Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
PROCESS FOR PRODUCING HYDROCARBONS FROM A SUBTERRANEAN
HYDROCARBON-BEARING FORMATION
Technical Field
[0001] The present invention relates to the production of hydrocarbons
such
as heavy oils and bitumen from a hydrocarbon-bearing formation utilizing a
single
well extending generally horizontally in the hydrocarbon-bearing formation.
Background
[0002] Extensive deposits of viscous hydrocarbons exist around the world,
including large deposits in the northern Alberta oil sands that are not
susceptible to
standard oil well production technologies. The hydrocarbons in reservoirs of
such
deposits are too viscous to flow at commercially relevant rates at the virgin
temperatures and pressures present in the reservoir. For such reservoirs,
thermal
techniques may be utilized to heat the reservoir to mobilize the hydrocarbons
and
produce the heated, mobilized hydrocarbons from wells. One such technique for
utilizing a horizontal well for injecting heated fluids and producing
hydrocarbons is
described in U.S. Patent No. 4,116,275, which also describes some of the
problems
associated with the production of mobilized viscous hydrocarbons from
horizontal
wells.
[0003] One thermal method of recovering viscous hydrocarbons utilizing
spaced horizontal wells is known as steam-assisted gravity drainage (SAGD). In
general, a SAGD process may be described as including three stages: the start-
up
stage; the production stage; and the wind-down (or blowdown) stage. The
production stage may be described as including further stages such as, for
example, a ramp-up stage and a plateau stage.
[0004] In the SAGD process, pressurized steam is delivered through an
upper,
horizontal, injection well (injector), into a viscous hydrocarbon reservoir
while
hydrocarbons are produced from a lower, parallel, horizontal, production well
(producer) that is near the injection well and is vertically spaced from the
injection
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well. The injection and production wells are situated in the lower portion of
the
reservoir, with the producer located close to the base of the hydrocarbon
reservoir
to collect the hydrocarbons that flow toward the base of the reservoir.
[0005] The SAGD process is understood to work as follows. The injected
steam initially mobilizes the hydrocarbons to create a steam chamber in the
reservoir around and above the horizontal injection well. The term steam
chamber
is utilized to refer to the volume of the reservoir that is saturated with
injected
steam and from which mobilized oil has at least partially drained. As the
steam
chamber expands, viscous hydrocarbons in the reservoir and water originally
present in the reservoir are heated and mobilized and move with aqueous
condensate, under the effect of gravity, toward the bottom of the steam
chamber.
The hydrocarbons, the water originally present, and the aqueous condensate are
typically referred to collectively as emulsion. The emulsion accumulates such
that
the liquid / vapor interface is located below the steam injector and above the
producer. The emulsion is collected and produced from the production well. The
produced emulsion is separated into dry oil for sales and produced water,
comprising the water originally present and the aqueous condensate.
[0006] With the complexity and cost of drilling associated with separate
injection and production wells, several approaches to recovery of viscous
hydrocarbons utilizing a single well have been proposed. Such approaches
include
both vertical single well recovery and horizontal single well recovery.
[0007] In such approaches, a mobilizing or displacement fluid, such as
steam
is utilized. For example, SAGD, or a cyclic steam simulation (CSS) approach in
which steam is injected and, after a soaking period, production of the
hydrocarbons
is carried out, may be utilized.
[0008] Hydrocarbons are commonly left unrecovered, resulting in
relatively
low recovery. The unrecovered hydrocarbons are due, at least in part, to the
difference in viscosity between the mobilizing or displacement fluid and the
oil.
Mobilizing or displacing of the more viscous oil, by the less viscous steam
tends to
promote non-uniform advance of the displacement front, including the
development
of channels or fingers, and consequent poor overall recovery. This non-
uniformity
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of displacement may be abetted by differences in density between the viscous
hydrocarbons and displacing fluids in situations where segregation of the
fluids due
to the influence of gravity is employed. Such non-uniformity adversely affects
recovery, particularly in a process in which the desired direction of
displacement is
horizontal. Non-uniform displacement resulting in poor recovery has made
recovery of hydrocarbons from thin formations, referred to as thin pay zones,
less
economically favourable or even unfavourable.
[0009] Improvements in recovery of hydrocarbons are desirable.
Summary
[0010] According to an aspect of an embodiment, a process is provided for
producing hydrocarbons from a hydrocarbon-bearing formation. The process
includes injecting mobilizing fluid into a single well that extends generally
horizontally in the hydrocarbon-bearing, from a heel to a toe, the single well
having
pipe sections coupled together and including a perforated first pipe section
having a
first inner diameter through which the mobilizing fluid is injected into the
hydrocarbon-bearing formation, a second pipe section coupled to the perforated
first pipe section and having a second inner diameter that is smaller than the
first
inner diameter, and a perforated third pipe section coupled to the second pipe
section and having third inner diameter that is larger than the second inner
diameter. Fluids are produced, including the mobilizing fluid and the
hydrocarbons
that flow through perforations in the perforated third pipe section and into
ports in
production tubing that extends through the pipe sections, from a location
proximal
the toe of the single well to a wellhead of the single well to provide
produced fluids
to the wellhead. The flow of the mobilizing fluid injected into the single
well is
restricted from passing from the perforated first pipe section into the second
pipe
section by the second inner diameter that is smaller than the first inner
diameter,
relative to an outer diameter of the production tubing.
[0011] According to another aspect of an embodiment, a system is provided
for producing hydrocarbons from a hydrocarbon-bearing formation. The system
includes a single well extending generally horizontally in the hydrocarbon-
bearing
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formation from a heel to a toe. The single well includes pipe sections coupled
together. The pipe sections include a perforated first pipe section having a
first
inner diameter for the injection of a mobilizing fluid into the hydrocarbon-
bearing
formation, a second pipe section coupled to the perforated first pipe section
and
having a second inner diameter that is smaller than the first inner diameter,
and a
perforated third pipe section coupled to the second pipe section and having a
third
inner diameter that is larger than the second inner diameter, to facilitate
flow of
fluids produced from the hydrocarbon-bearing formation into the third pipe
section.
The single well also includes production tubing extending from a top of the
single
well to a location proximal the toe of the single well, the production tubing
extending through the pipe sections, a portion of the production tubing within
the
perforated third pipe section including ports to facilitate the flow of the
fluids
produced from the hydrocarbon-bearing formation into the production tubing.
The
second inner diameter of the second pipe section is sized relative to an outer
diameter of the production tubing to inhibit flow of the mobilizing fluid from
the first
pipe section into the second pipe section.
Brief Description of the Drawings
[0012] Embodiments of the present invention will be described, by way of
example, with reference to the drawings and to the following description, in
which:
[0013] FIG. 1 is a schematic sectional view of a system including a
single well
in accordance with one example of the present invention;
[0014] FIG. 2 is a schematic sectional view through a portion of the
single
well in accordance with one example of the present invention;
[0015] FIG. 3 is a schematic sectional view through a portion of a single
well
in accordance with another example of the present invention;
[0016] FIG. 4 is a flowchart illustrating a process for producing
hydrocarbons
from a hydrocarbon bearing formation, in accordance with an aspect of the
present
invention;
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[0017] FIG. 5 is a graph showing corresponding temperatures and pressures
for suitable solvents for use in the process of FIG. 4;
[0018] FIG. 6 is a simulation diagram illustrating spread of propane in a
hydrocarbon-bearing formation after 480 days, according to one example of the
process of FIG. 4;
[0019] FIG. 7 is a graph illustrating production rate of oil and solvent
over
time utilizing the process of FIG. 4.
Detailed Description
[0020] For simplicity and clarity of illustration, reference numerals may
be
repeated among the figures to indicate corresponding or analogous elements.
Numerous details are set forth to provide an understanding of the examples
described herein. The examples may be practiced without these details. In
other
instances, well-known methods, procedures, and components are not described in
detail to avoid obscuring the examples described. The description is not to be
considered as limited to the scope of the examples described herein.
[0021] The disclosure generally relates to a system and a process for
producing hydrocarbons from a hydrocarbon-bearing formation. The process
includes injecting mobilizing fluid into a single well that extends generally
horizontally in the hydrocarbon-bearing, from a heel to a toe, the single well
having
pipe sections coupled together and including a perforated first pipe section
having a
first inner diameter through which the mobilizing fluid is injected into the
hydrocarbon-bearing formation, a second pipe section coupled to the perforated
first pipe section and having a second inner diameter that is smaller than the
first
inner diameter, and a perforated third pipe section coupled to the second pipe
section and having a third inner diameter that is larger than the second inner
diameter. Fluids are produced, including the mobilizing fluid and the
hydrocarbons
that flow through perforations in the perforated third pipe section and into
ports in
production tubing that extends through the pipe sections, from a location
proximal
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the toe of the single well to a wellhead of the single well to provide
produced fluids
to the wellhead. The flow of the mobilizing fluid injected into the single
well is
restricted from passing from the perforated first pipe section into the second
pipe
section by the second inner diameter that is smaller than the first inner
diameter,
relative to an outer diameter of the production tubing.
[0022] Referring first to FIG. 1, a schematic view of an example of a
system
100 including a single well 102 for use in the process for producing
hydrocarbons is
shown. The single well 102 includes a generally vertical portion 104 that
extends
from a wellhead 106 to a heel 108 and a generally horizontal portion 110 that
extends between the heel 108 and a toe 112. The system 100 also includes
recovery facilities, including a mobilizing fluid recovery facility 114 for
recovery of a
mobilizing fluid and recycling of the mobilizing fluid for re-injection into
the
hydrocarbon-bearing formation 116. In the example illustrated in FIG. 1, the
generally horizontal portion 110 of the single well 102 extends along a thin
hydrocarbon-bearing formation 116 of less than 20 meters in depth, referred to
as
a thin pay zone. The generally horizontal portion 110 of the single well 102
is
generally located in a lower portion of the hydrocarbon-bearing formation 116,
i.e.,
closer to a base than the top of the hydrocarbon-bearing formation, as
illustrated
for example in FIG. 1.
[0023] A sectional view of an example of a generally horizontal portion
110 of
a single well 102 is illustrated in FIG. 2. The single well 102 includes pipe
sections
coupled together. The pipe sections include a perforated first pipe section
220, a
second pipe section 222 coupled to the perforated first pipe section 220, and
a
perforated third pipe section 224 coupled to the second pipe section 222 and
that
has a third inner diameter.
[0024] Production tubing 226 extends from the wellhead (shown in FIG. 1),
through the perforated first pipe section 220 in the generally horizontal
portion 110,
the second pipe section 222, and the perforated third pipe section 224, to a
location
near the toe 112 of the single well 102. In the generally horizontal portion
110, the
production tubing 226 includes ports 228 through the sidewall to facilitate
the flow
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of fluids produced from the hydrocarbon-bearing formation, into the production
tubing 226.
[0025] The perforated first pipe section 220 has an internal diameter
that is
larger than the outer diameter of the production tubing 226 for the flow of
mobilizing fluid from the wellhead, through the first perforated pipe section
220,
and into the hydrocarbon-bearing formation via the perforations in the first
perforated pipe section 220. Thus, the perforated first pipe section 220 is
sized to
facilitate the flow of mobilizing fluid between the production tubing 226 and
the
perforated first pipe section 220.
[0026] The second pipe section 222 is coupled to the perforated first
pipe
section 220 and has an internal diameter that is close to that of the outer
diameter
of the production tubing 226 to inhibit the flow of the mobilizing fluid that
flows
through the perforated first pipe section 220, into the second pipe section
222. For
example, the internal diameter of the second pipe section 222 may be less than
about 5mm larger than the outer diameter of the production tubing 226. Thus,
the
internal diameter of the second pipe section 222 is sufficiently larger for
feeding the
production tubing 226 through the second pipe section 222, and is sufficiently
close
in size to the outer diameter of the production tubing 226 to restrict the
flow of
mobilizing fluid into the second pipe section 222.
[0027] The perforated third pipe section 224 is coupled to the second
pipe
section 222 and has an internal diameter that is larger than that of the
second pipe
section 222 to facilitate the flow of produced fluids, including the
mobilizing fluid
and the hydrocarbons, through perforations in the perforated third pipe
section 224
and to the production tubing 226.
[0028] Flow control devices 230 cooperate with the production tubing 226
to
control the flow of fluids produced from the hydrocarbon-bearing formation
into at
least some of the ports 228 in the production tubing 226. Thus, the flow
control
devices 230 are associated with the ports 228 in the production tubing 226 to
selectively open and close the associated ports in the production tubing 226.
[0029] Although the second pipe section 222 is depicted as being very
short
in the schematic illustration of FIG. 2, the second pipe section 222 may be
very
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long, for example 150 meters, to separate the perforated first pipe section
220
through which mobilizing fluid is injected into the hydrocarbon-bearing
formation,
from the perforated third pipe section 224 through which fluids from the
hydrocarbon-bearing formation flow into the production tubing 226. In one
example, the second pipe section 222 may be from about 10 meters to about 150
meters. A second pipe section length of less than about 10 meters, such as 2
meters, may also be successfully implemented. A length of 150 meters may be
made of multiple segments joined together, for example, each 10 meters in
length
such that 15 segments are joined to provide a second pipe section of 150
meters.
[0030] A sectional view of another example of a single well is shown in
FIG. 3.
As illustrated in FIG. 3, the length of the second pipe section 222 is longer
than that
shown in FIG. 2, for example, about 50 meters. Thus, the second pipe section
222
illustrated in FIG. 3 provides a greater separation between the perforated
first pipe
section 220 and the perforated third pipe section 224. The remaining elements
illustrated in FIG. 3 are similar to those described above with reference to
FIG. 2
and are not described again herein in detail.
[0031] A flowchart illustrating a process for producing hydrocarbons from
a
hydrocarbon bearing formation is illustrated in FIG. 4. The process may
contain
additional or fewer subprocesses than shown or described, and parts of the
process
may be performed in a different order.
[0032] A mobilizing fluid is injected at 402 via the single well 102. The
mobilizing fluid may be a solvent, for example, a solvent having 2 to 8 carbon
atoms per molecule, such as propane. The solvent is injected via a liner,
which
includes the pipe sections referred to above, such that the solvent travels
downhole
between the liner and the production tubing 226. The solvent enters the
perforated
first pipe section 220 and, because the inner diameter of the second pipe
section
222, to which the perforated first pipe section 220 is coupled, is much
smaller than
that of the perforated first pipe section 220, and is very close to the outer
diameter
of the production tubing 226, the flow of solvent is inhibited from entering
the
second pipe section 222. For example, the solvent flowing from the perforated
first
pipe section 220 directly into the second pipe section may be 5% or less of
the
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solvent that is injected. Thus, the restriction introduced by the smaller
diameter
second pipe section 222, by comparison to the perforated first pipe section
220,
forces the solvent out of the perforated first pipe section 220 through the
perforations, and into the hydrocarbon-bearing formation. Optionally steam may
be utilized to mobilize the fluid in addition to solvent or as an alternative
to the
solvent.
[0033] The solvent is injected in gaseous phase. Suitable solvents may
include C3 to C5 hydrocarbons such as, propane, butane, or pentane.
Additionally
or alternatively, a C6 hydrocarbon such as hexane may be utilized. A
combination
of solvents including C3-C6 hydrocarbons and one or more heavier hydrocarbons
may also be suitable in some embodiments. Solvents that are more volatile,
such
as those that are gaseous at standard temperature and pressure (STP), or
significantly more volatile than steam at reservoir conditions, such as
propane or
butane, or even methane, may be beneficial in some embodiments.
[0034] The properties and characteristics of various candidate solvents
are
utilized to identify and select a suitable solvent. For a given selected
solvent, the
corresponding operating parameters during co-injection of the solvent with
steam is
also selected or determined in view the properties and characteristics of the
selected solvent. In particular, the injection temperature is sufficiently
high and the
injection pressure is sufficiently low to ensure most of the solvent will be
injected in
the vapour phase into the vapour chamber. In this context, injection
temperature
and injection pressure refer to the temperature and pressure of the injected
fluid in
the injection well, respectively. The temperature and pressure of the injected
fluid
in the injection well may be controlled by adjusting the temperature and
pressure
of the fluid to be injected before it enters the injection well. The injection
temperature, injection pressure, or both, may be selected to ensure that the
solvent is in the gas phase upon injection from the injection well into the
vapour
chamber.
[0035] The mobilizing fluid utilized may be dependent on reservoir. For
example, in relatively thin hydrocarbon-bearing formations, a "washing effect"
of
bitumen may play a role. This "washing effect" relates to injection of solvent
in
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liquid phase or injection of solvent in the transitional phase from gas to
liquid. In
this case, the solubility of the injected solvent in oil is relatively fast
compared to
solvent injected in high temperature gaseous phase conditions. For example, at
3000 kPa solvent butane may be injected at 200 C or into a 200 C steam
chamber,
yielding a continuous gaseous phase until the solvent cools to about 125 C.
The
"washing effect" occurs in situations in which solvent butane is injected at
150 C or
into a 150 C steam chamber, resulting in gaseous injection and quick or almost
immediate transition of the solvent to the liquid or oleic phase. Such a
process may
be beneficial in inhibiting or reducing solvent losses to gaseous overburdens
by the
introduction of the solvent in the liquid phase or transitional phase.
Additionally, the
solubility of the solvent in oil may advance viscosity reduction, oil
upgrading and
increased rate of recovery of the solvent. A temperature of the solvent of at
least
60 C is utilized to reduce the viscosity of the oil to advance its flow. With
greater
formation heights, more gaseous mobilizing fluid may be utilized to recover
the oil
in the higher areas.
[0036] A graph showing corresponding temperatures and pressures for
suitable solvents is illustrated in FIG. 5. Suitable injection pressures and
corresponding temperatures are identifiable from the graph of FIG. 5. The
dashed
line at 3000 Kpa indicates one possible reservoir pressure. To inject solvent
in
vapour phase, the corresponding temperature for each solvent is indicated
utilizing
the graph. According to a particular example, propane may be injected at 2000
kPa
and 60 C in gaseous phase and once the propane mixes with oil at the interface
via
solubility or heat-transfer, may be produced in oleic phase.
[0037] Solvents may be selected based on reservoir characteristics such
as,
the size and nature of the pay zone in the reservoir, properties of fluids
involved in
the process, and characteristics of the formation within and around the
reservoir.
For example, a relatively light hydrocarbon solvent such as propane may be
suitable for a reservoir with a relatively thick pay zone, as a lighter
hydrocarbon
solvent in the vapour phase is typically more mobile within the heated vapour
chamber.
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[0038] Additionally or alternatively, solvent selection may include
consideration of the economics of heating a selected particular solvent to a
desired
injection temperature.
[0039] For example, lighter solvents, such as propane and butane, are
efficiently injected in the vapour phase at relatively low temperatures at a
given
injection pressure. In comparison, efficient pure steam injection in a SAGD
process
typically requires a much higher injection temperature, such as about 200 PC
or
higher.
[0040] Heavier solvents also require a higher injection temperature. For
example, pentane may be heated to about 190 PC for injection in the vapour
phase
at injection pressures up to about 3 MPa. In comparison, a light solvent such
as
propane may be injected at temperatures as low as about 50 to about 70 PC
depending on the reservoir pressure.
[0041] Different solvents or solvent mixtures may be suitable candidates.
For
example, the solvent may be propane, butane, or pentane. A mixture of propane
and butane may also be used in an appropriate application. It is also possible
that a
selected solvent mixture may include heavier hydrocarbons in proportions that
are,
for example, low enough that the mixture still satisfies the above described
criteria
for selecting solvents.
[0042] In some embodiments, the solvent may include one or more C1-12
alkanes, a natural gas liquid, a condensate, a diluent, or a mixture thereof.
The
solvent may also include CO2 or H2 and may include up to 10 wt% impurities.
[0043] The condensate or diluent may include 0-5% C3 alkane, 0-5% iso-C4
alkane, 0-5% n-C4 alkane, 40-50% C5 alkane, 15-25% C6 alkane, 10-20% C7
alkane, 0-15% C8 alkane, or 0-15% C9 alkane. Alternatively, the condensate or
diluent may include 25-65% C3 alkane, 35-55% iso- and n-C4 alkanes, or 10-20%
C5+ alkane.
[0044] Dissolution of the solvent in bitumen reduces the viscosity and
enhances mobility of the oleic phase. The reduction in viscosity results in
the flow of
oil, along with the solvent. As solvent injection progresses, the oil flows
toward the
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perforated third pipe section 224. Flow into the production tubing 226 via the
ports
228, is controlled at 404, utilizing the flow control devices 230. The first
port,
closest to the heel 108, may be opened to facilitate the flow of fluids into
the
production tubing 226 via the first port. As injection and production
continues,
however, the first port may be closed and the second port, or next port along
the
length of the production tubing 226, opened. As production continues further,
the
second port may be closed and a third or next port along the length of the
production tubing, opened. Thus, the flow control devices may be utilized to
selectively open and close the ports in the production tubing 226 to produce
hydrocarbons from ports along the production tubing 226 that are farther from
the
heel 108, and thus farther from the perforated first pipe section 220 and the
second
pipe section 222 with time. The discharge coefficient in the flow control
devices
may be modified to optimize the recovery and advance vapour chamber growth.
For
example, the closest port to the heel could be closed as the chamber develops
to
improve the conformance along the length of the reservoir. This control of the
flow
control devices also facilitates production of hydrocarbons farther from the
injection
locations of the perforated first pipe section 220, along the length of the
generally
horizontal portion 110 of the single well 102.
[0045] In the description above, the production occurs as injection
continues.
The injection and production, however, need not be carried out simultaneously.
For
example, the production may be carried out after a period of injection. The
injection and production therefore may be carried out alternatingly.
[0046] The flow control devices 230 are utilized to control the flow of
fluid into
the production tubing 226. The hydrocarbons along with the solvent that
consolidate at the production tubing 226, are produced to the surface at 406.
The
consolidation of liquids including the hydrocarbons and the solvent, limiting
the
volume of gasses that enter the perforated third pipe section 224 and thus
limiting
the volume of gasses produced via the production tubing 226.
[0047] The produced fluids may be treated at the surface to separate, at
408,
the hydrocarbons produced from the solvent or solvents injected, in the
mobilizing
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fluid recovery facility 114. The solvent may then be recycled back by re-
injecting
the solvent into the reservoir at 410 for mobilizing further hydrocarbons.
[0048] Advantageously, mobilizing fluid may be injected and mobilized
hydrocarbons, along with mobilizing fluid, produced from a single well. The
reduced diameter section of pipe, through which mobilizing fluid flow is
inhibited
may be any suitable length to separate the location or locations at which the
mobilizing fluid is injected from the locations at which the fluids are
produced. The
separation of the injection and production locations in the hydrocarbon-
bearing
formation facilitates production along the length of the single well. Flow
control
devices may also be utilized to further facilitate production along the length
of the
single well. The mobilizing fluid may be a solvent, in the absence of any
steam
injection, such that steam facilities are not required for production. Gaseous
solvent or steam injected reduces bitumen viscosity by heat transfer, and, for
solvent, an increasing mol % of solvent in oil results from the solubility and
advancing oil production. The present system and process are particularly
suitable
for recovery of hydrocarbons from thin formations of less than about 20 meters
in
depth (thickness), referred to as thin pay zones.
EXAMPLES:
Modelling
[0049] Reservoir simulations were performed to demonstrate the process.
Simulation parameters utilized are included in Table 1 below.
Table 1: Simulation Parameters
Rich Pay thickness 30m
Well Spacing 100m
Well Length 800m
Symmetry Half symmetry
Model grid Block Dimensions 26X16X30
(2mX50mX1m)
(X,Y,Z)
Porosity 35%
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Reservoir Temperature 12c
Reservoir Pressure 3 mPa
Initial Oil Saturation 0.8
Vertical Permeability 2 Darcy
Horizontal Permeability 4 Darcy
Methane mole fraction in Oleic 13%
Phase
GOR 8
Oil API 9.6
[0050] FIG. 6 illustrates the spread of propane in a hydrocarbon-bearing
formation after 480 days, according to another simulation of the process of
FIG. 4.
Solvent chamber growth and expansion is shown in FIG. 6 in which conditions
were
not optimized. Significant development is shown at the heel of the solvent
chamber.
Further expansion and growth of the chamber may be effected by optimizing the
flow control devices discharge coefficient and the timing at which each opens
and
closes. FIG. 6 illustrates that solvent and oil are advantageously produced
utilizing
the present process.
[0051] FIG. 7 illustrates oil and solvent production rates in tonnes/day
over
time. The low oil rates in this half symmetry model may be increased by
advancing
the expansion and growth of the chamber by optimization of the flow control
devices discharge coefficient and the timing at which each opens and closes.
FIG. 7
shows that steady oil and solvent recovery are possible in thin reservoirs
where the
SAGD process is not economic due to high steam to oil ratio (SOR) and
significant
energy losses to the overburden.
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