Note: Descriptions are shown in the official language in which they were submitted.
IN SITU STARTUP PROCESS WITH ELASTIC DEFORMATION OF THE RESERVOIR
TECHNICAL FIELD
[001] The technical field generally relates to startup of in situ
hydrocarbon recovery
operations, such as the startup stage of a Steam-Assisted Gravity Drainage
(SAGD)
operation.
BACKGROUND
[002] SAGD operations use well pairs that extend into a hydrocarbon
reservoir and
each includes a production well underlying an injection well. The startup
stage of the well
pair involves establishing fluid communication between the injection well and
the
production well. A fluid, such as steam, can be circulated through one or both
of the wells
to heat the surrounding reservoir region until the hydrocarbons are mobilized
and fluid
communication is established between the wells. In reservoir regions of high
initial water
mobility, steam can be injected into the wells without having to circulate.
However, there
are various challenges in terms of the long duration of the startup stage and
the lack of
uniformity of fluid communication along the length of the well pair.
SUMMARY
[003] Startup of a well pair used for SAGD or other gravity dominated in
situ
hydrocarbon recovery processes operated using a horizontal well pair can be
enhanced
by introducing fluid at sufficiently high pressure to induce elastic
deformation of the
reservoir within the near-wellbore region. Elastic deformation of the
reservoir can
significantly increase permeability and injectivity, which, in turn, can
enhance fluid
communication between the wells while mitigating drawbacks related to higher
pressure
injection. Higher pressure injection may result in permanent deformation or
fracturing of
the reservoir, which could occur as a result of plastic deformation and
failure at higher
pressures.
[004] In some implementations, there is provided a startup process to
establish fluid
communication between a well pair comprising an injection well overlying a
production
well located in a hydrocarbon-bearing reservoir, comprising: introducing a
startup fluid into
an interwell reservoir region defined between the injection well and the
production well at
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an elastic deformation pressure of the reservoir to induce temporary elastic
deformation
in the interwell reservoir region; and establishing fluid communication
between the
injection well and the production well.
[005] In
some implementations, the introducing of the startup fluid comprises
injection.
In some implementations, the introducing of the startup fluid comprises
circulation. In
some implementations, the startup fluid comprises steam. In some
implementations, the
startup fluid comprises water. In some implementations, the startup fluid
comprises a
hydrocarbon solvent, such as diesel. In some implementations, the elastic
deformation
pressure at which the startup fluid is introduced is between 0% and 15% below
a yield
point of the interwell reservoir region. In some implementations, the elastic
deformation
pressure at which the startup fluid is introduced is between 1% and 10% below
a yield
point of the interwell reservoir region. In some implementations, the elastic
deformation
pressure at which the startup fluid is introduced is between 2% and 7% below a
yield point
of the interwell reservoir region. In some implementations, the elastic
deformation
pressure at which the startup fluid is introduced is between 3% and 6% below a
yield point
of the interwell reservoir region. In some implementations, the elastic
deformation
pressure at which the startup fluid is introduced is between 0% and 15% below
a reservoir
fracture pressure. In some implementations, the elastic deformation pressure
at which the
startup fluid is introduced is between 3% and 10% below a reservoir fracture
pressure. In
some implementations, the introducing of the startup fluid comprises a
multistep
procedure comprising circulation and/or bullheading. In some implementations,
the
multistep procedure comprises: a fluid circulation step at pressures in an
elastic
deformation pressure zone; and a bullheading step at injection pressures in
the elastic
deformation pressure zone to provide fluid penetration into the interwell
reservoir region.
In some implementations, the fluid circulation step is performed at a pressure
between
85% and 95% of reservoir fracture pressure. In some implementations, the fluid
circulation
step is performed at a pressure between 88% and 92% of reservoir fracture
pressure. In
some implementations, the bullheading step is performed between 85% and 95% of
reservoir fracture pressure. In some implementations, the bullheading step is
performed
at a pressure between 88% and 92% of reservoir fracture pressure. In some
implementations, the bullheading step comprises a first bullheading stage
operated at a
first pressure and a second bullheading stage operated at a second pressure
that is lower
than the first pressure. In some implementations, the first pressure is
gradually reduced to
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the second pressure between the first and second bullheading stages. In some
implementations, the first pressure is up to 95% or 90% of the reservoir
fracture pressure
and the second pressure is 5% to 10% lower than the first pressure. In some
implementations, the bullheading step is performed until fluid communication
is
established between the injection well and the production well. In some
implementations,
the fluid circulation step is performed in only the injection well. In some
implementations,
the fluid circulation step is performed in only the production well. In some
implementations,
the fluid circulation step is performed in both the injection well and the
production well. In
some implementations, the bullheading step is performed via the injection well
only, and
the production well is operated in shut-in mode. In some implementations, the
bullheading
step is performed via both the injection well and the production well until
fluid
communication is established and then the production well is operated in
production
mode. In some implementations, the multistep procedure further comprises,
prior to the
fluid circulation step, a wellbore fluid unloading step wherein unloading
fluid is introduced
to remove completion fluid and/or drilling mud to surface. In some
implementations, the
unloading fluid comprises steam, and the reservoir has low injectivity below 1
m3 of
steam/hour. In some implementations, the multistep procedure further
comprises, prior to
the fluid circulation step, a wellbore fluid unloading step wherein unloading
fluid is
introduced to drive completion fluid and/or drilling mud into the reservoir.
In some
implementations, the unloading fluid comprises an unloading liquid. In some
implementations, the unloading fluid comprises water, and the reservoir has a
high
injectivity above 1 m3 of steam/hour. In some implementations, the multistep
procedure
comprises wellbore depressurization between steps. In some implementations,
the
multistep procedure comprises no wellbore depressurization between steps. In
some
implementations, the hydrocarbon-bearing reservoir comprises an oil sands
reservoir
comprising heavy oil or bitumen. In some implementations, the startup process
is
performed in preparation for Steam-Assisted Gravity Drainage (SAGD). In some
implementations, the startup process is performed in preparation for a solvent-
assisted
recovery process. In some implementations, the startup process is performed in
preparation for a solvent-dominated recovery process. In some implementations,
determining an elastic deformation pressure zone for the reservoir; and
selecting
operating pressures for the startup fluid based on the elastic deformation
pressure zone.
In some implementations, the determining of the elastic deformation pressure
zone utilizes
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Date Recue/Date Received 2022-09-28
data obtained from testing reservoir samples, measurements collected from
downhole
instrumentation, or a combination thereof. In some implementations, the
determining of
the elastic deformation pressure zone comprises: determining a fracture
pressure of a
near-wellbore region; and estimating the elastic deformation pressure zone
based on the
fracture pressure of the near-wellbore region. In some implementations,
monitoring at
least one operating parameter to detect indication of reservoir fracture or
plastic
deformation; and if reservoir fracture or plastic deformation is detected,
modifying
operating conditions of the startup process to cease the reservoir fracture or
the plastic
deformation. In some implementations, the monitoring comprises measuring
pressure
conditions and/or flow rate conditions of the startup fluid.
[006] In some implementations, there is provided a process for recovering
hydrocarbons from a reservoir, comprising: a startup phase operated according
to the
startup process as defined above or herein; and a hydrocarbon recovery phase
comprising
introducing an injection fluid via the injection well into the reservoir and
recovering
production fluid via the production well. In some implementations, the process
is a Steam-
Assisted Gravity Drainage (SAGD) process wherein the injection fluid is steam.
In some
implementations, the process is a solvent-assisted process wherein the
injection fluid
comprises steam and hydrocarbon solvent. In some implementations, the process
is a
solvent-dominated process wherein the injection fluid comprises a dominant
proportion of
hydrocarbon solvent. In some implementations, the injection fluid consists
essentially of
the hydrocarbon solvent. In some implementations, the injection fluid
comprises a
paraffinic solvent including C3 to C6; a solvent mixture comprising a diluent
blend; one or
more alcohols; one or more ethers; diesel; biodiesel; a mixture of alkanes and
alcohols;
one or more aromatic solvents; or a combination thereof. In some
implementations, the
introducing of the startup fluid comprising injecting via both the injection
well and the
production well to form respective elastically deformed zones in the interwell
reservoir
region that merge to form a merged elastically deformed zone in the interwell
reservoir
region.
[007] In some implementations, there is provided a well pair startup system
comprising: a well pair comprising an injection well overlying a production
well located in
a hydrocarbon-bearing reservoir; and a startup fluid delivery unit located at
surface and
being in fluid communication with one or both of the injection well and the
production well,
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the startup fluid delivery unit being configured for introducing a startup
fluid down at least
one of the wells and into an interwell reservoir region defined between the
injection well
and the production well at an elastic deformation pressure of the reservoir to
induce
temporary elastic deformation in the interwell reservoir region, and for
establishing fluid
communication between the injection well and the production well.
[008] In some implementations, the startup fluid delivery unit comprises a
pump for
when the startup fluid is a startup liquid. In some implementations, the
startup fluid delivery
unit comprises a steam generator and a pressure let-down unit for when the
startup fluid
comprises steam, the steam generator producing high pressure steam and the
pressure
let-down unit receiving the high pressure steam and reducing the pressure to
produce the
startup steam for introduction into the interwell region. In some
implementations, the
system further includes a circulation unit for circulating the startup fluid
through the
injection well and the production well, and a bullheading unit for bullheading
the startup
fluid via at least the injection well after circulation. In some
implementations, the system
also includes a monitoring unit configured to detect reservoir fracture or
plastic
deformation. In some implementations, the startup fluid comprising water. In
some
implementations, the startup fluid comprising liquid solvent. In some
implementations, the
startup fluid comprises the steam and a solvent that are co-injected together.
In some
implementations, the startup fluid consists of the steam.
[009] In some implementations, there is provided an in situ hydrocarbon
recovery
system comprising: a well pair comprising an injection well overlying a
production well
separated by an interwell reservoir region; and a well pair startup system
comprising a
fluid delivery unit provided at surface and in fluid communication with at
least one well
selected from the injection well and the production well, and configured to
introduce a
startup fluid into the interwell reservoir region via the at least one well at
an elastic
deformation pressure of the reservoir to induce temporary elastic deformation
in the
interwell reservoir region; wherein the injection well is configured to supply
an injection
fluid into the reservoir to facilitate mobilization of hydrocarbons, and the
production well is
configured to recover production fluid comprising mobilized hydrocarbons. In
some
implementations, the well pair startup system has one or more features as
described
above or herein.
Date Recue/Date Received 2022-09-28
[0010] In some implementations, there is provided a process for recovering
hydrocarbons from a reservoir comprising: operating a gravity based in situ
hydrocarbon
recovery operation comprising injecting an injection fluid via an injection
well to mobilise
hydrocarbons in the reservoir and recovering production fluid via a production
well
underlying the injection well; detecting suspected plugging in the production
well;
temporarily ceasing recovery of production fluid via the production well;
stimulating the
production well, the stimulating comprising: introducing a stimulation fluid
via the
production well and into a near-wellbore reservoir region of the production
well at an elastic
deformation pressure to induce temporary elastic deformation in the near-
wellbore
reservoir region; and injecting or circulating the stimulation fluid in the
elastically deformed
near-wellbore reservoir region and unplugging the production well. The process
then
includes reinitiating the production well in production mode for recovering
production fluid
to surface.
[0011] In
some implementations, the gravity based in situ hydrocarbon recovery
operation is Steam-Assisted Gravity Drainage (SAGD) and the stimulation fluid
is steam.
In some implementations, the elastic deformation pressure at which the
stimulation fluid
is introduced is between 0% and 15% below a yield point of the near-wellbore
reservoir
region. In some implementations, the elastic deformation pressure at which the
stimulation
fluid is introduced is between 1% and 10% below a yield point of the near-
wellbore
reservoir region. In some implementations, the elastic deformation pressure at
which the
stimulation fluid is introduced is between 2% and 7% below a yield point of
the near-
wellbore reservoir region. In some implementations, the elastic deformation
pressure at
which the stimulation fluid is introduced is between 3% and 6% below a yield
point of the
near-wellbore reservoir region.
[0012] In some implementations, there is provided a process for recovering
hydrocarbons from a reservoir comprising: operating a gravity based in situ
hydrocarbon
recovery operation comprising injecting an injection fluid via an injection
well at an
operating pressure to mobilise hydrocarbons in the reservoir and recovering
production
fluid via a production well underlying the injection well; in a chamber growth
promotion
mode for promoting growth of a chamber extending upward from the injection
well,
introducing the injection fluid into the chamber at an elastic deformation
pressure above
the operating pressure to induce temporary elastic deformation in the
reservoir and
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Date Recue/Date Received 2022-09-28
promote growth of the chamber; and returning the injection well to normal
operating mode
where the injection fluid is injected at the operating pressure.
[0013] In some implementations, the gravity based in situ hydrocarbon
recovery
operation is Steam-Assisted Gravity Drainage (SAGD) and the injection fluid is
steam. In
some implementations, the elastic deformation pressure at which the injection
fluid is
introduced is between 0% and 15% below a yield point of the near-wellbore
reservoir
region. In some implementations, the elastic deformation pressure at which the
injection
fluid is introduced is between 1% and 10% below a yield point of the near-
wellbore
reservoir region. In some implementations, the elastic deformation pressure at
which the
injection fluid is introduced is between 2% and 7% below a yield point of the
near-wellbore
reservoir region. In some implementations, the elastic deformation pressure at
which the
injection fluid is introduced is between 3% and 6% below a yield point of the
near-wellbore
reservoir region.
[0014] In some implementations, there is provided a process for treating a
reservoir for
recovery of hydrocarbons from the reservoir in which a horizontal well pair is
provided, the
well pair comprising an injection well overlying a production well, the
process including, in
an elastic deformation mode, introducing a fluid into the injection well or
the production
well or both at an elastic deformation pressure to elastically deform a
reservoir region and
increase injectivity of the reservoir region, wherein the elastic deformation
pressure at
which the fluid is introduced is between 0% and 15% below a yield point of the
reservoir
region; and injecting the fluid into the reservoir region while in elastic
deformation state.
The process also includes, in a normal operating mode, returning to a normal
operating
pressure where an injection fluid is injected into the reservoir via the
injection well, and
wherein production fluid is recovered via the production well.
[0015] In some implementations, the fluid is a startup fluid and the
reservoir region
comprises an interwell reservoir region in between the injection well and the
production
well. In some implementations, the startup fluid comprises steam, water or
hydrocarbon
solvent. In some implementations, the elastic deformation pressure at which
the fluid is
introduced is between 1% and 10%, between 2% and 7%, or between 3% and 6%
below
a yield point of reservoir region. between 2% and 7% the well pair is operated
as part of a
Steam-Assisted Gravity Drainage (SAGD) operation and the injection fluid is
steam.
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Date Recue/Date Received 2022-09-28
BRIEF DESCRIPTION OF THE DRAWINGS
[0016] The attached figures illustrate various features, aspects and
implementations
of the technology described herein.
[0017] Fig 1 is a side view schematic of an in situ recovery system
including a well pair
where a startup fluid is introduced at elastic deformation pressure.
[0018] Figs 2A-2D are side view schematics of an in situ recovery system
showing
steps of a startup process.
[0019] Fig 3 is a cross-sectional view schematic of a well pair around
which elastic
deformation zones have formed.
[0020] Fig 4 is a graph of injectivity versus startup fluid pressure.
DETAILED DESCRIPTION
[0021] The present description relates to a startup process for
establishing fluid
communication for a horizontal well pair used for in situ recovery of
hydrocarbons. The
startup process includes introducing a startup fluid at elevated pressure to
induce elastic
deformation of the reservoir proximate to one or more of the wells during
initial stages of
well pair start-up. The startup fluid¨which can be steam, hot water, and/or
solvent¨can be
injected or circulated at a pressure causing significant elastic deformation
while remaining
below shear and tensile failure conditions of the reservoir and caprock. The
elevated
pressure promotes elastic deformation of the reservoir sand and temporarily
increases
injectivity. High-pressure circulation and injection can help accelerate the
startup and
ramp-up performance of well pairs by promoting early fluid communication for
the well pair
as well as early steam or solvent chamber growth through improved injectivity.
In some
implementations, high-pressure startup within the elastic deformation zone of
the reservoir
sand can shorten the duration of the startup stage. Even small improvements in
early in
situ performance can allow significant economical benefits for the in situ
hydrocarbon
recovery process.
[0022] In some implementations, the startup fluid is introduced down one or
both of the
wells in the well pair at pressures that are close to yet below shear and
tensile failure
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Date Recue/Date Received 2022-09-28
conditions, thus enabling elastic deformation which can have a notable impact
on
injectivity. The startup fluid pressure can be selected based on both the
caprock properties
and the near-wellbore reservoir properties. For example, the startup fluid
pressure can be
provided such that it is below the plastic deformation pressure of the near-
wellbore
reservoir and also below the fracture pressure of the caprock. In certain
instances, the
relevant properties of the caprock and the near-wellbore region of the
reservoir in which
the wells are located can be relatively similar (e.g., similar fracture
pressures) such that
the startup fluid pressure can be provided based on one or the other.
[0023] Referring to Fig 1, a well pair 10 is shown including an injection
well 12 and a
production well 14 provided in a pay zone 16 of a reservoir. Caprock 18 is
located above
the pay zone 16 and underburden 20 is located below the pay zone 16. The wells
both
extend up to the surface 22 where surface facilities are located and each has
a generally
horizontal well section vertically spaced apart from each other. Surface
facilities can be
configured and operated depending on the design of the particular in situ
recovery
process. For example, SAGD operations would include steam generators while
solvent-
based processes would include equipment for processing and injecting solvent.
[0024] Still referring to Fig 1, the startup process includes introducing
a startup fluid 24
from surface through one or both of the wells at high pressure to induce
elastic deformation
of a reservoir region 26 surrounding the corresponding well. The startup fluid
24 can be
supplied by a fluid delivery unit 28 located at surface. The fluid delivery
unit 28 can be
provided depending on the type of startup fluid. For example, when the startup
fluid is
liquid, e.g., hot water or liquid phase solvent such as diesel, the fluid
delivery unit 28 can
include one or more pumps configured to supply the liquid at the elastic
deformation
pressure. The pump can be used for a particular well pad during startup and
then moved
to another location once startup is complete, for example. When the startup
fluid is a
vapour, e.g., steam or vapour-phase solvent, the fluid delivery unit 28 can
include
compressors and/or generators (e.g., steam generators such as Once-Through
Steam
Generators or OTSGs or solvent vaporizers) and associated equipment that can
be
controlled to provide the fluid at the elastic deformation pressure. For
example, steam
generators can produce steam at high pressure and the steam pressure can be
reduced
to the target pressure prior to introduction at the wellhead. The fluid
delivery unit 28 can
include a controller that facilitates fluid pressure control to achieve the
target pressure of
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Date Recue/Date Received 2022-09-28
the startup fluid to enable elastic deformation of the reservoir, it is also
noted that the
process could use electrical or electromagnetic devices downhole that could
heat and
vaporize the injected fluid, such that the fluid is introduced at the wellhead
as a liquid and
is vaporized downhole.
[0025] The elastic deformation can impact the reservoir proximate to the
wells and can
form an elastic deformation zone that extends a few meters from each well.
When both
the injection and the production well are used for startup fluid injection,
the corresponding
reservoir regions 26 that undergo elastic deformation can approach each other
and even
merge, as illustrated in Fig 3. Since well pairs in gravity dominated recovery
processes,
such as SAGD, are conventionally vertically spaced apart by approximately five
meters,
elastic deformation of only two or three meters can be sufficient to provide
beneficial
permeability enhancements in the interwell region for startup purposes. When
an
elastically deformed reservoir zone extends less than four or three meters
away form the
well, it can be advantageous to use both wells to facilitate permeability
increase over the
height of the interwell region. Furthermore, when both wells are used for
injection of startup
fluid, it can be of interest to manage injection pressures so that the wells
are at equal
pressure, i.e., no pressure differential, which can include accounting for
elevation
differences. Such an approach can mitigate issues related to short circuits
between the
wells via preferential flow paths, for example.
[0026] In addition, the process can include determining fluid parameters
such as
pressure and volume based on various factors (e.g., an average or estimate of
the yield
point or fracture pressure of the near-wellbore region taken along the length
of the well;
an estimated volume of the near-wellbore where the elastic deformation is to
occur and
which can be based on a cylindrical volume around the length of the well and
having a
radius of between 1 and 3 meters or up to 2, 3 or 4 meters from the well;
initial injectivity
of the near-wellbore region and target injectivity increase due to elastic
deformation; and
other factors). The process can generally include predetermining fluid
parameters such as
pressure, volume, rate, etc., based on properties of the reservoir and/or
process design.
[0027] Introduction of the startup fluid 24 can be performed using various
methods.
For example, the startup fluid 24 can be introduced by injection and/or
circulation; at
constant or cyclical pressures; using a single startup fluid for the entire
startup process or
Date Recue/Date Received 2022-09-28
using different fluids or compositions at different stages of the startup
process; via only
one of the injection well and production well; or via both injection and
production wells
either simultaneously or in alternating fashion. The properties of the startup
fluid 24 (e.g.,
pressure, phase, temperature, flow rate, composition) can also be controlled
and modified
at different stages of the startup process. The startup fluid 24 can also be
selected based
on predetermined reservoir properties and process design.
[0028] The introduction of the startup fluid 24 can be based on
predetermined
measurements regarding properties of the formation. Measurements can be
obtained from
observation wells and/or operational wells using downhole instrumentation
and/or
calculated using existing geological data and methods. Properties regarding
deformation
can be obtained for underburden, caprock, pay zone and/or target regions such
as near
wellbore regions of the pay zone. For example, caprock fracture pressure can
be
determined and used as a factor to set the startup fluid pressure to ensure
caprock
integrity. Stress-strain curves can be used to estimate the startup fluid
pressure that can
be used to induce an optimum or maximum elastic deformation without entering
zones of
plastic deformation or fracture. In some implementations, the yield point of
the reservoir
can be determined and used as an upper limit for the target pressure to induce
elastic
deformation, where the operating startup fluid pressure is set at, for
example, 2%, 5%,
10%, 15% or 20% below the yield point. The determination of the startup fluid
pressure
can include determining deformation properties of several zones of the
formation and
selecting the pressure below the caprock fracture pressure and below the yield
point of
the near-wellbore pay zone while providing the fluid pressure as high as
possible, e.g.,
within 10% or 5% or 2% of the lower of the caprock fracture pressure and pay
zone yield
point pressure. In some implementations, the startup fluid pressure can be
provided based
solely on the near-wellbore reservoir properties to remain within the elastic
deformation
zone of that region, especially if the caprock is remote from the well pair
since the elastic
deformation zone extends only a few meters into the pay zone from the well.
[0029] The startup fluid 24 can include hot water, steam, hydrocarbon
solvent or
various mixtures thereof, and may also include additional species that may be
desired to
condition the reservoir. Such additional species could include surfactants,
alcohols, ethers
(e.g., DME), diluent, diesel, biodiesel, one or more aromatic solvents, and
various
combinations of such chemicals. Other species known in the field of in situ
startup could
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Date Recue/Date Received 2022-09-28
also be used. The startup fluid 24 can be heated at surface to have a target
temperature
and/or can be provided in vapour phase or liquid phase. Different startup
fluids can be
used for different stages of the startup process. The startup fluid can
include some native
fluids and/or drilling fluids that are present in the wellbores after
drilling, particularly if the
injectivity of the reservoir is relatively high such that the introduction of
liquid startup fluid
from surface can push existing wellbore fluids into the reservoir.
[0030]
Turning now to Figs 2A to 2D, the startup process can include a multistep
procedure where different fluids and operating conditions can be used. The
multistep
procedure can include one or more injection and/or circulation steps, for
example. An
example of a multistep procedure will be described in relation to Figs 2A to
2D, but it
should be noted that various other combinations of steps can be used for the
startup
process.
[0031] Fig
2A shows an initial step of unloading of wellbore fluids, such as completions
kill fluid or drilling mud. An unloading fluid 30 is introduced and wellbore
fluids 32 can be
removed. The unloading step can be accomplished by injecting steam up to 95%
of
reservoir fracture pressure and within the elastic deformation zone for 48
hours, for
example, or until steam to toe is achieved with minimal water returns observed
at surface.
As steam is introduced the wellbore liquids are recovered to surface. In this
unloading
context using steam, the unloading step would typically not include elastic
deformation of
the near-wellbore reservoir regions, but would be operated for wellbore fluid
unloading
prior to an elastic deformation step. This unloading step can be favoured when
the
injectivity of the reservoir is relatively low. Alternatively, when the
injectivity of the reservoir
is high, the unloading fluid 30 can be a liquid, such as water, and can be
introduced via
bullheading into the well to push the wellbore fluids into the reservoir
rather than
recovering the fluids to the surface. In this scenario, the bullheading can be
performed to
induce elastic deformation of the reservoir zones surrounding the wells.
[0032] Fig
2B shows a steam circulation step, which can be performed at pressure up
to 90% of reservoir fracture pressure and within the elastic deformation zone,
for a duration
that can vary based on reservoir characteristics (e.g., days to weeks). This
circulation step
is performed to warm the near-wellbore area until reservoir fluid mobility is
high enough to
facilitate fluid (e.g., steam) injectivity into the reservoir. A circulation
fluid 34 is introduced
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Date Recue/Date Received 2022-09-28
and flows through the tubing and annulus of the corresponding well and forms a
warmed
zone 35 surrounding each well. This circulation step enables warming of the
wells and
reservoir as well as elastic deformation of the near-wellbore region. The
circulation
pressure can be selected to be in the elastic deformation zone, as discussed
above. The
circulation can be performed in both wells or one of the wells. If the
mobility in the near-
wellbore region is high enough, the startup process can forgo circulation and
pass directly
to injection/bullheading.
[0033] Fig 2C shows a bullheading step, which can be performed at a
pressure up to
90% of reservoir fracture pressure, which can be gradually reduced to 80%
reservoir
fracture pressure, for a duration generally of one to four months, or two to
four months, for
example, depending upon reservoir response. The bullheading step can be
performed
using steam as a bullheading fluid 36, although other fluids can be used. The
bullheading
can be performed until fluid communication is established between the wells.
The
bullheading step enables penetration of fluid into the reservoir, elastic
deformation of the
reservoir, and heating of the reservoir notably when a hot fluid such as steam
is used as
the startup fluid. It is also noted that the bullheading can be performed in
both wells or one
of the wells. In some implementations, the bullheading is first performed via
both wells and
then the production well is switched to production mode after a certain period
of time while
bullheading continues via the injection well until the production well begins
to produce fluid
to surface. This bullheading step can be performed with constant or cyclical
injection at
constant pressure or with a gradual decrease in pressure, for example.
[0034] Fig 2D shows a final step of the startup process which also leads
into the ramp-
up of the in situ hydrocarbon recovery process, where injection fluid 38 is
injected via the
injection well 12 and production fluid 40 is recovered via the production well
14. The
injection fluid 38 forms a chamber 42 (e.g., a steam chamber when steam is
used)
extending upward from the injection well 12 while the hydrocarbons drain
downward by
gravity and are recovered via the production well 14. The transition from
startup to
production can be gradual where startup conditions are brought to production
phase
conditions. When the startup fluid is different from the injection fluid,
there can also be a
transition period to switch to the injection fluid for the production phase.
There can also be
a shutdown period between startup and production phases if desired, and since
the
13
Date Recue/Date Received 2022-09-28
deformation during startup is substantially elastic the reservoir should
generally return to
its original state in terms of porosity and other petrophysical properties.
[0035] The elastic deformation region of the reservoir formed by the
startup fluid
pressure can have a shape and properties that depend on the well and near-
wellbore
reservoir characteristics. For example, the elastic deformation region can
extend a couple
or a few meters into the reservoir from the well, and can have a generally
cylindrical shape
that is generally symmetrical about the well. The deformation through the
elastic
deformation region may not be radially uniform though it may be generally
uniform along
the well particularly when the reservoir properties are not highly variable
along the well. In
addition, since the startup fluid is provided at low flow rate and higher-than-
normal
pressure, the pressure drop along the well is relatively low such that the
fluid pressure is
relatively consistent along the length of the well.
[0036] In addition, the startup fluid can be introduced so as to gradually
increase the
pressure that is exerted on the reservoir. For example, the startup fluid can
be introduced
to fill the wellbore and then the pressure can be gradually increased from
hydrostatic up
to the target pressure that may be 90% of reservoir fracture pressure or
another pressure
just below the plastic deformation zone. Gradually increasing the pressure can
provide
enhanced conformance along the well and can also reduce the risk of
inadvertent fractures
and breakthroughs.
[0037] It has been found that increasing startup fluid pressures compared
to
conventional pressures, which can be 50% or 60% of fracture pressure, resulted
in notable
improvements in terms of injectivity. For example, referring to Fig 4, the
startup fluid
injection pressure was increased up to 90% of fracture pressure (FP) (point 6)
and a non-
linear increase in injectivity was observed. The numbers on the points
indicate successive
injection cycles (injection, shut-in/fall-off, repeat) and demonstrate
injectivity increasing
with maximum pressure achieved in each cycle. It is clear that cycle 7 (going
back to initial
pressure) demonstrated the return to the low injectivity. In addition, the
observed injectivity
at 90% fracture pressure (FP) of cycle 6 was about 30% higher than a linear
projection of
points 1 and 2 to that high pressure. In addition, Fig 4 indicates that the
reservoir returned
to its original injectivity at the lower pressure (cycle 7) which indicates an
elastic response.
Fig 4 illustrates that higher pressure startup operations can yield
significant increases in
14
Date Recue/Date Received 2022-09-28
injectivity with an exponential-like relationship within those pressure
ranges. This testing
also demonstrated a 4-times increase in injectivity at pressures that were
approximately
12% higher than lower pressures and 90% of the expected failure pressure. The
testing
also indicated no adverse impacts to the caprock or to the adjacent well
pairs. Laterally,
pressure transient was limited; vertically, pressure response in the reservoir
monitoring
zone was barely measurable, supporting caprock integrity is maintained with
the process.
[0038] Testing can be conducted prior to the startup process to determine
operating
parameters and, in particular, the elastic deformation pressure. Various data
can be
collected and analysed to determine mechanical properties of the reservoir,
including the
pressures required to be in the elastic zone, the plastic zone, and the
fracture zone. Data
collection can include microfrac/minifrac testing, triaxial core testing, and
so on, to
determine the stress regime. From this data, the target startup fluid pressure
can be
determined and may be a pressure in the elastic zone and just below the
plastic zone.
Furthermore, the startup process can be monitored to assess whether the
reservoir is in
the elastic zone, e.g., by monitoring fluid flow parameters. For example, if
the startup fluid
is seen to be gradually entering the reservoir, this can indicate that the
reservoir is in the
elastic deformation zone, whereas a sudden increase in the fluid flow rate can
indicate a
fracture has occurred. It is noted that for a pumping operation, the pump
could be set at a
flow rate and pressure would be monitored real-time while performing pressure
transient
analysis (PTA) during shut-ins. Various other monitoring techniques could be
used to
assess the progress of the startup process. Fluid flow parameters can also be
compared
to prior tests where dilation or plastic deformation of the reservoir was
performed, so as to
avoid similar conditions and stay within the elastic deformation zone. It has
been found
that dilation can have adverse effects on the reservoir and there is a risk it
could
compromise operations safety; thus remaining in the elastic deformation zone
can be
advantageous. It is also noted that detailed reservoir geomechanical modeling
can be
performed to optimize the startup process for pressure, flow rate, fluid
volume, efficiency,
well conformance, and safety.
[0039] The startup process can be applied in advance of various in situ
recovery
operations, including SAGD, Expanding Solvent SAGD (ES-SAGD), solvent-assisted
gravity drainage processes, solvent-dominated gravity drainage processes,
and/or
Enhanced Bitumen Recovery Technology (EBRT) that can involve azeotropic heated
Date Recue/Date Received 2022-09-28
vapour extraction (AH-VAPEX) processes with co-injection of solvent and steam,
to
increase injectivity.
[0040] This high-pressure startup fluid approach can help accelerate the
start-up and
ramp-up performance of the well pair and it may have a duration of a week or
several
weeks. The elevated pressure used by this start-up process promotes elastic
deformation
of the reservoir sand and temporarily increases injectivity without long-term
negative
impacts to coalescence, premature breakthrough of steam, or risk to caprock
integrity
which is posed by other technologies which operate above shear failure stress
conditions.
Startup fluid pressure may be constant or vary cyclically in one or both
wells. Startup fluid
injection may occur simultaneously into the injection and the production wells
of a well pair
or in a staggered/alternating fashion. For longer-term SAGD operations, it can
be desirable
to gradually lower the operating pressure for improved thermal efficiency.
[0041] One advantage of this high-pressure startup fluid injection is
enhanced
permeability and injectivity and, therefore, faster start-up and steam chamber
growth.
High-pressure injection can promote much faster heating due at least in part
to convective
heat transfer achieved through higher rate and volume of energy input into the
reservoir.
For low-mobility areas in particular, the startup process may result in
significant savings
in time, equipment and workforce requirements by eliminating circulation start-
up through
a start-up skid. In some implementations, the startup process can include
multiple
bullheading stages using the same or different fluids. For example, the
process could first
include a water bullheading stage followed by a steam bullheading stage.
Alternatively,
steam is bullheaded from the beginning. Steam bullheading may occur for
several weeks,
and then the startup process could be assessed (e.g., with temperature fall-
off tests) and
then convert to SAGD mode with continuous injection and production from the
respective
wells once there is a solid indication of sufficiently high temperature
between the wells.
[0042] While well pair startup has been discussed in detail above, it is
noted that high-
pressure fluid injection in the elastic deformation zone can have other
applications for in
situ recovery operations. For example, the high-pressure process could be
implemented
to stimulate production wells with suspected liner and/or near-wellbore
plugging. In such
cases, the production well would be shut down and a stimulation fluid would be
introduced
at elastic deformation pressure to stimulate the reservoir surrounding the
production well.
16
Date Recue/Date Received 2022-09-28
In another example, the high-pressure process could be to stimulate the growth
of steam
chambers or extraction chambers impeded by poor reservoir quality. In such a
case, the
injection well would receive the fluid which would be injected at elastic
deformation
pressure into the reservoir to stimulate chamber growth for a stimulation
period and then
the injection would be brought back down to normal operating pressures.
[0043] Several alternative implementations and examples have been described
and
illustrated herein. The implementations of the technology described above are
intended to
be exemplary only. A person of ordinary skill in the art would appreciate the
features of
the individual implementations, and the possible combinations and variations
of the
components. A person of ordinary skill in the art would further appreciate
that any of the
implementations could be provided in any combination with the other
implementations
disclosed herein. It is understood that the technology may be embodied in
other specific
forms without departing from the central characteristics thereof. The present
implementations and examples, therefore, are to be considered in all respects
as
illustrative and not restrictive, and the technology is not to be limited to
the details given
herein. Accordingly, while the specific implementations have been illustrated
and
described, numerous modifications come to mind.
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Date Recue/Date Received 2022-09-28
