Note: Descriptions are shown in the official language in which they were submitted.
I
HYDROCARBON RECOVERY WITH INJECTION OF PRESSURIZED FLUID AND
PRODUCTION VIA SINGLE WELL
TECHNICAL FIELD
[001] The technical field generally relates to in situ hydrocarbon recovery
operations and,
more particularly, to hydrocarbon recovery using the injection of a
pressurized fluid which
may be done via a single well.
BACKGROUND
[002] In situ hydrocarbon recovery operations can use high temperature fluids
for injection
into a hydrocarbon-bearing reservoir. The hot injected fluids heat the
hydrocarbons in the
reservoir, reducing the viscosity and increasing the mobility of the
hydrocarbons to facilitate
production. The produced fluids that are recovered from the reservoir can then
be
separated to generate a hydrocarbon-enriched stream and a hydrocarbon-depleted
stream.
Various techniques have been developed to enhance mobilization of hydrocarbons
by
injection of a mobilizing fluid.
[003] In conventional steam-assisted gravity drainage (SAGD) processes, a well
pair is
drilled into the reservoir such that a horizontal injection well is vertically
spaced above a
horizontal production well. Steam is injected into the reservoir via the
horizontal injection
well in order to heat and mobilize hydrocarbons in the reservoir. Mobilized
hydrocarbons
flow by gravity toward the horizontal production well, and are then produced
to the surface
for processing. There are various challenges and drawbacks with respect to
drilling,
completing and operating such a SAGD well pair.
SUMMARY
[004] In some implementations, there is provided a process for recovering
hydrocarbons
from a reservoir, the process comprising: providing an injection conduit and a
production
conduit extending within a horizontal wellbore section, the injection conduit
comprising a
plurality of spaced-apart injection ports along a length thereof, and the
production conduit
comprising a plurality of spaced-apart production ports that are off-set with
respect to the
injection ports; delivering a pressurized mobilizing fluid into the injection
conduit so as to be
in substantially liquid phase within the injection conduit; discharging the
pressurized
mobilizing fluid into the reservoir through the injection ports of the
injection conduit, the
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pressurized mobilizing fluid at least partially vaporizing into a gas phase
upon discharge to
contact and mobilize the hydrocarbons in the reservoir; and recovering a
production fluid
comprising mobilized hydrocarbons via the production ports of the production
conduit.
[005] In some implementations, discharging the pressurized mobilizing fluid
comprises
providing a sufficient pressure drop across the injection ports to at least
partially vaporize
the mobilizing fluid upon discharge into the reservoir.
[006] In some implementations, the process includes heating the mobilizing
fluid before
delivery into the reservoir. In some implementations, the heating of the
mobilizing fluid is
performed before, after or during the pressurizing the mobilized fluid. In
some
implementations, the mobilizing fluid includes water, an organic solvent, or a
combination
thereof. In some implementations, the mobilizing fluid includes or consists
essentially of the
organic solvent that is a Cl-05 alkane solvent. In some implementations, the
alkane solvent
comprises propane, butane or a mixture thereof. In some implementations, the
mobilizing
fluid is water. In some implementations, the mobilizing fluid is a mixture of
water and
organic solvent.
[007] In some implementations, the mobilizing fluid is pressurized between 3
MPa and 16
MPa at a temperature between 100 C and 350 C within the injection conduit.
[008] In some implementations, the process includes delivering multiple
different
mobilizing fluids into the injection conduit. In some implementations,
multiple independent
injection conduits are provided within the horizontal section of the well, and
the process
comprises delivering multiple mobilizing fluids into the respective multiple
injection conduits.
[009] In some implementations, the injection conduit includes a tubular
injection line that
has a diameter between 20 mm and 300 mm. In some implementations, the diameter
of the
tubular injection line is between 50 mm and 150 mm. In some implementations,
the
production conduit includes a tubular production line that has a diameter
between 60 mm
and 200 m. In some implementations, the diameter of the tubular injection line
is between
100 mm and 150 mm. In some implementations, the horizontal well bore section
has a
diameter between 100 mm and 300 m.
[010] In some implementations, discharging the pressurized mobilizing fluid
comprises
providing sonic choked flow upon discharge of the mobilizing fluid. The sonic
choked flow
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can be provided by configuring or controlling flow control devices located at
each injection
port.
[011] In some implementations, the process further includes inhibiting
production of the
gas phase of the mobilizing fluid via the production ports. The inhibiting of
production of the
gas phase can include configuring or controlling flow control devices located
at each
production port, providing packers or isolation devices in between adjacent
injection ports
and production ports to inhibit gas flow therebetween, and/or directing gas
flow from the
injection ports away from adjacent production ports.
[012] In some implementations, the process includes applying a pressure
differential in an
axial direction along the well to form alternating lower-pressure regions and
higher-pressure
regions in the reservoir. The applying of the axial pressure differential can
cindlue providing
an injection pattern tailored to a given axial pressure differential to
produce the alternate
higher-pressure regions and lower-pressure regions within the reservoir,
configuring and
operating the injection ports to inject the gas phase of the mobilizing fluid
in axial directions
away from the production ports that are adjacent to the respective injection
ports, placing at
least one packer between an injection location and an adjacent production
location.
[013] In some implementations, the injection conduit and the production
conduit are
provided as a concentric injection-production assembly. The concentric
injection-production
assembly can include an inner injection tube defining the injection conduit
for transmitting
the mobilizing fluid; an outer tube concentric with the inner tube and
defining therebetween
an annular passageway as the production conduit, the outer tube fluidly
communicating with
the production ports to receive and transmit the production fluid
therethrough; and a fluid
passage fluidly connecting the inner tube to the injection ports for discharge
of the
mobilizing fluid therethrough.
[014] The concentric injection-production assembly can include an injection
module
including a chamber outside of the outer tube and being in fluid communication
with the
fluid passage for receiving the mobilizing fluid. The injection ports can be
provided on the
injection module so that the mobilizing fluid can flow through the chamber and
be
discharged from the injection ports. Multiple injection modules can be
provided in spaced
relation along the concentric injection-production assembly. Each module of
the concentric
injection-production assembly can include a tubular wall that is generally
concentric with the
outer tube and defines the chamber. The tubular wall of each module of the
concentric
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injection-production assembly can have two opposed spaced-apart rings. The
injection
ports can be provided on the rings of the module, and the injection ports can
be positioned
and oriented to provide two opposed sets of injection ports on opposed axial
sides of each
module. The two opposed sets of injection ports can be positioned and oriented
to inject the
mobilizing fluid toward each other.
[015] In some implementations, the horizontal well section follows a variable
base
elevation along a length thereof and is positioned proximate to the base of
the reservoir.
The horizontal well section is located at a substantially constant distance
away from the
base along the length thereof.
[016] In some implementations, there is provided a process for recovering
hydrocarbons
from a reservoir, the process comprising: delivering a pressurized mobilizing
fluid into an
injection conduit extending within a horizontal wellbore section so as to be
in substantially
liquid phase within the injection conduit, the injection conduit comprising a
plurality of
spaced-apart injection ports along a length thereof; discharging the
pressurized mobilizing
fluid into the reservoir through the injection ports of the injection conduit,
the pressurized
mobilizing fluid at least partially vaporizing into a gas phase upon discharge
to contact and
mobilize the hydrocarbons in the reservoir; and recovering a production fluid
comprising
mobilized hydrocarbons via a production conduit located in the horizontal
wellbore section
and comprising a plurality of spaced-apart production ports that are off-set
with respect to
the injection ports of the injection conduit.
[016a] In another implementation, there is provided a process for recovering
hydrocarbons
from a reservoir wherein an injection conduit and a production conduit extend
through the
reservoir in an axial direction, the process comprising:
delivering a mobilizing fluid into the injection conduit;
providing a pressure differential in the axial direction of the reservoir to
form
alternating lower-pressure regions and higher-pressure regions along the
injection
conduit, wherein providing the pressure differential comprises discharging the
mobilizing fluid into the higher-pressure regions of the reservoir via the
injection
conduit; and
Date Recue/Date Received 2021-02-26
4a
producing mobilized hydrocarbons from the lower-pressure regions of the
reservoir
via the production conduit, wherein the producing comprises drainage of the
mobilized hydrocarbons into the production conduit.
[017] In some implementations, there is provided a process for recovering
hydrocarbons
from a reservoir, the process comprising: discharging a pressurized mobilizing
fluid into the
reservoir via an injection conduit extending within a horizontal well, wherein
a pressure
differential between the injection conduit and the reservoir induces liquid to
gas phase
transition of at least a portion of the mobilizing fluid upon discharge
thereof into the
reservoir; mobilizing the hydrocarbons using the injected gas phase of the
mobilizing fluid to
form a production fluid comprising mobilized hydrocarbons; and producing the
production
fluid via a production conduit extending within the horizontal well.
Date Recue/Date Received 2021-02-26
5
[018] It is noted that various features mentioned above or herein can be
combined with
such process implementations.
[019] In some implementations, there is provided a process for recovering
hydrocarbons
from a reservoir wherein an injection conduit and a production conduit extend
through the
reservoir in an axial direction and are provided as a concentric injection -
production
assembly comprising: an inner injection tube defining the injection conduit
for transmitting
the mobilizing fluid; an outer tube concentric with the inner tube and
defining therebetween
an annular passageway as the production conduit, the outer tube fluidly
communicating with
production ports to receive and transmit the production fluid therethrough;
and a fluid
passage fluidly connecting the inner tube to injection ports for discharge of
the mobilizing
fluid therethrough; the process comprising: delivering a mobilizing fluid into
the inner
injection tube; providing a pressure differential in the axial direction of
the reservoir to form
alternating lower-pressure regions and higher-pressure regions along the
injection conduit,
wherein providing the pressure differential comprises discharging the
mobilizing fluid into
the higher-pressure regions of the reservoir via the injection ports; and
producing mobilized
hydrocarbons from the lower-pressure regions of the reservoir via the
production ports.
[020] In some implementations, the mobilizing fluid is delivered in liquid
phase into the
injection conduit and at least partially vaporizes during discharge through
the injection ports
into the reservoir, such that the vaporized gas phase facilitates formation of
the high-
pressure regions.
[021] In some implementations, there the injection conduit and the production
conduit are
deployed within in a same horizontal wellbore section. Such implementation can
include
additional features as described above and herein.
[022] In some other implementations, the injection conduit and the production
conduit are
respectively deployed within two different well sections. The two well
sections can include a
horizontal injection well accommodating the injection conduit, and a
horizontal production
well located generally vertically below the injection well and accommodating
the production
conduit, the horizontal injection well and the horizontal production well
forming a horizontal
well pair. The horizontal production well and the horizontal injection well
can extend from
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the same vertical well section or from two distinct vertical well sections.
The two-well
implementation can have various features as described herein that are
applicable to a two-
well configuration.
[023] It is also noted that there are various systems provided for
implementing processes
described herein. For example, a system for recovering hydrocarbons can
include a well
that includes injection and production conduits extending along a horizontal
well section,
injection and production ports that are optionally offset from one another, a
pressurization
unit for pressurizing a mobilizing fluid for transmitting the fluid in liquid
phase via the
injection conduit, the injection ports being configured to enable vaporization
of at least a
portion of the mobilizing fluid upon discharge into the reservoir. The system
can also
include modules, an injection-production conduit assembly, and various other
units as
described herein.
[024] While aspects of the process will be described in conjunction with
example
implementations, it will be understood that it is not intended to limit the
scope of the process
to such implementations. On the contrary, it is intended to cover all
alternatives,
modifications and equivalents as may be included as defined by the present
description.
The objects, advantages and other features of the process will become more
apparent and
be better understood upon reading of the following non-restrictive
description, given with
reference to the accompanying drawings.
BRIEF DESCRIPTION OF THE DRAWINGS
[025] Figure 1 is a schematic drawing of hydrocarbon recovery equipment and
operation
via a single well.
[026] Figure 2 is a simulated cross-section of the gas chamber along an axial
direction of
a reservoir and at three different times.
[027] Figure 3 is a schematic cross-section of a gas chamber surrounding a
single well
along a vertical direction of a reservoir.
[028] Figures 4A and 4B are schematic drawings of two process configurations
for fluid
injection.
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[029] Figure 5 is a schematic drawing of a hydrocarbon recovery process
including a
controlling unit.
[030] Figure 6 is a schematic drawing of an injection conduit and a production
conduit
according to an operation pattern.
[031] Figure 7 is a schematic drawing of an injection conduit and a production
conduit
according to another operation pattern.
[032] Figure 8 is a schematic drawing of an injection conduit and a production
conduit
according to yet another operation pattern.
[033] Figure 9 is a schematic drawing of hydrocarbon recovery equipment and
operation
via a single well including injection modules.
[034] Figure 10 is a schematic perspective view of an injection module.
[035] Figure 11 is another schematic drawing of hydrocarbon recovery equipment
and
operation via a single well including concentric injection and production
lines with packers.
[036] Figure 12 is a schematic perspective view of another injection module
with
concentric injection and production lines.
[037] Figure 13 is a simulated cross-section of a section of a reservoir
including a growing
steam chamber when recovering hydrocarbons with SAGD.
[038] Figure 14 is a simulated cross-section of a section of a reservoir when
recovering
hydrocarbons via a single well in operation conditions similar to SAGD.
[039] Figure 15 is a simulated temperature profile of a well portion between
two well bore
points and at a well-reservoir interface.
[040] Figure 16 is a simulated mass flow production profile of the same well
portion as per
Figure 12 and at a well-reservoir interface.
[041] Figure 17 is a graph of oil production in m3/day for simulated oil
recovery via a single
well operation with comparative three different axial pressure differences
(high dP, medium
dP, and low dP) and via SAGD operation.
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[042] Figure 18 is a graph of oil production in m3/day for simulated oil
recovery via a single
well operation with two different axial pressure differences (high dP and low
dP) and a
packer.
[043] Figure 19 is another schematic drawing of hydrocarbon recovery equipment
and
operation via a single well including concentric injection and production
lines.
[044] Figures 20A to 20E are cross-sectional side view schematics illustrating
various
configurations of part of a production-injection conduit assembly having an
injection module.
DETAILED DESCRIPTION
[045] Implementations of processes and systems for recovering hydrocarbons
from a sub-
surface hydrocarbon-bearing reservoir are provided. A fluid, including water
and/or solvent,
can be heated and pressurized so as to travel in liquid phase and be delivered
in gas phase
into the reservoir, thereby providing various advantages, such as downsizing
of surface and
sub-surface equipment. Utilizing liquid phase delivery of the mobilizing fluid
via a single well
that is also used to produce mobilized hydrocarbons from the reservoir
facilitates
advantages related to efficient deployment and operation of hydrocarbon
recovery wells.
[046] Hydrocarbons are contained in porous or fractured rock formations having
high
porosity, which keeps the viscous hydrocarbons immobile under existing
reservoir
conditions. Hydrocarbons may be referred to or understood as oil or bitumen.
The reservoir
can include, for example, a heavy oil reservoir (where the oil is initially
mobile), an oil sands
reservoir, a tar sands reservoir or any bituminous sands reservoir having an
exploitable pay
zone.
[047] To mobilize the hydrocarbons, the process includes injecting the heated
and
pressurized fluid via an injection conduit and into the reservoir. The fluid
in liquid phase
under the injection conduit conditions vaporizes upon exiting the injection
conduit under the
reservoir conditions. A gas chamber is thereby created and expands laterally
outwardly
within the reservoir. It should be noted that the gas chamber can have
different
characteristics depending on the stage of the recovery operation (e.g., start-
up, ramp up,
plateau, wind-down), the reservoir properties, and the mobilizing fluid that
is injected. For
example, when the mobilizing fluid is injected as steam, the gas chamber can
be referred to
as a steam chamber. Within the gas chamber, higher gas-phase saturation will
be at the
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center while at the boundaries of the gas chamber there will be liquids
including mobilized
liquid hydrocarbons and condensed mobilizing fluid.
Liquids are mobilized at the
boundaries of the chamber. Heat from the gas chamber is transmitted to the
hydrocarbons,
which lowers their viscosity to enable drainage thereof. It should be noted
that, in the case
where a solvent is used as a pressurized fluid, hydrocarbon viscosity can be
reduced when
the solvent dissolves in the in-place hydrocarbons (as opposed to simply
heating the
hydrocarbon). For soluble solvents, the hydrocarbons can be mobilized from
both increased
temperature and dilution effects. The condensed or dissolved gas phase and
mobilized
hydrocarbons are then produced, and can be referred to together as the
production fluid.
The acceleration due to gravity will cause the production fluid to move
downward along the
draining edges of the gas chamber and into a production conduit. The process
further
includes production of the mobilized hydrocarbons via the production conduit.
[048] In some implementations, the injection conduit and the production
conduit can be
located within a same well bore and are thus part of a single well. As the
fluid to be injected
is pressurized sufficiently to be in liquid phase, a smaller conduit can be
used for injection in
comparison to a typical SAGD operation. The injection conduit and the
production conduit
can be located within the single well to further simplify and downsize
equipment. The single
well configuration can also have certain economic advantages, since the
drilling,
maintenance and operational costs can be reduced compared to a dual well
configuration.
However, proximity of the injection conduit and the production conduit present
challenges,
such as production of the injected gas phase via the production conduit.
Various solutions
are described hereinafter to address such challenges.
[049] In other implementations, the injection conduit and the production
conduit may be
located in an injection well and a production well respectively, as in a
traditional dual well
configuration, e.g. a well pair in a SAGD, configuration. Other configuration
are also
possible, such as providing a SAGD well pair in which at least one of the
wells is completed
with injection-production capabilities so as to be operable as a single well
during certain
stages of the operation.
Injection implementations
[050] Implementations of injection of a heated and pressurized mobilizing
fluid via an
injection conduit into a sub-surface reservoir are described in further detail
below.
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Water and/or solvent
[051] It should be noted that the term fluid refers to a substance or a
mixture having the
ability to flow. Depending on the conditions within the conduits or the
reservoir, the fluid
may be in liquid state, referred to as the liquid phase, or in a gaseous
state, referred to as
the gas phase.
[052] In some implementations, the mobilizing fluid can include water, an
organic solvent
or a mixture thereof. Optionally, the organic solvent can be a lower alkane
solvent, including
propane and/or butane, which is compressible to a transportable liquid. The
mobilizing fluid
can also include other chemical compounds in various concentrations.
[053] Water and solvent may be mixed in a ratio between 5:1 and 12:1,
optionally between
7:1 and 11:1, and further optionally around 10:1. It should be noted that
solvent only may be
used as an injection fluid, where the produced fluids can have a solvent-to-
oil ratio
optionally between 3:1 and 9:1, further optionally between 5:1 and 7:1. Thus,
various ratios
of solvent and water can be used for injection.
[054] In some implementations, the solvent and water are combined together
using
equipment at surface facilities, and then the solvent-water mixture is
injected as the heated
pressurized fluid. The mixing, heating and pressurization steps can be
conducted in various
orders and using various units and equipment.
Downhole liquid-to-gas phase
[055] The process can take advantage of the injection of the mobilizing fluid
in liquid state
from the surface and transitioning to a gaseous state upon being subjected to
reservoir
conditions.
[056] Referring to Figure 1, hydrocarbons are contained within an in-situ
reservoir 2, in
which a wellbore 4 has been drilled. It should be noted that various
completions can be
provided, including casings and liners, within different sections of the
wellbore 4. Recovery
of the hydrocarbons involves flowing of the mobilizing fluid in liquid phase
via an injection
conduit 6. The injection conduit 6 extends downwardly from the surface within
a vertical
section of the wellbore 4 and then horizontally within a horizontal section of
the wellbore 4
located in reservoir 2 at a desired depth.
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[057] It should be noted that in the implementation illustrated in Figure 1, a
cased-hole
completion can be provided for the well, including the wellbore 4 containing a
first portion of
both injection and production conduits, and a liner 5 extending horizontally
from a distal end
of the well bore and containing both the injection and production conduits.
The liner 5 can
be slotted, screened, or perforated to enable fluid communication with the
reservoir.
Variations in the well completion design may exist as available to one skilled
in the art. It is
also noted that for some reservoirs the injection and production conduits can
be located
within the horizontal section of the wellbore without a liner.
[058] Implementations of the process include maintaining the fluid
substantially in liquid
state while flowing within the injection conduit. The mobilizing fluid in
liquid phase then
experiences a liquid-to-gas phase change when exiting the injection conduit at
a downhole
location, and the gas phase fluid enters the reservoir.
[059] It should be noted that the mobilizing fluid may not be fully in liquid
phase and may
vaporize to some extent or include some vapour phase within the injection
conduit
depending on the temperature and pressure conditions that are maintained
within the
injection conduit. The term "substantially" is therefore used to reflect this
behavior of the
fluid.
[060] It should be further noted that the mobilizing fluid, depending on the
nature of its
components, may not fully vaporize upon discharge via the injection conduit.
In this case, a
gas-liquid mixture may be discharged into an annulus of the well at a lower
temperature and
pressure than in the injection conduit. The gas phase can exit the well
through buoyancy-
drive, whereas the liquid phase mainly remains within the horizontal section
of the wellbore.
[061] Heat conduction is part of the oil recovery mechanisms. Therefore, the
mobilizing
fluid can be heated to subsequently provide at least part of this heat to the
hydrocarbons
and reduce viscosity thereof. In some implementations, pre-heating equipment
located at
the surface may be used to pre-heat the fluid to an adequate temperature
before being
made to flow within the injection conduit. For example, referring to Figure 1,
produced water
102 may be used as low quality steam in a heating unit 24, such as a heat
exchanger. In
other implementations, the fluid may be alternatively or additionally heated
downhole within
the injection conduit prior to being discharged within the reservoir. For
example, downhole
heating may be effected through a closed-loop circulation of a heating fluid,
such as a hot
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oil; through the use of electric resistance-based heating (e.g., in the form
of heating cables);
or through the use of downhole electric induction heaters or other types of
heaters that can
be deployed downhole.
[062] To maintain the heated fluid in substantially liquid phase, the process
further
includes pressurizing the heated fluid within an adequate pressure range. It
should be noted
that the conditions of pressure and temperature imposed in the injection
conduit may vary
according to the nature of the fluid used to mobilize the hydrocarbons.
Referring to Figure 1,
a pressurization unit 26 can be provided at the surface to pressurize the
mobilizing fluid
before delivery into the injection conduit 6. For example, a pump may be used
and
configured to put the fluid under adequate pressure for maintaining a liquid
state. It should
further be understood that various equipment available to one skilled in the
art may be used
to impose a given desired pressure to the injected fluid, including for
example a horizontal
electric pump. Depending on the configuration of the at-surface equipment,
various
structural and operational features can be implemented to maintain and/or
impart the
desired temperature and pressure to the fluid to be injected. It should
further be noted that
heating and pressurizing may be performed simultaneously or in any order
suited to fulfill
adequate operation conditions for the injection. The pressure can be provided
based on the
composition and the temperature of the fluid that is injected, as well as the
fluid dynamic
properties of the injection conduit (e.g., friction, internal diameter,
length, pressure loss), to
facilitate the mobilizing fluid to be in substantially liquid state until
discharge into the
reservoir.
[063] For example, water may be heated to a temperature between 200 C and 350
C,
and pressurized between 3 MPa and 16 MPa. Optionally, water may be heated to
about
315 C and pressurized at about 11 MPa. In another example, butane may be
heated to a
temperature between 100 C and 200 C and pressurized between 3 MPa and 5 MPa.
Optionally, butane may be heated to about 150 C and pressurized at about 4
MPa. It is
noted that the pressure and temperature conditions and/or fluid composition
can be
modified over time, for example at different stages of the hydrocarbon
recovery operation.
[064] The pressure differential existing between the injection conduit and the
reservoir
allows for downhole vaporization of the mobilizing fluid from liquid phase to
gas phase upon
discharge into the reservoir via the injection conduit. Pressure differentials
can be
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monitored using various pressure sensors, estimated, and regulated by
adjusting various
parameters of the process.
[065] It should be understood that implementations of the process and the
injection
conduit are not limited to flowing a liquid for flashing upon injection into
the reservoir.
Optionally, some implementations of the process can include flowing a high-
pressure
mobilizing gas phase fluid (e.g., high-pressure steam) within the injection
conduit and
distributing the steam along the conduit through the injection ports.
Injection equipment implementations
[066] Referring to Figure 1, the injection of the mobilizing fluid can include
injection via a
plurality of injection ports 8 providing sufficient pressure drop to vaporize
the fluid entering
the reservoir. The injection ports 8 are provided along a horizontal section
of the injection
conduit 6 to enable axial distribution of the gas phase within the reservoir.
The injection
ports 8 may be spaced apart from one another in a regular pattern to promote
spreading of
the generated gas phase within the reservoir 2. As better seen on Figure 2,
the spreading
pattern of the injected gas phase may change over time as the gas chambers
grow and
coalesce.
[067] It should be noted that the injection ports 8 can be spaced unevenly
along the
injection conduit at strategic and/or pre-determined locations. The
positioning of the
injection ports 8 can be based on various factors, such as reservoir
characteristics (e.g.,
geological barriers, hydrocarbon distribution within pay zone, etc.) or fluid
dynamic
properties of the mobilizing fluid and/or the production fluid. The recovery
operations can
therefore include strategically positioning the injection ports 8 along the
injection conduit to
promote and tailor gas chamber growth and oil recovery in a way that
optimizes, enhances
or maximizes oil production rate in variable geology.
[068] As supplying the fluid through the injection conduit in liquid state
enables using
conduits with smaller diameter than in a traditional SAGD process, using
multiple injection
conduits within a same well can be facilitated and can present further
advantages.
[069] In some implementations, the mobilizing fluid can include multiple
components
(which may also be referred to as multiple mobilizing fluids) that can be
injected, for
example, via the same or different injection conduits provided in the well.
Specific sets of
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temperature and pressure conditions can be applied to each component flowing
in each
injection conduit. For example, heated and pressurized water can be injected
into the
reservoir via a first conduit, and heated and pressurized butane can be
injected into the
reservoir via a second conduit, extending along the first conduit in parallel
relationship
therewith. Injection ports of the first and second conduits may be as defined
above and
distributed in parallel or staggered rows. The injection ports of the
different injection
conduits can be provided at similar locations along the length of the well, or
at different
longitudinal locations to achieve certain fluid injection patterns and
effects. The multiple
injection conduits can be distinct tubular conduits arranged beside each
other, or co-annular
conduits that may have tubular or annular forms depending on the overall
completion
design.
[070] Referring to Figure 4A, a first mobilizing fluid 101 and a second
mobilizing fluid 103
can be delivered simultaneously within a single injection conduit 6 and
discharged into the
reservoir 2 via the injection ports 8. Referring to Figure 4B, the first
mobilizing fluid 101 and
the second mobilizing fluid 103 can be delivered simultaneously into
respective first and
second independent injection conduits 6 and 60, and then discharged into the
reservoir via
respective injection ports 8 and 80. It should be noted that, when multiple
mobilizing fluids
are delivered via independent injection conduits, they can be discharged
successively,
alternatingly, or simultaneously into the reservoir. It is also noted that
there may be at least
two distinct injection conduits for injecting similar or different fluids at
similar or different
conditions into similar or different regions of the reservoir.
[071] The injection conduit can have various structural and operational
features. In some
implementations, the injection conduit can have an outer diameter between 20
mm and 300
mm, optionally between 30 mm and 200 mm, further optionally between 60 mm and
115
mm. In addition, the injection conduit can be insulated to limit heat loss of
the injection fluid
before reaching the injection ports. Insulation can be provided along certain
portions of the
injection conduit (e.g., primarily along upstream portions, portions with
greater risk of heat
loss and/or portions in which the wellbore has a larger diameter to facilitate
accommodation
of insulation liners or materials). The injection conduits can be provided as
tubular strings
for transmitting the fluid, as generally illustrated in Figures 4 to 8 for
example; or as part of a
co-annular constructions that includes both the injection and production
conduits, as
generally illustrated in Figure 11.
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[072] In some implementations, distribution of the injection fluid into the
reservoir may be
performed via a plurality of injection modules, spaced-apart from one another
along the
longitudinal axis of the horizontal wellbore. Examples of injection modules 80
are shown in
Figures 9 to 12, 19 and 20. The injection modules are in in fluid
communication with one
another via a longitudinal passageway that extends along the injection
conduit, and the
injection modules define spaced-apart adjacent injection locations. The
injection modules
can be used in particular when the injection and production conduits are
arranged generally
concentrically, e.g., where the injection conduit includes a central
passageway defined by
an inner tube and the production conduit is defined as an annular passageway
between the
inner tube and an outer tube, which is optionally co-axial with the inner
tube. Each injection
module may be configured and designed to include an injection annulus 82 that
is generally
co-annular with the outer tube, and a radial passage that fluidly connects
each injection
annulus 82 with the inner tube so that the mobilizing fluid can flow from the
inner tube,
through the radial passage, into the injection annulus 82 and then be expelled
from the
injection ports that are located as one or more locations around the injection
annulus 82.
The injection modules 80 deliver the injection fluid into the reservoir via
the injection ports 8
that can be distributed around the injection annulus. The injection ports 8
can be formed as
apertures through the wall that defines part of the injection annulus, and the
location and
direction in which the apertures point can be provided to enable desired
injection effects.
Referring to Figures 9 to 12, the injection module 80 may include two
injection rings 82
located at each opposed end of the module 80. Each injection ring can include
a rim that
faces the opposed rim of the other injection ring, and on which the injection
ports are
located, for example distributed in a generally circular pattern around the
rims. Various
other configurations can be used where two sets of injection ports 8 generally
face each
other in order to expel the vaporized fluid toward each other's general
direction.
[073] Referring still to Figures 9 to 12 and 19, the injection ports 8
provided on the module
can be positioned and configured so that the fluid is injected in a generally
axial direction. In
the case of the illustrated injection modules, two opposed sets of the
injection ports face
each other, such that the axes of the apertures are generally parallel with
each other and
with respect to the wellbore and conduits. Alternatively, the injection ports
could be
configured for oblique injection direction of the fluid, i.e., the fluid would
be injected at an
upward angle relative to the longitudinal axis of the wellbore and/or relative
to the adjacent
conduit. Other arrangements and configurations are also possible for the
injection ports to
enable injection of the fluid at certain angles and directions. Optionally,
the injection ports
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are arranged so that there are at least two spaced-apart injection ports that
are oriented to
inject fluid in each other's general direction to facilitate formation of a
high-pressure region
in a reservoir region in the vicinity between the two spaced-apart injection
ports. Figures
20A to 20E illustrate some possible configurations of injection modules and
ports that can
be used.
[074] With reference to implementations shown in Figures 9 to 12 and 19, each
corresponding set of injection ports 8 can be configured to inject the
injection fluid in
substantially facing directions to facilitate formation of a higher-pressure
region (HP) (a)
between two adjacent modules (as in Figure 9) or (b) between two rings of a
same module
(as in Figures 11 and 19). Optionally, the modules may be spaced apart from
each other at
a distance between 5 m and 100 m, further optionally between 10 m and 25 m.
[075] As it may be appreciated, number of modules, distance between the
modules,
injection pattern from the modules, and other structural and operational
features can vary to
meet design completion requirements in relation to the characteristics of the
reservoir. For
example, it should be noted that the injection ports can be configured or
controlled to
provide different injection rates at different locations along the wellbore
(e.g., higher
injection rates near or at the toe compared to the heel, lower injection rates
near or at the
toe compared to the heel, or higher injection rates at particular locations
along the wellbore
due to certain geological characteristics of the reservoir in that region or
due to certain
process performance characteristics). The injection pattern and approach can
be facilitated
by deployment of flow control devices at injection ports, which will be
discussed further
below.
Flow control devices for injection
[076] Optionally, each injection port of the injection conduit is equipped
with a flow control
device (FCD), which can be configured to provide sonic choked flow to the
injected
mobilizing fluid. It should be understood that sonic choked flow is achieved
when the
mobilizing fluid reaches the speed of sound (i.e., M =1) through the FCD. At
the speed of
sound, pressure variations between the injection conduit and the reservoir can
no longer be
communicated upstream of the FCD (i.e., within the injection conduit). Indeed,
the speed at
which these pressure changes are propagated is limited by the speed of sound.
The FCD
CA 3050701 2019-07-29
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can be provided with a restriction or nozzle which is able to isolate the
injection conduit from
the downstream reservoir side such that the pressure differential is not
propagated
upstream of the restriction in the injection conduit. Any reduction in
downstream pressure
within the reservoir has therefore no effect on the mass flow rate of the
mobilizing fluid.
[077] Other implementations of the FCD may include those described in Canadian
Patent
Application No. 2940953. Other FCDs can also be used. The FCDs used along the
injection
conduits can be the same or different FCDs can be used at different locations
to achieve a
desired effect. The FCDs can be active or dynamic, meaning that they can be
actively
controlled or changed, or the FCDs can be passive and predesigned for a
particular
purpose.
Production implementations
[078] Implementations of the process include production of a production fluid
via the
production conduit. Various aspects and details regarding production will be
discussed
below.
[079] Referring to Figure 3, the gas chamber 12 has a vertical section
corresponding to
the reservoir area contacted by the injected mobilizing fluid 14 and depending
on the
vertical sweep efficiency of the injected mobilizing fluid 14. As the
mobilizing fluid 14
mobilizes the hydrocarbons at the interface between the gas chamber 12 and the
reservoir
2, a fluid including mobilized hydrocarbons 16 is formed and referred to
herein as the
production fluid. The force of gravity will cause the production fluid 16 to
move downward
and flow by gravity drainage to the production conduit 10. The production
fluid may
accumulate at a downhole location 18 below the gas chamber 12 depending on the
production flowrate.
[080] Referring to Figure 1, the production conduit 10 is located proximate to
the injection
conduit 6 within the same well. Production is performed via a plurality of
production ports 20
that are provided along a horizontal section of the production conduit 10. The
production
ports 20 may be spaced away from one another in a regular pattern to promote
drainage of
the generated production fluid along an axial direction of the reservoir 2, or
in an irregular
pattern optimized based on the reservoir deliverability. The production fluid
may undergo
various downstream treatment operations to recover the mobilized hydrocarbons.
For
example, a separation unit 28 may be provided to separate mobilized
hydrocarbons 106
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from water 102 and produced mobilized fluid 104. Water 102 and recovered fluid
104 may
be recycled. For example, fresh mobilizing fluid 108 may be supplied and mixed
with
produced mobilizing fluid 104 before injection via the injection conduit.
[081] When using distinct tubes as the production and injection conduits, the
position of
the production conduit compared to the injection conduit can vary and the two
tubular
conduits can simply be deployed within the same wellbore 4. Deployment can be
conducted
so that the injection and production ports are offset, as discussed further
below, but
otherwise there is no particular arrangement that is required. Alternatively,
the production
and injection conduits could be arranged in some relative position to each
other (e.g.,
beside each other, one on top of each other, etc.). The production conduit 10
thus extends
into the reservoir and within the horizontal section of the well bore 4. When
using a
concentric configuration, such as the one shown in Figures 11 and 12, the
production
conduit can be defined as an annular passageway between inner and outer tubes,
as
described above. Other configurations of production and injection conduits can
also be
envisioned.
Control of gas phase production
[082] In some implementations, the process may include reducing or preventing
production of the gas phase via the production conduit. Due to the proximity
of the
production conduit with respect to the injection conduit, some production of
the gas phase
generated via the injection conduit can occur. Several gas phase production
control means
or methods can be used.
[083] For example, as illustrated in Figure 1, the production ports 20 may be
distributed
along the production conduit 10 in an offset configuration with respect to the
injection ports
8, to reduce production via the production ports 20 of the gas phase exiting
the injection
ports 8. Depending on the type, location and number of injection and
production ports that
are used, different offset features can be implemented.
[084] To further reduce production of the mobilizing fluid in gaseous state,
each production
port may be equipped with a flow control device (FCD), as described above in
relation to
the injection ports. FCDs on the production string can ce provided to
preferentially limit the
flow of gas phase relative to a liquid phase, ensuring production of mostly
liquid phase at
the production conditions.
CA 3050701 2019-07-29
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[085] In some implementations, the process may include controlling injection
and
production via the respective injection and production ports (e.g., via FCDs).
Referring to
Figure 5, a control unit 110 may be provided to provide control of FCDs 22
located on the
injection and productions conduits 6 and 10. The control unit can be
configured to remotely
control opening and closing of the devices, injection pressure, mobilizing
fluid flowrate,
production fluid flowrate, etc., via various instrumentation that can be
provided within the
well via at least one instrumentation line 24. For example, injection and
production ports
may be opened and closed in such a manner as to maximize the pressure
difference
between injection and production locations in the annular space, while
minimizing gas-
phase short circuiting.
Produced water
[086] The production fluid may include condensed water that is produced to
surface
through the production tubing. In some implementations, the process may
include providing
the produced water as a component of the mobilizing fluid injected via the
injection conduit.
The produced water may also be used to produce low-quality steam for pre-
heating the
mobilizing fluid via a heat exchanger, as schematized on Figure 1. Proximity
of the
production and injection conduits may render reuse of the produced water
possible and
beneficial.
[087] As noted previously, depending on the nature of the mobilizing fluid as
well as the
temperature and pressure conditions within the conduits and the reservoir, a
portion of the
injected fluid flashes to gas phase (referred to as flashed portion) and
another portion of the
injected fluid remains in liquid phase (referred to as liquid portion). For
example, preliminary
work has indicated that when water is used as the heated injected fluid,
approximately 15
wt% to 30 wt% (or about 18 wt% to 25 wt%) of the water boils to gas phase
(i.e., steam)
upon injection. Thus, a notable quantity of liquid water is injected into the
reservoir. There
are a few notable points worth discussing in relation to the liquid portion
that is injected.
[088] First, the injected liquid has to be drained out of the reservoir, and
is thus allowed to
flow toward at least one production port to be produced as part of the
production fluid. The
proximity of the production conduit in a single well configuration facilitates
this water
drainage. A two-well configuration is less practical as liquid water has to be
produced to
avoid flooding the injection well and reducing injectivity. The production
fluid that is
CA 3050701 2019-07-29
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recovered to the surface thus includes a notable portion of the mobilizing
fluid that drained
soon after entering the reservoir. There is thus a liquid passageway in
between the injection
ports and the production ports to enable adequate drainage of the injected
liquid portion of
the fluid.
[089] Second, the injected liquid portion and its circulation through the
system¨including
from the injection ports to the production ports and back through the
production conduit¨can
facilitate heating and maintaining temperature uniformity along the length of
the well, which
can benefit overall performance. Thus, the injection of the liquid portion of
the fluid can
facilitate certain advantages.
[090] Third, since a notable amount of the fluid is injected as a liquid and
drained to form
part of the production fluid, the production fluid can have higher fluid-to-
oil ratios compared
to some conventional operations. In addition, in some implementations, a fluid-
oil separator
can be provided proximate to the wellhead at the surface in order to separate
a significant
portion of the fluid from the produced oil, so that the fluid can be
reinjected. The fluid-oil
separator can be provided on or near the wellpad from which the well or well
extend into the
reservoir.
[091] In this regard, when water is used as the injection fluid approximately
15 wt% to 30
wt% vaporization upon injection has been estimated, but other mobilizing
fluids can have
relatively different vaporization characteristics depending on the properties
of the fluid and
the reservoir characteristics. In addition, mixtures of mobilizing fluids
(e.g., water and
solvent mixture, or solvent mixture that includes at least two different
components, etc.) can
display different vaporization properties depending on the particular
composition of the
mixture. The equipment and operation of the system can thus be designed with
the
characteristics of the fluid vaporization and liquid portion as factors.
Single wellbore configuration
[092] In some implementations, the process may include production via the
production
conduit located within the same well bore as the injection conduit. The
production conduit
may have a diameter between 60 mm and 200 mm, or between 100 mm to 150 mm, for
example. Further optionally, the diameter of the horizontal section of the
well in which the
production and injection conduits are located may be between 0.100 m and 300
mm.
CA 3050701 2019-07-29
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[093] In some implementations, the diameter of the wellbore and the dimensions
of the
production and injection conduits are coordinated to promote efficient and
cost-effective
wellbore drilling and completion, while enabling good performance in terms of
injection and
production rates. The injection and production conduits can be sized to
facilitate
deployment downhole while enabling sufficient structural integrity (e.g.,
pressure ratings) to
withstand the temperature and pressure conditions of the fluids transported
therethrough.
Smaller wellbores can be more economical to drill and complete, and thus the
sizing of the
wellbore as well as the injection and production conduits can be provided to
balance drilling
and completion costs with operational performance and production rates.
[094] It should be noted that, in some implementations, the production conduit
can be
disposed along the injection conduit and in substantial alignment with the
injection conduit.
Thus, the production and injection conduits can take the form of two distinct
tubular lines
that extend within the wellbore.
[095] In some implementations, the injection conduit and the production
conduit can be
configured to be concentric. For example, the injection conduit can be located
within the
production conduit. The process can also include injecting the injection fluid
via injection
modules configured to rest on the production conduit and be in fluid
communication with the
internal injection conduit. It should be noted that, in the case of a
concentric configuration,
the injection conduit may be referred to as an injection string or injection
line to refer to the
path taken by the injection fluid from the surface to the reservoir up to the
injection module.
Similarly, the production conduit may be referred to as the production string
or line.
[096] Referring to Figures 11 and 19 which generally illustrate a concentric
configuration,
the injection conduit 6 extends concentrically within the production conduit
10 in an axial
direction of the wellbore. As mentioned previously, delivery of the injection
fluid into the
reservoir 2 can be performed via injection modules 80 that can be configured
to wrap
around the production conduit 10 at specific and spaced-apart injection
locations. The
injection modules 80 can take various forms, e.g., a concentric module that
wraps around
the production conduit or a chamber that is disposed at a position outside of
the production
conduit (such as only on an upper part of the production conduit). To ensure
fluid
communication between the injection conduit 6 and the injection modules 80, at
least one
injection fluid path 90 is provided for each module 80 while preventing fluid
communication
between the injection string and production string. The fluid path can be a
channel defined
CA 3050701 2019-07-29
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by walls that fluidly connects the module 80 with the injection line and
passes through part
of the annular production conduit and thus allows production fluid to pass
around it. The
injection fluid path 90 delivers the injection fluid into a fluid chamber 84
of the injection
module 80, where the injection fluid is ready to be injected into the
reservoir via the injection
ports 8, which can be located about a radial wall of injection rings.
[097] As seen on Figure 12, the injection ports 8 may be positioned and
configured to
provide two sets of facing injection jets for a same module, thereby
facilitating formation of a
higher-pressure region above the corresponding injection module as the fluid
is injected
toward a central region in between the two sets of injection ports. In
contrast, a lower-
pressure region forms in the reservoir region between two adjacent injection
modules. This
axial pressure difference, also referred to as pressure drive, can enhance
convection
mechanisms and accelerate production of the oil-water emulsion or production
fluid via the
production ports. The axial pressure difference generally refers to the
pressure differences
between different regions in the reservoir located above the longitudinal axis
of the
wellbore. It should again be noted that liquid water that does not flash into
the reservoir can
be drained and produced via the production ports without risking flooding the
injection ports.
[098] Referring to Figure 11, in some implementations, packers 100 can be
provided
within the annular space between the liner 5 and an exterior surface of the
production
conduit 10, and longitudinally in between an injection location and a
production location to
enhance the pressure drive therebetween. Packers can be provided to reduce or
prevent
production of vaporize gas phase fluid that is injected. In addition, the
packers can be
located and configured to inhibit gas phase production, while facilitating
liquid phase flow to
and production via the production ports. For example, partial packers can be
used to allow
water drainage from the injection ports and/or avoid pressure build-up within
the annular
space. In some implementations, the packers can be controlled in order to
provide full or
partial packing or isolation, when desired. The control of the packers can be
performed from
a remote surface location or by pre-configuring the packers.
[099] It should be noted that variations in design and positioning of the
injection modules
and production ports can exist. The production ports can be positioned at a
variable
distance from the injection modules. For example, the production ports can be
located
proximate to or on the injection module, depending on the setup, and a
production fluid path
can be created to distribute the production fluid to the production conduits.
Alternatively,
CA 3050701 2019-07-29
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production modules, including multiple production ports may be distributed in
a staggered
relationship with the injection modules in an axial direction of the reservoir
along the
production conduit. Optionally, production ports may be disposed radially
about the
production conduit or production module.
[100] In some implementations, the injection and productions conduits may be
provided
within a single well and without any liner (as schematically shown on Figure
9). As the near-
well reservoir region warms up, the sand can slough in against the injection
and production
conduits or against the concentric injection-production conduits, as the case
may be.
Presence of sand may be beneficial in limiting or eliminating gas-phase short
circuiting
between injection and production points. In some alternative implementations,
a particular
material can be placed in the wellbore surrounding the injection and
production conduits.
Alternative well configurations
[101] In some implementations, the process can include production via the
production
conduit located in a separate well, e.g., disposed separately and below the
well in which the
injection conduit is deployed or present.
[102] In other implementations, the process may include injection and
production via a
single infill well located between two typical SAGD well pairs. In other
terms, the single well
that includes production and injection conduits, as described above, can be
deployed as an
infill well in a region of the reservoir defined between two adjacent SAGD
well pairs. Such
an infill well can be drilled, completed, and operated at any time during the
operation of the
adjacent SAGD well pairs. In another implementation, the single well that
includes
production and injection conduits can be deployed as a step-out well beside an
existing
recovery operation, e.g., beside a SAGD well pair.
[103] In some implementations, multiple single wells can be deployed as an
array
extending from a well pad. The wells can be arranged so that they are
generally parallel to
each other and the horizontal sections can be located at a similar elevation
within the pay
zone and extending a similar length.
[104] It is also noted that the production and injection conduits can be
deployed in a single
wellbore and can be operated in various modes, e.g., in production-only mode,
injection-
only mode, or injection-production mode. These different operating modes can
be
CA 3050701 2019-07-29
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implemented at different phases of the recovery operations (e.g., startup,
ramp-up, plateau,
wind-down, etc.), according to the availability of fluid and/or equipment at
surface facilities,
or according to the performance of the recovery process. Deploying both
production and
injection conduits within a wellbore also provides operational flexibility for
the well over its
lifetime.
[105] It should be noted that the production can be facilitated via a pump
(e.g., electric
submersible pump) deployed in the wellbore, typically near the heel section,
via gas lift, or
via natural lift, depending on the particular characteristics of the
reservoir, the well, and the
process operation.
Operational implementations
[106] It should be noted that the process equipment and design completion
described
herein can be used according to various operational strategies.
[107] For example, the hydrocarbon recovery process may include a start-up
phase where
injection and production are cyclically iterated to initiate recovery. In
other words, an
injection fluid can be continuously injected without any production, and then
the injected
fluid can optionally be let to soak with both injection and production turned
off, followed by a
production phase without simultaneous injection. This type of alternating
injection-
production operation can be conducted to initiate mobilization of the near
reservoir region
that surrounds the wellbore.
[108] Another way to initiate recovery can include injection of the injection
fluid at cooler
temperatures such that there is no flashing upon exiting the injection conduit
initially, and/or
circulation of the hot fluids back up through the production conduit, and then
gradually
increasing the injection fluid temperature to flashing conditions. Other start-
up operations
can be conducted, such as injecting fluid so that the fluid is in gas phase
within the injection
conduit and as it enters the reservoir. Start-up phase can also use different
fluids compared
to later more mature stages of operation (e.g., aromatic or aliphatic
hydrocarbon solvents
during start-up followed by water or water-solvent mixture for normal
operation). Start-up
operations can also use other heating means, such as electric or EM radiation
heaters, that
are deployed in the wellbore.
CA 3050701 2019-07-29
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[109] As will be explained below, implementations of the single well with
injection and
production conduits have been found to have various advantages compared to
conventional
example SAGD processes. For instance, the single well can enhance recovery of
cellar oil,
which is oil that is located below the production well and above the base of
the pay zone.
Since the single well position in the reservoir is not constrained by its
position relative to a
second well, which is the case for SAGD well pairs which should have
relatively consistent
inter-well spacing, the single well can be drilled to follow the base of the
pay zone. Thus, for
bases that change in elevation over the long lengths of horizontal wells, the
single well can
follow the base along its entire length and thus facilitate access to such low-
lying
hydrocarbons that are close to the base.
Leveraging convection
[110] It should be understood that, in some implementations, operation of the
process
within a single well can be referred to as Convection-Induced Gravity-Assisted
Recovery
(CIGAR). Typical SAGD operation benefits from uniform pressure along an axial
direction of
the injection well, thereby allowing even distribution of the injected steam
into the reservoir.
However, due the proximity of the injection conduit with respect to the
production conduit
according to implementations of the present process, uniform pressure within
the reservoir
along an axial direction may not facilitate efficient production of the
production fluid
including mobilized hydrocarbons.
[111] In some implementations, the process can include creating lower-pressure
regions
along a length of the well to induce convection of the production fluid
towards the
production conduit. An axial pressure differential or gradient can be provided
to create
alternating lower-pressure regions and higher-pressure regions along the
length of the well.
It should be noted that an axial direction refers to the direction along the
length of the well,
such that the injection conduit and the production conduit are extending into
the reservoir in
the axial direction (can also be referred to the horizontal direction).
[112] Figures 6 to 9 illustrate various optional implementations of the
process related to
providing axial pressure differentials. Optionally, the axial pressure
differential along the
well may be provided by a specific injection pattern through the injection
ports. For
example, referring to Figure 6, the injection pattern may include injecting in
a first direction
from a first injection port 8 and injecting in a second direction and against
the first direction
from a second and directly adjacent second injection port 8. A higher-pressure
(HP) region
CA 3050701 2019-07-29
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is thereby formed between the first and second injection ports 8, and a lower-
pressure (LP)
region is created between the second injection port 8 and an adjacent third
injection port 8
that is spaced away in a direction opposed to the injection direction of the
second injection
port. In other words, at least two injection ports are oriented and configured
so that they
inject the fluid toward each other, thereby facilitating the formation of a
higher-pressure
region in the reservoir above those injection locations. The injection pattern
may be
repeated along the injection conduit to provide for alternate higher and lower-
pressure
regions promoting convection of the production fluid towards the production
conduit.
[113] It should be noted that various designs for the injection equipment may
be provided
to facilitate completion of a desired injection pattern promoting axial
pressure differential
along the well. For example, referring to Figure 7, multiple sets of injection
ports 8, including
two or more injection ports, may be provided along the length of the injection
conduit 6 so
as to create higher-pressure (HP) regions at discharge. The fluid jets may be
oriented in
different configurations to facilitate convection through lower-pressure (LP)
regions.
[114] Optionally, the axial pressure differentials along the injection well
may be provided
by discharging the mobilizing fluid at different pressures along the injection
conduit. For
example, referring to Figure 8, a series of discharge pressures (P1, P2, P3,
P4) of the
mobilizing fluid can be controlled at specific injection ports 8, thereby
creating lower-
pressure regions whereby the production fluid drains and is produced at a
series of
production pressures (Pa, Pb, Pc) via the production ports. It should be noted
that various
combinations of pressure distributions within the annular space can be used,
such
combinations being cycled in time for instance.
[115] In some implementations, the formation of axial pressure differentials
(dP) may be
facilitated along the well by positioning packer(s) between the staggered
injection and
production ports around the respective conduits and within the well. In such
cases, each
packer can serve as an at least partial seal between a higher-pressure region
and a lower-
pressure region of the well. Optionally, the packers may be retrievable, or
provide only
partial flow isolation, allowing an axial pressure differential to be
established without sealing
off axial flow entirely within the well.
[116] It should be noted that various pressures and pressure differentials can
be provided
in the context of the processes described herein. In one example, the process
can be
operated such that the gas chamber pressures are in the range of about 800 kPa
and 1200
CA 3050701 2019-07-29
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kPa, and the fluid pressure in the injection conduits is between 3 MPa and 6
MPa, although
other pressure ranges are also possible. When higher gas chamber pressures are
employed, the fluid pressure in the injection conduit can be increased
accordingly to
facilitate the desired pressure drop and vaporization across the injection
ports. In addition,
the pressure differentials or gradients between the high-pressure regions and
the low-
pressure regions of the well annulus can be, for example, between about 10 kPa
and about
500 kPa, between about 50 kPa and about 400 kPa or between about 100 kPa and
about
300 kPa, when considering the highest pressure of the high-pressure region and
the lowest
pressure of the lower-pressure region. The pressure gradients can be different
from one
pair of adjacent high/low pressure regions to another. The pressure gradients
can be
implemented and adjusted by modifying one or more variables, such as fluid
injection
pressure, production pressure, pressure drop across the injection ports, and
mobilizing fluid
composition.
SIMULATIONS
[117] It has been found that oil recovery and production rates for SAGD and
CIGAR
processes can be similar; however, implementation of an axial pressure
differential between
an injection point and a production point was found to encourage the start of
the process.
[118] Referring to Figures 13 and 14, a 20-meter portion of horizontal wells
was modelled
for example SAGD and CIGAR processes under similar conditions and operating
limits.
Pressures in the well annulus (in communication with reservoir) were bounded
between
700 kPa and 1200 kPa. In the case of the example CIGAR process (Figure 14),
the
injection fluid was liquid water at 250 C, allowed to flash at the injection
location as the
pressure was dropped to the maximum allowable pressure of 1200 kPa. Resulting
simulated steam chamber shapes are different, including a higher cellar-oil
recovery for the
CIGAR model. Similar oil recovery rate is still obtained for both models.
[119] Figures 15 and 16 result from a simulation model (using ANSYSCFXTM,
which is a
computation fluid dynamic modelling tool) that modelled injection of steam via
an injection
conduit and production of mobilized hydrocarbons via a production conduit,
both injection
and production conduits being located within the same wellbore. Figure 15
offers
visualization of a temperature gradient along a portion of a well including an
injection
location. Injection of steam from a first injection port is modelled to be
directed to the left as
may be apparent from the higher temperature at the injection location. Figure
16 offers
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visualization of the mass flow production along the same modelled well portion
as per
Figure 15. The production is not homogeneous along the well. The region where
the
injection jets from the first injection port and a second adjacent injection
port (not illustrated
on Figure 16) meet corresponds to a higher-pressure region where steam flows
into the
reservoir best, whereas the production is maximized away from the first
injection port in an
opposite direction along the well at a lower-pressure region.
[120] Figure 17 is a graph illustrating a comparison of the oil production
rate between an
example SAGD process and example single well operations for several axial
pressure
differences between injection and production locations in an axial direction
of the reservoir.
The axial pressure difference between injection and production locations was
varied to
create high-pressure difference examples (300 kPa dP), medium pressure
difference
examples (100 kPa dP), and lower pressure difference examples (10 kPa dP).
Figure 17
shows an early ramp up of oil production for both SAGD and single well
operation with
higher pressure drive, with the CIGAR with high pressure different (dP)
outperforming
SAGD in terms of production rates at all time periods. The medium pressure
different
CIGAR example also outperformed SAGD in terms of production rates at later
time periods.
[121] Figure 18 is a graph illustrating a comparison of the oil production
rate for single well
operations with several axial pressure differences between injection and
production
locations in an axial direction of the reservoir. Figure 18 indicates that
enhanced oil
production can be obtained with a higher-pressure drive and that a similar
production profile
may be obtained whether the higher-pressure drive is created by a tailored and
controlled
injection pattern or by using a packer between injection and production
locations.
[122] It should be noted that any one of the above-mentioned aspects of the
process may
be combined with any other of the aspects thereof, unless two aspects clearly
cannot be
combined due to their mutually exclusivity. For example, the operational steps
and/or
structural elements of the process described herein-above, herein-below and/or
in the
appended Figures, may be combined with any of the general process descriptions
appearing herein and/or in accordance with the appended claims.
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