Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
1
USE OF UPGRADER PRODUCTS FOR MOBILIZING BITUMEN DURING AN IN SITU
STARTUP PROCESS
TECHNICAL FIELD
[1] The technical field generally relates to startup processes for
mobilizing bitumen
contained in bitumen-bearing reservoirs, and more particularly to the use of
startup fluids
to enhance startup procedures.
BACKGROUND
[2] There are various techniques for in situ recovery of heavy
hydrocarbons, such as
heavy oil and/or bitumen, from heavy hydrocarbon-bearing reservoirs. Some
techniques
are solvent-assisted recovery processes that employ a solvent to help mobilize
the
bitumen for recovery. Some solvent-assisted recovery processes can have
similarities
with conventional Steam-Assisted Gravity Drainage (SAGD), although solvent is
injected
into the heavy hydrocarbon-bearing reservoir instead or along with steam.
[3] In an example of a solvent-assisted recovery process, a pair of
horizontal wells
including an upper injection well and a lower production well can be provided
in the heavy
hydrocarbon-bearing reservoir, which can be an oil sands reservoir. The region
between
the injection well and the production well, i.e., the interwell region, can be
characterized
by various levels of hydrocarbon saturation and fluid mobility, and will
generally include a
region having a high saturation of hydrocarbons and a limited fluid mobility.
The general
goal of the startup process is to increase the mobility of the hydrocarbons in
the interwell
region, for instance by warming the interwell region using various methods,
such as using
electric resistive heaters or providing steam circulation, and injecting a
mobilizing fluid,
such as solvent, into the hydrocarbon-bearing reservoir via the injection
well.
[4] Once fluid communication is established in the region between the
injection well
and the production well, injection of mobilizing fluid can continue in order
to promote
growth of an extraction chamber in proximity of the injection well. The
extraction chamber
eventually extends upwardly and outwardly from the injection well within the
reservoir as
the mobilized hydrocarbons flow toward the production well mainly due to
viscous forces
and gravity forces. Overtime, a production fluid including the mobilized
hydrocarbons and
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a portion of the mobilizing fluid is recovered to the surface. The extraction
chamber can
be formed using various mobilizing fluids, such as steam, various hydrocarbon
solvents,
non-condensable gases, and combinations thereof.
[5] Various challenges still exist with regard to startup procedures for in
situ bitumen
recovery processes and there is a need for enhanced technologies.
SUMMARY
[6] In accordance with an aspect, there is provided a startup process for
mobilizing
bitumen in an interwell region defined between a horizontal injection section
of an injection
well and a horizontal production section of a production well located below
the horizontal
injection section, the injection well and the production well being located in
a bitumen-
containing reservoir, the startup process comprising:
introducing a startup fluid into the bitumen-containing reservoir via at least
the
injection well to mobilize bitumen in the interwell region, the startup fluid
comprising first and second upgrader products each obtained from a vacuum
distillation process for upgrading crude oil or a downstream process thereof,
the
first upgrader product having an aromatic content above 25%, and the second
upgrader product having an API gravity below 200; and
recovering mobilized bitumen from the interwell region via the production well
as
a production fluid to form a bitumen-depleted region that enables fluid
communication between the injection well and the production well;
wherein the startup fluid enables asphaltenes to remain substantially
solubilized
in the mobilized bitumen.
[7] In some implementations, the first upgrader product comprises light
vacuum gas
oil.
[8] In some implementations, the first upgrader product comprises coker
kerosene.
[9] In some implementations, the second upgrader product comprises coker
gas oil.
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[10] In some implementations, the second upgrader product comprises heavy
vacuum
gas oil.
[11] In some implementations, the first upgrader product is provided in a
proportion
ranging from 80:20 to 20:80 ratio by mass relative to the second upgrader
product.
[12] In some implementations, the startup fluid further comprises a third
upgrader
product obtainable from the vacuum distillation process for upgrading crude
oil or the
downstream process thereof.
[13] In some implementations, the aromatic content of the third upgrader
product is
above 25%.
[14] In some implementations, the third upgrader product comprises coker
kerosene.
[15] In some implementations, the startup fluid further comprises a third
upgrader
product obtainable from a vacuum distillation process for upgrading crude oil
or a
downstream process thereof.
[16] In some implementations, the aromatic content of the third upgrader
product is
above 25%.
[17] In some implementations, the third upgrader product comprises light
vacuum gas
oil.
[18] In some implementations, the startup fluid further comprises steam.
[19] In some implementations, the startup process further comprises heating
the
startup fluid at surface prior to introducing the startup fluid into the
bitumen-containing
reservoir.
[20] In some implementations, the startup process further comprises heating
the
startup fluid as the startup fluid travels along the injection well.
[21] In some implementations, heating the startup fluid as the startup
fluid travels
along the injection well is performed via at least one of radio-frequency (RF)
heating,
electric heating, and hot fluid closed-loop circulation.
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[22] In some implementations, the electric heating comprises providing one
or more
electric resistive heaters in the injection well.
[23] In some implementations, the heating is performed via radio-frequency
(RF)
heating.
[24] In some implementations, the heating is performed via hot fluid closed-
loop
circulation.
[25] In some implementations, the heating is performed via closed-loop
circulation.
[26] In some implementations, introducing the startup fluid into the
bitumen-containing
reservoir further comprises injecting the startup fluid via the production
well prior to
recovering the mobilized bitumen from the interwell region via the production
well.
[27] In some implementations, introducing the startup fluid into the
bitumen-containing
reservoir further comprises injecting the startup fluid via the production
well cyclically
between periods of recovering the mobilized bitumen from the interwell region
via the
production well.
[28] In some implementations, the startup process further comprises
determining an
amount of mobilized bitumen produced from the interwell region to assess
bitumen de-
saturation in the interwell region.
[29] In some implementations, the startup process further comprises
monitoring a
production variable related to recovering the production fluid.
[30] In some implementations, the production variable comprises a
compositional
characteristic of the production fluid.
[31] In some implementations, the compositional characteristic comprises a
concentration of the startup fluid in the production fluid.
[32] In some implementations, the compositional characteristic of the
production fluid
comprises a bitumen concentration of the production fluid.
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[33] In some implementations, the compositional characteristic of the
production fluid
comprises an asphaltene content of the production fluid.
[34] In some implementations, the compositional characteristic of the
production fluid
comprises an API gravity of the production fluid.
[35] In some implementations, the startup process further comprises pre-
heating the
interwell region.
[36] In some implementations, pre-heating the interwell region comprises
electrically
heating using one or more electric resistive heaters in the injection well
and/or the
production well.
[37] In some implementations, pre-heating the interwell region comprises
circulating
steam through the injection well and/or the production well.
[38] In some implementations, the startup process further comprises
separating the
production fluid to remove water and solids therefrom to obtain an upgrader
product-rich
fluid.
[39] In some implementations, the startup process further comprises
separating the
upgrader product-rich fluid to recover at least a portion of the first
upgrader product and
obtain a recycled first upgrader product suitable for reuse in the startup
fluid, and a mixed
bitumen and second upgrader product stream.
[40] In some implementations, the startup process further comprises
separating the
mixed bitumen and second upgrader product stream to recover at least a portion
of the
second upgrader product to obtain a recycled second upgrader product suitable
for reuse
in the startup fluid.
[41] In some implementations, introducing the startup fluid into the
bitumen-containing
reservoir comprises introducing at least a portion of the recycled first
upgrader product as
part of the startup fluid.
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[42] In some implementations, introducing the startup fluid into the
bitumen-containing
reservoir comprises introducing at least a portion of the recycled second
upgrader product
as part of the startup fluid.
[43] In some implementations, the startup process further comprises soaking
a portion
of the interwell region with the startup fluid for a period of time before
recovering the
production fluid.
[44] In accordance with another aspect, there is provided a startup process
for
mobilizing bitumen contained in a near-wellbore region of a bitumen-containing
reservoir,
the startup process comprising:
introducing a startup fluid into the bitumen-containing reservoir via a well
extending within the bitumen-containing reservoir to mobilize the bitumen in
the
near-wellbore region, the startup fluid comprising coker gas oil and at least
one
of coker kerosene and light vacuum gas oil; and
recovering mobilized bitumen from the near-wellbore region as a circulated
fluid
or a production fluid to form a bitumen-depleted region;
wherein the startup fluid enables asphaltenes to remain substantially
solubilized
in the mobilized bitumen.
[45] In some implementations, the startup fluid comprises coker kerosene
and light
vacuum gas oil.
[46] In some implementations, the well is an injection well and the
recovering of the
mobilized bitumen is performed via a production well located below the
injection well.
[47] In accordance with another aspect, there is provided a startup fluid
for
introduction into a bitumen-containing reservoir to mobilize bitumen located
in a near-
wellbore region of the bitumen-containing reservoir, the startup fluid
comprising:
first and second upgrader products each obtained from a vacuum distillation
process for upgrading crude oil or a downstream process thereof, the first
upgrader
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product having an aromatic content above 25%, and the second upgrader product
having an API gravity below 200;
wherein the first and second upgrader products are selected and proportioned
such that following introduction of the startup fluid into the bitumen-
containing
reservoir, the combination of the startup fluid and bitumen located in the
near-
wellbore region produces mobilized bitumen recoverable from the bitumen-
containing reservoir to form a bitumen-depleted region in the near-wellbore
region;
and
wherein the startup fluid enables asphaltenes to remain substantially
solubilized in
the mobilized bitumen.
[48] In some implementations, the first upgrader product has an aromatic
content
above 30%.
[49] In some implementations, the second upgrader product has an API
gravity below
15 .
[50] In some implementations, the first upgrader product comprises light
vacuum gas
oil.
[51] In some implementations, the first upgrader product comprises coker
kerosene.
[52] In some implementations, the second upgrader product comprises coker
gas oil.
[53] In some implementations, the second upgrader product comprises heavy
vacuum
gas oil.
[54] In some implementations, the first upgrader product is provided in a
proportion
ranging from 80:20 to 20:80 ratio by mass% relative to the second upgrader
product.
[55] In some implementations, the startup fluid further comprises a third
upgrader
product obtainable from the vacuum distillation process for upgrading crude
oil or the
downstream process thereof.
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[56] In some implementations, the aromatic content of the third upgrader
product is
above 25%.
[57] In some implementations, the third upgrader product comprises coker
kerosene.
[58] In some implementations, the startup fluid further comprises a third
upgrader
product obtainable from a vacuum distillation process for upgrading crude oil
or a
downstream process thereof.
[59] In some implementations, the aromatic content of the third upgrader
product is
above 25%.
[60] In some implementations, the third upgrader product comprises light
vacuum gas
oil.
[61] In some implementations, the first and third upgrader products are
provided as a
mixture in a proportion ranging from 80:20 to 20:80 ratio by mass% relative to
the second
upgrader product.
[62] In some implementations, the first and third upgrader products are
provided as a
mixture in a proportion ranging from 80:20 to 20:80 ratio by mass% relative to
the second
upgrader product.
[63] In some implementations, the startup fluid further comprises steam.
[64] In some implementations, the startup fluid is heated at surface prior
to being
introduced into the bitumen-containing reservoir.
[65] In some implementations, the startup fluid is introducible into the
bitumen-
containing reservoir via an injection well extending within the bitumen-
containing reservoir.
[66] In some implementations, the startup fluid is heated while traveling
along the
injection well.
[67] In accordance with another aspect, there is provided a startup process
for
mobilizing bitumen contained in a near-wellbore region of a bitumen-containing
reservoir,
the startup process comprising:
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introducing a startup fluid into the bitumen-containing reservoir via a well
extending within the bitumen-containing reservoir to mobilize the bitumen in
the
near-wellbore region, the startup fluid comprising a first upgrader product
obtained from a vacuum distillation unit and a second upgrader product
obtained
from a coker unit; and
recovering mobilized bitumen from the near-wellbore region to form a bitumen-
depleted region;
wherein the startup fluid enables asphaltenes to remain substantially
solubilized
in the mobilized bitumen.
[68] In some implementations, the first upgrader fluid comprises coker
kerosene.
[69] In some implementations, the first upgrader fluid comprises coker gas
oil.
[70] In some implementations, the second upgrader fluid comprises light
vacuum gas
oil.
[71] In some implementations, the startup fluid further comprises a third
upgrader
product.
[72] In some implementations, the third upgrader product is obtained from
the vacuum
distillation unit or the coker unit.
[73] In some implementations, the first upgrader fluid comprises coker
kerosene.
[74] In some implementations, the second upgrader fluid comprises light
vacuum gas
oil.
[75] In some implementations, the third upgrader product comprises coker
gas oil.
[76] In some implementations, the well is an injection well and the
recovering of the
mobilized bitumen is performed via a production well located below the
injection well.
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[77] In accordance with another aspect, there is provided a startup process
for
mobilizing bitumen contained in a near-wellbore region of a bitumen-containing
reservoir,
the startup process comprising:
introducing a startup fluid into the bitumen-containing reservoir via a well
extending
within the bitumen-containing reservoir to mobilize the bitumen in the near-
wellbore
region, the startup fluid comprising first and second upgrader products
obtained
from a vacuum distillation unit or a downstream process thereof; and
recovering mobilized bitumen from the near-wellbore region to form a bitumen-
depleted region;
wherein in a first stage of the startup process, the first and second upgrader
products are provided in a first stage proportion that enables asphaltenes to
remain
substantially solubilized in the mobilized bitumen; and
wherein in a second stage of the startup process following the recovering of
at least
a portion of the mobilized bitumen, the first and second upgrader products are
provided in a second stage proportion that induces asphaltenes precipitates to
form in the mobilized bitumen.
[78] In some implementations, the first upgrader fluid comprises coker
kerosene.
[79] In some implementations, the first upgrader fluid comprises light
vacuum gas oil.
[80] In some implementations, the second upgrader fluid comprises coker gas
oil.
[81] In some implementations, the well is an injection well and the
recovering of the
mobilized bitumen is performed via a production well located below the
injection well.
[82] In accordance with another aspect, there is provided a startup system
for
mobilizing bitumen contained in a near-wellbore region of a bitumen-containing
reservoir,
the startup system comprising:
an injection well extending into the bitumen-containing reservoir;
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a tubing string inserted into the injection well for introducing a startup
fluid into the
bitumen-containing reservoir to mobilize bitumen in the interwell region, the
startup
fluid comprising first and second upgrader products each obtained from a
vacuum
distillation process for upgrading crude oil or a downstream process thereof,
the
first upgrader product having an aromatic content above 25%, and the second
upgrader product having an API gravity below 200; and
a production well extending into the bitumen-containing reservoir and located
below the horizontal injection section for recovering mobilized bitumen as a
production fluid to form a bitumen-depleted region that enables fluid
communication between the injection well and the production well.
BRIEF DESCRIPTION OF THE DRAWINGS
[83] Figure 1 is a schematic representation of a well pair during a startup
process, the
well pair including an injection well and a production well located in a
hydrocarbon-bearing
reservoir, wherein a startup fluid is injected into the hydrocarbon-bearing
reservoir via the
injection well, including a representation of a zone comprising mobilized
bitumen.
[84] Figure 2 is a graph showing the aromatic content of five different
diluents.
[85] Figure 3 is a graph showing yields of asphaltenes precipitates and
toluene
insoluble solids for five different diluents and for various concentrations of
diluent in
corresponding bitumen blends.
[86] Figure 4 is a graph showing the API density for five different
diluents.
[87] Figure 5 is a graph showing the kinematic viscosity of five different
diluents.
[88] Figure 6 is a graph showing yields of asphaltenes precipitates and
toluene
insoluble solids for blends of bitumen and diluent at room conditions, for
different
concentrations of diluent in the bitumen blend.
[89] Figure 7 is a graph showing yields of asphaltenes precipitates and
toluene
insoluble solids for blends of bitumen, diluent, and toluene at room
conditions, for a
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concentration of 90 wt% of diluent in the bitumen blend and for various
concentrations of
toluene.
[90] Figure 8 is a graph showing yields of asphaltenes precipitates and
toluene
insoluble solids for blends of bitumen and diluent, and for bitumen alone,
combined with
various concentrations of pentane, at room conditions.
[91] Figure 9 is a graph showing yields of asphaltenes precipitates and
toluene
insoluble solids for blends of bitumen and diluent or combinations of
diluents, with the
shaded area indicating the range of measurement error from the toluene
insoluble content
which was 0.66 0.065 wt%.
[92] Figure 10 is a schematic representation of an example of a process for
separating
a production fluid that includes first and second upgrader fluids to produce a
bitumen-rich
stream.
DETAILED DESCRIPTION
[93] Techniques described herein relate to startup processes for mobilizing
bitumen
in a near-wellbore region of a bitumen-bearing reservoir in the context of in
situ bitumen
recovery operations. The startup process includes injecting a startup fluid
into the bitumen-
bearing reservoir, the startup fluid comprising one or more diluents obtained
from a
process for upgrading crude oil, such as a vacuum distillation process or a
downstream
process thereof. The diluents obtained from the crude oil upgrading process
can be
referred to as upgrader products. The choice of one or more upgrader products
can be
determined, for instance, in accordance with their aromatic content, their
ability to maintain
asphaltenes contained in the bitumen to be mobilized in solution, their
viscosity, and/or
their density. Examples of suitable diluents obtained from a crude oil
upgrading process
and that can be used as components of the startup fluid include light vacuum
gas oil, coker
gas oil, and coker kerosene. In some implementations, the startup fluid can
include a first
upgrader product and a second upgrader product. The first upgrader product can
have for
instance an aromatic content above 25%, and the second upgrader product can
have for
instance an API gravity below 20 . In some implementations, the first upgrader
product
can be, for example, light vacuum gas oil or coker kerosene, and the second
upgrader
product can be for example coker gas oil.
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[94] A startup process typically includes at least two stages, and the
startup fluid for
mobilizing bitumen as described herein can be used for performing at least one
of these
two stages. The initial stage of the startup process generally includes
introducing the
startup fluid in liquid phase into the reservoir to enable mobilization of
bitumen, for instance
by reducing the viscosity of the bitumen and exerting a pressure on the
bitumen to
displace, while avoiding precipitation of asphaltenes contained in the bitumen
within the
reservoir to prevent clogging in proximity of the wells. In this initial stage
of the startup
process, which can also be referred to as a displacement stage, the startup
fluid described
herein is formulated such that the asphaltenes contained in the bitumen remain
solubilized. In order to maintain the asphaltenes solubilized during the
initial stage of the
startup process, the selection and the proportion of the components of the
startup fluid
can be provided to arrive at desirable characteristics. In the present
description, the term
"components" refers to the upgrader products that can be used to make up all
or part of
the startup fluid. The components of the startup fluid and/or their proportion
can also be
varied over the course of the startup process as different objectives may be
sought after.
For instance, at the beginning of the startup process, the composition of the
startup fluid
can be provided so that asphaltenes remain substantially solubilized in the
mobilized
bitumen, while later on in the startup process, e.g., when a certain amount of
mobilized
bitumen has been produced, the composition of the startup fluid can be
adjusted so that
some asphaltene precipitation occurs.
[95] Although the general concept of using the startup fluid described
herein is
presented in the context of an injection well overlying a production so as to
define an
interwell region there between, it is to be understood that the startup
process can also be
performed according to different well configurations, such as via an infill
well that is located
between two adjacent well assemblies, or a step-out well located beside an
existing well
assembly, such that the infill or step-out well may become hydraulically
joined to other
extraction chambers.
[96] Optionally, the initial stage of the startup process can be preceded
by at least one
pre-heating step to subject the bitumen contained in the subsurface formation
to various
levels of pre-heating and facilitate mobilization. The pre-heating step can be
performed for
a certain period of time until the bitumen has reached a certain temperature,
for example,
at which point the startup fluid can be injected into the subsurface formation
or at which
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point the bitumen becomes flowable. This pre-heating can be performed by a
downhole
heater (e.g., electric resistance heater or a closed-loop fluid circulation
heater), for
example.
[97] After the startup fluid described herein has been introduced into the
subsurface
formation for a certain period of time corresponding to the initial stage of
the startup
process, the startup fluid can be modified or changed to another startup fluid
to proceed
with the second stage of the startup process which is typically aimed at
growing a
mobilizing fluid chamber. The mobilizing fluid chamber can be a chamber that
will include
steam, solvent, or both, which can depend on the mobilizing fluid that will be
introduced
into the subsurface formation during normal operations. Examples of solvents
that can be
used to grow a chamber can include paraffinic solvents, also referred to as
alkanes, such
as propane, butane, pentane, and natural gas condensates.
[98] After the second stage, the startup process can gradually be
transitioned to
normal operations and a production fluid that includes mobilized bitumen,
water and solids
can be recovered. The normal operations can be performed according to any
known
techniques, such as gravity drainage or cyclic stimulation techniques using
steam, solvent,
mixtures thereof, or other mobilizing fluids for injection. Examples of normal
operation
processes can include SAGD, ES-SAGD, solvent-assisted gravity drainage,
solvent-
dominated gravity drainage, cyclic steam or solvent stimulation, and so on.
The normal
operations can include the injection of a mobilizing fluid, such as steam,
solvent, non
condensable gas, air, etc. The production process can include the injection of
a paraffinic
solvent, such as propane, butane, pentane, hexane or heptane, alone or in
combination
in various proportions, in vapour phase to enable condensation of the solvent
within the
extraction chamber above the injection well and dissolution into the bitumen
to enhance
mobilization and recovery via an underlying production well. It is also noted
that the
production stage can include multiple different recovery processes, e.g., SAGD
followed
by solvent-assisted process or in situ combustion.
[99] A more detailed description of startup processes that can be part of
an in situ
bitumen recovery process and the startup fluid for use in such startup
processes, as well
as associated implementations, is provided below.
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Startup process of an in situ bitumen recovery process
[100] As mentioned above, the startup process described herein facilitates
mobilization
of bitumen contained in a subsurface formation using a startup fluid as a
mobilizing fluid,
the startup fluid comprising one or more upgrader products obtained from a
crude oil
upgrading process. It is to be noted that in the context of the present
description, the
expressions "upgrader fluids" and "diluents" can be used interchangeably. The
bitumen
within the formation includes various hydrocarbon components, including
heavier
asphaltenes and lighter maltenes. Mobilized bitumen can then be produced as
production
fluid from the subsurface formation during normal recovery operations that
follow the
startup process. As mentioned above, it should be understood that the startup
process
described herein can be implemented in the context of various suitable
subsequent in situ
recovery processes adapted to produce mobilize bitumen from a subsurface
formation,
such as a Steam Assisted Gravity Drainage (SAGD) process or a solvent-assisted
gravity
drainage operation. A SAGD process uses steam as a mobilizing fluid for
introduction in
the subsurface formation, sometimes with minor amounts of other fluids,
whereas a
solvent-assisted gravity drainage operation generally uses a solvent, with or
without
steam, for introduction into the subsurface formation. A solvent-dominated
process uses
mainly solvent with sometimes minor amounts of other fluids. Once the startup
process is
completed, normal recovery operations of the in situ recovery process can
follow.
[101] Figure 1 shows an implementation of a startup process in the context
of an in situ
recovery process that is carried out via a horizontal well pair 10 provided in
a subsurface
formation. The horizontal well pair 10 includes an injection well 12 overlying
a production
well 14. The injection well 12 and the production well 14 shown are generally
parallel and
separated by an interwell region 16. The injection well 10 includes a vertical
portion 18
and a horizontal portion 20 extending from the vertical portion 14, and the
production well
14 includes a vertical portion 22 and a horizontal portion 24 extending from
the vertical
portion 22.
[102] Still referring to Figure 1, the startup process includes injecting a
startup fluid 26
as a mobilizing fluid into the subsurface formation. In the illustrated
implementation, the
startup fluid 26 is injected into the subsurface formation via a tubing string
28 inserted into
the injection well 12. The injection well 12 generally includes a casing in
its vertical portion
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18, and a liner in its horizontal portion 20. The liner extends within the
wellbore and can
include injection ports such that, when the startup fluid 26 exits the tubing
string 28, the
startup fluid 26 can fill the horizontal portion 20 of the injection well 12
and penetrate into
the subsurface formation through the injection ports. Alternatively, the liner
can also
include a slotted portion or a screen portion that allows the startup fluid 26
to exit the
injection well 12 and penetrate into the subsurface formation. In some
implementations,
devices that can include straddle packers, inflatable packers, sleeves and/or
coiled tubing
can be used to influence the interval at which the startup fluid 26 is
injected into the
subsurface formation. The startup fluid 26 can also be injected via the
production well 14.
In some implementations, when the startup fluid 26 is injected via the
production well 14,
it can be done for instance at the beginning of the startup process when
recovery of
mobilized bitumen has not started yet, i.e., in implementations where the
production well
14 is not yet used to recover mobilized bitumen. In other implementations,
injection of the
startup fluid 26 can also be done for given periods of time in between which
mobilized
bitumen recovery through the production well 14 can resume to sustain
formation of a
bitumen-depleted region and of the startup chamber. In yet other
implementations, the
startup fluid can be injected into the subsurface formation via a single well
configuration
that is operated in a cyclic mode.
[103] A heater string 30 can also be inserted in the injection well 12 to
provide heat to
the startup fluid 26 as it is being carried through the injection well 12 via
the tubing string
28, to heat the startup fluid 26 prior to exiting from the tubing string 28.
In some
implementations, heating the startup fluid as the startup fluid travels along
the injection
well can also be performed via other means, such as radio-frequency (RF)
heating, closed-
loop circulation of a hot fluid, or a combination thereof.
[104] In addition to heating the startup fluid 26 while the startup fluid
26 travels along
the injection well 12, the heater string 30 can also provide heat to the
interwell region 16,
for instance to pre-heat the bitumen prior to the injection of the startup
fluid 26 into the
subsurface formation. In some implementations, a heater (e.g., electric
resistive heaters,
RF heaters or other heating means) can also be provided in the production well
14 to
provide additional heat to the interwell region 16. More details regarding
heating of the
interwell region 16 are provided below.
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Characteristics of the startup fluid
[105] As mentioned above, the startup fluid comprises one or more upgrader
products
obtained from a crude oil upgrading process. Processes for upgrading, or
refining, crude
oil can include processes for separating heavier products from lighter ones,
often to
prepare products that are marketable.
[106] In brief, crude oil is generally initially processed in an
atmospheric distillation
column to separate components of the crude oil mixture into various fractions,
or
petrolatum cuts, according to their respective boiling points. Treatment of
crude oil in an
atmospheric distillation tower produces lighter fractions, including naphtha
and refinery
gas; medium fractions, including kerosene and diesel oil distillates; and
heavier fractions,
including atmospheric gas oils; while the heaviest fractions with the highest
boiling points
settle at the bottom of the atmospheric distillation column.
[107] The heaviest fractions, which are also sometimes referred to as
atmospheric
bottoms or atmospheric resid, are then typically treated in a vacuum
distillation column to
produce light fractions such as light vacuum gas oil (LVGO), and vacuum
kerosene;
heavier fractions such as heavy vacuum gas oil (sometimes referred to as
HVG0); and a
vacuum residuum.
[108] The vacuum residuum can then be treated in a coker, such as a delayed
coker,
for cracking and conversion into lighter products such as coker gas oil (CGO)
and coker
kerosene (CK), coker distillate, and coker naphtha, while producing a heavy
fraction that
can include solid petroleum coke.
[109] Crude oil fractions produced from crude oil upgrading can have
properties that
can make them attractive for use as a startup fluid in the context of an in
situ bitumen
recovery process. For instance, diesel has been used as a mobilizing fluid in
startup
processes given that it is generally considered a non-deasphalting fluid and
given its ability
to dilute bitumen. However, the use of diesel as a mobilizing fluid can have
drawbacks, for
instance in terms of its cost, which can make it less attractive. Alternatives
to diesel as a
mobilizing fluid may thus be beneficial for use in startup processes.
Date Recue/Date Received 2020-12-15
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[110] In some implementations, selection of potential candidates among the
various
crude oil fractions can be made according to economical considerations, and
according to
properties such as its aromatic content, viscosity, API gravity, density,
ability to maintain
asphaltenes in solution, etc. Fractions that may have a lesser economic value
and that
can be advantageously used as suitable mobilizing fluids in the context of an
in situ
bitumen recovery process can include, for instance, lighter fractions from a
coker unit,
such as coker kerosene and coker gas oil, as well as fractions from a vacuum
distillation
unit such as light vacuum gas oil and heavy vacuum gas oil.
[111] In some implementations, the startup fluid can include at least two
upgrader
products chosen from a crude oil upgrading process. When the startup fluid
includes two
or more upgrader products, the composition of the startup fluid can be varied
over time by
changing the amount or proportion of the upgrader products to advantageously
leverage
properties of the components with regard to their effect on bitumen during the
startup
process. This aspect will be discussed in further detail below.
[112] The interwell region is characterized by various levels of oil or
bitumen saturation
and various levels of fluid mobility. In some implementations, prior to the
startup process,
the interwell region can include a high saturation interval having low fluid
mobility. For
instance, an oil or bitumen saturation between the range of 50% to 100% can be
considered a high saturation interval. A startup fluid suitable for use to
establish hydraulic
communication in the interwell region in the context of an in situ bitumen
recovery process
can be formulated such that when contacted with bitumen, the asphaltenes
contained in
the interwell region remain in solution, while enabling mobilization of
bitumen in the
interwell region via dissolution effects and promoting the flow of mobilized
bitumen from
the injection well to the production well. In some implementations, when
referring to the
asphaltenes remaining in solution or remaining substantially solubilized, it
can mean that
substantially all the asphaltenes remain in solution when contacted with the
startup fluid.
In some implementations, when referring to the asphaltenes remaining
substantially
solubilized, it can mean that the asphaltenes remain in solution when
contacted with the
startup fluid, although some precipitation of asphaltenes can occur, in a
limited amount,
for instance in certain portions of the interwell region. When referring to
the expression "a
limited amount", it can mean that although some asphaltenes precipitation can
occur, the
extent of asphaltenes precipitation would not cause clogging in proximity of
the wells. In
Date Recue/Date Received 2020-12-15
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other implementations, the startup fluid can be formulated such that a
majority of the
asphaltenes remain in solution when contacted therewith. In this context, the
expression
"a majority" can refer to more than 50% of the asphaltenes remaining
solubilized. In such
scenarios, the startup fluid can be referred to as a non-deasphalting
mobilizing fluid or
non-deasphalting startup fluid. Maintaining the asphaltenes in solution in the
interwell
region can be beneficial in the context of a displacement phase of a startup
process, as
precipitation of asphaltenes in proximity of the wells can impair the flow of
solvent and of
the mobilized bitumen in the interwell region and can also increase the risk
of clogging of
the wells. It is to be noted that in some implementations, a chase fluid, such
as water,
either as steam or as an aqueous liquid stream, can be injected into the
reservoir to aid in
establishing fluid communication in the interwell region.
[113] In the following paragraphs, additional details regarding certain
characteristics of
suitable components for the startup fluid will be provided.
Aromatic content of components of the startup fluid
[114] As mentioned above, the startup fluid is formulated such that when
the startup
fluid contacts the bitumen, the asphaltenes contained therein remain in
solution. In some
implementations, the aromatic content of the one or more diluents forming the
startup fluid
can be indicative of its associated property of maintaining asphaltenes in
solution. The
aromatic content of a diluent can also be indicative of its ability to
dissolve in bitumen. In
general, diluents having a lower aromatic content dissolve in bitumen less
readily than
those having a higher aromatic content. For instance, in some implementations,
toluene
can dissolve bitumen more readily than pentane, hexane or heptane. In that
respect, it is
to be noted that diesel obtained from an atmospheric distillation process of
crude oil
typically has a lower aromatic content than gas oil or kerosene produced from
a coker unit,
i.e., coker kerosene and coker gas oil.
[115] On the other hand, the ability of the diluent to dissolve bitumen
based on its
aromatic content may be balanced according to its ability to maintain
asphaltenes in
solution, as the two properties may not necessarily be directly proportional.
In other words,
an upgrader product can have a high aromatic content but trigger a certain
amount of
asphaltene precipitation. For instance, a heavy vacuum gas oil may appear
attractive
Date Recue/Date Received 2020-12-15
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given its high aromatic content, but such a heavy fraction can, in turn,
potentially induce
asphaltene precipitation when contacted with bitumen. Accordingly, finding a
desired
balance between the ability of the hydrocarbon solvent to dissolve in bitumen
and its ability
to maintain asphaltenes solubilized in bitumen may be key for a given startup
fluid to be
considered suitable as a component of the startup fluid.
[116] Crude oil upgrader fractions suitable for the startup fluid described
herein can
thus have a higher aromatic content than other startup fluids, such as diesel,
to provide
an enhanced capability to maintain asphaltenes in solution once in contact
with bitumen,
while still having an ability to dissolve in bitumen that is suitable to
achieve the purpose of
the startup fluid, i.e., to act as a non-deasphalting mobilizing fluid.
Examples of such
suitable crude oil upgrader fractions include coker kerosene, light vacuum gas
oil and
coker gas oil.
[117] Figure 2 illustrates examples of aromatic content of five different
upgrader
products, i.e., vacuum kerosene, which can also be referred to as light vacuum
gas oil,
coker kerosene, heavy vacuum gas oil, coker gas oil and diesel. It can be seen
from Figure
2 that vacuum kerosene, coker kerosene, heavy vacuum gas oil, coker gas oil
each has a
markedly higher aromatic content than diesel. More particularly, the vacuum
kerosene
sample, the coker kerosene sample, the heavy vacuum gas oil sample, and the
coker gas
oil sample shown in Figure 2 have an aromatic content of 30.8%, 39.6%, 39.5%
and 88.0%
respectively, whereas diesel the diesel sample has an aromatic content of
13.1%. This
property of vacuum kerosene, coker kerosene, heavy vacuum gas oil, and coker
gas oil
can make these upgrader products attractive candidates for startup fluid given
their ability
to maintain asphaltenes in solution. It is to be noted that other
characteristics of the
upgrader product can come into play to influence its ability to perform as a
non-
deasphalting startup fluid. For instance, although heavy vacuum gas oil may
have a higher
aromatic content, it may perform less in terms of keeping asphaltenes in
solution than
other upgrader fluids having a high aromatic content.
[118] Figure 3 illustrates corresponding yields of asphaltenes precipitates
and toluene
insoluble solids for each of the five upgrader products mentioned above, i.e.,
vacuum
kerosene (identified as light vacuum gas oil in the graph), coker kerosene,
heavy vacuum
gas oil, coker gas oil and diesel. The graph shows that heavy vacuum gas oil
and diesel,
Date Recue/Date Received 2020-12-15
21
when present in bitumen in a concentration above 70 wt%, led to an increased
precipitation of asphaltenes compared to light vacuum gas oil, coker gas oil
and coker
kerosene. The asphaltene precipitation with the light vacuum gas oil, coker
gas oil and
coker kerosene remained lower than with diesel, even at concentrations up to
90 wt%.
Density and viscosity of components of the startup fluid
[119] In some implementations and as mentioned above, the startup fluids
described
herein can be used in a first phase of a startup process to mobilize bitumen
contained in
the interwell region. One of the sought-after properties of a startup fluid
for mobilizing and
displacing the bitumen is to have a viscosity and/or density that is close or
similar to the
viscosity and/or density of the bitumen to displace. Substantial differences
in viscosity
between the startup fluid and the bitumen to mobilize can contribute to early
breakthrough
of the mobilizing fluid from one well to another, which can in turn can lead
to various
drawbacks including inefficient displacement and/or conformance issues along
the wells,
which in turn can later on contribute to impair the development of the
mobilizing fluid
chamber. In that regard, diesel has a low viscosity relative to bitumen, which
is another
drawback of this conventional startup fluid.
[120] In that respect, upgrader products such as coker gas oil and heavy
vacuum gas
oil can provide advantages that make them suitable for use as startup fluids
while avoiding
drawbacks associated with conventional mobilizing fluids, as their respective
API
(American Petroleum Institute) density and viscosity is closer to that of
bitumen.
[121] Referring to Figure 4, there are shown values of API densities, also
referred to
as API gravity, for vacuum kerosene, coker kerosene, heavy vacuum gas oil,
coker gas
oil and diesel. More particularly, the vacuum kerosene sample, the coker
kerosene
sample, the heavy vacuum gas oil sample, and the coker gas oil sample have an
API
density of 26.0 , 25.9 , 15.3 and 12.6 respectively, whereas diesel the
diesel sample
has an API density of 25.0 .
[122] Referring to Figure 5, there are shown values of kinematic viscosity
for vacuum
kerosene, coker kerosene, heavy vacuum gas oil, coker gas oil and diesel, with
the
viscosity of coker gas oil and heavy vacuum gas oil being higher than the
viscosity of
vacuum kerosene, coker kerosene, and diesel.
Date Recue/Date Received 2020-12-15
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[123] These differences in API gravity and kinematic viscosity between
various
upgrader products and how they can be taken advantage of are discussed below.
Mixture of various up grader products to achieve a desired startup fluid
[124] In some implementations, and in view of the considerations presented
above, the
startup fluid can include a mixture of upgrader products that are chosen so as
to achieve
given characteristics of the resulting startup fluid.
[125] For instance, in some implementations, one or more upgrader products
having
an aromatic content within a given range can be blended, or mixed, with one or
more
upgrader having a viscosity that is closer to the viscosity of the bitumen to
mobilize. This
type of combination can take advantage of the properties of each of the
upgrader products
taken alone to yield a startup fluid having properties of its respective
components in terms
of maintaining the asphaltenes in solution in the bitumen to mobilize and also
having a
viscosity similar to the viscosity of bitumen to facilitate bitumen
mobilization and
conformance of the displacement process along the length of the wells.
[126] An example of a combination of upgrader products that can be blended to
obtain
a startup fluid for use as a non-deasphalting startup fluid in the context of
an in situ
recovery process is one that includes coker kerosene, light vacuum gas oil and
coker gas
oil. In this combination, one of the main purposes of the coker gas oil is to
increase the
viscosity of the startup fluid, while one of the main purposes of the coker
kerosene and
the light vacuum gas oil is to maintain the asphaltene in solution, although
the aromatic
content of the coker gas oil can also contribute to maintaining asphaltenes in
solution as
well. Of course, the proportion of each of the components of the startup fluid
can be varied
to achieve desired properties of the startup fluid.
[127] Another example of a combination of upgrader products that can be
blended to
obtain a startup fluid for use as a non-deasphalting startup fluid in the
context of an in situ
recovery process is one that includes light vacuum gas oil and coker gas oil.
In this
combination, one of the main purposes of the coker gas oil is also to increase
the viscosity
of the startup fluid, while one of the main purposes of the light vacuum gas
oil is to maintain
the asphaltene in solution, although as mentioned above, the aromatic content
of the coker
gas oil can also contribute to maintaining asphaltenes in solution as well.
Date Recue/Date Received 2020-12-15
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[128] The composition of the startup fluid can be expressed using various
other units
to illustrate the proportion of each of the upgrader products, such as units
of vol% or
mass%. Given units can be chosen for instance depending on the choice of the
components in the startup fluid. In some implementations, the proportion of
the upgrader
products in the startup fluid can be expressed for instance with ratios by
mass% expressed
as A:B, with A representing a mixture of coker kerosene and light vacuum gas
oil, and B
representing coker gas oil. Examples of proportions of upgraders products
expressed as
such can include proportions of 80:20, 70:30, 50:50, 30:70 and 20:80, to name
a few. It is
to be noted that these examples of proportions are given for illustrative
purposes only, and
that a wide range of proportions is possible and within the scope of the
present description.
In addition, the proportion of coker kerosene and light vacuum gas oil can
also vary as
part of the component "A" of the startup fluid. For instance, in some
implementations, the
proportion of coker kerosene relative to the light vacuum gas oil can be
increased or
inversely, the proportion of coker kerosene relative to the light vacuum gas
oil can be
decreased. Alternatively and in accordance with the other example given above,
the
proportion of the upgrader products in the startup fluid can be expressed with
ratios by
mass% expressed as A:B, with A representing light vacuum gas oil, and B
representing
coker gas oil, with examples of proportions of upgraders products expressed
that can
range from proportions of 80:20, 70:30, 50:50, 30:70 and 20:80, with of course
several
other options of proportions being suitable. The proportion of coker kerosene
relative to
the light vacuum gas oil, the proportions of coker kerosene and light vacuum
gas oil
relative to coker gas oil, and the proportion of light vacuum gas oil relative
to coker gas
oil, can depend for instance on the availability of such fractions from the
upgrader facility,
their cost, and/or on the capability of the resulting startup fluid to
maintain asphaltene in
solution in the bitumen to mobilize.
[129] In some implementations, the blend of coker kerosene and light vacuum
gas oil
can be combined with an upgrader product other than coker gas oil for
increasing the
viscosity of the startup fluid closer to a viscosity of bitumen. For instance,
in some
implementations, the startup fluid can include heavy gas oil combined with
coker kerosene
and light vacuum gas oil.
[130] Advantageously, the startup fluid described herein can have a
versatile
composition that can be adapted according to various factors, such as in
accordance with
Date Recue/Date Received 2020-12-15
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the refinery production schedule. In other words, the proportions of the
various upgrader
products forming the startup fluid, and the upgrader products themselves, can
be varied
depending on what the refinery is producing and what is available to allocate
to the
preparation of the startup fluid.
Introduction of the startup fluid into the subsurface formation
[131] The startup fluid can be introduced into the subsurface formation via
at least one
well. In some implementations, introducing the startup fluid into the
subsurface formation
can include circulating the startup fluid down the at least one well such that
the startup
fluid contacts and dilute the bitumen to mobilize. Circulating the startup
fluid can be an
option for instance when hydraulic communication between the injection well
and the
production well has not been established yet, or after hydraulic communication
has been
established. Following dilution, a mixture of startup fluid and bitumen that
has been diluted
with the startup fluid flows back up to the surface via the well as circulated
fluid and is then
reintroduced into the subsurface formation in a circuit fashion. Over time,
the content of
bitumen diluted in the circulated fluid increases, at which point make-up
startup fluid can
be added and/or some of the bitumen can be removed to keep circulating the
startup fluid.
In some implementations, introducing the startup fluid into the subsurface
formation can
include injecting the startup fluid into the subsurface formation, for
instance by pumping
the startup fluid down the at least well and pushing it into the reservoir
without startup fluid
coming back up the well. Injecting the startup fluid into the subsurface
formation can be
performed for instance when hydraulic communication has been established
between the
injection well and the production well.
[132] In some implementations, when the startup fluid includes more than
one upgrader
products, the upgrader products can be blended at surface to arrive at the
desired
composition of the startup fluid.
[133] In other implementations, the upgrader products can be introduced
into the
subsurface formation as distinct streams and be substantially mixed as the
upgrader
products travel down the well and/or upon introduction into the subsurface
formation. In
other implementations, still when the startup fluid includes more than one
upgrader
products, components of the startup fluid can be introduced into the
subsurface formation
Date Recue/Date Received 2020-12-15
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in a staged fashion. For instance, components of the startup fluid that are
known to
maintain asphaltenes in solution, or solubilized, may be introduced in a first
stage to
prevent asphaltenes precipitation in proximity of the wells. Then, in a second
stage,
another component of the startup fluid may be additionally introduced into the
subsurface
formation. The second stage can be implemented for example once a given
portion of
bitumen has been produced to the surface to partially clear the interwell
region. In some
scenarios, the additional upgrader product can be one that induces a limited
amount of
asphaltenes precipitation, that has an increased viscosity, or any other
characteristic that
may make the additional upgrader product suitable for injection during a
subsequent
second stage.
[134] As mentioned above, the startup fluid can be introduced into the
subsurface
formation in liquid phase, i.e., exiting the injection well and/or the
production well in liquid
phase. The startup fluid can be heated at surface using various heating means
(e.g., a
direct fired heater or an indirect heat exchanger). The startup fluid can also
be heated as
it travels along the injection well by using electric heating such as one or
more electric
resistive heaters provided along the well.
[135] In some implementations, prior to the startup fluid being introduced
into the
subsurface formation, a step of pre-heating can be performed to pre-heat the
bitumen
present in the interwell region to contribute to its mobilization. The pre-
heating step can
be performed by heating the injection well and optionally the production well
using heater
strings such as those described above, or through electric resistive heaters,
RF heaters
or other heating means. Alternatively, the pre-heating step can be performed
by circulating
steam in the injection well or any other pre-heating technique. In some cases,
the heaters
can continue operating during subsequent stages of the startup processes, such
that the
startup fluid is introduced into the subsurface formation while the heaters
continue to
impart heat to the reservoir.
[136] In some implementations, the start-up process can include controlling
the startup
temperature and/or a startup pressure of the startup fluid such that it is
introduced into the
subsurface formation within a given range of temperature and/or pressure.
Various
devices and methods can be used to measure temperature and pressure at surface
or
downhole, such as gages, bubble tubes, thermocouples, fibers, etc. In some
Date Recue/Date Received 2020-12-15
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implementations, the temperature of the startup fluid can be selected to
condition the
region in proximity of the wells or the interwell region, by introducing the
startup fluid as a
heated startup fluid, to reach a desired production temperature tailored to a
subsequent
production process or stage.
[137] In some implementations, the startup fluid can be introduced into the
subsurface
formation intermittently to include a period when the injection of the startup
fluid is stopped,
so as to enable the startup fluid to soak within the subsurface formation for
a given soaking
period. In such implementations, the soaking period can be initiated for
instance once a
predetermined volume of the startup fluid has been introduced into the
subsurface
formation. Once the soaking period is terminated, the startup fluid can be
recovered at
surface and then introduced again into the subsurface formation and so on.
Various
operating strategies can be implemented with the liquid startup composition.
Monitoring variables related to startup process
[138] Various variables can be monitored to determine when the startup
fluid can be
transitioned to another startup fluid aimed at growing a mobilizing fluid
chamber during a
second stage of the startup process, and also to assess whether the startup
procedure
can be considered to be terminated such that transition into the normal
recovery
operations can be initiated.
[139] Once the startup fluid has been introduced into the subsurface
formation for a
given period of time, bitumen that has been mobilized by the presence of the
startup fluid
and optionally the heat provided during the pre-heating step, can drain into
the production
well by gravity and can be recovered to the surface using artificial lift or a
pump (e.g.,
electric submersible pump or ESP) deployed in the production well. A
compositional
characteristic of the produced mobilized bitumen during the startup process is
an example
of a variable that can be monitored. A compositional characteristic of the
produced
mobilized bitumen can be, for instance, the concentration of the startup fluid
in the
produced mobilized bitumen, the asphaltene content of the mobilized bitumen,
and/or the
API gravity of the mobilized bitumen.
[140] In particular, the compositional characteristic of the produced
mobilized bitumen
can be indicative of the extent of cleanup, or bitumen de-saturation, that has
occurred
Date Recue/Date Received 2020-12-15
27
between the injection well and the production well. Bitumen de-saturation
between the
injection well and production well refers to the process of substantially
reducing bitumen
saturation in the interwell region, which can be achieved at least in part by
the mobilization
of bitumen and production of mobilized bitumen to the surface. De-saturation
of the
interwell region from bitumen thus can create a space between the injection
well and the
production well which can facilitate subsequent growth of the mobilizing fluid
chamber
described herein. Sufficient bitumen de-saturation of the interwell region can
be said to be
achieved for instance when the startup fluid is found in high concentration in
the production
fluid (in which case the startup fluid can be said to be back produced). Other
techniques
that can be used to serve as indicators of bitumen de-saturation in the
interwell region and
thus the degree of interaction between the injection well and the production
well can
include analysis of pressure interaction between the wells, seismic analysis,
use of
observation well temperature readings, and repeat saturation logging.
[141] The asphaltene content of the produced mobilized bitumen can be assessed
to
determine whether the composition of the startup fluid is sufficient for
asphaltenes to
remain in solution, i.e., to ensure that asphaltene deposition does not occur
or is minimized
in proximity of the wells. For instance, if the asphaltene content of the
produced mobilized
bitumen is low, it could be hypothesized that asphaltenes are left in the
subsurface
formation as precipitates, which is to be avoided. On the other hand, if the
asphaltene
content in the produced mobilized bitumen is high, then it could be
hypothesized that
asphaltenes are solubilized in the startup fluid and are being removed from
the subsurface
formation with the produced mobilized bitumen.
[142]
Simulations can be performed to help predict which level of asphaltene content
is to be expected for a given subsurface formation and/or given combination
and
proportion of non-deasphalting mobilizing solvent and deasphalting mobilizing
solvent as
components of the startup fluid. Thus, when such simulations are available,
one can
assess whether the asphaltene content of the produced mobilized bitumen is
below a
predetermined asphaltene content threshold. If the asphaltene content is above
the
predetermined asphaltene content threshold, then the composition of the
startup fluid
could be considered effective at least for the purpose of keeping the
asphaltenes in
solution such that the space between the injection well and the production
well can be
cleaned up. If the asphaltene content is below the predetermined asphaltene
content
Date Recue/Date Received 2020-12-15
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threshold, the proportion or choice of upgrader product in the startup fluid
can be modified
to favor the solubilization of the asphaltenes.
[143] The API gravity of the produced mobilized bitumen can also be
evaluated in a
similar fashion as the asphaltene content itself, as the API gravity can be
considered
indicative of the asphaltene content of the produced mobilized bitumen.
[144] As the startup process progresses and the interwell space becomes
cleaner, the
concentration of bitumen in the mobilized bitumen that is produced to the
surface can
decrease and include an increasing proportion of the startup fluid. Monitoring
the
concentration of the startup fluid in the produced mobilized bitumen can be
used to
determine the timing of when the space can be considered clean enough that the
startup
fluid can be transitioned to a second startup fluid. In other words, because
the space
around the injection well and the production well is now cleaned up, i.e.,
mobilized bitumen
has been removed from the interwell space, the risk of asphaltenes
precipitates forming
and impairing the flow of mobilized bitumen or clogging the wells is
decreased.
Accordingly, the startup fluid can be transitioned for instance to another
startup fluid that
includes a paraffinic solvent such as propane, butane, pentane, and
condensates,
because it is no longer as relevant to keep asphaltenes in solution and the
startup fluid
can rather be optimized to further grow the mobilizing fluid chamber
efficiently.
[145] Another option to determine when it can be appropriate to transition
the startup
fluid used to a second startup fluid is to use volumetric simulations. Such
volumetric
simulations can provide an estimate of a given volume between the injection
well and the
production well, and once a corresponding volume of mobilized bitumen has been
produced to the surface, it can be expected that this volume of interwell
region has been
cleaned up.
[146] Other types of simulations to determine the extent of cleanup around
the wells
include 4D seismic reservoir analysis to monitor changes in fluid location and
saturation,
pressure and temperature by evaluating the changes in the acoustic and elastic
properties
of the geological formation. Relevant data can also be obtained from
strategically
positioned observation wells.
Date Recue/Date Received 2020-12-15
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[147] In some implementations, it may be advantageous that one or more
components
of the startup fluid be changed over the course of the startup process. In
such
implementations, the startup fluid can include one or more upgrader products
that enables
the asphaltenes to remain solubilized in the mobilized bitumen. As the startup
process
evolves over time and the interwell region becomes cleaner, the startup fluid
can be
transitioned to include one or more upgrader products that induce a limited
amount of
asphaltene precipitation, as there is a lesser risk to clog the wells in this
later stage of the
startup process. For instance, in some implementations, the startup fluid can
include at
least two upgrader products that are provided in a first stage proportion that
enables
asphaltenes to remain substantially solubilized in the mobilized bitumen.
After a certain
period of time, in a second stage of the startup process which can be for
instance once at
least a portion of mobilized bitumen has been recovered at surface as a
circulated fluid or
production fluid, the proportion of the upgrader products in the startup fluid
can be
transitioned to a second stage proportion that induces a limited amount of
asphaltene
precipitation in the mobilized bitumen.
Implementations related to separation of startup fluid from mobilized bitumen
[148] As
mentioned above, the startup fluid is introduced into the subsurface
formation,
for instance via an injection well, to dilute and heat bitumen to produce
mobilized bitumen.
When the startup fluid is introduced into the subsurface formation for
circulation, a mixture
of startup fluid and bitumen diluted therein, that can be referred to as
circulated fluid, can
be recovered at surface via the injection well, or the well via which it was
introduced. When
the startup fluid is introduced into the subsurface formation for injection
via the injection
well, mobilized bitumen can then drain into the production well and be
recovered to the
surface as a production fluid. Both techniques can eventually create a space
around the
injection well. The mixture of startup fluid and bitumen obtained following
circulation, or
the production fluid recovered from the production well following injection,
can have a
variable composition depending on the stage of the startup process. Depending
on
different factors, such as the composition of the circulated fluid or of the
production fluid,
the proportion of the startup fluid in the circulated fluid or the production
fluid, as well as
economic considerations, it may be desirable to subject the mixture of startup
fluid and
bitumen or the production fluid to a separation step to recover at least a
portion of the
startup fluid therefrom. The recovered startup fluid can then be used as a
recycled startup
Date Recue/Date Received 2020-12-15
30
fluid. In implementations where more than one upgrader products are present in
the
startup fluid, the difference between their respective vaporization
temperatures can mean
that different separation steps can be put in place to recover a given
upgrader product.
[149] It is to be noted that in other implementations, it may be desirable
to leave the
startup fluid as part of the production fluid, for instance to achieve a
desired viscosity and
density and obtain a pipelinable production fluid because the presence of the
upgrader
fluid may act as a diluent. The mixture of the startup fluid and bitumen
forming the
production fluid can also represent a valuable standalone marketable product.
[150] With reference to Figure 10, a circulated fluid of a production fluid
42 is recovered
during the startup process. The production fluid includes mobilized bitumen,
water, solids
and at least a portion of the startup fluid. The production fluid 42 is
subjected to a first
separation 44 to remove water and solids 46 as an underflow, and to recover an
upgrader
product-rich fluid 48 comprising mobilized bitumen and a portion of the
startup fluid as an
overflow. In some implementations, the first separation 44 can be performed
for instance
through gravity separation mechanisms. The upgrader product-rich fluid 48 is
then
subjected to a second separation 50. The second separation 50 can be
configured to
recover at least one of the upgrader products forming the startup fluid, or to
recover more
than one upgrader product if present. For instance, if the startup fluid
includes coker
kerosene and coker gas oil, the difference in their respective vaporization
temperature
may be sufficiently large for implementing the second separation step 50 to
selectively
separate the coker gas oil, which has a lower vaporization temperature than
the
vaporization temperature of coker kerosene, as a first upgrader product from a
mixture of
bitumen and coker kerosene, and to recover a first upgrader product stream 52
comprising
the coker gas oil and the mixture of bitumen and coker kerosene stream 54. In
this
scenario, the coker kerosene would thus be considered a second upgrader
product. It is
to be understood that coker kerosene and coker gas oil are given as examples
only to
illustrate the general principle of separation steps that can be implemented
to recover a
recycled startup fluid and a bitumen-rich stream. Other upgrader products can
of course
be used and separated in accordance with the general principle described
herein.
[151] The second separation 50 can be performed for instance in a flash
vessel through
evaporation mechanisms to flash the first upgrader product from the upgrader
product-
Date Recue/Date Received 2020-12-15
31
rich fluid 48. As mentioned above, this separation technique can
advantageously leverage
the difference in vaporization temperature between the first and second
upgrader products
that may be present in the startup fluid, such that the first upgrader product
can be
selectively separated. The recovered first upgrader product can be reused as a
component of the startup fluid for reintroduction into the subsurface
formation.
[152] In other implementations, when the startup fluid includes a first and
second
upgrader products that have a respective vaporization temperature within a
close range,
such as a closer range than for coker kerosene and coker gas oil for example,
the second
separation 50 may be implemented to separate both the first and second
upgrader
products at the same time according to the lowest vaporization temperature of
the first and
second upgrader products to recover a first upgrader product stream 52
comprising the
first and second upgrader products and a bitumen stream 54. In such scenario,
the startup
fluid could include for instance light vacuum gas oil and coker kerosene, or
any other
upgrader products having a vaporization temperature within a close range.
[153] In yet other implementations, the startup fluid can include three
upgrader
products. The second separation 50 may be implemented to separate a first and
second
upgrader products having a respective vaporization temperature within a
certain range,
from a mixture of bitumen and a third upgrader product having a vaporization
temperature
that if different enough from the first and second upgrader products. For
example, in some
implementations, the first and second upgrader products can be coker kerosene
and light
vacuum gas oil, and the third upgrader can be coker gas oil or heavy vacuum
gas oil.
[154] When an additional separation step is desired, the mixture of bitumen
and second
upgrader product 54 (or third upgrader product) can be separated in a third
separation 56
to recover the second or third upgrader product 58 and a bitumen-rich stream
60. In some
implementations, the bitumen-rich stream 60 can then be further processed to
obtain a
suitable bitumen product.
[155] Of note, although the first separation 44, the second separation 50
and the third
separation 56 are illustrated as a single step, each one of the first
separation 44, the
second separation 50 and the third separation 56 can include more than one
separation
stage in order to achieve the desired separation.
Date Recue/Date Received 2020-12-15
32
EXPERIMENTATION
[156] Various experiments were conducted to illustrate some characteristics
of the
startup fluid described herein. Description of experiments performed, and
corresponding
results are presented below.
[157] Experiments were conducted to assess asphaltene precipitation yield
measurements for bitumen diluted with five diluents at ambient temperature and
atmospheric pressure. As used in the context of the experiments performed and
described
below, the term "diluent" refers to upgrader products that have been used to
dilute bitumen
samples to evaluate asphaltene precipitation. These five diluents are diesel,
distillate
kerosene (DK), which can also be referred to as coker kerosene, light vacuum
gas oil
(LVGO), distillate gas oil (DGO), which can also be referred to as coker gas
oil, and heavy
vacuum gas oil (HVGO). Four types of experiments were conducted.
[158] In a first set of experiments, the yields of asphaltenes precipitates
were measured
at five different diluent contents, or concentration. The bitumen samples
diluted with the
various diluents were also assessed for their toluene insoluble content.
[159] In a second set of experiments, for experiments where asphaltene
precipitation
was observed for a given combination of bitumen samples a diluent, the onset
of
precipitation was determined. For four diluents, Le., DK, LVGO, DGO and HVGO,
the
onset of asphaltene precipitation was measured for mixtures of 10 wt% bitumen
and 90
wt% diesel with toluene at ambient temperature and atmospheric pressure for
different
toluene contents to determine the amount of toluene required to prevent
precipitation.
[160] In a third set of experiments, yields of asphaltenes precipitates
were measured
for blends of 50 wt% bitumen and 50 wt% diluent diluted with n-pentane at
ambient
temperature and atmospheric pressure. Three diluents were assessed, i.e.,
diesel, and
DK, DGO, and tests were also performed on undiluted bitumen. Yields of
asphaltenes
precipitates were measured at a minimum of 5 different n-pentane contents.
[161] In a fourth set of experiments, yields of asphaltenes precipitates
were measured
for bitumen diluted with mixtures of DK and DGO diluents at 70:30, 50:50, and
30:70 ratios
Date Recue/Date Received 2020-12-15
33
by mass at ambient temperature and atmospheric pressure. Yields of asphaltenes
precipitates were measured at a minimum of 5 different diluent contents.
[162] The water content of the bitumen sample was measured with the Karl
Fischer
method and was determined to be 2.34 wt%. The toluene insoluble (TI) content
on a dry
basis was determined to be 0.66 wt%.
[163] To measure the yields of asphaltenes precipitates and solids content
of the
samples evaluated, a known mass of bitumen (approximately 1.5 g) was placed in
a
centrifuge tube and diluted with the selected solvent to arrive at the target
diluent content.
The mixture was sonicated for 45 minutes and left to settle for 24 hours.
After the settling
period, the tube was centrifuged for 6 minutes at 6000 rpm. The supernatant
was then
decanted to leave a mass of asphaltenes and solids with some residual
maltenes. This
mass was washed with pentane, sonicated, and centrifuged twice as described
above,
leaving the asphaltenes, solids, and some pentane. At this point the tube and
contents are
dried in a vacuum oven and weighed to obtain the total mass of asphaltenes and
solids in
the sample.
[164] The solids content of the bitumen was determined starting from 10 g
of bitumen
diluted to toluene and washed until the toluene is colorless. Then, the tube
and solids were
dried in a vacuum oven and weighed to obtain the solids content.
[165] The "solids" are thus defined as the toluene insolubles obtained from
an
asphaltene and solids precipitate. The asphaltene content is simply the
asphaltene-solids
content less the solids content. The repeatability of the contents is usually
+1- 0.15 wt%.
[166] The diluents are more viscous than pure hydrocarbon solvents and it
is more
challenging to mix the bitumen with the diluent and to separate the
precipitated
asphaltenes. Thus, to measure the yields of asphaltenes precipitates when
blended with
a given diluent, sonication times were increased for each diluent as required
to ensure
complete mixing. The centrifuge times were increased to 8 minutes except for
HVGO (the
most viscous sample) which was increased to 12 minutes.
[167] The diluents also contain non-volatile material that does not
evaporate during the
drying procedure and artificially adds to the apparent asphaltene yield.
Therefore, a pure
Date Recue/Date Received 2020-12-15
34
hydrocarbon solvent was used for the washing step. If the diluent did not
contain
asphaltenes, the standard procedure was followed except that the precipitate
was washed
with n-pentane instead of the diluent. If the diluent contained asphaltenes,
the standard
procedure was followed except that the precipitate was washed with cyclohexane
instead
of the diluent. The yields from the diluted bitumen were corrected to account
for the
amount of precipitation expected from the diluent itself.
Results ¨ First and second sets of experiments
[168] The yields of asphaltenes precipitates for the mixtures of bitumen
and the five
diluents, i.e., diesel, DK, LVGO, DGO and HVGO, are shown in Figure 6, and the
yields
of asphaltenes precipitates from the mixtures of bitumen and toluene/diluent
blend are
shown in Figure 7. The yields of asphaltenes precipitates are reported on a
dry basis and
their repeatability was 0.065 wt%. The results shown in Figures 6 and 7 are
summarized
in Table 1 below, which shows the required mixing time, the onset of
precipitation, and the
minimum amount of toluene in the diluent blend required to prevent
precipitation (2 g
bitumen at 90 wt% diluent blend).
Table 1: Required mixing time, diluent content at the onset of precipitations,
and
minimum amount of toluene in diluent blend required to prevent precipitation,
all at
room conditions. The uncertainties of the onset and toluene content are 3 and
2
wt%, respectively.
Mixing Time Onset Minimum Toluene
Diluent
hr wt% Content, wt%
Diesel 4 70 13
DK 2.5 none
LVGO 3.5 90 -
DGO 7.5 72 16
HVGO 20 71 20
Date Recue/Date Received 2020-12-15
35
Results ¨ Third set of experiments
[169] Figure 8 compares the yields of asphaltenes precipitates for blends
of 50 wt%
bitumen and 50 wt% diluent, each diluted with n-pentane. In such experiments,
when less
n-pentane was required to precipitate asphaltenes, it was considered that the
blends were
less efficient at solubilizing asphaltenes. Figure 8 shows that the blend of
bitumen and
DGO, and the blend of bitumen and DK were slightly poorer solvents for
maintaining
asphaltenes in solution, or solubilized, compared to a sample of bitumen that
was not
diluted with a diluent. In addition, Figure 8 also shows that the blend of
bitumen and diesel
was a significantly poorer solvent compared to the blend of bitumen and DGO
and the
blend of bitumen and DK. The data shown in Figure 8 illustrates a solubility
trend among
the diluents that is consistent with Figure 6 where the yields of asphaltenes
precipitates
were higher in samples of bitumen diluted with diesel than in samples of
bitumen diluted
with either DGO or DK.
Results ¨ Fourth set of experiments
[170] Turning now to Figure 9, the graph shows yields of asphaltenes
precipitates from
bitumen diluted with DGO and DK over dilutions ranging from 50 wt% to 90 wt%.
The two
diluents were used alone, and also combined together at different ratios. The
different
ratios used were a blend of 70 wt% of DK combined with 30 wt% of DGO (referred
to as
70:30 DK:DGO), a blend of 50 wt% of DK combined with 50 wt% of DGO (referred
to as
50:50 DK:DGO), and a blend of 30 wt% of DK combined with 70 wt% of DGO
(referred to
as 30:70 DK:DGO). No asphaltenes precipitation was observed when DK was used
alone
and for the 70:30 DK:DGO blend, across the dilution range studied. A limited
amount of
precipitation was observed with the DGO, the 50:50 DK:DGO, and the 70:30
DK:DGO
blend. However, the amount of asphaltenes precipitation was barely above the
error of the
measurements and the onsets of precipitation, which can be seen as the change
in slope
of the respective fitted lines. The shaded area represents the range of
measurement error
from the toluene insoluble content which was 0.66 0.065 wt%. Figure 9 thus
shows that
DK can be mixed with DGO at different ratios and be a suitable mixture that
can be used
as a startup fluid to dilute bitumen while avoiding precipitation of
asphaltenes in the
mixture, i.e., maintaining asphaltenes substantially solubilized in the
bitumen, the mixture
having a viscosity that is closer to bitumen than when DK would be used alone.
Date Recue/Date Received 2020-12-15
36
[171] Tables 2 to 9 provided below illustrate raw data obtained from
experiments that
were conducted.
[172] Tables 2 to 6 show yields of asphaltenes precipitates and toluene
insoluble
fraction for samples of bitumen and diesel, DK, DGO, LVGO or HVGO that were
blended
in concentrations ranging from 50 wt% to 90 wt%. These results are also shown
in Figure
6. As discussed previously, these raw data show that diesel and HVGO are less
suitable
to maintain asphaltenes in solution, whereas DK, DGO and LVGO maintained
asphaltenes
in solution at least up to a dilution range of 90 wt% for DK and LVGO, and 80
wt% for
DGO.
Table 2. Yield of asphaltenes and toluene insoluble from mixtures of bitumen
and
diesel at room conditions.
Diluent Content in Feed Yield, wt%
wt% Run 1 Run 2
50 0.63 -
60 0.67 -
70 0.64 0.67
80 0.76 0.82
90 0.91 0.94
Table 3. Yield of asphaltenes and toluene insoluble from mixtures of bitumen
and
kerosene at room conditions.
Diluent Content in Feed Yield, wt%
wt% Run 1 Run 2
50 0.62 -
61 0.64 -
70 0.65 0.62
80 0.65 0.67
90 0.66 0.64
Date Recue/Date Received 2020-12-15
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Table 4. Yield of asphaltenes and toluene insoluble from mixtures of bitumen
and
light vacuum gas oil (LVGO) at room conditions.
Diluent Content in Feed Yield, wt%
wt% Run 1 Run 2
50 0.61 -
61 0.63 -
70 0.62 0.62
80 0.66 0.67
90 0.69 0.69
Table 5. Yield of asphaltenes and toluene insoluble from mixtures of bitumen
and
distillate gas oil (DGO) at room conditions.
Diluent Content in Feed Yield, wt%
wt% Run 1 Run 2
50 0.62 -
60 0.62 -
70 0.65 0.65
80 0.72 0.70
90 0.77 0.79
Table 6. Yield of asphaltenes and toluene insoluble from mixtures of bitumen
and
heavy vacuum gas oil (HVGO) at room conditions.
Diluent Content in Feed Yield, wt%
wt% Run 1 Run 2
50 0.62 -
60 0.72 -
70 0.64 0.62
80 1.33 1.38
90 2.08 2.10
[173] Table 7 shows the yields of asphaltene precipitation and toluene
insoluble fraction
for mixtures of bitumen and either diesel, DGO or HVGO, each provided at a
concentration
Date Recue/Date Received 2020-12-15
38
of 90 wt%. The concentration of toluene was increased from 0 wt% to 20 wt%. As
described above for Figure 7, these results show that when no toluene was
present, the
yields of asphaltene precipitation was lower for DGO than for the other
diluents diesel and
HVGO. As the toluene concentration increased, the yields of asphaltene
precipitation
remained lower for DGO until at 15 wt%, when it became similar between diesel
and DGO
while it remained higher for HVGO. At a concentration of 20 wt%, the three
diluents diesel,
DGO and HVGO were similar at preventing asphaltenes precipitation. These
results show
that DGO can advantageously prevent asphaltenes precipitation even when no
toluene is
present. Thus, in some implementation, DGO can perform better than diesel as a
startup
fluid aimed at preventing asphaltene precipitation in proximity of the wells.
Table 7. Yield of asphaltenes and toluene insoluble from mixtures of bitumen
and
three diluents (diesel, DGO, and HVGO) each diluted with toluene at room
conditions. The mixtures were prepared with 90 wt% blend in the feed in all
cases.
Toluene Content in Yield, wt%
Diluent Blend, wt% Diesel DGO HVGO
0 0.92 0.78 2.09
0.80 0.74 1.68
0.74 0.71 1.33
0.64 0.63 0.95
0.63 0.69 0.69
[174] In Table 8, the experiments were performed to assess the onset of
asphaltene
precipitation when increasing amounts of pentane were added to bitumen and
diluent
blends. In these experiments, DK, DGO and diesel were used, as well as bitumen
that
was not mixed with any diluent. These results are also shown in Figure 8.
According to
the results shown in Table 8, the blends of bitumen and DGO or DK performed
better than
diesel at maintaining asphaltenes in solution up to a concentration of 60 wt%
of pentane,
whereas asphaltene precipitation was significantly increased at a
concentration of 45 wt%
of pentane for the blend of bitumen and diesel. Similar results were obtained
for diesel,
DGO and bitumen alone at concentrations of pentane above 60wt%, while the
blend of
bitumen and DK showed a lower level of asphaltene precipitation even at
concentrations
higher than 60 wt% of pentane.
Date Recue/Date Received 2020-12-15
39
Table 8. Yield of asphaltenes and toluene insoluble from bitumen or blends of
50
wt% bitumen and 50 wt% diluent each diluted with n-pentane at room conditions.
n-Pentane Content Yield, wt%
wt% Bitumen DGO Diesel
35 - 1.0 1.0 1.4
40 - 1.1 1.0 1.9
45 0.8 1.1 1.1 4.8
50 1.3 2.5 2.5 7.1
55 5.0 - - 9.3
60 9.9 10.7 8.3 11.5
70 16.0 15.0 12.8 15.1
80 17.8 17.0 15.7 17.0
90 18.7 17.3 16.9 18.2
90 18.6 17.5 16.9 -
[175] Table 9 shows yields of asphaltenes precipitation for blends of
bitumen mixed
with a combination of two diluents, i.e., DK and DGO, provided at different
ratios defined
above in reference to Figure 9. As also seen in Figure 9, the blend comprising
bitumen
and a ratio of 70:30 DK:DGO enabled maintaining asphaltene substantially
solubilized
over the range of concentrations of the mixture of diluents in the bitumen.
The other ratios
of 50:50 DK:DGO and 30:70 DK:DGO appeared to have performed similarly in
maintaining
the asphaltenes in solution, and appeared to perform better than DGO alone.
Table 9. Yield of asphaltenes and toluene insoluble from mixtures of bitumen
with
blends of DK and DGO at room conditions.
Blend Content in Feed Yield, wt%
wt% 70:30 DK:DGO 50:50 DK:DGO 30:70 DK:DGO
50 0.69 0.61 0.63
60 0.68 0.65 0.55
70 0.64 0.63 0.57
80 0.70 0.65 0.63
90 0.68 0.75 0.78
Date Recue/Date Received 2020-12-15
