Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
I
WATER WETTING CHEMICAL SELECTION FOR SAGD AND WELL PAIR STARTUP
USING WATER WETTING SURFACTANTS
TECHNICAL FIELD
The techniques described herein generally relate to the field of in situ
bitumen recovery.
BACKGROUND
The injection of chemical compounds into hydrocarbon-bearing reservoirs has
been
performed in an attempt to enhance some aspects of in situ hydrocarbon
recovery. For
some in situ hydrocarbon recovery processes, the selection of chemical
compounds has
largely centered on decreasing the interfacial tension between oil and water
phases in the
reservoir.
In one type of in situ recovery operation referred to as Steam-Assisted
Gravity Drainage
(SAGD), a well pair is provided in the reservoir. The well pair includes an
injection well
and an underlying production well that are vertically spaced apart from each
other. Steam
is injected via the injection well in order to mobilize the hydrocarbons which
drain by gravity
toward the production well. SAGD includes a startup phase in order to
establish fluid
communication between the injection and production wells. The startup phase
can include
injection of steam or circulation of hot water through one or both of the
wells in order to
mobilize the bitumen in between the well pair. After startup, SAGD typically
then includes
a ramp up phase, a normal operational phase, and a wind-down phase.
There are various challenges related to chemical selection and use for in situ
hydrocarbons recovery operations such as SAGD.
SUMMARY
In some implementations, there is provided a process for producing bitumen
from a
bitumen-bearing reservoir, comprising:
injecting an aqueous emulsification solution comprising a water wetting agent
into
the bitumen-bearing reservoir, wherein:
the bitumen-bearing reservoir comprises a matrix comprising solid mineral
particles and micro-channels, the micro-channels having channel walls
defined by mineral surfaces of the mineral particles;
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the water wetting agent is selected for increasing the water wettability of
the mineral surfaces; and
the aqueous emulsification solution flows through the micro-channels,
thereby:
increasing the water wettability of the mineral surfaces;
increasing water mobility in the matrix; and
generating a bitumen-in-water emulsion; and
producing the bitumen-in-water emulsion from the bitumen-bearing reservoir.
In some implementations, the process further includes selecting the water
wetting agent
comprising:
measuring the ability of a chemical agent candidate to increase the water
wettability of sample mineral surfaces corresponding to the mineral surfaces
of the
micro-channels; and
selecting the chemical agent candidate as the water wetting agent for use in
the
bitumen-bearing reservoir, if the chemical agent increased the water
wettability of
the sample mineral surfaces.
In some implementations, the sample mineral surfaces are comparable in
chemical
composition to the mineral surfaces of the micro-channels of the reservoir.
In some implementations, the sample mineral surfaces are obtained from core
samples
from the reservoir.
In some implementations, the sample mineral surfaces are synthetic. In some
implementations, the synthetic sample mineral surfaces are selected to
simulate the
chemical composition of the mineral surfaces of the micro-channels of the
reservoir.
In some implementations, the process also includes selecting the water wetting
agent
based solely on the ability of a candidate chemical agent to increase water
wettability of
mineral surfaces corresponding to the mineral surfaces of the micro-channels.
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In some implementations, the chemical agent is selected from a plurality of
candidate
chemicals based on enabling a maximum water wetting affectivity.
In some implementations, the chemical agent is selected from a plurality of
candidate
chemicals based on enabling a maximum water wetting affectivity per cost
ratio.
In some implementations, there is provided a method of selecting a chemical
agent as a
water wetting agent for use in SAGD bitumen recovery from a bitumen-bearing
reservoir
comprising a matrix comprising solid mineral particles and micro-channels, the
micro-
channels having channel walls defined by mineral surfaces of the mineral
particles, the
method comprising:
measuring the ability of a chemical agent candidate to increase the water
wettability of sample mineral surfaces corresponding to the mineral surfaces
of the
micro-channels; and
selecting the chemical agent candidate as the water wetting agent for use in
the
bitumen-bearing reservoir, if the chemical agent increased the water
wettability of
the sample mineral surfaces.
In some implementations, there is provided a method of selecting a chemical
agent as a
water wetting agent for use in steam-assisted gravity drainage (SAGD) bitumen
recovery
from a bitumen-bearing reservoir comprising a matrix comprising solid mineral
particles
and micro-channels, the micro-channels having channel walls defined by mineral
surfaces
of the mineral particles, the method comprising:
measuring the respective abilities of chemical agent candidates to increase
the
water wettability of sample mineral surfaces corresponding to the mineral
surfaces
of the micro-channels; and
selecting at least one of the chemical agent candidates as the water wetting
agent
for use in the bitumen-bearing reservoir, if the at least one chemical agent
candidate increased the water wettability of the sample mineral surfaces.
In some implementations, the sample mineral surfaces are obtained from core
samples from the reservoir.
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In some implementations, the sample mineral surfaces are synthetic.
In some implementations, the synthetic sample mineral surfaces are selected to
simulate
the chemical composition of the mineral surfaces of the micro-channels of the
reservoir.
In some implementations, selecting the chemical agent candidate as the water
wetting
agent is based solely on the ability of the candidate chemical agent to
increase water
wettability of the sample mineral surfaces.
In some implementations, the chemical agent is selected from a plurality of
candidate
chemicals based on enabling a maximum water wetting affectivity.
In some implementations, the chemical agent is selected from a plurality of
candidate
chemicals based on enabling a maximum water wetting affectivity per cost
ratio.
In some implementations, there is provided a process for Steam-Assisted
Gravity
Drainage (SAGD) startup, comprising:
injecting an aqueous emulsification solution comprising a water wetting agent
into
at least one of a SAGD injection well and a SAGD production well provided in a
bitumen-bearing reservoir, in order to penetrate into an interwell region
defined
between the SAGD injection well and the SAGD production well, wherein:
the interwell region of the bitumen-bearing reservoir comprises a matrix
comprising solid mineral particles and micro-channels, the micro-channels
having channel walls defined by mineral surfaces of the mineral particles;
the water wetting agent is selected for increasing the water wettability of
the mineral surfaces; and
the aqueous emulsification solution flows through the micro-channels,
thereby:
increasing the water wettability of the mineral surfaces;
increasing water mobility in the matrix; and
generating a bitumen-in-water emulsion; and
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producing the bitumen-in-water emulsion from the bitumen-bearing reservoir,
thereby removing bitumen from the micro-channels of the interwell region while
increasing the water mobility between the SAGD injection well and the SAGD
production well.
In some implementations, there is provided a process for well pair startup,
comprising:
injecting into an interwell region defined between an injection well and a
production
well, a surfactant-generating agent that converts native compounds present in
the
reservoir into natural surfactants to increase the water wettability of the
region of
the reservoir;
injecting a synthetic surfactant into the region to further increase the water
wettability of the region of the reservoir;
generating a bitumen-in-water emulsion in the interwell region; and
producing the bitumen-in-water emulsion from the bitumen-bearing reservoir.
In some implementations, the aqueous emulsification solution is co-injected
with steam.
In some implementations, the aqueous emulsification solution is injected alone
in the form
of a liquid.
In some implementations, the process further includes pre-heating the aqueous
emulsification solution prior to injection.
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In some implementations, the injection of the aqueous emulsification solution
is performed
via the injection well.
In some implementations, the process further includes providing a pressure
sink in the
production well to promote flow of the aqueous emulsification solution through
the interwell
region.
In some implementations, the process further includes providing a pressure
sink in the
production well to promote flow of the aqueous emulsification solution through
the interwell
region.
In some implementations, the process further includes isolating a section of
the interwell
region to provide an isolated section, and injecting the aqueous
emulsification solution into
the isolated section.
In some implementations, the process further includes identifying the section
of the
interwell region in accordance with permeability.
In some implementations, the process further includes injecting the aqueous
emulsification solution in order to increase uniformity of permeability along
a length of the
interwell region.
In some implementations, there is provided a process for startup of an infill
well located in
between two adjacent well pairs in a Steam-Assisted Gravity Drainage (SAGD)
operation,
comprising:
injecting an aqueous emulsification solution comprising a water wetting agent
into
the infill well, in order to penetrate into part of a pre-heated region
defined between
two adjacent well pairs, wherein:
the pre-heated region comprises a matrix comprising solid mineral particles
and micro-channels, the micro-channels having channel walls defined by
mineral surfaces of the mineral particles;
the water wetting agent is selected for increasing the water wettability of
the mineral surfaces; and
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the aqueous emulsification solution flows through the micro-channels,
thereby:
increasing the water wettability of the mineral surfaces;
increasing water mobility in the matrix; and
generating a bitumen-in-water emulsion; and
producing the bitumen-in-water emulsion from the bitumen-bearing reservoir via
the infill well, thereby removing bitumen from the micro-channels of the pre-
heated
region.
In some implementations, there is provided a process for startup of an step-
out well
located laterally spaced away from an adjacent well pair in a Steam-Assisted
Gravity
Drainage (SAGD) operation, comprising:
injecting an aqueous emulsification solution comprising a water wetting agent
into
the step-out well, in order to penetrate into part of a pre-heated region
defined
around the step-out well, wherein:
the pre-heated region comprises a matrix comprising solid mineral particles
and micro-channels, the micro-channels having channel walls defined by
mineral surfaces of the mineral particles;
the water wetting agent is selected for increasing the water wettability of
the mineral surfaces; and
the aqueous emulsification solution flows through the micro-channels,
thereby:
increasing the water wettability of the mineral surfaces;
increasing water mobility in the matrix; and
generating a bitumen-in-water emulsion; and
producing the bitumen-in-water emulsion via the step-out well, thereby
removing
bitumen from the micro-channels of the pre-heated region.
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In some implementations, there is provided a process for Steam-Assisted
Gravity
Drainage (SAGD) startup, comprising:
injecting into an interwell region defined between a SAGD injection well and a
SAGD production well, a surfactant-generating agent that converts native
compounds present in the reservoir into natural surfactants to increase the
water
wettability of the region of the reservoir; and
injecting a synthetic surfactant into the region to further increase the water
wettability of the region of the reservoir;
generating a bitumen-in-water emulsion in the interwell region; and
producing the bitumen-in-water emulsion from the bitumen-bearing reservoir.
In some implementations, the surfactant-generating agent includes an alkali
compound.
The alkali compound may injected within an aqueous solution. The alkali
compound may
be co-injected steam.
In some implementations, the process also includes selecting the surfactant-
generating
agent based solely on generating natural surfactants having the ability to
increase water
wettability of sample mineral surfaces corresponding to mineral surfaces of
micro-
channels of the reservoir.
In some implementations, the process also includes selecting the surfactant-
generating
agent based on enabling a maximum water wetting affectivity of the natural
surfactants.
In some implementations, the process also includes selecting the surfactant-
generating
agent based on enabling a maximum water wetting affectivity per cost ratio of
the natural
surfactants.
In some implementations, the process also includes selecting the synthetic
surfactant
based solely on ability to increase water wettability of sample mineral
surfaces
corresponding to mineral surfaces of micro-channels of the reservoir.
In some implementations, the process also includes selecting the synthetic
surfactant
based on enabling a maximum water wetting affectivity.
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In some implementations, the process also includes selecting the synthetic
surfactant
based on enabling a maximum water wetting affectivity per cost ratio.
In some implementations, the process also includes injection of the surfactant-
generating
agent is ceased prior to commencing injection of the synthetic surfactant.
In some implementations, the process is performed during SAGD startup to
achieve fluid
communication between the SAGD injection well and a SAGD production well.
In some implementations, the process includes not soaking the region after
injection of
the surfactant-generating agent or after injection of the synthetic
surfactant.
In some implementations, injection of the surfactant-generating agent and the
synthetic
surfactant are each performed continuously through a SAGD injection well. The
process
may also include producing a bitumen-in-water emulsion via an underlying SAGD
production well.
In some implementations, there is provided a process for Steam-Assisted
Gravity
Drainage (SAGD) startup, comprising:
injecting via a SAGD injection well an aqueous emulsification solution
comprising
a water wetting agent, into an interwell region defined between the SAGD
injection
well and a SAGD production well, to generate a bitumen-in-water emulsion in
the
interwell region;
producing the bitumen-in-water emulsion via the SAGD production well; and
providing a residence time of the aqueous emulsification solution in the
interwell
region to promote formation of the bitumen-in-water emulsion while inhibiting
formation of a water-in-bitumen emulsion.
In some implementations, there is provided a method of selecting a chemical
agent as a
water wetting agent for use in a steam-assisted bitumen recovery operation
from a
bitumen-bearing reservoir comprising a matrix comprising solid mineral
particles and
micro-channels, the micro-channels having channel walls defined by mineral
surfaces of
the mineral particles, the method comprising:
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described herein with respect to SAGD startup operations, may also be adapted
and used
in normal ramped-up SAGD operations and/or other hydrocarbon recovery methods.
BREIF DESCRIPTION OF THE DRAWINGS
Figs la are lb are cross-sectional view schematics of part of a matrix of a
bitumen-bearing
reservoir.
Fig 2 is a front cross-sectional view schematic of a well pair.
Fig 3 is a top side perspective view schematic of a well pair with a process
flow illustration
of pumps, lines and heat exchangers.
Fig 4 is a side cross-sectional view schematic of a well pair.
Fig 5 is a close-up front cross-sectional view schematic of parts of a well
pair and a matrix
of a bitumen-bearing reservoir.
Fig 6 is a front cross-sectional view schematic of a well pair.
Fig 7 is a front cross-sectional view schematic of a Steam-Assisted Gravity
Drainage
(SAGO) recovery operation.
Fig 8 is a front cross-sectional view schematic of a SAGD recovery operation.
Figs 9a and 9b are cross-sectional view schematics of part of a micro-channel
of a
bitumen-bearing reservoir.
Figs 10a to 10b are cross-sectional view schematics of part of a micro-channel
of a
bitumen-bearing reservoir.
Fig 11 is a schematic of matching candidate chemical agents to sample rocks.
Fig 12 is a process flow diagram.
DETAILED DESCRIPTION
Various techniques are described for enhancing the micro-channel water
wettability in a
bitumen-bearing reservoir by injecting an aqueous emulsification solution
including a
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water wetting agent selected to increase the water wettability of mineral
surfaces that form
part of the micro-channels. Enhancing the water wettability facilitates the
production of a
bitumen-in-water emulsion as the aqueous emulsification solution flows through
the micro-
channels, removing bitumen from the micro-channels and increasing water
mobility in the
micro-channels of the reservoir matrix. Aqueous emulsification solutions may
be injected
in the context of Steam-Assisted Gravity Drainage (SAGD) startup operations,
during
normal operation of SAGD processes, during SAGD wind-down and/or during other
stages
of SAGD operations.
Some techniques include the selection of a chemical agent for injection into a
bitumen-
bearing reservoir for enhancing SAGD operations, based on the chemical agent's
water
wetting properties for the mineral surfaces of the bitumen-bearing reservoir.
The selection
may be based on a maximum water wetting affectivity or a maximum ratio of
water wetting
affectivity per cost of the chemical agent. The "affectivity" may be
considered to be the
time needed to achieve a certain result; the "water wetting affectivity" may
be the time to
achieve a given degree of water wetting of the mineral surfaces. The selection
of a given
chemical agent may also be based on the chemical agent's water welling
properties for
particular phases of the SAGD operation, such as startup phase. Thus, one
water wetting
agent may be selected for maximizing water wetting during startup phase and
another
water wetting agent may be selected for maximizing water wetting during normal
operation
phase, for example.
In the context of the present description, "water wettability" refers to the
tendency of water
to adhere to solid mineral surfaces in the presence of an immiscible
hydrocarbon fluid.
Water wettability may be defined by the contact angle of water with the solid
mineral
surface.
Conventional approaches for enhancing in situ recovery operations have treated
bitumen-
containing reservoirs with the focus of increasing the mobility of the oil
phase and reducing
the interfacial tension between the oil and the water phases of the produced
emulsion.
However, by increasing the water wettability of the micro-channels in the
reservoir matrix
along with injecting an aqueous phase emulsification solution, the water
mobility in the
reservoir matrix can be increased and, in turn, the bitumen-in-water
emulsification process
can be improved.
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The techniques for enhancing water wettability may be used in a variety of
scenarios for
in situ recovery operations. For example, some of the techniques may be used
for
enhancing a SAGD startup operation.
Injection of water wetting agent through micro-channels
Referring to Fig la, in some implementations the techniques can be applied to
a bitumen-
bearing reservoir that includes a matrix 10 including solid mineral particles
12 and micro-
channels 14. The micro-channels 14 have channel walls defined by mineral
surfaces 16
of the mineral particles 12. The micro-channels 14 are also partially occupied
with free
water native to the reservoir matrix.
Now referring to Fig 1 b, an aqueous emulsification solution 20 including a
water wetting
agent 22 is injected into the reservoir so as to flow through the micro-
channels 14. As the
aqueous emulsification solution 20 flows through the micro-channels 14, the
water wetting
agent 22 contacts the mineral surfaces 16 and enables hydrophilic surface
modification,
thereby forming hydrophilically modified mineral surfaces 24 effectively
increasing the
water wettability of the mineral surfaces. The hydrophilically modified
mineral surfaces 24
are in contact with adhered surface water 26. The flow of the aqueous
emulsification
solution 20 also forms a bitumen-in-water emulsion 28 including bitumen
droplets and a
continuous water phase. The bitumen droplets in the bitumen-in-water emulsion
28 may
include bitumen that was present as droplets in the micro-channels 14 as well
as bitumen
that was previously bound to mineral surfaces under bitumen-wet conditions.
Referring to Figs 9a and 9b, some of the micro-channels 14 may be
predominantly water
wet at the outset of the process with only some oil-wet areas. The injection
of the water
wetting agent enables formation of the hydrophilically modified mineral
surfaces which
promote detachment of bitumen from bitumen-wet surfaces.
Referring to Figs 10a to 10e, some of the micro-channels 14 may be
predominantly
bitumen-wet at the outset of the process with only some water-wet areas. The
injection of
the water wetting agent enables formation of the hydrophilically modified
mineral surfaces
which promotes modified contact angles between the mineral surfaces and the
liquid
phases (see Figs 10b and 10c), followed by detachment of bitumen from bitumen-
wet
surfaces (see Figs 10d and 10e).
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The matrix of the bitumen-bearing reservoir may have an initial permeability
or water
mobility facilitating injection of the aqueous emulsification solution. For
example, the initial
permeability of the matrix may be at least 10 millidarcies (md) to enable
initial injection. In
some scenarios, the initial permeability of the matrix may be at least 20 md,
50 md, 100
md, or 500 md.
In some implementations, the aqueous emulsification solution is provided as a
liquid in a
tank at the surface, and is pumped through one or more injection wells of the
SAGD
operation. The aqueous emulsification solution may be injected alone as a
liquid, or co-
injected with steam. For example, in SAGD startup implementations, the aqueous
emulsification solution may be injected alone, while in ramped-up SAGD
operations the
aqueous emulsification solution may be injected along with the high
temperature steam.
The injection pressure may depend on the stage of SAGD. In SAGD startup, the
injection
pressure may be below the fracture pressure of the reservoir region
surrounding the
SAGD well pair, while in ramped-up SAGD operations co-injection with steam
involves the
given steam pressure conditions.
SAGD startup implementations
Referring to Figs 2 to 5, in some implementations, a SAGD well pair may be
provided in
the reservoir. The SAGD well pair includes an injection well 29 overlying a
production well
30 separated by an interwell region 32. SAGD startup may include injecting the
aqueous
emulsification solution including the water wetting agent into the SAGD
injection well 29
and/or the SAGD production well 30 provided in the bitumen-bearing reservoir
in order to
penetrate into the interwell region 32. The interwell region 32 may include a
matrix as
described above and illustrated in Figs la and lb. The aqueous emulsification
solution
forms a bitumen-in-water emulsion, removing bitumen from the channel walls of
the micro-
channels of the interwell region and increasing water mobility in the
interwell region.
Various implementations and scenarios may be used for SAGD startup with
enhanced
water wetting of the micro-channels, as will be further described below.
Targeted injection along length of interwell region
Referring to Figs 3 and 4, in some scenarios the injection of the aqueous
emulsification
solution may be performed into isolated areas along the length interwell
region 32 based
on different properties, such as water permeability, along interwell region
32. The interwell
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region 32 may extend about a kilometer in length and it may have relatively
different water
permeabilities along its length. The interwell region 32 may include low water
permeability
zones 34, medium water permeability zones 36 and/or high water permeability
zones 38.
The water permeabilities can be tested or estimated, and then the chemical
injection can
be adapted by isolating (e.g., with packers) certain zones having low
permeability for early
and/or extra chemical injection. Fig 4 illustrates isolating a medium
permeability zone 36
with packers 40 in the injection well 29 in order to provide targeted
injection of the aqueous
emulsification solution into that zone 36, to improve conformance along the
well and
enhance balanced startup operations.
Staged addition of different chemicals
In some implementations, the process may include initially injecting a first
chemical agent
(e.g., an alkali compound that can convert in situ acids in the bitumen into
native
surfactants) followed by injection of a second chemical agent (e.g., a
synthetic surfactant)
to complete the emulsification cleaning of the interwell region 32. Staged
chemical addition
may provide the advantage of using native surfactants effectively at the
beginning of the
process and saving the expense of using large quantities of synthetic
surfactants.
In some scenarios, the first chemical agent is a surfactant-generating agent
that converts
native compounds in the reservoir into natural surfactants to pre-treat the
interwell region;
and the subsequent chemical agent is a synthetic surfactant with high water
wetting
affectivity to further enhance the water wetting of the interwell region.
Other compounds,
such as hydrocarbon solvents or steam, may be injected before and/or after the
surfactant-
generating agent as well as before and/or after the synthetic surfactant.
In some implementations, the selection of the chemical agent selected for use
at each
stage is based on water wetting properties of the chemical agents. For
example, if the
ratio of water wetting affectivity per cost is used to determine the selection
of the chemical
agent, a lower cost agent that reacts with native acids to form surfactants in
situ may be
selected as a first agent for the first stage of the SAGD startup, while a
higher cost
synthetic surfactant may be selected as a second agent for the later stage of
the SAGD
startup operation. In this way, the overall startup phase may be divided into
multiple stages
for which different chemical agents are injected in accordance with an optimum
water
wetting per cost ratio. The SAGD startup phase may be divided into more than
two stages.
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Injection with pressure sink in production we//
Referring to Fig 6, in some implementations the process includes injecting the
aqueous
emulsification solution through the injection well 29 only and the production
well 30 is put
on production mode, creating a pressure sink that draws the aqueous
emulsification
solution through the interwell region and into the production well 30. The
pressure sink
enabled flow can be facilitated by the water permeability in the interwell
region and allows
reduced consumption of the injected solution which permeates the area between
the well
pair rather than outward into other areas of the reservoir where it is not
required for SAGD
startup. Fig 6 illustrates a chemical-affected region 42 using the pressure
sink technique.
In some implementations, various fluids may be injected into the interwell
region using the
pressure sink technique. The fluids may be aqueous solutions including one or
more
chemical agents for enhancing SAGD startup in various ways, such as increasing
water
wettability of the mineral surfaces.
Continuous flow through the interwell region
In some implementations, the aqueous emulsification solution is not permitted
to soak
within the interwell region but rather is continuously injected via the
injection well and
produced as a bitumen-in-water emulsion via the production well. The residence
time of
the aqueous emulsification solution in the interwell region can be selected to
promote
formation of the bitumen-in-water emulsion while avoiding formation of a water-
in-bitumen
emulsion.
In some implementations, the water mobility of the interwell region may be pre-
determined
and the injection conditions, such as pressure and flow rate, may be provided
according
to the water mobility.
Injection with sufficient temperature for emulsification
Referring to Fig 3, in some implementations, the injection of the aqueous
emulsification
solution 20 may be performed, while ensuring the temperature of the affected
region of
the reservoir is sufficient to heat the bitumen to enable increased
emulsification. For
example, the aqueous emulsification solution 20 may be pre-heated by one or
more heat
exchangers 44 above ground to produce a pre-heated aqueous emulsification
solution 46,
which is injected through the injection well 29. The heat exchangers 44 may be
fed with
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steam, hot water, and/or a hot process fluid derived from the SAGD operation
for pre-
heating the solution 20. The pre-heated aqueous emulsification solution 46 may
be at a
temperature of at least about 50 C, for example, in order to facilitate
emulsification of the
bitumen. Sufficient heating lowers the viscosity of the bitumen in contact
with the solution
flowing through the micro-channels, facilitating bitumen droplets to be
adsorbed into the
flowing aqueous phase. In some implementations, the temperature may be
provided to
soften the bitumen and thus facilitate emulsification, while not so high as to
mobilize the
bitumen such that it would start to flow as a bulk fluid toward the production
well 30 and/or
promote formation of a water-in-bitumen emulsion. The reservoir temperature
may be
provided between about 50 C and about 80 C, for example, to increase the
bitumen-in-
water emulsification. Heating may be performed by pre-heating the injected
aqueous
emulsification solution, and/or by providing a separate source of heat by
injection,
circulation or electrical heating methods.
The aqueous emulsification solution may be formulated to have a desired
concentration
of the water wetting agent, according to the reservoir matrix chemistry,
permeability,
bitumen saturation, water saturation, operating parameters of the injection,
among other
factors. In some scenarios, the initial concentration of the water wetting
agent is relatively
high to promote a more rapid initial increase in water wettability and
mobility, and then the
concentration is decreased in a gradual or step-wise manner as the injection
continues.
The aqueous emulsification solution may be injected in accordance with various
injection
strategies. For example, the aqueous emulsification solution may be injected
at an initial
injection rate and the beginning of the startup phase, and then modified to a
lower or
higher injection rate as the startup phase progresses. For example, the
process may
include a first step using a relatively slow injection rate with a high
concentration of water
wetting agent, followed by a second step of using a higher injection rate with
a lower
concentration of water wetting agent. The concentration of the water wetting
agent may
be dictated on the basis of the cost of the chemicals, and batch injection may
be
advantageous for injecting different chemicals as the process evolves.
In some scenarios, the flow rate of injection via the SAGD injection well may
be
coordinated with the pressure sink provided in the SAGD production well. For
example,
high injection rates may be coordinated with a high pressure sink. At
different stages of
the startup phase, the injection rate and the pressure sink may also be
coordinated so as
to be offset; for instance, at the beginning of the startup phase one may
provide a relatively
Date Recue/Date Received 2021-01-14
16
high pressure sink and a relatively low injection flow rate, followed by a
lower pressure
sink and a higher injection flow rate at latter stages of the startup phase. A
high initial
pressure different between the injection and production wells may be
advantageous to
overcome lower initial water mobilities in the interwell region, for example,
and once the
mobility increases then lower pressure differential may be employed to save on
pump
energy. The injection and the pressure sink may also be provided in a
gradually or step-
wise increasing manner, a gradually or step-wise decreasing manner and/or a
pulsed
manner. In some scenarios, the flow of the aqueous emulsification solution may
be
provided in an alternating or cyclic manner, for instance by reversing the
flow between the
SAGD injection and production wells. Alternating flow can facilitate cleaning
of micro-
channels, and can also enable access of the aqueous emulsification solution to
new or
different micro-channels and retrieval of some of the aqueous emulsification
solution that
has been trapped in dead-end pores rather than micro-channels.
The amount of injected aqueous emulsification solution can also be provided in
accordance with various factors. For example, the volume of injected aqueous
emulsification solution may be based on a target volume of the interwell
region or part of
the interwell region. The volume of the aqueous emulsification solution may be
based on
water wetting affectivity of the water wetting agent, i.e., lower volumes for
higher affectivity.
Ina well and step-out well startup implementations
Referring to Fig 7, in some implementations, the injection of the aqueous
emulsification
solution 20 may be performed through an infill well 48 and/or a step-out well
50. The infill
well 48 may be a single well located in between two adjacent SAGD well pairs
that
previously operated to form SAGD steam chambers 52 extending upward into the
reservoir. The SAGD steam chambers 52 may pre-heat an in-between region 54
located
in between the two steam chambers 14 where the infill well 48 is provided.
Operation of
the infill well 48 may benefit from injecting the aqueous emulsification
solution 20 through
the infill well 48 into the surrounding pre-heated region 54 to increase water
weftability in
the region 54. Following injection of the aqueous emulsification solution 20,
the infill well
48 may be put on production mode to produce the bitumen-in-water emulsion from
the
surrounding region. In some scenarios, the injection of the aqueous
emulsification solution
20 may be performed once the surrounding region to be water wetted has reached
a
temperature sufficient to facilitate emulsification and prevent significant
mobilization of the
Date Recue/Date Received 2021-01-14
17
bitumen. The infill well may be a single well 48 as illustrated in Fig 7, or
part of an infill well
pair 56 as illustrated in Fig 8. In the case of the infill well pair 56, the
SAGD startup methods
described above may be employed.
Similar techniques to those describe above for infill wells may also be
employed for step-
out wells 50 located in a region 58 of the reservoir adjacent to one of the
SAGD steam
chambers 14. The step-out well may be a single well 50 as illustrated in Fig
7, or part of a
step-out well pair 60 as illustrated in Fig 8. In the case of the step-out
well pair 60, the
SAGD startup methods described above may be employed.
Selection of water wetting agent
In some scenarios, the water wetting agent may be selected in accordance with
certain
methodologies. The methods for selecting a chemical agent as a water wetting
agent for
use in SAGD bitumen recovery may include measuring the ability of a candidate
chemical
agent to increase the water wettability of sample mineral surfaces
corresponding to the
mineral surfaces of the micro-channels; and then including or excluding the
candidate
chemical agent as a potential water wetting agent for use in the bitumen-
bearing reservoir
depending on the results. If the chemical agent increased the water
wettability of the
sample mineral surfaces, it may be retained for use in the given reservoir. In
some
scenarios, the method consists of measuring the ability of candidate chemical
agents to
increase the water wettability of sample mineral surfaces, without measuring
other
properties such as the impact on the interfacial tension between oil and water
phases.
Conventionally, chemicals have been selected for use in SAGD methods based on
reduction in interfacial tension between the oil and the water phases of the
produced
emulsion. However, the present methods select chemicals based on an increase
in wall
wettability, which has been found to be a more consistent predictive factor in
the success
of an injected chemical to improve recovery. The ability of a chemical agent
to make the
surface of the pore space more hydrophilic and more oleophobic can facilitate
bitumen-in-
water emulsion formation in situ, and thereby increase production rate. By
testing the
ability of a candidate chemical to alter the water wettability of mineral
walls defining micro-
channels and pore space, the improved selection of water wetting agents can
result in
improved production rates and increased economic performance. It has been
observed
Date Recue/Date Received 2021-01-14
18
that an increase in wall wettability is a more consistent predictive factor in
the success of
an injected chemical to improve recovery.
The step of measuring the water wettability may include determining impacts of
the
candidate chemical agent on the hydrophilic properties of mineral surfaces
and/or on the
roughness of mineral surfaces, both of which can affect water wettability.
Chemical agents
that increase the hydrophilic or oleophobic properties of mineral surfaces may
be retained
as potential water wetting agents. Chemical agents that maintain or increase
the
roughness of hydrophilic mineral surfaces may also be retained as potential
water wetting
agents. The impact of chemical agents on roughness may be tested in the
laboratory as
an approximation for reservoir behavior.
It is also noted that while the techniques described herein primarily concern
generating
bitumen-in-water emulsions, some alternative methods may be adapted for
reservoirs
where production of water-in-oil emulsions are desired, e.g., by selecting an
oil wetting
chemical to increase the preference of the micro-channels for oil.
In some scenarios, the water wetting agent is selected from a plurality of
candidate
chemical agents, each having a theoretical or determined oil-water interfacial
tension
effect, a theoretical or determined water wettability effect, and other
physical or chemical
properties. The plurality of candidate chemical agents may be subjected to
laboratory
wettability tests, including water wettability and/or oil wettability tests.
The wettability tests
may be conducted with respect to sample rock surfaces that correspond to a
plurality of
different reservoir minerals. For example, the reservoir minerals may include
carbonate
minerals, silicate minerals and/or clays, including various different sub-
types of each. The
sample rocks may be obtained from core samples from the given reservoir and/or
from
other sources in order to imitate certain reservoir minerals. In some
scenarios, wettability
can be determined using synthetic mineral surfaces and measuring the contact
angle or
leaching of a fluid from its surface when contacted by the chemical solution.
Additionally,
wettability tests such as the Amoft index test can be done in core samples to
determine
wettability preference. The plurality of candidate chemical agents may be
ranked for
applicability to one or more given bitumen-bearing reservoir matrices.
Date Recue/Date Received 2021-01-14
19
In microfluidic environments, such as those found with the injection of fluids
into a reservoir
matrix having micro-channels, the wettability of the solid mineral surfaces is
the controlling
factor in emulsion formation.
Referring to Fig 12, the selection method may include the flowing steps:
providing chemical agent candidates (step 100);
providing sample rock candidates corresponding to different reservoir matrices
(step 102);
testing each chemical agent candidate with each sample rock candidate to
assess
water wettability (step 104); and
selecting chemical agents for use as water wetting agents for given reservoir
matrices based on high (e.g., highest) water wettability for the corresponding
sample rock (step 106).
Referring to Fig 11, various chemical agent candidates (I to V) may be tested
with various
sample rock candidates (A to E) corresponding to different reservoir matrices,
and the
results may indicate that certain chemical agent candidates are not suitable
for any of the
reservoir matrices (e.g., II and V) while other chemical agent candidates are
suitable for
one of the reservoir matrices (e.g., IV) or more of the reservoir matrices
(e.g., I and III).
While five chemical agent candidates and five sample rock candidates are
illustrated in
the example of Fig 11, it should be understood that less or more of both sets
of candidates
may be tested with each other to identify and select suitable water wetting
agents for use
in corresponding reservoir matrices. In some scenarios, only the candidate
with the
maximum water wettability properties for the sample rock is selected for use
as the water
wetting agent in the corresponding reservoir matrix.
The candidate chemical agents may be of various different types. For example,
the
candidate chemicals may include alkali agents or natural or synthetic
surfactants.
In some scenarios, the aqueous emulsification solution may be formulated to
further
include other chemical agents, which may be selected based on various factors,
such as
co-surfactant properties (e.g., alcohols), surfactant properties (e.g.,
reduction of interfacial
oil-water tension), pH properties, viscosity properties, etc. Alternatively,
the aqueous
Date Recue/Date Received 2021-01-14
20
emulsification solution may consist essentially of water and the water wetting
agent. The
water in the aqueous emulsification solution may at least partly be derived
from SAGD
process water, oil sands extraction water, recycled oil sands tailings water,
and/or fresh
or treated water. Process waters may be pre-treated or selected so as to
remove
components that could precipitate or otherwise deactivate the water wetting
agent.
Low pressure SAGD implementations
In some implementations, the injection of the aqueous emulsification solution
is performed
in the context of low pressure SAGD. Increased water wettability can lead to
increased
water mobility and, in turn, requires less pressure to move the bitumen-in-
water emulsion
through the micro-channels. Low pressure SAGD can be uneconomical in some
cases
due to the lower production rates, since at lower pressures the steam also has
a lower
temperature and thus the viscosity of the bitumen tends to be higher.
Injecting the water
wetting agents can enhance oil/water emulsification leading to lower emulsion
viscosity
and thus increasing production rates.
Various advantages of some implementations
In some implantations, increasing the water wettability of the micro-channels
in the
reservoir matrix can accelerate oil production rates, increasing the economic
performance.
In some scenarios, making the rock surfaces more oleophobic may increase the
recovery
factor by facilitating the production of oil. Faster production rates,
potentially higher
recovery, lower steam-to-oil ratios (SOR), lower temperatures for bitumen
extraction, and
production of bitumen previously believed to be non-economical for SAGD or too
difficult
to exploit (e.g., in shallow reserves), are also advantages of some
implementations of the
techniques described herein.
It should also be noted that the treatment of the reservoir matrix with the
aqueous
emulsification solution may be a first of multiple treatments. Alternatively,
the reservoir
matrix may have been previously conditioned with an additional pre-treatment
method, for
example to increase the initial water permeability to a desired level for
injection of the
aqueous emulsification solution. The treatment of the reservoir matrix with
the aqueous
emulsification solution may also be the first and only pre-treatment before a
given in situ
bitumen recovery operation is initiated.
Date Recue/Date Received 2021-01-14
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It should also be noted that while various techniques are described herein
relating to
particular implementations, such as SAGD startup methods and low pressure
SAGD,
techniques could also be used in other implementations of in situ bitumen
recovery
methods. Various optional aspects and features of some implementations can
thus be
combined with one or more other optional aspects and features as illustrated
or described
herein.
Date Recue/Date Received 2021-01-14
