Note: Descriptions are shown in the official language in which they were submitted.
PROCESS FOR PRODUCING HYDROCARBONS FROM A HYDROCARBON-
BEARING RESERVOIR
Technical Field
[0001] The present disclosure relates to the production of fluids
including
hydrocarbons from a subterranean reservoir bearing heavy oil or bitumen.
Background
[0002] Extensive deposits of hydrocarbons exist around the world.
Reservoirs of such deposits may be referred to as reservoirs of light oil,
medium
oil, heavy oil, extra-heavy oil, bitumen, or oil sands, and include large oil
deposits in Alberta, Canada. It is common practice to segregate petroleum
substances into categories that may be based on oil characteristics, for
example,
viscosity, density, American Petroleum Institute gravity ( API), or a
combination
thereof. For example, light oil may be defined as having an API 31, medium
oil as having an API 22 and < 31, heavy oil as having an API 10 and < 22
and extra-heavy oil as having an API 10 (see Santos, R. G., et al. Braz.
J.
Chem. Eng. Vol. 31, No. 03, pp. 571-590). Although these terms are in common
use, references to different types of oil represent categories of convenience,
and
there is a continuum of properties between light oil, medium oil, heavy oil,
extra-
heavy oil, and bitumen. Accordingly, references to such types of oil herein
include the continuum of such substances, and do not imply the existence of
some fixed and universally recognized boundary between the substances.
[0003] One thermal method of recovering viscous hydrocarbons in the form
of bitumen, also referred to as oil sands, is known as steam-assisted gravity
drainage (SAGD). In the SAGD process, pressurized steam is delivered through
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an upper, horizontal, injection well, also referred to as an injector, into a
viscous
hydrocarbon reservoir while hydrocarbons are produced from a lower, generally
parallel, horizontal, production well, also referred to as a producer, that is
near
the injection well and is vertically spaced from the injection 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.
[0004] The injected steam during SAGD initially mobilizes the
hydrocarbons
to create a steam chamber in the reservoir around and above the horizontal
injection well. The term steam chamber in the context of a SAGD operation is
utilized to refer to the volume of the reservoir that is heated to the steam
saturation temperature with injected steam and from which mobilized oil has at
least partially drained and been replaced with steam vapor. 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 and is collected and produced from the production well. The
produced emulsion is separated into dry oil for sales and produced water.
[0005] Such thermal processes are extremely energy intensive, utilize
significant volumes of water for the production of steam, and may require
additional equipment to control or handle the steam or gasses produced.
[0006] A solvent may be utilized to aid a steam-assisted recovery
process,
in a so-called solvent-aided process (SAP). Hydrocarbon solvent is generally
utilized to improve mobility in the hydrocarbon reservoir, potentially
improving
production and/or reducing steam and/or heating requirements. Gas production
is problematic however, as gas coning occurs. Increasing steam injection in an
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attempt to reduce gas coning, however, is energy intensive, may require
additional capital costs, and results in additional greenhouse gas emissions.
[0007] Improvements in hydrocarbon recovery from reservoirs are
desirable.
Summary
[0008] According to an aspect of an embodiment, a process for producing
hydrocarbons from a subterranean hydrocarbon-bearing reservoir includes
injecting mobilizing gas via an injection well into the hydrocarbon-bearing
reservoir and producing fluids from the hydrocarbon-bearing reservoir to a
surface through a production well, and injecting combined fluids including
water
and solvent through the injection well and into the hydrocarbon-bearing
reservoir
to mobilize the hydrocarbons, the combined fluids injected at a temperature at
which a majority of the water injected is liquid and at least 50% of the
solvent is
in vapour phase in the hydrocarbon-bearing reservoir. A fluid mixture is
produced through the production well, the fluid mixture including the
mobilized
hydrocarbons and at least a portion of the water and the solvent, from the
hydrocarbon-bearing reservoir to the surface. The water in the produced fluid
mixture is separated from the mobilized hydrocarbons.
[0009] The combined fluids may be injected at a temperature at which at
least 80% by weight of the water is liquid and at least 50% of the solvent is
in
vapour phase in the hydrocarbon-bearing reservoir.
[0010] The process may include controlling a rate of water injected in
the
combined fluids based on a water content of the fluid mixture produced.
[0011] The rate of water injected in the combined fluids may be adjusted
to
achieve a target water cut of the fluid mixture produced.
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[0012] The process may include controlling one or both of pressure and
temperature in the reservoir to control a ratio of the water to the solvent in
the
gas phase in the reservoir.
[0013] According to another aspect, a process for producing hydrocarbons
from a subterranean hydrocarbon-bearing reservoir includes injecting fluids
including water via an injection well and into the hydrocarbon-bearing
reservoir
to mobilize the hydrocarbons, producing a fluid mixture through the production
well, the fluid mixture including the mobilized hydrocarbons and at least a
portion of the water injected, identifying a water cut of the fluid mixture
produced, and based on the water cut identified, adjusting the rate of water
injection during injecting the fluids.
[0014] According to yet another aspect, a process for producing
hydrocarbons from a subterranean hydrocarbon-bearing reservoir is provided.
The process includes injecting combined fluids including water and solvent
through the injection well and into the hydrocarbon-bearing reservoir to
mobilize
the hydrocarbons, controlling at least one of pressure and temperature in the
reservoir to control a ratio of the water to the solvent in the gas phase in
the
reservoir, and producing a fluid mixture through the production well, the
fluid
mixture including the mobilized hydrocarbons and at least a portion of the
water
and the solvent, from the hydrocarbon-bearing reservoir to the surface.
Brief Description of the Drawings
[0015] Embodiments of the present invention will be described, by way of
example, with reference to the drawings and to the following description, in
which:
[0016] FIG. 1 is a schematic sectional view of a reservoir and shows the
relative location of an injection well and a production well;
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[0017] FIG. 2 is a sectional side view of a well pair including an
injection
well and a production well;
[0018] FIG. 3 is a flowchart showing a process for producing fluids from
a
subterranean hydrocarbon-bearing reservoir according to an embodiment; and
[0019] FIG. 4 is a graph illustrating recovery factor and cumulative
steam
to oil ratio (CSOR) equivalent for SAGD and for the process according to an
embodiment of the present invention utilizing pentane and utilizing hexane.
Detailed Description
[0020] The present application is directed to a process for producing
hydrocarbons from a subterranean hydrocarbon-bearing reservoir. The process
includes injecting mobilizing gas via an injection well into the hydrocarbon-
bearing reservoir and producing fluids from the hydrocarbon-bearing reservoir
to
a surface through a production well, and injecting combined fluids including
water and solvent through the injection well and into the hydrocarbon-bearing
reservoir to mobilize the hydrocarbons. The combined fluids are injected at a
temperature at which a majority of the water injected is liquid and at least
50%
of the solvent is in vapour phase in the hydrocarbon-bearing reservoir. The
process also includes producing a fluid mixture through the production well,
the
fluid mixture including the mobilized hydrocarbons and at least a portion of
the
water and the solvent, from the hydrocarbon-bearing reservoir to the surface.
The water in the produced fluid mixture is separated from the mobilized
hydrocarbons.
[0021] 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
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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.
[0022] One example of a well pair is illustrated in FIG. 1 and FIG. 2.
The
hydrocarbon production well 100 includes a generally horizontal segment 102
that extends near the base or bottom 104 of the hydrocarbon reservoir 106. An
injection well 112 also includes a generally horizontal segment 114 that is
disposed generally parallel to and is spaced vertically above the horizontal
segment 102 of the hydrocarbon production well 100.
[0023] During production utilizing, for example, SAGD, solvent aided
process (SAP), a solvent driven process (SDP), and high temperature solvent
only (HTSO) process, a gas is injected through an injection well to mobilize
the
hydrocarbons and create a mobilizing gas chamber in the reservoir, around and
above the generally horizontal segment of the injection well. Referring to
SAGD,
for example, steam is injected into the injection well head 116 and through
the
steam injection well 112 to mobilize the hydrocarbons and create a steam
chamber 108 in the reservoir 106, around and above the generally horizontal
segment 114.
[0024] Viscous hydrocarbons in the reservoir 106 are heated and
mobilized
and the mobilized hydrocarbons drain under the effects of gravity. Fluids,
including the mobilized hydrocarbons along with condensate, are collected in
the
generally horizontal segment 102 and are recovered via the hydrocarbon
production well 100 and the production well head 118. The fluids may also
include steam. Production may be carried out for any suitable period of time
as
referred to below.
[0025] After the period of production of fluids including hydrocarbons,
hot
water is co-injected with solvent into the hydrocarbon-bearing reservoir 106
through the injection well 112. The water and solvent are co-injected at a
temperature sufficient for at least 50% of the solvent to be in vapour phase
in
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the hydrocarbon-bearing reservoir 106. The solvent may be a single solvent or
a
mixture of solvents. The solvent vapor in the hydrocarbon reservoir
facilitates
hydrocarbon recovery.
[0026] In the example shown in FIG. 1 and in FIG. 2, a well pair,
including
the production well 100 and the injection well 112, is illustrated.
Alternatively,
the production well and injection well may be, for example, laterals of a
multi-
lateral well.
[0027] A flowchart illustrating a process for producing hydrocarbons in
accordance with one embodiment of the present invention is shown in FIG. 3.
The process may include additional or fewer elements than shown and described
and parts of the process may be performed in a different order than shown or
described herein. The process is carried out to produce hydrocarbons from a
subterranean hydrocarbon-bearing reservoir, such as the reservoir illustrated
in
FIG. 1.
[0028] A mobilizing gas is injected via the injection well at 302 into
the
hydrocarbon-bearing reservoir 106. Viscous hydrocarbons in the reservoir 106
are heated and mobilized and the mobilized hydrocarbons drain under the effect
of gravity. The mobilizing gas forms a mobilizing gas chamber, referred to as
a
steam chamber in the case of SAGD, around and above the generally horizontal
segment 114 of the injection well 112 in the reservoir 106.
[0029] Fluids are produced at 304. The produced fluids include mobilized
hydrocarbons as well as condensate, such as water from the steam, and connate
water, in an emulsion. The injection of mobilizing gas at 302 and the
production
of fluids at 304 may be part of a SAGD process, solvent aided process (SAP), a
solvent driven process (SDP), and high temperature solvent only (HTSO)
process.
[0030] The mobilizing gas injection and fluid production is carried out,
for
example, for a predetermined or threshold period of time. The period of time
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may be one year or may be any other suitable period of time. Alternatively,
the
mobilizing gas injection and fluid production may be carried out until another
threshold or target is reached. For example, mobilizing gas injection and
fluid
production may be carried out until a hydrocarbon production rate is
stabilized,
until gas, which may be or may include steam, has reached a top of a
hydrocarbon-rich zone in the reservoir 106, until a target recovery is
reached,
until a steam to oil ratio increases, or until a steam to oil ratio reaches a
pre-
determined valued.
[0031] A determination is made at 306 if the threshold or target is
reached.
As indicated, the threshold or target may be any suitable threshold or target
such as a threshold period of time, stabilization of a hydrocarbon production
rate,
mobilizing gas reaching a top of a rich zone in the reservoir 106, a target
recovery, such as a target of from 20% to 50% of total hydrocarbons in the
reservoir 106 being reached, a steam to oil ratio increase, or a steam to oil
ratio
reaching a pre-determined valued, for example, about 2.5 to about 3Ø In
response to determining that the threshold or target is reached at 306, the
process continues at 308.
[0032] Combined fluids including hot water and solvent are co-injected at
308. The combined fluids are injected at a temperature that is near saturation
temperature at the pressure in the reservoir, or between the bubble and dew
points at reservoir conditions. The combined fluids are thus injected at a
temperature such that a majority of the water that is injected is liquid in
the
hydrocarbon-bearing reservoir 106 and at least 50% of the solvent is in the
vapour phase. Along with the hot water and the solvent, the combined fluids
includes some steam or gas phase. The temperature of the combined fluids may
be selected such that at least 80% by weight of the water is liquid and at
least
50% of the solvent is in vapour phase in the hydrocarbon-bearing reservoir
conditions.
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[0033] The volume of water injected may be adjusted to achieve a desired
water cut, i.e., the percentage of emulsion produced that is water. Typically,
more water is produced when more water is injected. Thus, by controlling the
water that is injected, the water cut may be controlled to maintain sufficient
water to reduce the chance of gas breakthrough in the production well. The
volume of water injected may be controlled to achieve a water cut of, for
example, greater than 50%, or greater than 75%. The volume of water injected
may also be controlled to achieve a water cut that falls within a range, such
as
from about 60% to about 70%, from about 70% to about 80%, or from about
45% to about 55%. The water cut may be measured in line or via sampling.
Additional water that is injected may be heated to achieve a desired
percentage
of solvent in the gas phase.
[0034] The solvent may be any organic solvent, such as dinnethyl-ether,
methanol, ethanol, or any other suitable organic solvent, or combination of
solvents. The concentration of solvent in the combined fluids may vary
depending on reservoir conditions. The solvent concentration may be 3 wt.% or
greater. For example, the solvent concentration may be 10 wt.%, 15 wt.%, 20
wt.%, 50 wt.%, 60 wt.%, 80 wt.% or any other suitable concentration.
Regardless of the solvent concentration, at least 50% of the solvent injected
is in
the vapour phase at the bottom hole conditions in the reservoir 106. A higher
portion of the solvent of, for example, 60%, 80%, 90%, 95%, 99%, or even
greater wt. % in the vapour phase is desirable. Optionally, a heating coil or
electric heater may be utilized in the injection well to heat the combined
fluids, in
the production well, or in both the injection well and the production well.
[0035] The reservoir conditions may be controlled to control the ratio of
water to solvent in the gas phase. The reservoir conditions are controlled by
controlling the pressure in the reservoir, which is controllable based on the
rate
of injection of gasses including steam, and the temperature in the reservoir,
which is controllable based on the injection of heated fluids such as steam.
The
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pressure or the temperature or both the temperature and pressure may be
controlled to control the ratio of the water to solvent in the gas phase to
achieve
a favourable or desired ratio for production. The temperature of the heated
fluids with propane as the solvent may be, for example from 115 C to 160 C at
a
reservoir pressure of 3000 kPa. The temperature of the heated fluids with
propane as the solvent may be, for example from 110 C to 155 C at a reservoir
pressure of 2500 kPa.
[0036] Viscous hydrocarbons in the reservoir 106 are mobilized and the
mobilized hydrocarbons drain under the effects of gravity. A fluid mixture,
including the mobilized hydrocarbons along with at least a portion of the
water
and solvent injected in the combined fluids are collected in the generally
horizontal segment 102 and are produced at 310 via the hydrocarbon production
well 100 and the production well head 118.
[0037] The fluid mixture that is produced is treated at the surface to
separate out the mobilized hydrocarbons and the solvent. The solvent may be
recycled for injection into the reservoir 106. In addition, water may be
recovered from the produced fluids and recycled back for re-injection into the
reservoir 106.
[0038] As indicated above, the water cut may be controlled to maintain
sufficient water to reduce the chance of gas breakthrough in the production
well
by controlling the injection of water at 308. The water cut may be determined
and, based on the water cut, the rate of injection of water is adjusted. By
controlling the water cut, the chance of gas breakthrough or gas coning in the
production well is reduced, more efficient pump operation may be achieved, and
generally consistent drawdown across the production well may be achieved.
[0039] As indicated, the water may be recovered and reinjected. The
water is treated at the surface and then recycled along with other injected
fluids.
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[0040] As indicated, the solvent may be, for example, dinnethyl ether or
ethanol. Such solvents that are soluble in water may be recycled with the
water
without separation from the aqueous phase at any point.
[0041] The concentration of solvent in the combined fluids injected may
be
consistent for a period of time, followed by a reduction in the concentration
of
the solvent in the combined fluids injected at 312. The reduction in the
concentration of the solvent in the combined fluids may be carried out for any
suitable reason. For example, the reduction in concentration of the solvent
may
be carried out in response to reaching a threshold recovery factor, in
response to
reaching a threshold total solvent loading in the reservoir, in response to a
hydrocarbon production rate dropping below a predetermined value, in response
to reaching a threshold value of an equivalent cumulative steam to oil ratio,
in
response to reaching steady state solvent recovery, or in response to reaching
a
target bottom hole pressure.
[0042] With the reduction in solvent injected, additional water may be
injected to maintain bottom hole pressure. Thus, at least some of the solvent
may be replaced with water. Alternatively, at least some of the solvent may be
replaced with steam, a non-condensable gas, or any combination of two or all
three of water, steam, and non-condensable gas. As indicated above, the
reservoir conditions may be controlled to control the ratio of water to
solvent in
the gas phase.
[0043] A determination is made at 314 if a threshold or target production
is
reached. As indicated, the threshold or target production may be a target or
threshold total solvent recovery, such as 80% of the total solvent injected or
higher. Alternatively, the threshold or target production may be a low
threshold
such as a solvent recovery rate that has declined to a target value or less,
such
as 15 t/d or less, or an oil rate that has dropped to a threshold value, for
example, 25 t/d or less. The threshold or target production may instead be a
cumulative steam to oil ratio (CSOR) or energy equivalent that has reached a
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threshold value such as 2 or greater, or a pressure that has reached a
threshold
value, for example, 0.5 MPa or greater.
[0044] In response to determining that the threshold or target is
reached
at 314, the process continues at 316. Injection of the fluids including hot
water
and any solvent is discontinued at 316. Production of the fluid mixture,
including
mobilized hydrocarbons along with water and some solvent continues at 316.
Injection of a non-condensable gas such as methane or air in order to maintain
the reservoir pressure, to continue bitumen production, and to recover solvent
in
the absence of the injection of the fluid mixture, may continue during a
blowdown process at 316.
[0045] The process for producing hydrocarbons is described with
reference
to the examples shown in FIG. 1 and FIG. 2. Optionally, other wells may be
utilized. For example, the system may include more production wells than
injection wells or may include more injection wells than production wells. In
addition, the injection wells may extend along a path that is laterally spaced
from
any production well, for example, and thus is not located directly above.
Optionally, the injection and production well may be spaced laterally and
generally at a same depth in the reservoir. In addition, vertical wells and
wedge
wells may also be utilized.
[0046] The use of hot water with solvent is advantageous as the heating
and injection of water is less costly than the generation of steam. The water
used in steam generation requires significant pre-treatment by comparison to
heated water for injection. The hot water stream may also include 1 to 2% oil,
for example, without reducing efficacy of the process, saving separation
costs.
[0047] In addition, the volume of hot water to heat the solvent is
greater
than would be utilized by steam alone, resulting in a greater liquid volume at
the
production well, reducing gas coning and increasing oil rates. Additionally,
the
large volume of water injected results in the production of an emulsion that
is
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similar in quality to that produced during a SAGD operation, as opposed to low-
water emulsion formed by a solvent driven process, facilitating the use of
existing SAGD facilities.
[0048] The water utilized for the process may be a by-product of the
steam
generation. In addition, the water produced may be re-heated and re-injected,
reducing the amount of heat input and the physical equipment for heating.
Solvent that remains in the produced water after separation of the bitumen and
after any attempted solvent separation, may be heated along with the water and
reinjected into the formation. Solvents that are soluble in water may be
recycled
with the water without any attempt to separate the solvent from the aqueous
phase.
[0049] The use of solvent reduces the density of oil and facilitates
separation of the produced fluids at the surface. In addition, the produced
bitumen may be upgraded due to in-situ solvent deasphalting. Solvent
deasphalting further facilitates oil separation at the surface. The volume of
solvent that is retained in the reservoir is less than that for other solvent
processes because the water fills up pore space in the reservoir, thus
improving
process economics.
[0050] Injected water may include chemicals such as potassium chloride
(KCI) to reduce the chance of formation damage. Because KCI stays in liquid
phase, KCI is not easily injected during SAGD yet is injectable in the present
process. Further, solvents that are highly soluble in water or chemically
unstable
at steam temperature may be utilized in the present process.
EXAMPLES
Modelling
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Reservoir simulations were performed to demonstrate the process. Simulation
parameters utilized are included in Table 1 below. For demonstration purposes,
a two-hundred meter wide reservoir containing both rich and non-rich pay, as
well as two injector and producer well pairs was simulated.
Table 1: Simulation Parameters
Reservoir Properties (Rich Pay)
Property Value Units
Pay Height 10 meters
Permeability (Horiz) 5 Darcies
Permeability (Vertical) 3 Darcies
Initial Oil Saturation 0.86 -
Initial Water Saturation 0.14 -
Initial Temperature 12 C
Initial Pressure 3000 kPa
Porosity 0.33 -
Non-Rich Pay Properties
Property Value Units
Pay Height 10 meters
Permeability (Horiz) 0.05 Darcies
Permeability (Vertical) 0.02 Darcies
Initial Oil Saturation 0.8 -
Initial Water Saturation 0.2 -
Initial Temperature 12 C
Initial Pressure 3000 kPa
Porosity 0.25 -
Well & Reservoir Dimensions
Property Value Units
Well length 800 meters
No. Wells 2 -
Well Pair Lateral Spacing 100 meters
Injector/Producer Spacing 5 meters
Operating Parameters
Property Value Units
Injection Pressure Constraint 3200 kPa
Injector Rate Constraint 800 t/d/well
Injector Solvent Concentration 10 Percent (W)
Producer Pressure Constraint 3200 kPa
Producer Rate Constraint 800 t/d/well
Producer Gas Constraint 5 t/d/well
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[0051] To quantify the benefit of the use of solvents, CSOR and
cumulative
recovery factor were determined. FIG. 4 is a graph showing the recovery factor
(RF) and cumulative steam to oil ratio (equivalent) for the process
illustrated in
FIG. 3 and described herein utilizing propane, referred to as C3, as the
solvent
and utilizing pentane, referred to as C5, as the solvent. The recovery factor
(RF)
and cumulative steam to oil ratio (equivalent) for SAGD is illustrated for
comparison purposes. The solid lines indicate recovery factor and the dashed
lines show the cumulative steam to oil ratio (equivalent). The circles plotted
on
the lines indicate the recovery factor (RF) and cumulative steam to oil ratio
(equivalent) for the process utilizing propane. The triangles plotted on the
lines
indicate the recovery factor (RF) and cumulative steam to oil ratio
(equivalent)
for the process utilizing pentane. The squares plotted on the lines indicate
the
recovery factor (RF) and cumulative steam to oil ratio (equivalent) for SAGD.
[0052] A solvent concentration of 10 wt.% was utilized at 308. As
indicated, propane and pentane were utilized in separate simulations. The
volume of water and solvent injected was varied to maintain reservoir
pressure.
The relative amount of water to solvent injected, however, was constant. Thus,
the relative volume of solvent injected was not reduced. Hot water and solvent
injection continued for 3000 days. The production rate was constrained to
limit
the volume of gas produced.
[0053] As shown in FIG. 4, utilizing pentane in the process and utilizing
propane in the process reduced energy intensity in comparison with a SAGD only
process. Utilizing pentane and propane in the process produced a CSOR
equivalent of 1.9 and 1.5, respectively, at an oil recovery factor of 55%. By
comparison, the SAGD CSOR at 55% oil recovery was 2.7. The use of pentane
had the additional benefit of reaching 55% oil recovery factor after
approximately four years of simulation as compared with 5.6 and 6.9 years for
SAGD and for the process utilizing propane, respectively.
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[0054] The results shown in FIG. 4 illustrate that the present process
reduces energy intensity associated with bitumen production by comparison to a
SAGD operation. Utilizing the present process, a reduction in gas coning, and
simplification of facilities and operations is achievable by comparison to
processes such as solvent aided processes or solvent driven processes.
[0055] Tests were carried out to show the effect of the presence of water
combined with solvent. The tests were carried out in basket soaking tests
utilizing simulated reservoir conditions and known amount of oil in sand. The
test parameters and results are shown in Table 2. As shown, the tests were
carried out utilizing propane as the solvent at 80 wt. % and 20 wt. % water in
the combined fluids for extraction of oil from the sand. For comparison
purposes, tests were carried out utilizing propane as the solvent at 100 wt. %
and 0 wt. % water in the combined fluids for extraction of oil from the sand.
Tests were also carried out utilizing butane as the solvent at 70 wt. % and at
100 wt. % of the combined fluids.
TABLE 2: BASKET SOAKING TESTS
Conc Total oil
Oil
Asphaltene,
in the %00IP Tcore, C Pressure kPa oil
API
Solvent % drained g mass%
core, g
propane 80 1841 11.50 62.47 80.6 3117
11.5 1t72
propane 80 17.95 1201. 66.89 81.9 3175
propane 100 18A6 13.79 75.93 81.2 3150
10.5 12.90
propane 100 18.20 1340 73.62 81.2 3155
butane 70 18.09 10.33 57.10 134.2 3168 all
sample used
13.5 for blending
butane 70 18.01 11A8 6207. 133A 3166 tests
butane 100 18.22 15.23 83.61 136.9 3172
12/ 11A0
butane 100 18.01 15.33 85A4 136.6 3157
butane 100 18A1 14.78 8t60 148.0 4012
10/
butane 100 17.92 13.87 7T38 144.0 4022
butane 100 18A6 10.83 59.23 153.2 4842
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In which:
Conc % is the wt. % solvent utilized;
Total oil in the core is the weight of the oil in the sample;
Oil drained in the weight of oil recovered utilizing the combined fluids (or
solvent in the case of 100% solvent);
%00IP is the percentage of the original oil in the sample that is
recovered;
Tcore is the measured temperature of the core of the sample;
Pressure is the pressure at which the sample is tested;
Oil API is the index of density of the oil recovered; and
Asphaltene mass % is the mass percent of asphaltene in the recovered oil.
[0056] As shown, the API is higher in the tests utilizing 80% propane
(and
20% water) in the combined fluids by comparison to the tests utilizing about
100% propane. This improvement in API is a result of upgrading by reducing the
asphaltenes in the oil recovered. The asphaltene mass % is also lower than the
asphaltene mass % of typical produced oil, which is generally about 20%.
[0057] The API is also higher in the tests utilizing 70% butane (and 30%
water) in the combined fluids by comparison to the tests utilizing about 100%
butane.
[0058] Thus, the produced oil, in the form of bitumen, is upgraded due to
solvent deasphalting, which facilitates oil separation at the surface.
[0059] The described embodiments are to be considered in all respects
only
as illustrative and not restrictive. The scope of the claims should not be
limited
by the preferred embodiments set forth in the examples, but should be given
the
broadest interpretation consistent with the description as a whole. All
changes
that come with meaning and range of equivalency of the claims are to be
embraced within their scope.
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Date Recue/Date Received 2021-01-28
