 365 days of SAGD production and continuing for 2
years. As
can be seen, the bitumen recovery factor increased more rapidly when propane
was
injected, as compared to without propane injection. However, the impact was
similar
in the range of 3 wt% to 20 wt% propane injection. FIG. 23 shows similar
effects on
the methane removal factor.
[00215] FIGS. 24A to 24F show methane distribution in the simulated
reservoir
along the length of the well in the x-z plane, after 365, 450, 550, 650, 730,
and 1,096
days of SAGD oil production operation, respectively, without propane
injection. FIGS.
25A to 25E show corresponding methane distribution but with 3 wt% propane co-
injection after 365 days of SAGD production. FIGS. 26A to 26E show
corresponding
methane distribution but with 5 wt% propane co-injection after 365 days of
SAGD
production. FIG. 27A to 27E show corresponding methane distribution but with
10 wt%
propane co-injection after 365 days of SAGD production.
[00216] FIGS. 28A to 31E are similar to FIGS. 24A to 27E but show methane
distribution along the length of the well in the y-z plane.
[00217] Example 4 ¨ Live Oil Simulations
[00218] A further simulation study was conducted that was similar to the
study
discussed in Example 3 and included the following simulation parameters.
[00219] A different completion design was used in the simulations and
modified
during the lifetime of the simulated well pair. Some of the effects observed
in the
simulated reservoir may be attributed to the completions modification.
[00220] Some of the key oil, methane and reservoir properties used in this
simulation study are listed in Table IV.
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Table IV. Simulation Reservoir Properties
Property Value Units
Solid Sand N/A
Initial Reservoir Temperature 12 C
Initial Reservoir Pressure 3 MPa
Initial Water Saturation 0.20 N/A
Initial Oil Saturation 0.80 N/A
Initial Methane Fraction in Oil 16 Mol%
Horizontal hydraulic 6
permeability (KH)
Vertical hydraulic permeability 5
(Kv)
Porosity 0.33 N/A
Solvent injection 1-5 wt%
Pay thickness 15
[00221] In this simulation study, propane was injected at the start of a
SAGD oil
production operation. Propane injection was terminated after 3 years of oil
production
in some cases, and after 10 years of oil production in other cases. The
propane
injection concentration was varied from 1 wt % to 5 wt%. A standard SAGD
operation
without propane injection was used as the baseline reference.
[00222] FIG. 32 shows effects of propane injection at different
concentrations and
for different periods of time on bitumen (oil) production rates over time with
co-injection
of propane commencing at the start of a SAGD production operation (i.e.
immediately
after communication or at the beginning of the ramp-up stage).
[00223] FIG. 33 shows a similar plot but for effects on bitumen recovery
factor
over time. As can be seen, propane injection improved bitumen production rate
and
bitumen recovery factor until about three years of oil production. After three
years, the
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oil production rates with propane injection were similar or below the
production rate
without propane injection. Further, the improvement in oil production rate was
similar
within the range of 1 wt% to 5 wt% propane injection. Continued propane
injection
after three years, up to 10 years, did not show significant impact on the oil
production
rate. Similarly, the impact on bitumen recovery factor also dropped
significantly after
three years of oil production.
[00224] FIGS. 34 and 35 show similar plots as FIGS. 32 and 33 but for
effects on
methane production rates (indicating the rates of methane removal from the
steam
chamber) and methane production factor (indicating overall percentage of
methane
removal from the steam chamber), respectively. As can be seen, propane
injection
improved the methane removal rate and the methane removal factor more
significantly
within the first three years of oil production. Increasing the amount of
propane injection
from 1 wt% to 3 wt% and then 5 wt% also had some additional effects. Continued
propane injection after three years also offered some limited additional
improvement.
[00225] FIGS. 36 and 37 show effects of propane injection at different
concentrations and for different periods of time on CSOR in relation to the
bitumen
recovery factor and the methane removal factor, respectively.
CONCLUDING REMARKS
[00226] Various changes and modifications not expressly discussed herein
may
be apparent and may be made by those skilled in the art based on the present
disclosure. For example, while a specific example is discussed above with
reference to
a SAGD process, some changes may be made when other recovery processes, such
as CSS, are used.
[00227] 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.
48
CA 02953352 2016-12-29
[00228] 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.
[00229] 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.
[00230] 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.
[00231] Of course, the above described embodiments of the invention are
intended to be illustrative only and in no way limiting. The described
embodiments of
the invention are susceptible to many modifications of form, arrangement of
parts,
details and order of operation. The invention, rather, is intended to
encompass all such
modification within its scope, as defined by the claims.
49
