Note: Descriptions are shown in the official language in which they were submitted.
1
METHOD FOR RECOVERING VISCOUS OIL FROM A RESERVOIR
TECHNICAL FIELD:
[0001] The present disclosure relates to oil recovery methods. More
particularly,
the present disclosure relates to in situ thermal oil recovery methods.
BACKGROUND:
[0002] A variety of in situ steam-based thermal oil recovery processes
have been
used for recovering heavy oil and bitumen from subterranean reservoirs. One
such
method is steam-assisted gravity drainage (SAGD). Typical SAGD operations use
a pair
of horizontal wells including a production well located near the bottom of the
reservoir
and an injection well located about 5 meters above and co-planar with the
production
well. High pressure steam may be injected through the injection well to heat
the
adjacent volume of reservoir and reduce the viscosity of the oil therein.
Provided flow
communication has been established between the injection and production well,
mobilized oil and condensed steam may drain under the force of gravity to the
production well while a voided pore space created by the draining oil is
filled with steam.
Mobilized oil and condensed steam may be produced to surface from the
production
well.
[0003] Other steam-based gravity drainage oil recovery methods may use
the
same paired well configuration as SAGD. However, instead of injecting steam
alone,
other vapor phase fluids may be injected. For example, a combination of steam
and a
solvent that is effective in reducing the viscosity of oil by dilution, a
combination of
steam and non-condensable gas, a hot solvent vapor alone, or any other
sequential or
simultaneous combination of steam, solvent, and/or non-condensable gas may be
injected.
[0004] Thermal gravity drainage processes typically require significant
thermal
energy input to raise the temperature within the reservoir to the extent
needed to reduce
the viscosity of the oil therein such that it flows under the force of
gravity.
Conventionally, the thermal energy input for thermal oil recovery is provided
by the
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combustion of natural gas. However, the greenhouse gas emissions from natural
gas
combustion are undesirable and subject to increasingly strict regulations.
[0005] An alternative source of thermal energy input is electricity.
Some
electrically powered thermal oil recovery processes use radio frequency
radiation or
resistive heating to directly heat the reservoir rather than injecting a
heated vapor-phase
working fluid such as steam. Other processes involve inserting a resistive
heating
element into an injection well to provide additional thermal energy to
injected hot solvent
vapor. Alternatively, a resistive heating element may be inserted into a
production well
to reduce the viscosity of the oil therein and potentially also reflux
condensed solvent
vapor. However, these processes have difficulty achieving comparable oil
production
performance to that of SAGD.
[0006] U.S. Patent No. 9,097,110 to Kaminsky etal. describes an oil
recovery
process in which some of the steam for injection is generated using an
electrical heater
powered by fluctuating power sources, for example, wind or solar power. The
electrical
heater is supplemented by a fired heater system, thereby generating two
separate fluid
streams that are combined prior to injection to maintain continuous steam
injection
rates. However, this approach requires duplicated equipment for both
electrical and
conventional steam generation capacity.
[0007] Alternatively, Klinginger et al. proposed a SAGD-type process in
which
the steam for injection is generated by solar radiation in a solarthermal
plant (Klinginger,
C., "Cyclic steam Injection into the subsurface ¨ solarthermal steam
generation for
enhanced oil recovery", University of Stuttgart, submitted January 26, 2010).
Steam is
injected at a cyclic injection rate based on the daily available hours of
direct sunlight.
However, the author notes that steam chamber development may progress
differently
than that of conventional SAGD. Other limitations of this method include the
need to
have the solarthermal plant in close proximity to the SAGD wells and the
potential for
significantly increased capital costs.
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SUMMARY:
[0008] In one aspect, there is provided a method of recovering viscous
oil from a
subterranean reservoir having at least one well installed therein, the method
comprising:
injecting a first heated vapor-phase working fluid via the at least one well
to form a
heated vapor chamber and producing a first production fluid via the at least
one well;
ceasing injection of the first heated vapor-phase working fluid and
intermittently injecting
a second heated vapor-phase working fluid via the at least one well and
producing a
second production fluid via the at least one well; and wherein the second
heated vapor-
phase working fluid is heated electrically.
[0009] In some embodiments, the at least one well comprises an injection
well
and a production well in fluid communication within the vapor chamber, the
first and
second heated vapor-phase working fluids are injected via the injection well,
and the
first and second production fluids are produced via the production well.
[0010] In some embodiments, the method of recovering oil is steam
assisted
gravity drainage (SAGD).
[0011] In some embodiments, the same at least one well is used for
injection and
production.
[0012] In some embodiments, the method of recovering oil is cyclic steam
stimulation (CSS).
[0013] In some embodiments, the method of recovering oil is steam
flooding.
[0014] In some embodiments, at least a portion of the second heated vapor-
phase working fluid is heated electrically using a variably available
electrical power
source.
[0015] In some embodiments, the variably available electrical power
source is a
low carbon power source.
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[0016] In some embodiments, the low carbon power source is at least one
of
wind power, solar power, hydroelectric power, geothermal power, nuclear power,
and
co-generation power.
[0017] In some embodiments, all of the second heated vapor-phase working
fluid
is generated electrically using the variably available electrical power
source.
[0018] In some embodiments, a first portion of the second heated vapor-
phase
working fluid is generated electrically using the variably available
electrical power
source and a second portion of the second heated vapor-phase working fluid is
generated electrically using a continuously available electrical power source.
[0019] In some embodiments, the first heated vapor-phase working fluid is
heated using a fired heating system.
[0020] In some embodiments, the method further comprises continuously
injecting a third heated vapor-phase working fluid concurrently with
intermittent injection
of the second heated vapor phase working fluid, wherein the third heated vapor-
phase
working fluid is about 50% or lower of a cumulative injected volume of the
second and
third vapor-phase working fluids by liquid volume equivalent.
[0021] In some embodiments, the third heated vapor-phase working fluid
has
substantially the same composition or a substantially similar composition as
the second
heated vapor-phase working fluid.
[0022] In some embodiments, the method further comprises intermittently
injecting a fourth vapor-phase working fluid when an injection rate of the
second heated
vapor-phase working fluid is at or near zero.
[0023] In some embodiments, the fourth vapor-phase working fluid
comprises at
least one of a vapor-phase solvent and a non-condensable gas.
[0024] In some embodiments, ceasing injection of the first heated vapor-
phase
fluid is based on at least one of a preselected time, a numerical simulation,
and a
comparable continuous thermal oil recovery process.
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[0025] In some embodiments, the method further comprises determining a
target
range for an operating parameter of the vapor chamber.
[0026] In some embodiments, the method further comprises monitoring the
operating parameter of the vapor chamber during injection of the first heated
vapor-
phase working fluid.
[0027] In some embodiments, a lower limit of the target range is adjusted
upward
or downward based on observed fluctuations in at least one of operating
pressure and
oil production.
[0028] In some embodiments, ceasing injection of the first heated vapor-
phase
working fluid and starting intermittent injection of the second heated vapor-
phase
working fluid when the operating parameter of the vapor chamber is within the
target
range.
[0029] In some embodiments, monitoring the operating parameter of the
vapor
chamber during intermittent injection of the second heated vapor-phase working
fluid.
[0030] In some embodiments, if the operating parameter of the vapor
chamber
falls below the target range, continuously injecting the first or second
heated vapor-
phase working fluid to bring the operating parameter of the vapor chamber
within the
target range.
[0031] In some embodiments, adjusting an instantaneous injection rate of
the
second heated vapor-phase working fluid to maintain the operating parameter of
the
vapor chamber within the target range.
[0032] In some embodiments, the operating parameter is at least one of
pressure
and temperature.
[0033] In some embodiments, the method further comprises maintaining a
level
of a pool of drained liquid around the at least one production well at or
above a
threshold level to prevent vapor breakthrough into the at least one production
well
during production of the second production fluid.
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[0034] In some embodiments, maintaining the level of the pool of drained
liquid
comprises adjusting an instantaneous production rate of the second production
fluid.
[0035] In some embodiments, adjusting the instantaneous production rate
of the
second production fluid comprises increasing the instantaneous production rate
during
periods when injection of the second heated vapor-phase working fluid is high
and
decreasing the instantaneous production rate during periods when injection of
the
second heated vapor-phase working fluid is low.
[0036] In some embodiments, the level of the drained pool of liquid is
allowed to
vary while maintaining an approximately constant instantaneous production rate
of the
second production fluid.
[0037] In some embodiments, the level of the drained pool of liquid is
estimated
using a subcool value.
[0038] In some embodiments, injecting the first heated vapor-phase
working fluid
comprises continuously injecting the first heated vapor-phase working fluid.
[0039] In some embodiments, the first heated vapor-phase working fluid
comprises steam, a vapor-phase solvent, a non-condensable gas, or a
combination
thereof.
[0040] In some embodiments, the second heated vapor-phase working fluid
comprises steam, a vapor-phase solvent, a non-condensable gas, or a
combination
thereof.
[0041] In some embodiments, the vapor-phase solvent comprises propane,
butane, pentane, hexane, heptane, octane, nonane, decane, undecane, dodecane,
tridecane, tetradecane, diluent, natural gas condensate, kerosene, naptha,
dimethyl
ether, or a combination thereof.
[0042] In some embodiments, the non-condensable gas comprises natural
gas,
carbon dioxide, nitrogen, carbon monoxide, hydrogen sulfide, hydrogen,
anhydrous
ammonia, helium, flue gas, methane, ethane, or a combination thereof.
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[0043] In some embodiments, the second heated vapor-phase working fluid
has
substantially the same composition as the first heated vapor-phase working
fluid.
[0044] In another aspect, there is provided a system for recovering
viscous oil
from a subterranean reservoir comprising: at least one well installed in the
subterranean
reservoir; an electrical heating system to heat a vapor-phase working fluid
for injection
via the at least one injection well; and a control system configured to
implement
embodiments of the methods disclosed herein.
[0045] In some embodiments, the electrical heating system is operatively
connected to a variably available power source.
[0046] In some embodiments, the electrical heating system is operatively
connected to a continuously available power source.
[0047] In some embodiments, the system further comprises a fired heater
system
to heat the vapor-phase working fluid for injection via the at least one
injection well.
[0048] Other aspects and features of the present disclosure will become
apparent, to those ordinarily skilled in the art, upon review of the following
description of
the specific embodiments of the disclosure.
BRIEF DESCRIPTION OF THE DRAWINGS:
[0049] Some aspects of the disclosure will now be described in greater
detail with
reference to the accompanying drawings. In the drawings:
[0050] Figure 1 is a side view diagram of a system for implementing
embodiments of the methods disclosed herein, including a well pair in a
subterranean
reservoir;
[0051] Figure 2 is a cross-sectional view of the well pair of Figure 1;
[0052] Figure 3 is a flowchart of an example method for recovering
viscous oil
from a subterranean reservoir, according to some embodiments;
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[0053] Figure 4 is a flowchart of another example method showing
additional
details regarding transition from injection of a first heated vapor-phase
working fluid to
intermittent injection of a second heated vapor-phase working fluid, according
to some
embodiments;
[0054] Figure 5 is a flowchart of another example method showing
additional
details regarding how an operating pressure may be maintained within a target
operating pressure range, according to some embodiments;
[0055] Figure 6 is a flowchart of another example method showing
additional
details regarding how a liquid pool around the production well may be
maintained at or
above a threshold level, according to some embodiments;
[0056] Figure 7 shows a simulated distribution of horizontal absolute
permeability
distribution for a two-dimensional SAGD model in a deep reservoir;
[0057] Figure 8 is a graph showing simulated steam injection rate and oil
production rate over time for a SAGD baseline case;
[0058] Figure 9 is a graph showing simulated bottom-hole pressure (BHP)
of an
injection well (injector) and production well (producer) over time for the
SAGD baseline
case;
[0059] Figure 10 is a graph showing hourly wind power availability for
Pan-
Canadian Wind Integration (PCWIS) site 3416 for the year 2008;
[0060] Figure 11 is a graph showing monthly wind power availability for
PCWIS
site 3416 for 2008, 2009, and 2010;
[0061] Figure 12 is a graph showing a simulated daily steam injection
rate for an
example case, in which steam is injected intermittently, and the SAGD baseline
case;
[0062] Figure 13 is a graph showing simulated daily oil production rate
for the
example case of Figure 12 and the SAGD baseline case;
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[0063] Figure 14 is a graph showing simulated cumulative oil production
rate for
the example case of Figure 12 and the SAGD baseline case;
[0064] Figure 15 is a graph showing simulated injector BHP over time for
the
example case of Figure 12 and the SAGD baseline case;
[0065] Figure 16 is a graph showing simulated injector BHP over time for
three
example cases in which intermittent steam injection is preceded by varying
periods (1,
2, or 4 months) of continuous steam injection, and the SAGD baseline case;
[0066] Figure 17 is a graph showing simulated wellbore temperature over
time for
one of the example cases of Figure 16 and the SAGD baseline case;
[0067] Figure 18 is a graph showing simulated daily oil production rate
for the
example cases of Figure 16 and the SAGD baseline case;
[0068] Figure 19 is a graph showing simulated cumulative oil production
rate for
the example cases of Figure 16 and the SAGD baseline case;
[0069] Figure 20 is a graph showing simulated injector BHP over time for
two
example cases in which intermittent steam injection is preceded by two months
of
continuous steam injection and starts in January or June, respectively, and
the SAGD
baseline case;
[0070] Figure 21 is a graph showing simulated daily oil rate for the
example
cases of Figure 20, and the SAGD baseline case;
[0071] Figure 22 is a graph showing simulated cumulative oil production
rate for
the example cases of Figure 20, and the SAGD baseline case;
[0072] Figure 23 is a graph showing simulated injector BHP over time for
three
example cases in which steam is injected intermittently, and the SAGD baseline
case, in
a shallow reservoir;
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[0073] Figure 24 is a graph showing simulated daily oil production rate
for the
example cases of Figure 23, and the SAGD baseline case, in the shallow
reservoir;
[0074] Figure 25 is a graph showing simulated cumulative oil production
rate for
the example cases of Figure 23, and the SAGD baseline case, in the shallow
reservoir;
[0075] Figure 26 shows a simulated vapor chamber expansion for the deep
reservoir cases; and
[0076] Figure 27 shows a simulated vapor chamber expansion for the
shallow
reservoir cases.
DETAILED DESCRIPTION OF EMBODIMENTS:
[0077] Generally, the present disclosure provides a method for recovering
viscous oil from a subterranean reservoir having at least one well installed
therein. The
method may comprise injecting a first heated vapor-phase working fluid via the
at least
one well to form a heated vapor chamber and producing a first production fluid
via the at
least one well. Injection of the first heated vapor-phase working fluid may be
ceased
and then a second heated vapor-phase working fluid may be intermittently
injected via
the at least one well and a second heated vapor-phase working fluid may be
produced
via the at least one well. In some embodiments, the second heated vapor-phase
working fluid may be heated electrically. In some embodiments, at least a
portion of the
second vapor-phase working fluid may be heated electrically using a variably
available
power source.
[0078] As used herein, "viscous oil" refers to a hydrocarbon material
having a
high viscosity and a high specific gravity. In some embodiments, viscous oil
comprises
heavy oil and/or bitumen. As used herein, "heavy oil" refers to a hydrocarbon
material
having a viscosity greater than 100 centipoise under virgin reservoir
conditions and an
API gravity of 20 API or lower. Bitumen may be defined as a hydrocarbon
material
having a viscosity greater than 10,000 centipoise under virgin reservoir
conditions and
an API gravity of 10 API or lower.
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[0079] As used herein, "reservoir" refers to any subterranean region, in
an earth
formation, including at least one pool or deposit of hydrocarbons such as
viscous oil
therein. A portion of the reservoir containing viscous oil therein may be
referred to as a
"pay interval" or "pay zone". In some embodiments, the reservoir has a
relatively thick
pay interval, for example, a pay interval with a thickness of 15 meters or
greater. In
some embodiments, the reservoir has relatively high vertical permeability, for
example,
a permeability of 1 Darcy or greater.
[0080] As used herein, a "thermal oil recovery process" refers to a
process
comprising in situ heating of the reservoir, via injection of a heated vapor-
phase working
fluid, to mobilize the viscous oil therein such that the oil may be displaced
to a
production well from which it may be produced to surface. In some embodiments,
the
displacement mechanism of the thermal oil recovery process is gravity drainage
such
that heated mobilized oil flows to the production well under the force of
gravity while the
voided pore space from which the oil is displaced is filled with injected hot
vapor.
[0081] Thermal gravity drainage oil recovery processes may be implemented
using a variety of different well configurations. In some embodiments, the
well
configuration comprises at least one injection well and at least one
production well. The
injection well is used to inject a heated vapor-phase working fluid into the
reservoir. The
heated vapor-phase working fluid reduces the viscosity of the viscous oil and
mobilizes
the viscous oil within the reservoir. The production well is used to collect
drained
mobilized oil and condensed working fluid and convey a production fluid to the
surface.
As used herein, "production fluid" refers to the fluid produced from the
production well
which may include oil, condensed working fluid, and any other fluids flowing
into the
production well from the reservoir. In other embodiments, a single well may
function as
both the injection well and the production well.
[0082] In some embodiments, one or both of the wells are vertical wells.
As used
herein, a "vertical" well refers to a well that extends substantially directly
downward from
the surface of the reservoir into the target pay interval. In some
embodiments, one or
both of the wells are horizontal wells. As used herein, a "horizontal" well
refers to a well
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having a vertical section that extends downward into the pay interval followed
by a
horizontal section that extends approximately parallel to the bottom of the
pay interval.
In some embodiments, the horizontal section of the horizontal well may be at
least 800
from vertical.
[0083] Figure 1 shows an example system 100, according to some
embodiments,
that may implement one or more of the methods described herein. The example
system
100 may comprise a well pair 101. The well pair 101 in this embodiment is
similar to the
well pairs typically used in SAGD operations.
[0084] The well pair 101 in this embodiment is installed in an earth
formation 102
having subterranean reservoir 103 with pay interval 105. The well pair 101 may
comprise an injection well 104 and a production well 106. In this embodiment,
the
injection well 104 and the production well 106 are both horizontal wells. The
production
well 106 may be located at or near the bottom of the pay interval 105. The
injection well
104 may be vertically spaced above the production well 106 and substantially
parallel
with the production well 106. In some embodiments, the injection well 104 is
approximately five meters above the production well 106. In some embodiments,
the
reservoir 103 may comprise a plurality of pay intervals 105 and at least one
well pair
101 may be installed in each pay interval 105.
[0085] The injection well 104 and the production well 106 may be in flow
communication via the reservoir 103. In some embodiments, flow communication
between the injection well 104 and the production well 106 may be established
through
a process known as "initialization". Initialization may comprise mobilizing
oil in an inter-
well zone 108, between the injection well 104 and the production well 106 such
that
mobilized oil in the inter-well zone 108 can flow to the production well 106.
In some
embodiments, initialization comprises heating the injection well 104 and the
production
well 106 for an extended period to mobilize the oil in the interwell zone 108
by
conductive heating. In some embodiments, the injection and production wells
104 and
106 are heated by injecting steam through both the injection well 104 and the
production well 106 in a process known as "steam circulation". In other
embodiments,
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initialization may be achieved or assisted by an extended period of solvent
injection,
either alone or in combination with steam. The solvent may be injected through
the
injection well 104 or through both the injection and production wells 104 and
106.
[0086] Once flow communication is established between the injection well
104
and the production well 106, a heated vapor-phase working fluid may be
injected via the
injection well 104 and flow into the reservoir 103. Mobilized oil in the
reservoir 103,
along with condensed working fluid, may flow to the production well 104 via
gravity
drainage. Production fluid may then be produced to surface via the production
well 106.
In some embodiments, a pump 107 may be installed in the production well 106 to
lift the
production fluid to surface.
[0087] As shown in Figure 2, as the heated vapor-phase working fluid is
injected
into the reservoir 103 via the injection well 104, a vapor chamber 110 may be
formed in
the reservoir 103. As used herein, "vapor chamber" refers to a volume of the
reservoir
that is at least partially filled with heated vapor-phase working fluid and at
least partially
depleted of oil. In SAGD operations, the vapor chamber is also referred to as
a steam
chamber. The vapor chamber 110 may grow upward and outward from the injection
well
104 as indicated by arrows A. Mobilized oil and condensed working fluid may
drain
downward within or along the periphery of the vapor chamber 110 towards the
production well 106 as indicated by arrows B. Within the vapor chamber 110,
the
mobilized oil is displaced from the pore space within the reservoir 103 and
the voided
pore space is filled with the hot vapor of the heated vapor-phase working
fluid.
[0088] The heated vapor-phase working fluid may thereby mobilize the
viscous
oil in the reservoir 103 by reducing its viscosity by heat and, in some
embodiments, also
by dilution of the oil at the boundaries of the vapor chamber 110. The heated
vapor-
phase working fluid may also act as a gaseous displacement fluid to fill the
void space
voided by the drained mobilized oil. Other functions of the working fluid
include
maintaining the operating pressure of the vapor chamber and, in some
embodiments,
transporting a solvent component of the working fluid to the boundaries of the
vapor
chamber.
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[0089] As the vapor chamber 110 may be filled with heated vapor-phase
working
fluid, the vapor chamber 110 may store a considerable amount of heat. The
stored heat
may be released into the reservoir 103 beyond the vapor chamber 110 even if
the rate
of heat input into the vapor chamber 110 is reduced. Therefore, in some
embodiments,
the viscous oil in the pay interval 105 may continue to be heated and
mobilized even
when injection of the heated vapor-phase working fluid is temporarily
suspended. A
previous study by Birrell et al. demonstrated that short term variances in
injection rate
may have little impact on vapor chamber temperature (Birrell et al., "Cyclic
SAGD ¨
Economic Implications of Manipulating Steam Injection Rates in SAGD Projects ¨
Re-
examination of the Dover Project", J. Can. Petrol. Technol. 2005 Vol 44(1), pp
54-58).
[0090] In some embodiments, a liquid pool 112 of drained, mobilized oil
and
condensed working fluid may be maintained around and above the production well
106.
The liquid pool 112 may act as a barrier to prevent vapor breakthrough into
the
production well 106. As used herein "vapor breakthrough" or "steam
breakthrough"
refers to heated vapor-phase working fluid entering the production well 106
such that
the vapor-phase fluid may be produced to the surface.
[0091] Referring again to Figure 1, in some embodiments, the production
fluid
produced from production well 106 may be received at a treatment facility 109
where
the condensed working fluid may be separated from the oil in the production
fluid. In
some embodiments, the condensed working fluid may be treated to remove
residual
contaminants such that the treated fluid may be recycled and used to generate
new
heated vapor-phase working fluid for injection. In some embodiments, the
treated
working fluid, typically in liquid-phase, is received in working fluid storage
111 where the
treated working fluid may be combined with make-up working fluid, also
typically in
liquid phase.
[0092] The system 100 may further comprise at least one heating system.
In
some embodiments, the heating system comprises at least one electrical heating
system 116. The electrical heating system 116 may receive working fluid from
the
working fluid storage 111 and heat the working fluid for injection into
injection well 104.
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As used herein, "heated" or "heating", when used in reference to a working
fluid, refers
to increasing the thermal energy of a fluid to the extent that the fluid can
transport heat
into the reservoir to mobilize the oil therein. In some embodiments, heating
the working
fluid comprises vaporizing a liquid-phase fluid to vapor-phase. In some
embodiments,
the electrical heating system 116 comprises an electrode boiler that passes an
electrical
current through liquid-phase working fluid to vaporize the liquid-phase
working fluid to
heated vapor-phase working fluid. In other embodiments, the electrical heating
system
116 comprises electrical resistance heating elements that are submerged in the
liquid-
phase working fluid. In other embodiments, the electrical heating system 116
comprises
an indirect heating system in which a heat transfer fluid is heated and
transfers heat to
the working fluid. In other embodiments, the electrical heating system 116
comprises
any suitable electrical heating means. In some embodiments, the electrical
heating
system 116 may comprise more than one heating means, for example, more than
one
electrical boiler.
[0093] Optionally, the system 100 may further comprise a fired heating
system
117, which may also receive working fluid from the working fluid storage 111
and heat
the working fluid for injection into injection well 104. In some embodiments,
the fired
heating system 117 comprises a fired boiler such as a natural gas fired
boiler. In other
embodiments, the fired heating system 117 comprises any other suitable type of
fired
heating system.
[0094] The system 100 may further comprise a control system 118
operatively
connected to the heating system. The control system 118 may be configured to
implement embodiments of the methods described herein. In this embodiment, the
control system 118 is operatively connected to the electrical heating system
116 and the
optional fired heating system 117. The control system 118 may thereby control
the
operation of the electrical heating system 116 and the fired heating system
117 if used.
In some embodiments, the control system 118 is also operatively connected to
one or
more temperature and/or pressure sensors installed in the injection and/or
production
wells 104 and 106. In some embodiments, the control system 118 is operatively
connected to at least one pressure sensor 113 and at least one temperature
sensor 115
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installed in the injection and/or production wells 104 and 106. In Figure 1,
pressure
sensors 113 are shown as triangles and temperature sensors 115 are shown are
circles. Therefore, in some embodiments, the control system 118 may receive
input
from the pressure and temperature sensors 113 and 115 and may regulate the
electrical
heating system 116 and the fired heating system 117 based on such input.
[0095] In some embodiments, at least one temperature sensor 115 may be
installed in the injection well 104 to monitor the temperature of the heated
vapor-phase
working fluid. In some embodiments, at least one temperature sensor 115 may be
installed in the production well 106 to monitor the temperature of the
production fluid.
Each of the temperature sensors 115 may comprise thermocouples, a fiber optic
array,
or any other suitable temperature sensing means. In some embodiments, at least
one
pressure sensor 113 is installed in the horizontal section of the production
well 106, to
provide a measurement of bottom-hole pressure. In some embodiments, at least
one
pressure sensor 113 is installed in the injection well 104 to provide a means
to monitor
pressure within the vapor chamber.
[0096] In some embodiments, the electrical heating system 116 is
operatively
connected to at least one power source. In some embodiments, the power source
is a
variably available power source 119. As used herein, a "variably available
electrical
power source" refers to a power source from which the amount of available
power
varies at least somewhat unpredictably over time and at some time points may
be zero.
In some embodiments, the amount of available power varies hourly, daily,
weekly,
and/or seasonally. In some embodiments, the variably available electrical
power source
119 may comprise a single primary power plant. In other embodiments, the
variably
available electrical power source 119 may comprise a local or regional
electrical power
grid that is supplied by several independently operated primary power plants.
[0097] As used herein, the "amount of available power" refers to the
amount of
power available to be used by the electrical heating system, which may be
limited by
physical and/or economic factors. In some embodiments, the amount of available
power
may not be all of the power that is generated, for example, if some of the
generated
CA 3057184 2019-10-01
17
power is committed to another application or if some of the generated power is
sold to
an electrical power grid when the price for power is at or above a certain
threshold. In
other embodiments, the amount of available power may be the amount of
available
power from a commercial electrical power grid at or below a specific price
threshold.
[0098] In some embodiments, the variably available electrical power
source 119
is a low-carbon power source. As used herein "low-carbon power source" refers
to a
power source that produces power with substantially lower carbon dioxide
emissions
than conventional fossil fuel power sources. In some embodiments, the low-
carbon
power source comprises at least one of of wind power, solar power,
hydroelectric
power, geothermal power, nuclear power, and combinations thereof. In some
embodiments, the electrical heating system 116 may receive power from more
than one
variably available electrical power source 119.
[0099] In some embodiments, the low-carbon power source comprises a co-
generation power source in which power is co-generated along with heat. For
example,
SAGD operations may include one or more natural gas-fired co-generation plants
in
which electricity is co-generated along with steam for injection. In some
embodiments,
the SAGD "co-gen" plant may generate power continuously even when other
demands
for power are low.
[00100] In some embodiments, the electrical heating system 116 may also be
operatively connected to a continuously available power source 120. As used
herein, a
"continuously available electrical power source" refers to a power source from
which at
least some amount of power is approximately constantly available, although
minor
fluctuations may still be possible. For example, the continuously available
electrical
power source 120 may be a natural gas fired steam and power co-generation
plant, an
electrical power grid supplied by at least one power plant capable of
continuous power
generation, or any other continuously available electrical power source.
[00101] Figure 3 is a flowchart of an example method 300 for recovering
viscous
oil from a subterranean reservoir that may be implemented using the system 100
of
Figure 1.
CA 3057184 2019-10-01
18
[00102] At block 302, a first heated vapor-phase working fluid is
injected, via the
injection well 104, to form a vapor chamber 110 in flow communication with the
injection
well 104 and the production well 106.
[00103] In some embodiments, the first heated vapor-phase working fluid
comprises steam. In other embodiments, the first heated vapor-phase working
fluid
comprises at least one vapor-phase solvent that is effective in reducing the
viscosity of
viscous oil by dilution. In other embodiments, the first heated vapor-phase
working fluid
comprises a combination of steam and at least one vapor-phase solvent. In some
embodiments, the vapor-phase solvent may comprise at least one Cl to 030
hydrocarbon solvent. The Cl to C30 hydrocarbon solvent may comprise at least
one of
propane, butane, pentane, hexane, heptane, octane, nonane, decane, undecane,
dodecane, tridecane, and tetradecane. In some embodiments, the vapor-phase
solvent
comprises a multi-component solvent including but not limited to diluent,
natural gas
condensate, kerosene, naptha, and combinations thereof. In other embodiments,
the
vapor-phase solvent may comprise dimethyl ether. In other embodiments, the
vapor-
phase solvent is any suitable vapor-phase solvent capable of mobilizing
viscous oil.
With respect to heat transport performance, a first heated vapor-phase working
fluid at
least partially comprising steam may be preferred in some embodiments because
water
has a particularly high latent heat of vaporization.
[00104] In some embodiments, the first heated vapor-phase working fluid
further
comprises a non-condensable gas (NCG). As used herein, a "non-condensable" gas
refers a gas that does not condense under reservoir conditions. Examples of
suitable
non-condensable gases include, but are not limited to, natural gas, carbon
dioxide,
nitrogen, carbon monoxide, hydrogen sulfide, hydrogen, anhydrous ammonia,
helium,
flue gas, methane, ethane, and combinations thereof.
[00105] The first heated vapor-phase working fluid may be injected at a
suitable
pressure and temperature such that the working fluid remains in vapor phase.
The
upper limit on operating pressure is typically set on a reservoir-specific
basis as the
pressure beyond which the risk of loss of reservoir confinement is deemed to
be too
CA 3057184 2019-10-01
19
high. For both steam-dominated processes, where the hot vapor-phase working
fluid in
the vapor chamber 110 comprises 90% or more steam on a liquid volume
equivalent
basis, and solvent-dominated thermal processes, where the hot vapor-phase
working
fluid in the vapor chamber 110 comprises 90% or more solvent on a liquid
volume
equivalent basis, operating temperature is determined by the operating
pressure. For an
all-steam process, the operating pressure range may be from about 500kPa to
about
5,000kPa corresponding to an operating temperature range from about 150 C to
about
260 C. Preferably the operating pressure ranges from about 1,500kPa to about
3,300kPa corresponding to an operating temperature range from about 200 C to
about
240 C. For solvent-dominated processes the operating pressure may range from
about
500kPa to about 5,000kPa and the corresponding operating temperature depends
on
the composition of the solvent or mixture of solvents used. To achieve
improved energy
intensity performance, preferably the operating temperature for solvent-
dominated
processes ranges from about 40 C to about 150 C.
[00106] A person skilled in the art will recognize that, depending on the
composition of the first heated vapor-phase fluid, some constituents may not
condense
at the boundaries of the vapor chamber 110 and may dissolve into the viscous
oil in a
gaseous state. As one example, methane will remain in vapor phase at the
operating
temperatures and pressures described above.
[00107] The first vapor-phase working fluid may be heated using any
suitable
heating means at a surface facility prior to injection via the injection well
104. In some
embodiments, the first vapor-phase working fluid is heated using the
electrical heating
system 116. In other embodiments, the first vapor-phase working fluid is
heated using
the fired heating system 117 if used. In other embodiments, the first vapor-
phase
working fluid is heated using any other suitable heating means.
[00108] In some embodiments, the first heated vapor-phase working fluid is
injected continuously. As used herein, "continuous injection" or "injected
continuously"
refers to substantially uninterrupted injection of a heated vapor-phase
working fluid,
CA 3057184 2019-10-01
20
although occasional interruptions may be required, for example, for
maintenance or
emergency purposes.
[00109] As the first heated vapor-phase working fluid is injected, a first
production
fluid may be produced via the production well 106 to surface. The first
production fluid
may comprise mobilized oil and condensed working fluid that drains to the
production
well 106 via gravity drainage.
[00110] In some embodiments, injection of the first heated vapor-phase
working
fluid, and production of the first production fluid, is similar to or the same
as a SAGD
process. In other embodiments, injection of the first heated vapor-phase
working fluid,
and production of the first production fluid, is similar to or the same as a
cyclic steam
stimulation (CSS) process, a combination of a SAGD process and a CSS process,
or
any other suitable thermal oil recovery process that promotes the formation of
a vapor
chamber.
[00111] At block 304, injection of the first heated vapor-phase working
fluid is
ceased and a second heated vapor-phase working fluid is intermittently
injected via the
injection well 104.
[00112] The second heated vapor-phase working fluid may comprise at least
one
of steam and a vapor-phase solvent. The vapor-phase solvent may comprise, for
example, any of the solvents described above for the first heated vapor-phase
working
fluid. In some embodiments, the second heated vapor-phase working fluid
further
comprises a non-condensable gas, for example, any of the NCG described above
with
respect to the first heated vapor-phase working fluid. In some embodiments,
the second
heated vapor-phase working fluid has approximately the same composition as the
first
heated vapor-phase working fluid. In other embodiments, the second heated
vapor-
phase working fluid has a different composition than the first heated vapor-
phase
working fluid.
CA 3057184 2019-10-01
21
[00113] The second heated vapor-phase working fluid may be injected at any
suitable temperature and pressure, for example, within the temperature and
pressure
ranges described above with respect to the first heated vapor-phase working
fluid.
[00114] As used here, "intermittently injecting" or "intermittent
injection" of the
second heated vapor-phase working fluid refers to injecting the second heated
vapor-
phase working fluid at an irregular or non-continuous injection rate that
varies over a
given time period and may at some time points be zero. The time period may be,
for
example, an hour, a day, or a week. For clarity, intermittent injection does
not refer to
extended periods of continuous injection followed by extended shut-in periods
with no
injection, such as seen in CSS processes, for example. As one example,
intermittent
injection may comprise injecting a heated vapor-phase working fluid (e.g.
steam) at an
injection rate that varies daily between zero to around 700 m3/day as shown in
Figure
12 and discussed in the Examples below.
[00115] At least a portion of the second vapor-phase working fluid may be
heated
electrically using the electrical heating system 116. In some embodiments, all
of the
second vapor-phase working fluid is heated electrically using the electrical
heating
system 116.
[00116] As the second heated vapor-phase working fluid is injected, a
second
production fluid may be produced via the production well 106 to surface. The
second
production fluid may comprise mobilized oil and condensed working fluid that
drains to
the production well 106 by gravity drainage.
[00117] Therefore, in some embodiments, the continuous injection of a
first heated
vapor-phase working fluid forms a vapor chamber and thereby stores heat in the
reservoir such that the second heated vapor-phase working fluid may be
injected
intermittently. By using a variably available, low-carbon electrical power
source to heat
the second heated vapor-phase working fluid, the greenhouse gas emissions
during
intermittent injection of the second heated vapor-phase working fluid may be
reduced or
minimized compared to conventional thermal oil recovery processes.
CA 3057184 2019-10-01
22
[00118] In some embodiments, the second heated vapor-phase working fluid
is
heated only when power is available from the variably available electrical
power source
119. The second heated vapor-phase working fluid may then be injected, via the
injection well 104, as the second heated vapor-phase working fluid is heated.
In some
embodiments, the instantaneous injection rate of the second heated vapor-phase
working fluid is approximately equivalent to the rate at which the second
heated vapor-
phase working fluid is heated. As used herein, "instantaneous injection rate"
refers to
the injected volume of fluid over a short time period, for example, the volume
of injected
fluid per hour, as opposed to the cumulative injection rate over time. As
described in the
Examples below, the instantaneous injection rate of the second heated vapor-
phase
working fluid may exhibit large amplitude variations including periods during
which the
instantaneous injection rate is essentially zero and periods in which the
instantaneous
steam injection rate is considerably higher than rates typically used in
continuous
injection processes such as SAGD.
[00119] In some embodiments, an instantaneous production rate at the
production
well 106 may be held approximately constant during intermittent injection of
the second
heated vapor-phase working fluid. As used herein, "instantaneous production
rate"
refers to the produced volume of production fluid over a short time period,
for example,
the volume of produced fluid per hour, as opposed to the cumulative production
rate
over time. In this embodiment, the level of the liquid pool 112 above and
around the
production well 106 may rise during periods of high injection and may be drawn
down
during periods of low injection. As the ratio of the instantaneous injection
rate to the
instantaneous production rate may vary, there may be periods during which more
condensed working fluid in the production fluid is produced than heated vapor-
phase
working fluid is injected. In some embodiments, if the condensed working fluid
is to be
recycled for re-injection, additional storage capacity may be needed to store
condensed
working fluid during periods of low injection.
[00120] In other embodiments, the instantaneous production rate at
production
well 106 may be decreased during periods in which the instantaneous injection
rate is
low and increased during periods in which the instantaneous injection rate is
high.
CA 3057184 2019-10-01
23
Therefore, in this embodiment, the level of the liquid pool 112 rises during
periods of low
injection and low production, thereby effectively storing mobilized oil and
condensed
working fluid in the reservoir. During periods of high injection and high
production, the
liquid pool 112 may be drawn down and higher volumes of production fluid may
be
produced to surface.
[00121] In some embodiments, a cumulative oil production rate during
intermittent
injection of the second heated vapor-phase working fluid may be maintained
approximately equivalent to that of a comparable continuous injection thermal
oil
recovery process. As used herein, "cumulative oil production rate" refers to
the
cumulative volume of production fluid produced over time. As used herein,
"comparable", when used in reference to a continuous thermal oil recovery
process,
refers to a thermal gravity drainage process comprising continuous injection
of a
compositionally similar heated vapor-phase working fluid into a reservoir of
similar
petrophysical characteristics. For example, in embodiments in which the second
heated
vapor-phase working fluid is steam, the cumulative oil production rate during
intermittent
injection of the second heated vapor-phase working fluid may be approximately
equivalent to that of a SAGD process operated in the same or a substantially
similar
reservoir.
[00122] In some embodiments, to maintain the cumulative oil production
rate
approximately equivalent to that of the comparable continuous injection
process, higher
instantaneous injection rates may be needed during time periods in which there
is a
large amount of available power in order to compensate for time periods in
which the
amount of available power is low or essentially zero. Therefore, in some
embodiments,
the electrical heating system 116 may require a higher capacity than the fired
heating
systems typically used in conventional continuous injection thermal oil
recovery
processes like SAGD.
[00123] In other embodiments, a first portion of second heated vapor-phase
working fluid heated using the variably available electrical power source 119
may be
supplemented with a second portion of second heated vapor-phase working fluid
heated
CA 3057184 2019-10-01
24
using the continuously available electrical power source 120. In some
embodiments, the
second portion of second heated vapor-phase working fluid is injected
continuously. In
other embodiments, the second portion of second heated vapor-phase working
fluid is
injected only when the amount of power from the variably available electrical
power
source 119 is low. In other embodiments, additional second heated vapor-phase
working fluid may be heated using the optional fired heater system 117. By
supplementing the second heated vapor-phase working fluid heated from the
variably
available power source 119, in some embodiments, the large amplitude
fluctuations in
the instantaneous injection rate may be reduced and a lower capacity
electrical heating
system may be used.
[00124] In other embodiments, a third heated vapor-phase working fluid may
be
continuously injected concurrently with intermittent injection of the second
heated vapor-
phase working fluid. In some embodiments, the third heated vapor-phase working
fluid
may form only a small portion of a cumulative injected volume of the second
and third
heated vapor-phase working fluids by liquid volume equivalent. In some
embodiments,
the third heated vapor-phase working fluid may be about 50% or lower of the
cumulative
injected volume by liquid volume equivalent. In some embodiments, the third
heated
vapor-phase working fluid may be about 25% or lower of the cumulative injected
volume
by liquid volume equivalent.
[00125] In some embodiments, the third heated vapor-phase working fluid
has
substantially the same composition as the second heated vapor-phase working
fluid or
a substantially similar composition. In other embodiments, the third heated
vapor-phase
working fluid may have a different composition than the second heated vapor-
phase
working fluid.
[00126] In some embodiments, the third heated vapor-phase working fluid is
heated via the electrical heating system 116 using power from the continuously
available power source 120. In other embodiments, the third heated vapor-phase
working fluid is heated via the optional fired heating system 117.
CA 3057184 2019-10-01
25
[00127] In other embodiments, a fourth vapor-phase working fluid may be
intermittently injected during periods when the instantaneous injection rate
is at or near
zero. The fourth vapor-phase working fluid may be heated or unheated. In some
embodiments, the fourth vapor-phase working fluid may comprise at least one of
a
vapor-phase solvent and a non-condensable gas. The solvent and non-condensable
gas may comprise any of the solvents and NCG described above for the first or
second
vapor-phase working fluids that can be injected in the vapor-phase at the
operating
temperature and pressure of the vapor chamber 110. By supplementing
intermittent
injection of the second heat transport fluid with intermittent injection of
the fourth vapor-
phase working fluid, the cumulative oil production rate may be maintained
approximately equivalent to that of a continuous injection process without
additional
thermal input or with only minor additional thermal input.
[00128] Figure 4 is a flowchart of another example method 400 that may be
implemented using the system 100 of Figure 1, showing additional details of a
transition
between injection of the first heated vapor-phase working fluid and
intermittent injection
of the second heated vapor-phase working fluid.
[00129] As discussed in the Examples below, the timing of the transition
may
affect oil production performance during intermittent injection of the second
heated
vapor-phase working fluid. A person skilled in the art will understand that
oil production
performance is a multi-factorial measure that includes the time to achieve a
suitably
high oil production rate, the ability to sustain a high oil production rate,
and the ultimate
recovery factor (RF). If the transition to intermittent injection is made too
soon, the oil
production performance may be poorer than desired. The presence of a
sufficiently
large vapor chamber at the transition between injection of the first heated
vapor-phase
working fluid and intermittent injection of the second heated vapor-phase
working fluid
may prevent a reduction in oil production performance.
[00130] As the size of the vapor chamber itself is difficult to directly
monitor, one or
more operating parameters may be monitored as a proxy to estimate the
development
of the vapor chamber. In the example method 400 of Figure 4, the operating
parameter
CA 3057184 2019-10-01
26
is an operating pressure, also referred to as "bottom-hole pressure" or BHP.
In other
embodiments, the operating parameter may be an operating temperature or a
combination of operating pressure and operating temperature. In other
embodiments,
any other suitable proxy for the development of the vapor chamber may be used.
[00131] At block 402 of Figure 4, a first heated vapor-phase working fluid
is
injected via the injection well 104 to form a vapor chamber 110 in flow
communication
with the injection well 104 and the production well 106. The steps at block
402 may be
similar to those of block 302 in Figure 3 as described above.
[00132] At block 404, a target operating pressure range is determined for
the
vapor chamber 110. Although in the example method 400 of Figure 4, the step of
determining the target operating pressure range (block 404) is shown between
the
injection of the first heated vapor-phase working fluid and intermittent
injection of the
second heated vapor-phase working fluid (blocks 402 and 408); a person skilled
in the
art will understand that the target operating pressure range may be determined
at any
time before intermittent injection of the second heated vapor-phase working
fluid,
including during or before injection of the first heated vapor-phase working
fluid.
[00133] The target operating pressure range may have an upper limit and a
lower
limit. In some embodiments, the upper limit of the target operating pressure
range is
based on the allowable maximum operating pressure (MOP), which is determined
with
respect to the depth and geology of the reservoir and is independent of the
thermal oil
recovery process being employed.
[00134] In some embodiments, the lower limit of the target operating
pressure
range is determined based on the minimum operating pressure required to
achieve a
desired oil production performance during intermittent injection of the second
heated
vapor-phase working fluid (block 408, discussed in more detail below). In some
embodiments, the desired oil production performance and the minimum operating
pressure to achieve that oil production performance are determined based on
simulation
studies. In other embodiments, the minimum operating pressure is determined
based on
CA 3057184 2019-10-01
27
the operating pressure that maintained the desired oil production performance
in a
comparable continuous thermal oil recovery process.
[00135] In some embodiments, the lower limit of the target operating
pressure
range may be set at approximately 70 to 95% of the operating pressure required
to
maintain the desired oil production performance in the comparable continuous
injection
thermal oil recovery process. In some embodiments, an approximately 70% value
may
be used when large amplitude fluctuations in the instantaneous injection rate
are
expected during intermittent injection of the second heated vapor-phase
working fluid,
such as in embodiments in which all of the second heat transfer fluid will be
heated
electrically using the variably available power source 119. In other
embodiments, an
approximately 95% value may be used when the fluctuations in the instantaneous
injection rate are expected to be lower, such as in embodiments in which a
first portion
of second heated vapor-phase working fluid heated using the variably available
power
source 119 will be supplemented with a second portion of second heated vapor-
phase
working fluid heated using the continuously available electrical power source
120.
[00136] At block 406, an operating pressure of the vapor chamber 110 is
monitored during injection of the first heated vapor-phase working fluid. In
some
embodiments, the operating pressure may be monitored at set time intervals,
for
example, once per hour, once per day, once per week, etc. In other
embodiments, the
operating pressure may be monitored substantially continuously.
[00137] In some embodiments, the operating pressure of the vapor chamber
110
is monitored by converting temperature data collected by at least one
temperature
sensor 115 in the injection well 104 into corresponding pressure data. For
example, in
embodiments in which the first heated vapor-phase working fluid is steam,
steam
saturation temperature data from the temperature sensors 115 may be converted
to
corresponding steam saturation pressures. In other embodiments, the operating
pressure may be monitored by conducting injection well annulus blanket gas
pressure
surveys. In other embodiments, the operating pressure may be monitored by
periodically reducing the injection rate to near-zero and estimating operating
pressure
CA 3057184 2019-10-01
28
based on measured surface injection pressure. A person skilled in the art will
understand that monitoring operating pressure "during" injection of the first
heated
vapor-phase working fluid may involve temporarily suspending injection to
measure the
operating pressure.
[00138] At block 408, a transition is made from injection of the first
heated vapor-
phase working fluid to intermittent injection of the second heated vapor-phase
working
fluid when the monitored operating pressure is within the target range. As
used herein,
"transition" or "transitioning", when used in reference to injection of the
first and second
heated vapor-phase working fluids, refers to ceasing injection of the first
heated vapor-
phase working fluid and initiating intermittent injection of the second heated
vapor-
phase working fluid.
[00139] In some embodiments, the transition from injection of the first
heated
vapor-phase working fluid to intermittent injection of the second heated vapor-
phase
working fluid is made as soon as, or shortly after, the operating pressure
reaches the
target range. In other embodiments, the transition may be made after the
operating
pressure has remained within the target range for an extended period of time,
for
example, at least one month, two months, three months, or longer. The longer
the first
heated vapor-phase working fluid is continuously injected, the larger will be
the vapor
chamber 110 at the transition to intermittent injection of the second heated
vapor-phase
working fluid, which may reduce the risk that oil production performance drops
during
intermittent injection. In addition, a larger vapor chamber 110 at the
transition may lead
to reduced fluctuations in operating pressure during intermittent injection of
the second
heated vapor-phase working fluid, as described in the Examples below.
[00140] In some embodiments, the timing of the transition may be based on
a
numerical simulation. The numerical simulation may be based on a predicted
availability
of the variably available electrical power source 119 and therefore a
predicted profile of
intermittent injection of the second heated vapor-phase working fluid. For
example, if
wind power is to be used as the variably available electrical power source
119, the
CA 3057184 2019-10-01
29
numerical simulation may use a predicted intermittent injection profile based
on
historical wind patterns in the region from which the wind power will be
sourced.
[00141] In other embodiments, the timing of the transition may be based on
data
from a comparable continuous injection thermal oil recovery process. For
example, for a
comparable continuous process the operating pressure response to short
periods, for
example 1 to 2 days, during which injection of heated vapor-phase working
fluid is
suspended may be recorded for a range of cumulative injected heated vapor-
phase
working fluid volumes. This data may then be used to develop a relationship
between
cumulative injected volume of working fluid, a proxy for vapor chamber size,
and the
rate of operating pressure fall-off during periods of no injection. This
relationship may
then be used to estimate a lower limit for the cumulative injected volume
required to
maintain the operating pressure above a specified lower limit during a period
of no
injection of a specified duration. Then, since injection rate history will be
known, the
estimated lower limit for cumulative injection of heated vapor-phase working
fluid can be
converted into a time at which intermittent injection may begin.
[00142] In other embodiments, the timing of the transition may be based on
a
preselected time, for example, after one month, two months, or three months of
continuous injection of the first heated vapor-phase fluid, as described in
the Examples
below.
[00143] At block 410, operating pressure of the vapor chamber is monitored
during
intermittent injection of the second heated vapor-phase working fluid. The
steps at block
410 may be similar to the steps of block 406 as described above.
[00144] If the operating pressure is within the target range (yes at block
412), then
intermittent injection of the second heated vapor-phase working fluid can
continue at
block 414. The intermittent injection of the second heated vapor-phase working
fluid
may continue in a similar manner to that of block 408.
[00145] If the operating pressure falls below the target operating
pressure range
(no at block 412), then, at block 416, the first or second heated vapor-phase
working
CA 3057184 2019-10-01
30
fluid may be continuously injected to bring the operating pressure into the
target range.
In some embodiments, the steps at block 416 are similar to the steps at block
402. In
other embodiments, a first portion of second heated vapor-phase working fluid
heated
using the variably available electrical power source 119 is supplemented with
injection
of a second portion of second heated vapor-phase working fluid heated using
the
continuously available electrical power source 120 or using the optional fired
heating
system 117 to bring the operating pressure within the target range.
[00146]
The method 400 may then return to block 408, at which point a transition
is again made to intermittent injection of the second heated vapor-phase
working fluid.
At block 410, the operating pressure of the vapor chamber 110 may again be
monitored. If the operating pressure is now within the target range (yes at
block 412),
then intermittent injection of the second heated vapor-phase working fluid may
continue
at block 414. If the operating pressure still falls below the target range (no
at block 412),
then at block 416, continuous injection of the first or second heated vapor-
phase
working fluid can resume. This method 400 may continue in this manner until
the
operating pressure is within the target operating pressure range and
intermittent
injection can continue at block 414.
[00147] As
demonstrated in the Examples below, the large fluctuations in the
instantaneous injection rate during intermittent injection of the second
heated vapor-
phase working fluid may lead to large fluctuations in the operating pressure
of the vapor
chamber 110. Therefore, in some embodiments, additional steps may be taken to
maintain the operating pressure of the vapor chamber 110 within the target
operating
pressure range during intermittent injection of the second heated vapor-phase
working
fluid.
[00148]
Figure 5 is a flowchart of another example method 500, implemented
using the system 100 of Figure 1, with additional steps for maintaining the
operating
pressure within the target operating pressure range during intermittent
injection of the
second heated vapor-phase working fluid.
CA 3057184 2019-10-01
31
[00149] At block 502, a first heated vapor-phase working fluid is injected
via the
injection well 104 to form a vapor chamber 110 in flow communication with the
injection
well 104 and the production well 106. The steps at block 502 may be similar to
those of
block 302 in Figure 3 as described above.
[00150] At block 504, a target operating pressure range is determined for
the
vapor chamber 110. The steps at block 504 may be similar to those of block 404
in
Figure 4 as described above.
[00151] At block 506, a second heated vapor-phase working fluid may be
intermittently injected. At least a portion of the second heated vapor-phase
working fluid
may be heated electrically using the variably available power source 119. The
steps at
block 506 may be similar to those of block 304 in Figure 3 as described above.
[00152] At block 508, an operating pressure of the vapor chamber 110 is
monitored. The steps at block 508 may be similar to those of block 410 in
Figure 4 as
described above.
[00153] If the operating pressure of the vapor chamber 110 is within the
target
operating pressure range (yes at block 510), then the method 500 can return to
block
506 and intermittent injection of the second heated vapor-phase working fluid
can
continue as before.
[00154] If the operating pressure of the vapor chamber 110 is outside of
the target
operating pressure range (no at block 510), then the instantaneous injection
rate of the
second heated vapor-phase working fluid may be adjusted at block 512 to bring
the
operating pressure into the target range. If the operating pressure is above
the upper
limit of the target range, the instantaneous injection rate may be reduced to
lower the
operating pressure. In some embodiments, the instantaneous injection rate may
be
lowered by suspending power to the electrical heating system 116. In other
embodiments, the injection rate may be lowered by injecting only a portion of
the
second heated vapor-phase working fluid that has been heated.
CA 3057184 2019-10-01
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[00155] If the operating pressure is below the lower limit of the target
range, the
instantaneous injection rate may be increased to increase the operating
pressure. In
some embodiments, the injection rate may be increased by supplementing the
second
heated vapor-phase working fluid heated using the variably available power
source 119
with additional second heated vapor-phase working fluid heated using the
continuously
available power source 120 or the fired heater system 117 if used.
[00156] In some embodiments, if the operating pressure is still within the
target
range, but is close to the upper or lower limit, the injection rate may still
be adjusted to
maintain the operating pressure within the target operating pressure range.
[00157] In some embodiments, the lower limit of the target operating
pressure
range may be adjusted upward or downward during the intermittent injection of
the
second heated vapor-phase working fluid based on the observed fluctuations in
operating pressure as well as the desired oil production performance at a
given time.
For example, if the oil production performance drops below a desired level,
the lower
limit may be adjusted upward to increase the oil production rate.
[00158] The method 500 may then return to block 508 and the operating
pressure
of the vapor chamber 110 can be determined again. If the operating pressure is
now
within the target range (yes at block 510), then the method may return to
block 506 and
the intermittent injection of the second heated vapor-phase working fluid may
continue.
If the operating pressure is still outside of the target range, (no at block
510), then the
injection rate may be adjusted again at block 512. In some embodiments, the
method
500 may continue in this manner until the operating pressure is within the
target
operating pressure range and the intermittent injection of the second heated
vapor-
phase working fluid can continue at block 506.
[00159] In other embodiments, to maintain the operating pressure within
the target
operating pressure range, a fourth vapor-phase working fluid may be
intermittently
injected when the instantaneous injection rate of the second heated vapor-
phase
working fluid is at or near zero as discussed above.
CA 3057184 2019-10-01
33
[00160] Due to the potentially large amplitude fluctuations in the
instantaneous
injection rate during intermittent injection of the second heated vapor-phase
working
fluid, there may be extended periods during which the injection rate is
relatively low.
During such periods, unless the production rate is also decreased, the level
of the liquid
pool 112 around the production well 106 may be drawn down, thereby increasing
the
risk of vapor breakthrough into the production well 106. Therefore, in some
embodiments, additional steps may be taken to maintain the liquid pool 112 at
or above
a threshold level during intermittent injection of the second heated vapor-
phase working
fluid.
[00161] Figure 6 is a flowchart showing another example method 600 that
may be
implemented using the system 100 of Figure 1, with additional steps to
maintain the
liquid pool 112 at or above a threshold level during intermittent injection of
the second
heated vapor-phase working fluid.
[00162] The level of the liquid pool 112 may be difficult to directly
monitor from
surface. Therefore, in some embodiments, subcool may be used as a proxy for
the level
of the liquid pool 112. As used herein, "subcool" refers to a difference
between the
saturation temperature for the primary heat transport component of the heated
vapor-
phase working fluid at its partial pressure within the vapor chamber 110 and
the
temperature of the mobilized oil and condensed working fluid entering the
production
well 106. Higher subcool values may indicate a higher level of the liquid pool
112 while
lower subcool values may indicate a lower level of the liquid pool 112 and
thus an
increased risk of vapor breakthrough. In other embodiments, any other suitable
proxy
for the level of the liquid pool 112 may be used.
[00163] At block 602, a first heated vapor-phase working fluid is injected
to form a
vapor chamber 110 in flow communication with the injection well 104 and the
production
well 106. The steps at block 602 may be similar to those of block 302 in
Figure 3 as
described above.
[00164] At block 604, a target subcool is determined as a proxy for a
threshold
level of the liquid pool 112. In some embodiments, the target subcool is a set
CA 3057184 2019-10-01
34
temperature; in other embodiments, the target subcool is a temperature range.
In this
embodiment, the target subcool is determined before intermittent injection of
the second
heated vapor-phase working fluid, for example, during injection of the first
heated vapor-
phase working fluid. In other embodiments, the target subcool may be
determined
during intermittent injection of the second heated vapor-phase working fluid
after
observing the fluctuations in the subcool as the result of fluctuations in the
instantaneous injection rate of the second heated vapor-phase working fluid.
In some
embodiments, the target subcool may be selected based on typical target
subcool
values as practiced in SAGD operations, for example, ranging from about 5 C to
30 C.
[00165] At block 606, a second heated vapor-phase working fluid is
intermittently
injected. The steps at block 606 may be similar to those of block 304 in
Figure 3 as
described above.
[00166] At block 608, a subcool value is determined for at least a
portion of the
production well 106. The subcool value may be determined at one or more
locations
along the well pair 102 where temperature sensors 115 installed along the
length of the
production well 106 may be used to estimate the subcool value at each
temperature
measurement location. In other embodiments, the subcool value may be
determined
using any other suitable method.
[00167] If the determined subcool value is approximately at the target
subcool (yes
at block 610), then the method 600 can return to block 606 and intermittent
injection of
the second heated vapor-phase working fluid can be continue as before. In some
embodiments, the subcool value may be slightly above or below the target
subcool, for
example, within 10% of the target subcool.
[00168] If the determined subcool value is significantly above or below
the target
subcool (no at block 610), then an instantaneous production rate at production
well 106
may be adjusted at block 612. If the subcool value is too low, the
instantaneous
production rate may be decreased to allow the liquid pool 112 to rise and
thereby
reduce the risk of vapor breakthrough. In some embodiments, too high of a
subcool
value may also be undesirable as the higher level of the liquid pool 112 may
reduce the
CA 3057184 2019-10-01
35
overall gravity drainage head and thereby reduce the oil production rate.
Therefore, if
the subcool value is too high, the instantaneous production rate may be
increased to
draw down a portion of the liquid pool 112.
[00169] The method 600 may then return to block 608 and the subcool value
may
be determined again. If the subcool value is now approximately at the target
subcool
(yes at block 610), then the method may return to block 606 and the
intermittent
injection of the second heated vapor-phase working fluid may continue. If the
subcool
value is still too high or too low, (no at block 610), then the production
rate may be
adjusted again at block 612. In some embodiments, the method 600 may continue
in
this manner until the subcool is approximately at the target subcool and
intermittent
injection of the second heated vapor-phase working fluid can continue at block
606.
[00170] In other embodiments, the level of the liquid pool 112 may be
maintained
at or above a threshold level by adjusting the pumping rate of the optional
pump 107. In
this embodiment, the undesirable presence of vapor in the production well 106
can be
detected by monitoring the performance of the pump 107. For example, by
monitoring at
least one of the load, operating temperature, and mechanical vibration of the
pump 107,
the presence and amount of vapor that is co-mingled with the production fluid
may be
detected and estimated. The detection of a significant volume of vapor at the
pump 107
may indicate that the liquid level has been drawn down too low at some point
along the
production well 106, thereby allowing live vapor to enter the production well
106. When
this condition occurs, the pumping rate may be reduced to allow the liquid
level at all
points along the production well 106 to rise until the vapor breakthrough is
remediated,
which may be confirmed by a return to stable performance for the pump 107.
[00171] In other embodiments, the liquid pool 112 may be maintained at or
above
a threshold level using any other suitable method.
[00172] For a given target subcool range, corresponding to a working
range for the
level of the drained liquid pool 112, two different operating strategies may
be chosen
during intermittent injection of the second heated vapor-phase working fluid.
In one, the
liquid pool 112 may be drawn down, by increasing the instantaneous production
rate of
CA 3057184 2019-10-01
36
the second production fluid, during periods when the rate of injection of the
second
heated vapor-phase working fluid is high and may be expanded, by reducing the
instantaneous production rate, during periods when the rate of injection of
the second
heated vapor-phase working fluid is low. In this embodiment, condensed second
working fluid in the liquid pool 112 is effectively stored in the reservoir
103 during
periods when injection of the second heated vapor-phase working fluid is low.
During
periods when injection of the second heated vapor-phase working fluid is high,
the
instantaneous supply of condensed second working fluid produced to surface may
also
be high and such condensed working fluid may be recycled to produce second
heated
vapor-phase working fluid for injection. Thus, this strategy may reduce the
amount of at-
surface storage capacity required to store the recycled second working fluid.
However,
the throughput for treatment facility 109 may fluctuate, perhaps quite
dramatically.
[00173] In other embodiments, the instantaneous production rate is
controlled to
be essentially constant, providing that the subcool is maintained within the
target range.
The advantage of this approach may be that the treatment facility 109 sees an
essentially constant throughput rate. However, there may be a need to provide
more at-
surface storage capacity for recycled second working fluid.
[00174] Numerous variations of the thermal oil recovery processes
described
herein are also possible. As noted above, in some embodiments, instead of a
SAGD-
like well pair as shown in Figures 1 and 2, the system 100 may comprise a
single
injection and production well as used in CSS processes. In these embodiments,
injection of the first heated vapor-phase working fluid may be similar to or
the same as a
CSS process. The second heated vapor-phase working fluid may then be
intermittently
injected during an injection period, followed by a soaking period and then a
production
period. During the soaking and production periods, no second heated vapor-
phase
working fluid may be injected. Embodiments of the methods described above may
be
implemented in a similar fashion in the single-well arrangement. However, an
important
difference between CSS and SAGD processes is that typical operating pressure
for
SAGD may only be a fraction of the allowable maximum to maintain a caprock
seal
whereas, in CSS, operating pressure may be at our above this maximum
CA 3057184 2019-10-01
37
limit. Therefore, implementation of intermittent injection during the
injection cycles of a
CSS-like process may require a much tighter operating pressure range than that
of the
SAGD-like processes described above.
[00175] In other embodiments, variations of the methods described herein
may be
applied to steam flooding or any other suitable thermal oil recovery
processes.
[00176] A few other variations are discussed below using steam as the
exemplary
first and second heated vapor-phase working fluid. However, a person skilled
in the art
will understand that any other suitable heated vapor-phase working fluid may
be used in
the examples described below and embodiments are not limited to steam.
[00177] In some embodiments, the composition of the first or second heated
vapor-phase working fluid may be adjusted over time or may cycle between two
or more
different compositions. As one example, the second heated vapor-phase working
fluid
may initially comprise steam or a mixture of steam and a vapor-phase solvent
and may
later be adjusted to a composition comprising solvent-only or a mixture of
steam and/or
solvent and a non-condensable gas.
[00178] In some embodiments, steam injection may be supplemented with
concurrent or sequential injection of at least one of a solvent and a NCG. The
solvent
and NCG may be any of the solvents or NCG described above with respect to the
first
and second heated vapor-phase working fluids. The solvent may be liquid-phase
or
vapor-phase. The injection of the solvent and/or NCG may be continuous or
intermittent.
If intermittent, solvent and/or NCG injection may vary at the same rate as the
intermittent steam injection (during intermittent injection of the second
heated vapor-
phase working fluid) or at a different intermittent rate.
[00179] In some embodiments, steam injection may be combined with
injection of
at least one natural or synthetic surfactant to reduce the oil-water
interfacial tension.
Injection of the surfactant may be concurrent with steam injection or may be
alternated
with steam injection. The surfactant may be volatile such that the surfactant
is
CA 3057184 2019-10-01
38
transported with the steam to the boundary of the vapor chamber. The
surfactant may
be ionic, zwitterionic, or non-ionic.
[00180] In other embodiments, steam injection may be combined concurrently
or
sequentially with injection of at least one surfactant-generating agent. As
used herein, a
"surfactant generating agent" is a substance that converts native compounds
present in
the reservoir into natural surfactants. In some embodiments, the surfactant
generating
agent comprises at least one of ammonia, an acid compound, and an alkali
compound.
For example, alkali compounds may convert in situ acids in bitumen into
natural
surfactants. The surfactant-generating agent can be combined with the steam or
injected separately in an aqueous solution or a suitable solvent.
[00181] In some embodiments, steam injection may be combined concurrently
or
sequentially with a foaming agent to generate a foam within the reservoir. The
foam
may function to reduce the mobility of the steam, force the steam into
undeveloped
regions along the well pair, and/or contribute to more uniform development of
the steam
chamber. Suitable foaming agents include, for example, alpha olefin sulfonates
(AOS),
alpha olefin sulfonate dimers (AOSD), internal olefin sulfonates (I0S),
alkylaryl
sulfonates (AAS), alkylaryl ethoxy sulfonates, and combinations thereof.
[00182] In other embodiments, any other suitable additive may be injected
concurrently or sequentially with steam and embodiments are not limited by the
specific
additives described herein.
EXAMPLES
[00183] Simulation studies were undertaken to test the viability of a
thermal gravity
drainage process comprising intermittent injection of steam. Conventional SAGD
with
continuous steam injection was chosen as the baseline thermal gravity drainage
process for comparison. Wind power was chosen as the variably available power
source and it was assumed that the profile of steam generation and injection
would
follow the profile of power availability. Simulation studies were performed
using models
of both deep and shallow reservoirs.
CA 3057184 2019-10-01
39
Example 1 ¨ Simulation model of deep reservoir
[00184] A generic two-dimensional Athabasca bitumen SAGD reservoir model
was
implemented in a STARSTm simulator (Computer Modelling Group Ltd., Calgary,
Canada). Figure 7 illustrates the distribution of horizontal permeability in
this model.
[00185] In this model, the depth to the top of the reservoir is 330 m and
the
calculated maximum operating pressure (MOP) is 5,500 kPa. The target oil sand
pay
zone is 25 m thick. The average horizontal absolutely permeability is 3,000
md. The
average oil saturation of the target pay zone is 0.85. The model also includes
an upper
low quality zone for which the absolutely permeability is set at 100 md. The
width of the
model is 100 m and the well pair (injection well and production well) is
located in the
centre of the model. The well length is 1,000 m. The petrophysical and thermal
properties of the geomaterials in the model are typical of those used in
simulations of
Athabasca oil sand reservoirs. The initial reservoir pore pressure is 1,000
kPa. Porosity
is 0.32. Initial reservoir temperature is 12 C. The initial dissolved gas to
oil ratio (GOR)
of the reservoir is 3Ø
Example 2 ¨ Simulation model of shallow reservoir
[00186] To assess the application of intermittent steam injection to
shallow
reservoirs, a generic two-dimensional reservoir model representing a
relatively shallow
reservoir, at a depth of 110m, was developed. The petrophysical properties of
this
shallow reservoir model mimic those of the MacKay River SAGD project run by
Suncor
Energy lnc.TM. The initial reservoir pore pressure is 400 kPa and the
temperature is 7 C.
The initial dissolved gas/oil ratio (GOR) of the reservoir is 0.82, compared
to 3.0 for the
deep reservoir model. The calculated MOP for this shallow reservoir model is
1,800
kPa.
Example 3 ¨ Baseline case for deep reservoir simulations
[00187] To establish flow communication between the injection and
production
wells, a 90-day steam circulation phase was run in both wells using the
HTVVELL utility
in STARS. After 90 days of steam circulation, the temperature at the mid-point
between
CA 3057184 2019-10-01
40
the injection and production well was approximately 85 C. Thereafter, a
continuous
steam injection SAGD simulation was run for the baseline case. The operating
pressure
is set at 2,500 kPa and the maximum steam injection rate is set at 400 m3/day,
which is
representative of typical field practice. The production well is operated
under steam trap
control with a subcool value of 10 C. The SAGD simulation was run for 10
years.
[00188] The steam injection rate and oil production rate for this
baseline case are
shown in Figure 8. It can be observed that maximum steam injection rate
achieved was
a little less than 300 m3/day, 25% below the pre-set maximum. The bottom hole
pressure (BHP) for the injection well (injector) and production well
(producer) are shown
in Figure 9.
Example 4 ¨Baseline case for shallow reservoir simulations
[00189] A continuous steam injection SAGD baseline case for the shallow
reservoir model was run as follows. To establish flow communication between
the
injection and production wells, a 90-day steam circulation phase is run in
both wells
using the HTWELL utility in STARS. After 90 days of steam circulation the
temperature
at the mid-point between the injection and production well is approximately 85
C.
Thereafter, a continuous steam injection SAGD simulation is run for 10 years.
Because
of the reduced MOP, the operating pressure is set at 1,200 kPa and the maximum
steam injection rate is set at 400 m3/day. The production well is operated
under steam
trap control with a subcool value of 10 C. Except for the switch to
intermittent steam
injection, all of the shallow reservoir cases were initialized and run in the
same way.
Example 5 ¨ Wind power availability
[00190] To test the impact intermittent steam injection on SAGD
performance, a
varying steam injection profile was developed to mimic representative variable
availability of wind power in Alberta. To do this, an example of the three-
year wind
power production profiles developed as part of the Canadian Wind Energy
Association's
(CanWEA) 2016 Pan Canadian Wind Integration Study (PCWIS) was used. The final
report of the PCWIS and the hourly wind data are downloadable from the CanWea
CA 3057184 2019-10-01
41
website (www.canwea.ca/wind-integration-study/) and the 10-minute grid cell
data may
be obtained from CanWea upon request. As part of the PCWIS, wind power
generation
profiles were developed for thousands of locations across Canada, including
Alberta.
For each chosen location, an hourly power availability profile was developed
for the
years 2008, 2009, and 2010 based on modelled wind speed data. The profile for
each
site represents the time varying availability of power from an assumed amount
of
installed generation capacity. The site designated ID 3416 in the PCWIS
report, at
longitude -111.03 and latitude 52.259, was chosen for this study. This site is
located
approximately 100 km south of the city of Lloydminster on the Alberta-
Saskatchewan
border.
[00191] To illustrate the degree of variability in the hourly data,
predicted wind
power availability for the year 2008 is shown in Figure 10. Note the y-axis
represents
gross power output in megawatts (MW).
[00192] Monthly wind power availability for each of 2008, 2009, and 2010
is shown
in Figure 11. Although there is quite a bit of variability from year to year,
it can be seen
that wind power availability is general higher in winter than in summer.
Example 6 ¨ Intermittent steam injection profile
[00193] To develop an intermittent steam injection profile that mimicked
the
variable wind power availability profile, the following assumptions were made.
All
available wind power output from a representative PCWIS wind farm site is used
for
electrical steam generation for SAGD operations, such that the availability of
electrically
generated steam is driven by the availability of variable wind power. An
adequate
representation of variability over a multi-year period is provided by
sequentially
repeating the variable hourly profile developed for the three-year period
modelled in the
PCWIS. To a first approximation it is assumed that cumulative oil production
is driven by
cumulative steam injection such that, to compare the impact on oil production,
cumulative annual steam injection should be the same for both the continuous
and
intermittent injection scenarios.
CA 3057184 2019-10-01
42
[00194] Given the foregoing assumptions and the constraint that, in the
STARS
simulator, the smallest time interval for which input steam injection rates
can be
specified is one day, a representative variable hourly steam injection profile
is
implemented as follows. Using the steam injection profile from the continuous
steam
injection base case (as shown in Figure 8), an average daily steam injection
rate is input
for each year of the ten year long simulation run. To capture the impact of
the sort of
hourly variability that results from electrical steam generation using wind
power, the
simulation time step is set to one hour. Variable hourly steam injection rates
are
determined by dividing the daily average rate by 24, effectively converting it
to an
average hourly rate, which is then multiplied by a normalized variable wind
power
availability factor. The normalized variable wind power availability factor is
calculated by
dividing the raw hourly wind power availability predicted by the PCWIS by the
average
predicted hourly wind power availability for the relevant year.
Example 7 ¨ Simulation Cases
[00195] A number of simulation cases were run using hourly variable steam
injection rate to assess the impact of various parameters, including:
reservoir depth; the
timing of the switch from continuous to intermittent steam injection; and the
month in
which intermittent steam injection begins. The combination of parameter values
used for
each simulation case is listed in Table 1.
TABLE 1
Simulation Reservoir Starting month for Timing of switch from
continuous
case depth Intermittent steam injection to intermittent steam
injection
1 330 m January 0 months
2 330 m January 1 month
3 330 m January 2 months
4 330 m January 4 months
330 m June 2 months
6 110 m January 0 months
7 110 m January 2 months
8 110 m January 4 months
CA 3057184 2019-10-01
43
[00196] For simulations using hourly variable steam injection, operating
pressure
control is relaxed to accommodate periodically high instantaneous steam
injection rates
to allow the annual cumulative steam injection to approximately match that of
the
continuous steam injection base case. Also, in the intermittent steam
injection
simulation runs, the maximum steam injection rate restriction of 400 m3/day
that applied
to the continuous steam injection baseline case is removed.
Example 8 ¨ Results of Simulation Case 1
[00197] Figure 12 shows the daily steam injection rate for Case 1, in
which hourly
variable steam injection starts immediately after completion of the same 90-
day period
of steam circulation start-up as used in the baseline case. For comparison,
the daily
steam injection rate for the SAGD baseline case is also shown in Figure 12.
The
equivalent daily steam injection rate for Case 1 ranges from 0 m3/day to 700
m3/day.
[00198] Figures 13 and 14 compare the daily oil rate and cumulative oil
rate,
respectively, between Case 1 and the SAGD baseline. The spike in daily oil
production
at the commencement of intermittent steam injection appears to be an artifact
associated with modelling the impact of a rapid increase in steam pressure on
gravity
drainage of the bank of mobilized oil generated during the steam circulation
phase.
[00199] As shown in Figure 14, the simulation predicts that intermittent
steam
injection can achieve approximately the same oil production performance as the
continuous steam injection baseline. In practice, a number of factors may
reduce the oil
production performance of the intermittent steam injection process. For
example, if the
intermittent steam injection process is operated with a too high of a level of
drained
liquid above and around the production well, the overall gravity drainage head
may be
reduced, thereby reducing the oil production rate. This outcome can be avoided
by
implementing more reliable temperature and pressure monitoring to ensure
reliable
liquid level control at the production well. In combination with improved
liquid level
control, the oil production rate for intermittent steam injection could also
be increased by
increasing cumulative steam injection thereby increasing the time averaged
operating
CA 3057184 2019-10-01
44
temperature. However, this may result in an increased steam-oil ratio,
reflecting a
reduced energy intensity performance.
[00200] Figure 15 compares the injector BHP for Case 1 compared to the
SAGD
baseline case. It can be seen that in Case 1, the BHP spikes above the maximum
operating pressure (MOP) of 5,500 kPa, which is a non-permissible condition.
For the
first two years of operation, the BHP for Case 1 fluctuates above and below
the set BHP
for the SAGD baseline case with significant but ever declining amplitude.
After year
three, the fluctuation in BHP for Case 1 is minimal.
Example 9 ¨ Results of Simulation Cases 2, 3, and 4
[00201] To investigate the impact of a period of continuous steam
injection before
switching to intermittent steam injection, simulation Cases 2, 3, and 4 were
run.
[00202] Figure 16 shows the injector BHP for Cases 2, 3, and 4, in which
intermittent steam injection was preceded by one, two, or four months of
continuous
steam injection, respectively. Injector BHP for the continuous steam injection
SAGD
baseline case is shown for reference. In all three intermittent steam
injection cases, the
allowable MOP of 5,500 kPa is never exceeded. Thus, even a short period of
continuous steam injection, during which the steam chamber is expanded to a
modest
extent, may be sufficient to establish the desired "storage heater"
characteristic of the
steam chamber. Also, it can be seen that as the length of the initial period
of operation
with continuous steam injection is increased, the amplitude of the BHP
fluctuations is
reduced during subsequent operation with intermittent steam injection, most
noticeably
during the first year of intermittent steam injection.
[00203] Figure 17 shows the injector and producer wellbore temperature
for Case
3 compared to the SAGD baseline case. Operating pressure directly determines
steam
condensation and operating temperature at the steam chamber boundary. Wellbore
temperature fluctuates in sync with operating pressure fluctuations. However,
during the
first few years of operation, the magnitude of the wellbore temperature
fluctuations is
significantly lower than the respective fluctuations in operating pressure.
For the injector
CA 3057184 2019-10-01
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wellbore, the maximum percentage temperature fluctuation below the mean is
approximately -6% (13 C below an average of about 225 C) whereas the maximum
percentage pressure fluctuation below the mean is approximately -20% (500 kPa
below
an average of 2,500 kPa). This effect reduces cyclic thermally induced
stresses on
wellbore liners and other hardware.
[00204] Figure 18 shows the daily oil rate for Cases 2, 3 and 4 compared
to the
SAGD baseline case. For all three intermittent steam injection cases, the
amplitude of
the fluctuations in the daily oil rate is significantly reduced by the end of
the third year of
operation.
[00205] Figure 19 shows cumulative oil production for Cases 2, 3 and 4
compared
to the SAGD baseline case. The cumulative oil production curve is
approximately the
same for all cases.
Example 10 ¨ Results of Simulation Case 5
[00206] From the monthly wind power data presented in Figure 11, it can be
seen
that significantly more wind power is available in winter (e.g. during the
month of
January) than in summer (e.g. during the month of June). To investigate the
impact of
the seasonal timing of the switch to intermittent steam injection, simulation
Case 5 was
run. Case 5 is the same as Case 3 except that intermittent steam injection
starts in June
rather than in January.
[00207] Figures 20, 21, and 22 show the BHP, daily oil rate, and
cumulative oil
production, respectively, for Cases 3 and 5 compared to the SAGD baseline
case. The
seasonal shift in the timing of the switch to intermittent steam injection was
not found to
have a significant impact on oil production performance. However, there is an
observable impact on injector BHP, which reaches a maximum of just under 3,500
kPa
for Case 3 relative to 3,000 kPa for Case 5. These results suggest that BHP
during the
early stages of intermittent steam injection may be managed by reducing the
highest
spikes in the injection rate.
CA 3057184 2019-10-01
46
Example 11 ¨ Results for Simulation Cases 6, 7, and 8
[00208] Cases 6, 7, and 8 were run to assess the impact of the timing of
the switch
from continuous to intermittent steam injection for the shallow reservoir
model. Cases 6,
7, and 8 include periods of zero, two, and four months of continuous steam
injection
prior to the switch to intermittent injection, respectively.
[00209] Figures 23, 24, and 25 show injector BHP, daily oil rate, and
cumulative oil
production, respectively, for Cases 6, 7, and 8 compared to the SAGD baseline
case for
the shallow reservoir model. For the shallow reservoir model, daily oil rate
and
cumulative oil production for the intermittent steam injection cases follow a
similar
pattern as was seen for the deep reservoir model. Specifically, cumulative oil
production
is approximately the same for all intermittent steam injection cases as well
as the
baseline case, and the oscillations in daily oil rate are largely attenuated
after three
years of operation.
[00210] However, in absolute terms, the daily oil rate for the deep
reservoir model
is approximately 50% higher than for the shallow reservoir model, indicating
that the
steam chamber is expanding more slowly for all shallow reservoir cases. In
addition, for
cases with intermittent steam injection, early spikes in BHP as a percentage
of the
target continuous injection SAGD baseline are significantly higher for the
shallow
reservoir model compared to the deep reservoir model. Thus, a longer period of
SAGD
operation with continuous steam injection may be required before switching to
intermittent steam injection in shallow reservoirs to avoid instances where
the MOP of
1,800 kPa is exceeded.
Example 12 ¨ Vapor chamber development in the deep reservoir model
[00211] Figure 26 shows the development of the expanding vapor chamber
over
time for the deep reservoir model cases. The vapor chamber develops as the
heated
and mobilized oil drains under gravity, which means that sustained oil
drainage (and
production) requires sustained vapor chamber expansion. However, sustained
expansion of the vapor chamber need not occur at a uniform or smoothly
changing rate.
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Since the cumulative oil production curves are essentially the same for all
the deep
reservoir simulation cases, whether with continuous or intermittent steam
injection, the
expanding cross-sectional area of the vapor chamber as represented in Figure
26 is
representative of all of deep reservoir cases.
[00212] The leftmost image represents the vapor chamber at the end of the
90-day
steam circulation (initialization) period. Referring to the temperature
gradation scale on
the right, it can be seen that at this time only the wellbores are at the
target steam
temperature of 225 C. The centre image represents the vapor chamber after 120
days
of SAGD operation, corresponding to the timing of the switch to variable steam
injection
for Case 4. At this time, there is a substantially expanded zone that has
reached the
target steam temperature. The rightmost image represents the vapor chamber
after 480
days of SAGD operation, by which time the vapor chamber has expanded
substantially
both vertically and horizontally.
Example 14 ¨ Vapor chamber development in the shallow reservoir model
[00213] Figure 27 shows the development of the expanding vapor chamber
over
time for the shallow reservoir cases. Compared to the deep reservoir cases,
the
cumulative rate of vapor chamber expansion is slower, which results from the
lower
mean operating temperature which in turn results from the lower mean target
operating
pressure. As discussed above, the oil production rate for the deep reservoir
cases is
also about 50% higher than for the shallow reservoir cases. Comparing the
graded
temperature scale of Figure 27 to Figure 26, it can be seen that the steam
temperature
for the shallow reservoir cases is approximately 190 C, compared to 225 C for
the deep
reservoir cases.
[00214] Various modifications besides those already described are
possible
without departing from the concepts disclosed herein. Moreover, in
interpreting the
disclosure, all terms should be interpreted in the broadest possible manner
consistent
with the context. In particular, the terms "comprises" and "comprising" should
be
interpreted as referring to elements, components, or steps in a non-exclusive
manner,
indicating that the referenced elements, components, or steps may be present,
or
CA 3057184 2019-10-01
48
utilized, or combined with other elements, components, or steps that are not
expressly
reference.
[00215]
Although particular embodiments have been shown and described, it will
be appreciated by those skilled in the art that various changes and
modifications might
be made without departing from the scope of the disclosure. The terms and
expressions
used in the preceding specification have been used herein as terms of
description and
not of limitation, and there is no intention in the use of such terms and
expressions of
excluding equivalents of the features shown and described or portions thereof.
CA 3057184 2019-10-01
