Note: Descriptions are shown in the official language in which they were submitted.
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SAGD OPERATIONS WITH INJECTION OF WATER WETTING AGENTS
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:
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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
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.
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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.
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, 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, 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.
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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 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
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, 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.
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In some implementations, the process further includes pre-heating the aqueous
emulsification solution prior to injection.
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;
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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 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
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producing the bitumen-in-water emulsion via the step-out well, thereby
removing
bitumen from the micro-channels of the pre-heated region.
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.
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In some implementations, the process also includes selecting the synthetic
surfactant
based on enabling a maximum water wetting effectivity.
In some implementations, the process also includes selecting the synthetic
surfactant
based on enabling a maximum water wetting effectivity 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.
It should be noted that one or more features of the processes and methods
described or
illustrated herein may be used in connection with other processes and methods
described herein. For example, the water wetting chemical selection method,
and
various optional features thereof, may be used in combination with some of the
SAGD
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startup and/or hydrocarbon recovery processes described herein. In addition,
certain
features that are 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
(SAGD) 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
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Various techniques are described for enhancing the micro-channel water
wettability in a
bitumen-bearing reservoir by injecting an aqueous emulsification solution
including a
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 wetting 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
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,
water mobility in the reservoir matrix can be increased and, in turn, the
bitumen-in-water
emulsification process can be improved.
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 I a, 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
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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).
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.
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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 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
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14
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.
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.
CA 02831950 2013-10-29
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 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
CA 02831950 2013-10-29
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. 16
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 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.
In fill well and step-out well startup implementations
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17
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
wettability 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 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
CA 02831950 2013-10-29
18
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 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
CA 02831950 2013-10-29
19
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 Amott 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.
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., ll 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
CA 02831950 2013-10-29
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 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
CA 02831950 2013-10-29
,
21
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.
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.
