Note: Descriptions are shown in the official language in which they were submitted.
1
THERMAL SOLVENT GRAVITY DRAINAGE PROCESS WITH OPERATING
STRATEGIES
TECHNICAL FIELD
[1] The technical field generally relates to a gravity drainage process for
recovering heavy oil or bitumen from an underground reservoir using solvent
and
heat. More particularly, the technical field relates to a thermal solvent
injection
process with operating strategies, such as operating strategies involving
pressure
changes, for mobilizing and recovering heavy oil or bitumen from an
underground
reservoir.
BACKGROUND
[2] In situ recovery of viscous petroleum hydrocarbons, such as heavy oil
or
bitumen, from an underground formation, can be performed by injecting a
solvent
within the formation to mobilize the viscous hydrocarbons. Solvent vapor is
injected into the formation via a horizontal well, which can be referred to as
an
injector well. When contacting the cold viscous hydrocarbons in the reservoir,
the
solvent condenses and diffuses into and dissolves the hydrocarbons. As a
result,
the viscous hydrocarbons are diluted to a lower viscosity fluid, which drains
to a
production well that can be placed vertically below the injector well, in a
spaced-
apart relationship. Depending on the solvent composition that is used, some in
situ deasphalting and upgrading of the viscous hydrocarbons can occur. Upon
continuing solvent injection, a solvent chamber can grow around the well pair
and
above the injection well. Such hydrocarbon recovery processes can require the
use of large quantities of solvent, in part because a portion of the solvent
condenses within the chamber prior to reaching the chamber edges. In such
scenarios, larger solvent quantities need to be recovered from the reservoir
and
then recycled via surface facilities.
[3] The performance of the solvent hydrocarbon recovery process can be
impacted by its operating conditions. Various challenges exist in terms of
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operating strategies for recovering hydrocarbons, such as heavy oil or
bitumen,
from an underground reservoir using solvent vapour injection.
SUMMARY
[4]
According to an aspect, there is provided a process for recovering bitumen
from an underground reservoir having a horizontal injection well and a
horizontal
production well located below the injection well. The process comprises
a first phase during which a solvent comprising butane is injected in vapor
form via the injection well at a first pressure of from about 50 to about 300
kPa above an initial reservoir pressure condition to enter the reservoir and
develop an extraction chamber extending upward and outward from the
injection well;
a second phase during which the solvent is injected via the injection well
into the extraction chamber at a second pressure that is lower than the first
pressure and at most about 50 kPa above an initial reservoir pressure
condition;
wherein each of the first and second phases further comprises:
providing heat to the injection well;
condensing the solvent at a bitumen extraction interface thereby
delivering heat to the bitumen and dissolving the bitumen; and
recovering produced fluids comprising at least bitumen and solvent
from the production well;
wherein the heat is provided using downhole heating means
delivering heat energy at a rate per unit length ranging about 300 to
about 800 W/m, and/or through injecting the solvent in a superheated
state at a temperature of at least 100 C above a dew point thereof.
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[5] In some implementations, the process further comprises monitoring a
process parameter during the first phase and/or the second phase.
[6] In some implementations, the process parameter comprises at least one
of
HBR, SBR and a bitumen production rate.
[7] In some implementations, the downhole heating means includes an
electric resistive heater.
[8] In some implementations, the first phase is performed after completion
of
a start-up operation for the recovery process.
[9] In some implementations, the first phase is performed as part of a ramp-
up
phase of the recovery process.
[10] In some implementations, the first phase is performed until a bitumen
production rate reaches a plateau and/or inflection point.
[11] In some implementations, the first phase is performed as part of a ramp-
up
phase of the recovery process and until reaching an early portion of a bitumen
production rate plateau.
[12] In some implementations, the first pressure ranges from about 350 to
about 1000 kPa. In other implementations, the first pressure ranges from about
350 to about 900 kPa, or from about 350 to about 800 kPa, or from about 500 to
about 700 kPa, or from about 600 to about 700 kPa, or from about 400 to about
550 kPa, or from about 450 to about 500 kPa.
[13] In some implementations, the first pressure is about 700 kPa and the
second pressure is about 500 kPa.
[14] In some implementations, the second phase includes an initial transition
phase during which the pressure is gradually reduced from the first pressure
to
the second pressure. In some implementations, the initial transition phase is
performed over a period of about 10 months to about 15 months.
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[15] In some implementations, the solvent injection in the second phase is
performed about 1 year to about 2 years after a peak production rate is first
achieved.
[16] In some implementations, the heat is provided during the first phase at a
first phase heat energy that is lower than a second phase heat energy in the
second phase.
[17] In some implementations, the first phase, heat energy is provided at a
rate
per unit length ranging from about 300 to about 600 W/m. In another
implementation, in the second phase, heat energy is provided at a rate per
unit
length ranging from about 400 to about 800 W/m.
[18] In some implementations, the superheated solvent has a temperature
ranging from about 30 C to about 200 C. In other implementations, the
superheated solvent has a temperature ranging from about 30 C to about 170 C.
In another implementation, the superheated solvent has a temperature ranging
from about 30 C to about 140 C.
[19] According to another aspect, there is provided a process for recovering
bitumen from an underground reservoir having a horizontal injection well and a
horizontal production well located below the injection well. The process
comprises:
a first phase during which a solvent is injected in vapour form into the
injection well at a first pressure that is higher than an initial reservoir
pressure condition;
a second phase during which the solvent is injected into the injection well
at a second pressure that is lower than the first pressure;
wherein each of the first and second phases further comprises:
providing heat to the injection well;
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condensing the solvent at a bitumen extraction interface thereby
delivering heat to the bitumen and dissolving the bitumen; and
recovering produced fluids comprising at least bitumen and solvent
from the production well.
[20] In some implementations, the solvent is selected and provided in an
amount to induce asphaltene precipitation in the reservoir.
[21] In some implementations, the solvent is selected from propane, butane,
pentane or any mixture thereof. In particular implementations, the solvent is
butane.
[22] In some implementations, the process further comprises monitoring a
process parameter during the first phase and/or the second phase.
[23] In some implementations, the process parameter comprises at least one of
HBR, SBR and a bitumen production rate.
[24] In some implementations, the heat is provided using a downhole electric
resistive heater, through electromagnetic heating, through injecting the
solvent in
a superheated state, or a combination thereof.
[25] In some implementations, the first phase is conducted to cause rapid
growth of a first phase solvent chamber in the reservoir.
[26] In some implementations, the first phase is performed after completion of
a start-up operation for the recovery process.
[27] In some implementations, the first phase is performed as part of a ramp-
up
phase of the recovery process.
[28] In some implementations, the first phase is performed until a bitumen
production rate reaches a plateau.
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[29] In some implementations, the first phase is performed as part of a ramp-
up
phase of the recovery process and until reaching an early portion of a bitumen
production rate plateau.
[30] In some implementations, the first pressure is from about 50 to about 600
kPa above the initial reservoir pressure condition. In some implementations,
the
first pressure is from about 50 to about 500 kPa above the initial reservoir
pressure condition. In other implementations, the first pressure is from about
50
to about 400 kPa above the initial reservoir pressure condition. In another
implementation, the first pressure is from about 50 to about 300 kPa above the
initial reservoir pressure condition.
[31] In some implementations, the solvent is butane and the first pressure
ranges from about 350 to about 1000 kPa. In other implementations, the solvent
is butane and the first pressure ranges from about 350 to about 900 kPa, or
from
about 350 to about 800 kPa, or from about 500 to about 700 kPa, or from about
600 to about 700 kPa.
[32] In some implementations, the second pressure is from about 50 to about
400 kPa above the initial reservoir pressure condition. In some
implementations,
the second pressure is from about 50 to about 300 kPa above the initial
reservoir
pressure condition. In other implementations, the second pressure is from
about
50 to about 200 kPa above the initial reservoir pressure condition. In another
implementation, the second pressure is from about 50 to about 100 kPa above
the initial reservoir pressure condition.
[33] In some implementations, the second pressure is at most about 50 kPa
above the initial reservoir pressure condition.
[34] In some implementations, the solvent is butane and the second pressure
ranges from about 450 to about 500 kPa.
[35] In some implementations, the second pressure is 75% or lower than the
first pressure. In other implementations, the second pressure is 50% or lower
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than the first pressure. In another implementation, the second pressure is 25%
or
lower than the first pressure.
[36] In some implementations, the second pressure is at least about 200 kPa
lower than the first pressure.
[37] In some implementations, the difference between the second pressure
and the initial reservoir pressure condition is at least about 200 kPa lower
than
the difference between the first pressure and the initial reservoir pressure
condition.
[38] In some implementations, the second phase includes an initial transition
phase during which the pressure is gradually reduced from the first pressure
to
the second pressure. In some implementations, the initial transition phase is
performed over a period of about 10 months to about 15 months.
[39] In some implementations, the solvent injection at the lower second
pressure is performed about 1 year to about 2 years after a peak production
rate
is first achieved.
[40] In some implementations, the heat provided during the first phase is
lower
than the heat provided in the second phase.
[41] In some implementations, the heat is provided during the first phase at a
first phase heat energy that is lower than a second phase heat energy in the
second phase.
[42] In some implementations, in the first phase, heat energy is provided at a
rate per unit length ranging ranging from about 300 to about 1200 W/m. In some
implementations, in the first phase, heat energy is provided at a rate per
unit
length ranging from about 300 to about 1000 W/m, or from about 300 to about
800 W/m, or from about 300 to about 600 W/m, or from about 300 to about 500
W/m, or from about 300 to about 400 W/m.
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[43] In some implementations, in the first phase, heat energy is provided at a
rate per unit length ranging from about 400 to about 600 W/m. In some
implementations, in the first phase, heat energy is provided at a rate per
unit
length ranging from about 400 to about 500 W/m.
[44] In some implementations, in the first phase, heat energy is provided at a
rate per unit length ranging from about 500 to about 600 W/m.
[45] In some implementations, in the second phase, heat energy is provided at
a rate per unit length ranging from about 400 to about 1200 W/m. In some
implementations, in the second phase, heat energy is provided at a rate per
unit
length ranging from about 400 to about 1000 W/m, or from about 400 to about
700 W/m, or from about 400 to about 600 W/m.
[46] In some implementations, in the second phase, heat energy is provided at
a rate per unit length ranging from about 500 to about 800 W/m. In some
implementations, in the second phase, heat energy is provided at a rate per
unit
length ranging from about 500 to about 700 W/m, or from about 500 to about 600
W/m.
[47] In some implementations, in the second phase, heat energy is provided at
a rate per unit length ranging from about 600 to about 800 W/m. In some
implementations, in the second phase, heat energy is provided at a rate per
unit
length ranging from about 600 to about 700 W/m.
[48] In some implementations, the heat energy is provided at least using a
downhole electric resistive (ER) heater.
[49] In some implementations, the heat is provided at least through injecting
superheated solvent and the superheated solvent has a temperature of at least
100 C above a dew point thereof and up to a maximum temperature of 250 C. In
some implementations, the heat is provided at least through injecting
superheated solvent and the superheated solvent has a temperature of at least
100 C above a dew point thereof and up to a maximum temperature of 200 C.
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[50] In some implementations, the heat is provided at least through injecting
superheated solvent and the superheated solvent has a temperature ranging
from about 30 C to about 200 C. In some implementations, the heat is provided
at least through injecting superheated solvent and the superheated solvent has
a
temperature ranging from about 30 C to about 170 C, or from about 30 C to
about 140 C.
[51] In accordance with another aspect, there is provided a process for
recovering bitumen from an underground reservoir having a horizontal injection
well and a horizontal production well located below the injection well. The
process comprises:
injecting a solvent in vapour form into the underground reservoir via the
injection well at a first pressure during a first phase, the first pressure
being higher than an initial reservoir pressure;
monitoring a process parameter;
injecting the solvent in vapour form into the underground reservoir via the
injection well at a second pressure during a second phase, the second
pressure being determined at least in part based on the process
parameter; and
recovering a production fluid comprising bitumen via the production well.
[52] In some implementations, the process further comprises providing heat to
the injection well.
[53] In some implementations, the heat is provided using a downhole electric
resistive heater, through electromagnetic heating, through injecting the
solvent in
a superheated state, or a combination thereof.
[54] In some implementations, the process parameter comprises at least one of
HBR, SBR and a bitumen production rate.
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[55] In some implementations, when the HBR and/or the SBR reaches an
upper threshold, the process is transitioned from the first phase to the
second
phase.
[56] In some implementations, when the HBR and/or the SBR has been
maintained at an upper threshold for a given duration, the process is
transitioned
from the first phase to the second phase.
[57] In some implementations, the heat is provided during the second phase to
remain within a similar range of the bitumen production rate achieved during
the
first phase.
[58] In some implementations, the heat is provided during the second phase to
reduce a pressure differential between the first pressure and the second
pressure.
[59] In some implementations, the heat is provided during the second phase to
decrease the HBR or the SBR compared to the first phase.
[60] In some implementations, the second pressure is determined to limit
solvent leaking-off to the underground reservoir.
[61] In accordance with another aspect, there is provided a method to
determine an operating strategy for a process for recovering bitumen from an
underground reservoir having a horizontal injection well and a horizontal
production well located below the injection well using solvent injection. The
process comprises:
performing a first set of reservoir simulations over a first range of
simulation pressures to determine a first pressure at which to inject the
solvent in a first phase of the process, wherein the first pressure enables
to achieve a peak bitumen production rate or to achieve the peak
bitumen production faster than other pressures within the first range of
simulation pressures;
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performing a second set of reservoir simulations over a second range of
simulation pressures to obtain a set of data indicative of solvent
consumption over a period of time; and
performing a third set of reservoir simulations using the first pressure in
the first phase and the set of data indicative of solvent consumption to
determine a second pressure at which to inject the solvent in a second
phase of the process, wherein the second pressure is lower than the first
pressure.
[62] In some implementations, the data indicative of solvent consumption
comprises at least one of SBR and HBR.
[63] In some implementations, the first range of simulation pressures is
between about a native pressure of the underground reservoir and about 300
kPa above the native pressure of the underground reservoir.
[64] In some implementations, the first range of simulation pressure is
determined in accordance with a property of the underground reservoir.
[65] In some implementations, the property of the underground reservoir
comprises reservoir permeability, water saturation or water mobility.
[66] In some implementations, the period of time corresponds to between a
completion of a start-up operation for the recovery process up until a wind-
down
phase.
[67] In some implementations, the method further comprises performing a
fourth set of simulations to determine at which temperature to inject the
solvent in
the first phase and/or the second phase.
[68] In some implementations, the method further comprises injecting the
solvent as vaporized solvent into the underground reservoir at the first
pressure
during the first phase of the process, and injecting the solvent as vaporized
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solvent into the underground reservoir at the second pressure during the
second
phase of the process.
[69] It should also be noted that various aspects, implementations, features
or
steps described or illustrated herein can be combined with other aspects,
implementations, features or steps.
BRIEF DESCRIPTION OF THE DRAWINGS
[70] Fig. 1 is a cross sectional view of a solvent chamber developed above a
horizontal well pair within an underground reservoir, using a thermal solvent
recovery process according to some implementations.
[71] Fig. 2 is a diagram representing the effect of operating pressure and
heat
input on cumulative bitumen (oil) in a simulation of a two-phase thermal
solvent
recovery process according to some implementations. The simulation
contemplates the use of an electric resistive heater to provide heat.
[72] Fig. 3 is a diagram representing the effect of operating pressure and
heat
input on cumulative hold-up in a simulation of a two-phase thermal solvent
recovery process according to some implementations. The simulation
contemplates the use of an electric resistive heater to provide heat.
[73] Fig. 4 is a diagram representing the effect of operating pressure and
heat
input on bitumen (oil) rate in a simulation of a two-phase thermal solvent
recovery
process according to some implementations. The simulation contemplates the
use of an electric resistive heater to provide heat.
[74] Fig. 5 is a diagram representing the effect of operating pressure and
heat
input on solvent-to-bitumen (oil) ratio in a simulation of a two-phase thermal
solvent recovery process according to some implementations. The simulation
contemplates the use of an electric resistive heater to provide heat.
[75] Fig. 6 a diagram representing the effect of operating pressure and heat
input on cumulative bitumen (oil) in a simulation of a two-phase thermal
solvent
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recovery process according to some implementations. The simulation
contemplates the use of superheated solvent to provide heat.
[76] Fig. 7 is a diagram representing the effect of operating pressure and
heat
input on cumulative hold-up in a simulation of a two-phase thermal solvent
recovery process according to some implementations. The simulation
contemplates the use of superheated solvent to provide heat.
[77] Fig. 8 is a diagram representing the effect of operating pressure and
heat
input on bitumen (oil) rate in a simulation of a two-phase thermal solvent
recovery
process according to some implementations. The simulation contemplates the
use of superheated solvent to provide heat.
[78] Fig. 9 is a diagram representing the effect of operating pressure and
heat
input on solvent-to-bitumen (oil) ratio in a simulation of a two-phase thermal
solvent recovery process according to some implementations. The simulation
contemplates the use of superheated solvent to provide heat.
DETAILED DESCRIPTION
[79] Techniques described herein relate to processes for recovering heavy oil
or bitumen from an underground reservoir using a solvent and heat to enhance
mobilizing the heavy oil or bitumen within the reservoir. More particularly,
the
techniques involve injecting at least one solvent in the underground reservoir
while providing heat at the injection location, for recovering heavy oil or
bitumen,
where the operating pressure and heating conditions are selected to balance
bitumen production rate, solvent-to-bitumen ratio and/or hold-up bitumen
ratio.
[80] In some implementations, there is provided a process for recovering
bitumen from an underground reservoir having a horizontal injection well and a
horizontal production well located below the injection well in a spaced-apart
relationship. The process includes a first phase and a second phase. During
the
first phase, a solvent is injected in vapor form via the injection well into
the
reservoir so as to pressurize the reservoir to a first pressure that is higher
than an
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initial reservoir pressure condition. During the second phase, the solvent is
injected via the injection well so that the reservoir pressure is reduced to a
second pressure that is lower than the first pressure. In each one of the
first and
second phases, the solvent is injected into the reservoir at a sufficiently
high
temperature such that the solvent remains in vapour phase until it contacts
bitumen at an extraction interface. In order to do so, the solvent can be, for
instance, heated at surface to be injected via the injected well as a
superheated
solvent, and/or various heating means can be provided in at least one of the
horizontal wells so that the solvent can be heated and vaporized as it travels
therealong prior to being injected into the reservoir. The process further
includes
providing heat to the injection well, condensing the solvent at the bitumen
extraction interface thereby delivering heat to the bitumen and dissolving the
bitumen, and recovering produced fluids including at least bitumen and solvent
via the production well.
[81] "Bitumen" as used herein can refer to hydrocarbon material extracted from
bituminous formations, such as oil sands formations, the density of which is
typically around 1000 kg/m3 and the American Petroleum Industry's (API)
gravity
is around 8 . Bitumen can be recovered from a bitumen-containing reservoir
using in situ recovery processes. The bitumen can include various non-
hydrocarbon compounds (e.g., sulfur, metals, etc.) that are often found in
bitumen and can be associated with certain hydrocarbon components (e.g.,
asphaltenes). Examples of bitumen include bitumen extracted from the
Athabasca and Cold Lake regions, in Alberta, Canada.
[82] "Heavy oil", which can also be referred to as "heavy crude oil", can
refer to
any liquid petroleum with an American Petroleum Industry's (API) gravity of
less
than 22.3 and a density of about 920 to about 1000 kg/m3, although the
density
could be higher. Heavy oil usually contains asphaltenes and resins.
[83] For ease of reading, the term "bitumen" will be used in the following
description of some implementations. However, one will understand that the
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described processes can be used in underground reservoirs containing either
bitumen or heavy oil.
[84] Some of the quantitative expressions mentioned herein can be qualified
with the term "about". The term "about" means within an acceptable error range
for the particular value as determined by one of ordinary skill in the art,
which will
depend in part on how the value is measured or determined, i.e. the
limitations of
the measurement system. It is commonly accepted that a 10% precision measure
is acceptable and encompasses the term "about".
[85] As mentioned above, the process described herein involves the injection
of solvent to mobilize and then recover bitumen from a well region around
horizontal injection and production wells of a well pair in subsurface bitumen
containing reservoirs. This process can be used after fluid communication has
been established between the wells, i.e. after completion of a start-up phase.
[86] In some implementations, a SAGD-type well pair as represented in Fig. 1
can be used for implementing the process. The well pair includes a first
horizontal well 12, also referred to as an injection well, and a second
horizontal
well 14, also referred to as a production well, downwardly spaced apart from
the
injection well 12. A bitumen containing space is defined between the two
horizontal wells and can be referred to as the interwell region 16. It should
be
understood that SAGD-type horizontal wells refer to the wells in their
entirety
including both the vertical and horizontal portions thereof. Multiple well
pairs are
generally arranged in parallel to one another in the reservoir, with an array
of well
pairs extending from a well pad at surface.
[87] As mentioned above, the present process is generally implemented after
completion of a start-up phase. In some implementations, the start-up phase
can
include a reservoir conditioning phase during which a mobilizing fluid, such
as a
non-deasphalting fluid, is circulated in each horizontal well and then pushed
from
the injection well to the production well to sweep the interwell region. An
initial
pre-heating of the horizontal wells can be performed before circulating the
non-
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deasphalting fluid. The mobilizing fluid can include diesel, naphtha or any
other
fluid known in the art for assisting mobilizing the bitumen in the interwell
region
and establish communication between the injection and production well. The
fluid
can also include steam, or a combination of a hydrocarbon-based fluid as
mentioned above and steam.
[88] Various other start-up methods can be used to establish fluid
communication between the horizontal wells. For instance, start-up methods can
include fluid injection, fluid circulation, electrical heating, radio-
frequency (RF)
heating, chemical injection in at least one of the wells. Various combinations
of
these start-up methods can also be implemented. The injected or circulated
fluid
can include a hydrocarbon solvent, steam or a combination thereof, and the
fluid
can be provided as a vapour or a liquid. The start-up method can also be
conducted in more than one stage using a different technique for each stage.
[89] Once the start-up phase is completed and fluid communication has been
established between the horizontal wells, a heated solvent is injected into
the
reservoir in vaporized form via the injection well 12. When contacting the
cold
bitumen in the reservoir, the solvent condenses on the bitumen surface and
releases latent heat of condensation which is transferred to the bitumen. In
addition to providing heat to the bitumen, the solvent can also contribute to
diluting the bitumen. The bitumen that has been diluted and heated produces a
mobilized fluid having a lower viscosity, enabling the mobilized fluid to
drain
towards the production well 14. From the production well 14, the mobilized
bitumen can be recovered to the surface as a production fluid and be further
treated using surface facilities. The production fluid, in addition to the
mobilized
bitumen and some solvent, can include water that can be present in the
reservoir,
such as connate water from the pores of rock sediments, and also some solids
and gas. Depending on the solvent composition that is used, some degree of in
situ solvent deasphalting can occur, and asphaltenes can be precipitated
within
the reservoir resulting in an in situ upgrading of the bitumen.
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[90] Upon continuation of solvent injection, a solvent chamber 18 can grow
upward and outward from the injection well 12. Optionally, to reduce early
condensation of solvent and therefore solvent demand, additional heat can be
provided in the reservoir. Heat addition can assist in maintaining the solvent
in
vapor state within the solvent chamber such that less solvent is produced with
the bitumen when the production fluid is recovered to the surface via the
production well. In such implementations, the heat can be provided at the
injection well, at the production well, or both. The heat can also be provided
proximate the injection, e.g., above the injection well, within the chamber.
Various methods and equipment can be used to provide heat, for instance
providing downhole heaters or injecting solvent that has been superheated at
surface.
[91] In the present process, at least one solvent can be injected in the
reservoir
to dissolve bitumen and thereby reduce the bitumen viscosity, such that
bitumen
having a reduced viscosity can drain towards the production well and be
recovered to the surface. In some implementations, the solvent can be selected
and provided in an amount sufficient to induce asphaltene precipitation and
deposition within the reservoir. Examples of solvents that can be used are low
molecular weight alkanes, such as propane, butane or pentane, as well as
combinations of such solvents can also be used.
[92] In the present thermal process, the solvent is injected into the
reservoir as
a vaporized solvent. Various methods can be used to introduce the solvent as
vaporized solvent into the reservoir. For instance, heat can be provided to
the
injection well by direct wellbore heating, for instance by using electric
resistive
heaters. In other implementations, the solvent can be injected in a
superheated
state. A combination of superheated solvent and downhole heating can also be
used. In this context, "superheated solvent" refers to a solvent that is
injected at a
temperature above its dew point temperature at the operating reservoir
pressure.
Other heating means can include hot tubes that use a circulating heating media
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provided in the well, induction or electromagnetic heating, radio-frequency
heating, microwave heating, or the like.
[93] In some implementations, the injection design can include injecting the
solvent in vapour phase and then controlling the degree of superheating of the
vapour via surface heaters and downhole electric resistive heaters. The degree
of superheat can be 20 C, 30 C, 40 C or more.
[94] In some implementations, heating through downhole heating and/or
injecting a superheated solvent having a certain degree of superheat can
contribute to maintaining solvent within the solvent chamber in a vaporized
state.
[95] The operating pressure in the solvent chamber, i.e., the pressure within
the solvent chamber, and, optionally, the heat input provided to keep the
solvent
in vapor state in at least a portion of the solvent chamber, can impact the
performance of the bitumen recovery process. For instance, process parameters
such as solvent-bitumen ratio (SBR), hold-up bitumen ratio (HBR) and/or
bitumen
production rate can be particularly affected. For instance, injecting solvent
such
that the solvent chamber operating pressure is at a high pressure, or within a
range of high pressures, can facilitate rapid solvent chamber development,
which
in turn can result in a higher production rate. On the other hand, operating
the
solvent chamber at a high pressure can result in a high SBR and HBR, which can
be undesirable, for example for economical reasons. Operating the solvent
chamber at a low pressure, or within a range of low pressures, can results in
a
low SBR and HBR, which can be advantageous under certain circumstances.
The present process proposes operating strategies that include initially
injecting
solvent at high pressure, and then injecting solvent at a lower pressure
during the
hydrocarbon recovery process to balance bitumen production rate, SBR and/or
HBR.
[96] In some implementations, an example of an operating pressure strategy
for the present thermal solvent hydrocarbon recovery process can include
initially
injecting solvent at a high injection pressure to rapidly grow the solvent
chamber
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in the reservoir, and subsequently reducing the injection pressure such that
the
solvent is injected at a lower injection pressure. In some implementations,
the
transition from a high injection pressure to a low injection pressure can be
implemented to lower the long term SBR and HBR. The initial rapid chamber
growth can result in a solvent chamber having a large surface area, which can
facilitate bitumen drainage when subsequently operating at lower pressures as
recovery operations continues over time. This operating strategy can result in
a
bitumen production profile that is substantially similar to one that would be
obtained using high pressures only, but with limited impact on long term
solvent
performance, SBR and HBR.
[97] According to the present process, the solvent can be injected at a first
pressure during a first phase and then at a second pressure during a second
phase, the second pressure being lower than the first pressure. The "first
pressure" and "second pressure" at which the solvent can be injected refer to
the
pressure that is reached in the chamber in the underground reservoir upon
solvent injection. The expression "extraction pressure" or "injection
pressure" can
also be used to refer to such pressure in the reservoir. The first pressure is
also
above the initial reservoir pressure condition. The terms "initial reservoir
pressure
condition" or "initial reservoir pressure" refer to the pressure in the
reservoir
before starting the present two-phase recovery process, which corresponds to
the reservoir native pressure.
[98] By injecting the solvent at high pressure in the first phase of the
process,
solvent leak-off can be facilitated which, in turn, can enhance convective
mixing
of the solvent with the bitumen. The solvent/bitumen fluid that is produced in
situ
can then drain towards the production well and be produced at the surface,
resulting in a rapid growth of the solvent chamber in the reservoir.
[99] In some implementations, the injection pressure in the first phase of the
process can range from about 50 to about 600 kPa above the initial reservoir
pressure. In other implementations, the injection pressure in the first phase
can
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range from about 50 to about 500 kPa, or from about 50 to about 400 kPa, or
from about 50 to about 300 kPa, or from about 50 to about 200 kPa, or from
about 50 to about 100 kPa above the initial reservoir pressure.
[100] As previously mentioned, the solvent used for assisting the bitumen
recovery from the underground reservoir can be butane. When butane is used as
the solvent, the injection pressure in the first phase can range from about
350 to
about 1000 kPa, for example. In some implementations where butane is the
solvent that is injected in the reservoir, the first phase injection pressure
can
range from about 350 to about 900 kPa, or from about 350 to about 800 kPa, or
from about 500 to about 700 kPa. In other implementations, butane can be
injected in the first phase at an injection pressure ranging from about 600 to
about 700 kPa. The selection of the pressure in the first phase of the process
can
be determined in accordance with the type of reservoir, the type of solvent,
and
the initial pressure condition thereof. In addition, the first phase can be
operated
at a generally constant first phase pressure, or can be operated at different
pressures that are within a first operating envelope for the first phase
pressure.
[101] In some implementations, the first phase of the process involving
injecting
the solvent at high pressure can be performed after completion of the start-up
operation for the recovery process. This first phase can therefore be
performed
as part of the ramp-up phase of the recovery process. During this phase, the
communication zone between the wells is expanded axially along the full well
pair
length to enhance conformance along the well, and the solvent chamber grows
vertically up to the top of the bitumen zone in the reservoir.
[102] In some implementations, the first phase of the process can be performed
until a bitumen production rate reaches a plateau or a maximum, i.e., when
substantially full expected production rate capacity is attained. The
injection of
the solvent at high pressure can be maintained throughout the ramp-up and into
the early portion of the plateau to maximize bitumen production rates. In some
implementations, the first phase can be performed until the bitumen production
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rate reaches about 120 to about 160 m3/d, or from about 120 to about 150 m3/d,
or from about 120 to about 140 m3/d, or from about 130 to about 150 m3/d, or
from 130 to about 140 m3/d.
[103] In the second phase of the present process, the solvent is injected into
the
reservoir at a lower pressure than that of the first phase. In some
implementations, the injection pressure can be gradually decreased from the
higher level in the first phase to the lower level in the second phase. In
other
words, a transition phase can be implemented at the end of the high pressure
injection phase until reaching the lower pressure intended to be used for the
second phase.
[104] In some implementations, the solvent injection pressure in the second
phase can range from about 50 to about 400 kPa above the initial reservoir
pressure condition. In other implementations, the solvent injection pressure
in the
second phase is at most about 10 kPa, 20 kPa, 30 kPa, 40 kPa, 50 kPa, 60 kPa,
70 kPa, 80 kPa, 90 kPa or 100 kPa above an initial reservoir pressure, for
example. Using a lower solvent injection pressure in the second phase of the
process can help minimize solvent losses as the solvent chamber spreads and/or
the production rates decline. In some implementations, the injection pressure
is
lowered in the second phase to approach or generally match the initial
reservoir
conditions thereby minimizing solvent leak-off rate to the native reservoir
adjacent to the swept solvent chamber.
[105] In some implementations, butane can be used as the solvent for
mobilizing the bitumen within the reservoir, and the butane injection pressure
during the second phase of the process can range from about 400 to about 550
kPa or 450 to 500 kPa.
[106] In some implementations, the second phase injection pressure can be at
least about 100 kPa, 150 kPa, 200 kPa, or 250 kPa lower than the first
pressure.
In other implementations, the difference between the second pressure and the
initial reservoir pressure condition can be at least about 200 kPa, 250 kPa or
300
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kPa lower than the difference between the first pressure and the initial
reservoir
pressure condition.
[107] In some implementations, the solvent is injected in the second phase at
a
pressure which can be at most 75% compared to the injection pressure in the
first phase of the process. In other implementations, the injection pressure
in the
second phase can be at most 50% of the first phase pressure, at most 25% of
the first phase pressure, or lower.
[108] As explained above, the timing for the operating pressure change between
the first and second phases of the recovery process, i.e., the timing to
switch to a
lower operating pressure, can be aligned with the end of ramp-up/early stages
of
the plateau phase of production. In some implementations, the solvent
injection
at the lower pressure in the second phase of the process can start about one
year to about two years after a peak production rate is first achieved. In
other
implementations, the solvent injection in the second phase of the process can
be
performed about one year after a peak production rate is first achieved.
[109] In some implementations, an operating pressure strategy that includes a
first phase during which vaporized solvent is injected at a first pressure,
i.e., a
high pressure, followed by a second phase during which vaporized solvent is
injected at a second that is lower than the first pressure, can contribute to
balance process parameters such as HBR, SBR and production rate. In the
present description and as mentioned above, a high pressure can be for
instance
a pressure between about 50 to about 600 kPa above the initial reservoir
pressure. For instance, operating the solvent chamber at a first pressure
during
ramp-up can facilitate growing the solvent chamber as rapidly as possible, and
advantageously result in a desirable production rate. However, maintaining the
solvent chamber at the first pressure involves injecting substantial amount of
vaporized solvent into the reservoir to compensate for solvent leak-off,
resulting
in a high SBR and HBR. To benefit from the advantages of operating the solvent
chamber at the first pressure without continuing the injection of large
amounts of
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vaporized solvent, the first phase is performed for a given duration which can
be
up until a peak bitumen production rate is attained, and then a transition to
the
second phase can be initiated. In the second phase, the extent of pressure
reduction can be determined so as to maintain the bitumen production rate
within
a desirable range while reducing solvent leak-off and thus HBR and SBR so that
the recovery operations can remain economical over time. Advantageously,
reducing the operating pressure of the solvent chamber can contribute to
maintain solvent in vaporized form within the solvent chamber, thereby
reducing
the amount of solvent necessary to remain within the desirable range of
production rate as less solvent is being produced with the production fluid,
and
thus reducing HBR and SBR. In some implementations, additional heat can also
be provided in at least a portion of the solvent chamber to contribute
maintaining
solvent in vaporized form within the solvent chamber, which can also
facilitate
remaining within the desirable range of bitumen production rate.
[110] During the first phase of the recovery process where the solvent is
injected
at high pressure and during the second phase of the process which is performed
at a lower pressure than the first phase, heat energy is provided in at least
a
portion of the solvent chamber, for instance to the injection well, to
maintain the
solvent in vaporized form. As mentioned above, the amount of heat energy
provided around the injection well can affect the performance of the recovery
process. In some implementations, the heat input provided in the first phase
and
the second phase of the recovery process can thus be selected to balance the
bitumen production rate, SBR and/or HBR. The heat input can also be selected
based on the pressure operating strategy.
[111] In some implementations, the method selected for providing the desired
heat during the first phase of the process can be different than the heating
method used during the second phase. For instance, superheated vaporized
solvent can be injected at high pressure during the first phase, and then
solvent
can be injected at a lower temperature while heat is provided using downhole
heating during the second phase. Alternatively, the first phase can involve
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injecting vaporized solvent at high pressure and heating the injection well
using
downhole heating, and then injecting superheated solvent during the second
phase. The two phases can also utilize both heating methods to different
degrees, such that one phase uses more superheating energy than the other. In
some implementations, the solvent injected temperatures and pressures can be
varied in the first phase and the second phase, using surface and downhole
equipment and/or by varying the degree of solvent superheat at surface.
[112] In some implementations, the heat provided during the first phase and
the
second phase of the recovery process can be the same. However, it can be
advantageous, in some implementations, to vary the heat input in the first
phase
and the second phase of the process. In some implementations, the heat energy
provided in the first phase of the process while injecting the solvent at high
pressure can be lower than the heat energy provided in the second phase of the
process while injecting the solvent at lower pressure. In other
implementations,
the heat energy provided in the first phase of the process while injecting the
solvent at high pressure, can be higher than the heat energy provided in the
second phase of the process while injecting the solvent at lower pressure. For
instance, during the first phase of the process when the solvent is injected
at a
first pressure, i.e., a high pressure, that is sufficient to facilitate
convective mixing
of the solvent with the bitumen at the extraction interface, the solvent
chamber is
still small and it may be advantageous to limit the heat provided such that
solvent
is still under conditions that it can condenses at the extraction interface.
Then, as
the first phase of the process transitions to the second phase of the process
and
as the solvent chamber grows, increased heat can be provided since the solvent
chamber is now larger. Then, during the second phase of the process, the
amount of heat can be chosen such that sufficient solvent remains in vapor
phase within the solvent chamber to maintain the operating pressure of the
solvent chamber and/or maintain a desirable production rate. Use of a downhole
electric resistive (ER) heater to provide the desired heat energy can be
particularly convenient in the context of the present description, although
other
downhole heating means can also be contemplated, as previously mentioned.
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[113] The amount of heat energy can be adapted depending on the type of
solvent that is injected. Higher heat energy can be desired to maintain a
solvent
having a higher molecular weight in vapour form. For instance, if the solvent
is
pentane, the heat energy can be higher than the heat energy provided if butane
or propane are used as the solvent, at the same operating pressure.
[114] In addition, in some implementations, the amount of heat provided can be
determined according to the operating pressure of the solvent chamber, to
compensate for certain drawbacks of operating at either a high pressure or a
lower pressure. For instance, as mentioned above, the amount of heat to be
provided can be determined such that the production rate is maintained within
an
acceptable range when the operating pressure of the solvent chamber is
reduced. In some implementations, providing additional heat to a portion of
the
solvent chamber can also contribute to maintain a certain pressure within the
solvent chamber while less solvent is being injected.
[115] In some implementations, the heat energy can be provided in the first
phase of the process, at a rate per unit length ranging from about 300 to
about
1200 W/m. An amount of up to 1200 W/m can be desirable when pentane is used
as the solvent. In other implementations, the heat energy can be provided in
the
first phase of the process at a rate per unit length ranging from about 300 to
about 1000 W/m, or from about 300 to about 800 W/m, or from about 300 to
about 600 W/m, or from about 300 to about 500 W/m, or from about 300 to about
400 W/m, or from about 400 to about 600 W/m, or from about 400 to about 500
W/m, or from about 500 to about 600 W/m.
[116] In the second phase of the process, while the solvent is injected at
lower
pressure, the heat energy can be provided a rate per unit length ranging from
about 400 to about 1200 W/m. As for the first phase, higher heat energy rate
can
be desired if the solvent is pentane compared to butane or propane. In other
implementations, the heat energy can be provided in the second phase of the
process at a rate per unit length ranging from about 400 to about 1000 W/m, or
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from about 400 to about 700 W/m, or from about 400 to about 600 W/m, or from
about 500 to about 800 W/m, or from about 500 to about 700 W/m, or from about
500 to about 600 W/m, or from about 600 to about 800 W/m, or from about 600 to
about 700 W/m.
[117] When the solvent is injected in a superheated state, the heat energy
transferred by the solvent to the reservoir around the injection well can be
sufficient to limit early condensation of the solvent in the proximity of the
injection
well. Therefore, in some implementations, the recovery process can involve
injecting superheated solvent during the first phase and the second phase of
the
process, without requiring additional downhole heating means. However, if the
degree of superheating of the solvent vapour provided by surface heaters is
insufficient, downhole electric resistive heaters, or any other downhole
heating
means, can be used to increase the superheated solvent temperature in either
one or both phases of the process.
[118] In further implementations, the injection temperature of the superheated
solvent can be the same in the first and second phase. In other
implementations,
the temperature of the superheated solvent injected in the first phase can be
different than the temperature in the second phase of the process. For
instance,
the superheated solvent can be injected at a temperature that is higher in the
first
phase of the process than in the second phase. Alternatively, the superheated
solvent can be injected at a lower temperature in the first phase than in the
second phase of the process. For instance, in some implementations, process
parameters such as HBR, SBR and bitumen production rate can be monitored,
and the degree of superheat in the first phase and/or the second phase can be
determined at least in part based on a monitored process parameter. For
instance, when solvent is injected at a pressure higher than the native
reservoir
pressure during the first phase of the process, a portion of solvent can leak-
off to
the reservoir, resulting in a high HBR and SBR. In such implementations,
additional solvent may be injected at a high degree of super heat to encourage
solvent to remain within the chamber and reduce the need for injection of
fresh
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solvent in the reservoir. In other implementations, the amount of heating in
the
second phase can be chosen so as to maintain the production rate achieved
during the first phase of the process without having to inject substantial
amount
of fresh solvent in the reservoir, as the heating contributes to solvent
remaining in
vapour phase in the solvent chamber to efficiently extract bitumen at the edge
of
the solvent chamber. Thus, the amount of heat can be determined so as to
reduce the amount of fresh solvent that would be required to maintain the
solvent
chamber at a given pressure and maintain a desirable bitumen production rate.
[119] In some implementations, the determination of the degree of superheat in
each one of the first phase and the second phase can be done in accordance
with the injection pressure of the solvent in these respective phases. In some
implementations, injecting the solvent at a higher degree of superheat can
contribute to maintain a given operating pressure of the solvent chamber since
the solvent will thus have a higher tendency to remain in the solvent chamber.
[120] In some implementations, the superheated solvent can be injected at a
temperature of at least 100 C above a dew point of the solvent. In some
implementations, the superheated solvent can be injected up to an upper
temperature threshold. The upper temperature threshold can be a temperature at
which coking of bitumen is avoided in the reservoir. The upper temperature
threshold can be a temperature determined according to practical
considerations
of the process. For example, the upper temperature threshold can be 200 C, or
can be 250 C.
[121] In other implementations, the solvent can be injected in a superheated
state at a temperature ranging from about 30 C to about 200 C, or from about
30 C to about 170 C, or from about 30 C to about 140 C. If butane is used as
the solvent, a temperature from about 30 C to about 140 C can be suitable.
[122] The second phase of the process can continue as long as the bitumen
production rate is economic and/or that the SBR does not increase to an
undesirable limit. In some implementations, solvent injection is then ceased
and
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a wind-down phase can be implemented, where a non-condensable gas (NCG)
can be injected under pressure in the context of a pressure maintenance
strategy.
[123] It is also noted that several well pairs can be deployed from a well pad
and
are typically arranged so that at least some of the well pairs are in parallel
and
side-by-side relationship to each other to form an array of well pairs in the
reservoir. For an array of side-by-side well pairs, the solvent injection can
be
controlled so that multiple well pairs, and optionally all of the well pairs,
are
transitioned from the high pressure phase to the low pressure phase generally
at
the same time. Coordinating the transition from high to low pressure for the
side-
by-side well pairs can reduce the risk of high pressure solvent inadvertently
leaking from a high pressure chamber into an adjacent low pressure chamber. In
some implementations, adjacent well pairs are transitioned from the higher
pressure phase to the low pressure phase together. Surface operations can also
be facilitated when all adjacent well pairs are converted together from high
to low
pressure modes. Nevertheless, depending on well pair spacing, chamber growth,
and the progression of the process for each well pair, it may be desirable to
operate some adjacent well pairs at different pressure phases.
[124] It is also noted that an array of adjacent well pairs can be operated so
that
all of the injection wells are operated under the same pressure during the
different pressure stages of the process. Alternatively, the well pairs could
be
operated at different specific pressures from each other while all being
within a
general pressure operating envelope for the given stage. In addition, for an
array
of wells, eventually adjacent chambers can coalesce to form a common chamber
that has a generally uniform pressure. The well pairs can be operated such
that
coalescence occurs during the second phase and thus under low pressure
conditions.
[125] The pressure and heating operating conditions of the process described
above can vary depending on the nature of the bitumen reservoir and the
initial
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reservoir parameters. However, thermal solvent bitumen recovery from any
bitumen reservoir can benefit from the two-phase strategy described herein.
[126] In accordance with another aspect, there is provided a method that can
be
implemented to determine a first pressure and a second pressure at which to
operate the two-phase strategy, the second pressure being lower than the first
pressure. In the method, simulations are performed, such as reservoir
simulations, and solvent injection can be performed in accordance with the
output
of the simulations, in particular with regard to the pressure and optionally
the
temperature at which the solvent is injected. The method includes performing a
first set of simulations over a first range of simulation pressures to
determine a
first pressure at which to inject the solvent in a first phase of the process.
In other
words, an initial reservoir pressure is set in a simulation model, and this
initial
pressure can be determined for instance taking into account reservoir
permeability, water saturation, and water mobility. In some implementations,
this
initial pressure can be for instance about 200 to 300 kPa above the native
reservoir pressure. In other implementations, the initial pressure can be set
to be
between the native reservoir pressure and up to about 500 kPa above the native
reservoir pressure. Simulations are run for the life of the well at the
initial
pressure chosen. Then simulations are repeated to determine which of the
initial
pressure chosen enables to achieve a peak bitumen production rate or at which
a
faster peak bitumen production can be achieved, compared to other pressures
used in the simulations. Simulations are also performed at different pressures
to
obtain data that is indicative of solvent consumption over the life of the
well. A
combination results obtained from the simulations can be used to determine
which pressure is advantageous to achieve a desirable bitumen production rate
and/or to achieve the peak bitumen production rate faster, at which point
during
the life of the well the consumption of solvent reaches an upper limit that is
undesirable, for instance for economic considerations, and at which point
during
the life of the well the initial pressure can be dropped to a lower pressure
that
enables maintaining a substantially similar bitumen production rate while
reducing solvent consumption. The initial pressure data indicative of solvent
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consumption can thus contribute to determine a second pressure at which to
inject the solvent in a second phase of the process, wherein the second
pressure
is lower than the first pressure.
EXAMPLES / SIMULATION EXPERIMENTS
[127] Reservoir simulations were performed using the software STARS
developed by the company Computer Modelling Group Ltd. Several sensitivity
runs were performed with respect to operating pressure and heat input to
verify
operating strategies. Two sets of simulations were performed. The first
simulation
set was performed contemplating the use of an electric resistive heater (ER
heater) to provide heat and the second set was performed contemplating the use
of superheated solvent to provide heat. Both simulations were initialized with
reservoir properties around the producer and injector representative of a pre-
heat
and start-up phase having been completed. The initial reservoir pressure was
thus set to 450 kPa. The solvent contemplated for the simulation was butane.
[128] The results are reported in Figs. 2 to 9. For both simulation sets, the
cumulative bitumen (oil), the cumulative hold-up, the bitumen (oil) rate and
the
solvent-to-bitumen ratio (referred to as "iSvOR" in the diagrams) were
recorded.
It is worth mentioning that the cumulative hold-up can be converted to HBR by
dividing by cumulative oil.
[129] In both simulation sets, data were collected to compare a single-phase
process in which the injection pressure was set to a single value over time
(400,
450, 500, 600 or 700 kPa) with a two-phase process according to the present
technology in which the pressure in the first phase was higher than the
pressure
in the second phase. More particularly, the two-phase process simulation was
performed at a pressure set to 700 kPa in the first phase and to 500 kPa in
the
second phase. The pressure was dropped from 700 KPa to 500 KPa over 1-2
months. In the simulations, the pressure change translated into the artefact
observed around 31-35 months in the plots represented in Figs. 3 to 5 and 7 to
9,
where a rapid pressure drop can be observed. It is worth mentioning that in a
real
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reservoir, the injection pressure may not transition so rapidly, as the
transition
can occur over a period of about 10 months to about 15 months, or about one
year.
[130] The results reported in Figs. 2 to 9 show that the influence of pressure
and
heat input on the cumulative bitumen, the cumulative hold-up, the bitumen rate
and the solvent-to-bitumen ratio, is generally comparable whichever heating
method is used.
[131] The data show that low operating pressures (400 to 500 kPa) encourage a
low solvent-bitumen ratio (SBR) and hold-up bitumen ratio (HBR), while high
pressures (500 to 700 kPa) encourage rapid solvent chamber development and
thus higher oil rates, at the expense of higher SBR and HBR, for instance due
to
solvent leak-off. From the simulations, one can note that the operating
pressure
strategy for a solvent-based gravity drainage recovery process comprising of a
combination of high injection pressures initially, to rapidly grow the
chamber,
followed by a gradual drop to low pressures to reduce solvent leak-off, can
contribute to lower the long term SBR and HBR. The initial rapid chamber
growth
can advantageously provide a large surface area for drainage to occur more
effectively at lower pressures throughout the remainder of the well life. This
can
result in a bitumen profile similar to that of the high pressure cases, with
limited
impact to long term solvent performance, as well as the SBR and HBR on a
facility basis.
[132] The simulation data also indicate that the amount of heat input can
affect
process parameters. In general, higher heat input lowers SBR and HBR as
solvent is encouraged to remain in the solvent chamber as vaporized solvent,
while operating at high pressure in the solvent chamber can contribute to
increase the bitumen production rate.
[133] It is worth noting that heating rates, whether accomplished via ER
heater
power or degrees of solvent superheat at surface, can be tied to the process
operating pressure. Since the dew point temperature of butane increases with
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pressure, it can take a greater amount of enthalpy to maintain butane in the
vapour phase and to condense butane in the reservoir as the operating pressure
increases.
[134] From the simulations data, one can note that a particularly interesting
strategy for a reservoir presenting the above mentioned conditions (initial
pressure of 450 kPa) and using butane as solvent, can be to implement the
first
phase at a pressure of about 700 KPa and the second phase at a pressure of
about 500 KPa. Moreover, heating to about 600 W/m using an ER heater or
injected superheated butane at about 140 C, in both the first and second
phases, appear to provide a good balance in terms of the cumulative oil, oil
rate,
SBR and/or cumulative HBR.
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