Note: Descriptions are shown in the official language in which they were submitted.
CA 02778135 2012-05-18
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SOLVENT ASSISTED STARTUP TECHNIQUES FOR IN SITU BITUMEN RECOVERY
WITH SAGD WELL PAIRS, INFILL WELLS OR STEP-OUT WELLS
FIELD OF THE INVENTION
The present invention generally relates to the field of in situ bitumen
recovery and in
particular relates to techniques for solvent assisted startup for SAGD well
pairs, infill wells
and/or step-out wells.
BACKGROUND
There are a number of in situ techniques for recovering bitumen from
subsurface reservoirs.
One technique called Steam Assisted Gravity Drainage (SAGD) has become a
widespread
process of recovering heavy oil and bitumen particularly in the oil sands of
northern Alberta.
The SAGD process involves well pairs each of which consists of two horizontal
wells drilled
in the oil sands and aligned in spaced relation one on top of the other. The
upper well is a
steam injection well and the lower well is a producer well. The injected steam
forms a steam
chamber that grows upward and outward within the formation, heating the
bitumen or crude
oil sufficiently to reduce its viscosity and allow it to flow toward the
producer well along with
condensed water.
Numerous SAGD well pairs are usually provided in groups extending from central
pads for
hundreds of meters. The well pairs of a group often extend parallel generally
parallel to one
another.
Once a SAGD well pair is drilled and completed, the first phase of SAGD
operations is the
so-called startup phase. In the startup phase, fluid communication is
established between
the injection and producer wells of a given well pair. Prior to startup, the
high saturation
bitumen interval separating the injection and production wells of each pair
has low fluid
mobility and the SAGD process relies on initially establishing a heated mobile
interval in
between the injection and production wells. It is important for an effective
SAGD operation
to reduce the viscosity of the bitumen between injection and production wells
and produce
it. This procedure, establishing heat communication between two wells at the
initial stages
of SAGD, can be done by circulating steam into both injection and production
wells. The
wells act as hot fingers in the reservoir and heating is by conduction. When
initial steam
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injectivity is possible, steam may be injected in the top well and production
obtained from
the bottom well. After the pre-heat period the displacement and production of
the bitumen in
the region between wells is the step responsible for the initiation of the
steam chamber.
However, heat conduction is generally a slow process. Pre-heat of SAGD wells
takes
between three and six months.
Solvent injection for SAGD startup and initialization has been attempted with
limited
success. In particular, it has been proposed to provide solvent via the
injection and
production wells and to allow a solvent soak period to reduce the viscosity of
the bitumen in
between the injection and production wells. However, this technique has a
number of
drawbacks, including slow solvent penetration and consistency along the well
pair. Solvent
soaking relies on diffusion which is a slow process.
A solvent pre-soak process includes the injection of solvent in advance to the
usual pre-
heating process. The time between the injection of solvent and the circulation
of steam
allows the solvent to slowly diffuse and mix with the bitumen lowering its
viscosity. Solvent
pre-soak leads to mobile water displacement and creation of a halo of solvent
surrounding
each well. Due to vertical-horizontal permeability contrast, the lateral
expansion of the halo
is often encouraged. It follows that to be able to deliver solvent to the
whole bitumen volume
between a well pair a large volume of solvent is necessary.
The known processes for in situ recovery operations startup, such as for SAGD,
have a
variety of disadvantages.
SUMMARY OF THE INVENTION
The present invention provides techniques for solvent assisted startup for in
situ recovery of
bitumen.
In some optional implementations, there is an in situ bitumen recovery startup
process,
including:
injecting a solvent-containing startup fluid into a first horizontal well
located in a
bitumen-containing reservoir, where the fluid is injected below a fracturing
pressure
of the reservoir proximate the first horizontal well;
¨
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providing a pressure sink in a second horizontal well located adjacent to the
first well
to define an interwell region there-between, to promote pressure drive of the
solvent
from the first horizontal well toward the second horizontal well to mobilize
bitumen in
the interwell region; and
establishing fluid communication between the first horizontal well and the
second
horizontal well.
In some optional implementations, the pressure sink is created by a pump
associated with
the second horizontal well for producing fluids therefrom.
In some optional implementations, the solvent containing startup fluid
contains a solvent
selected from aromatic compounds and alkanes.
In some optional implementations, the solvent in the solvent containing
startup fluid
comprises at least one of toluene, xylene, diesel, butane, pentane, hexane,
heptane and
naphtha.
In some optional implementations, the solvent in the solvent containing
startup fluid
comprises naphtha.
In some optional implementations, the solvent in the solvent containing
startup fluid consists
of naphtha.
In some optional implementations, the solvent containing startup fluid further
comprises
water.
In some optional implementations, the process includes:
producing fluids from the second horizontal well; and
halting the injection and the production upon reaching an upper solvent
concentration threshold in produced fluid.
In some optional implementations, the step of producing fluids from the second
horizontal
well comprises operating so that the produced fluid comprises between about
20% and
about 50% volume of solvent based on the total volume of bitumen and solvent
mixture.
In some optional implementations, the upper solvent concentration threshold is
approximately 50% volume based on the total volume of the bitumen and solvent
mixture.
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In some optional implementations, the solvent is selected to avoid asphaltene
deposition.
In some optional implementations, the solvent containing startup fluid is
formulated to avoid
asphaltene deposition.
In some optional implementations, the solvent containing startup fluid is
injected at a
temperature between an initial reservoir temperature and about 150 C.
In some optional implementations, the solvent containing startup fluid is
injected at a
temperature above 100 C.
In some optional implementations, the solvent containing startup fluid is
injected at a
pressure between about initial reservoir pressure and about 100 kPa below the
fracturing
pressure of the reservoir proximate the injection well.
In some optional implementations, the interwell region is about 3 m to about
10m.
In some optional implementations, the interwell region is about 4 to 7 m.
In some optional implementations, the process includes:
(i) isolating a first horizontal startup interval of the well pair;
(ii) injecting the solvent containing startup fluid into the first well at the
first
horizontal startup interval;
(iii) providing the pressure sink in the second well to promote pressure drive
of the
solvent from the first well toward the second well at the first horizontal
startup
interval, to mobilize bitumen in a first portion of the interwell region;
(iv) establishing fluid communication between the first well and the second
well in
the first portion of the interwell region;
(v) halting solvent injection and production in the first horizontal startup
interval; and
(vi) isolating additional horizontal startup intervals one-by-one and
repeating steps
(ii) to (v) for each of the additional horizontal startup intervals.
In some optional implementations, the isolating is performed using packers.
In some optional implementations, the isolating is performed using at least
one diverter.
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In some optional implementations, the isolating is performed using balls
and/or sliding
sleeves.
In some optional implementations, the injecting of the solvent containing
startup fluid is only
done via the first well.
In some optional implementations, the providing the pressure sink is done only
in the
second well.
In some optional implementations, the first well is a SAGD injection well and
the second
well is a SAGD production well, forming a well pair.
In some optional implementations, the first well is a first step-out well and
the second well is
a second step-out well, both being provided in a recovery zone of the
reservoir in spaced
relation with respect to an adjacent SAGD steam chamber.
In some optional implementations, the first step-out well is further away from
the SAGD
steam chamber than the second step-out well.
In some optional implementations, the first and second step-out wells are
located at
approximately the same depth as each other.
In some optional implementations, the first and second step-out wells are
located at
approximately the same depth as an adjacent SAGD well pair.
In some optional implementations, the first well is a first infill well and
the second well is a
second infill well, both being provided in a residual zone, the residual zone
being defined in
between two flanking SAGD steam chambers.
In some optional implementations, the first and second infill wells are
operated in startup
mode prior to coalescence of the two flanking SAGD steam chambers along the
length of
the first and second infill wells.
In some optional implementations, the process further includes operating a
third infill well in
the residual zone as a solvent injection well or a pressure sink well.
In some optional implementations, there is an in situ bitumen recovery startup
process for a
well in a bitumen containing reservoir, the well being approximately parallel
to one or more
adjacent SAGD steam chambers, the process including:
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selecting a plurality of startup intervals along a length of the well;
for each of the plurality of startup intervals:
isolating the startup interval;
injecting a solvent-containing startup fluid into the startup interval;
wherein
the injected startup fluid penetrates the reservoir and mobilizes bitumen in a
region proximate the interval;
ceasing solvent injection into the startup interval; and
establishing fluid communication with at least one adjacent SAGD chamber;
and
producing bitumen from the well.
In some optional implementations, the process further includes selecting one
or more of the
startup intervals based on a distance from the well within the selected
startup interval to the
one or more adjacent SAGD steam chambers.
In some optional implementations, the process further includes selecting one
or more of the
startup intervals based on a distance based on a temperature of the reservoir
around the
selected startup interval.
In some optional implementations, the well is a step-out well provided in a
recovery zone of
the reservoir in spaced relation with respect to one adjacent SAGD steam
chamber.
In some optional implementations, at least one of the startup intervals is
selected to inject
the solvent-containing startup fluid into a surrounding region that is at
initial reservoir
temperature.
In some optional implementations, at least one of the startup intervals is
selected to inject
the solvent-containing startup fluid into a surrounding region that is colder
than other
intervals of the step-out well.
In some optional implementations, at least one of the startup intervals is
selected to inject
the solvent-containing startup fluid into a surrounding region that is further
away from the
adjacent SAGD steam chamber than other intervals of the step-out well.
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In some optional implementations, the process further includes injecting the
solvent
containing startup fluid through a selected startup interval into a
surrounding region of the
reservoir in a greater amount, for a greater duration and/or at an earlier
injection time,
based on the temperature of the surrounding region and/or a distance from the
well within
the selected startup interval to the adjacent SAGD steam chamber.
In some optional implementations, the injecting of the greater amount, for the
greater
duration and/or at the earlier injection time is performed where the
surrounding region of the
selected startup interval is at initial reservoir temperature and/or is colder
than other
intervals of the well.
In some optional implementations, the injecting of the greater amount, for the
greater
duration and/or at the earlier injection time is performed where the distance
from the well
within the selected startup interval to the adjacent SAGD steam chamber is
greater than
other intervals of the well.
In some optional implementations, the well is an infill well provided in a
residual zone, the
residual zone being defined in between two flanking SAGD steam chambers.
In some optional implementations, at least one of the startup intervals is
selected to inject
the solvent containing startup fluid into a surrounding region that is at
initial reservoir
temperature.
In some optional implementations, at least one of the startup intervals is
selected to inject
the solvent containing startup fluid into a surrounding region that is colder
than other
intervals of the infill well.
In some optional implementations, at least one of the startup intervals is
selected to inject
the solvent containing startup fluid into a surrounding region that is further
away from the
flanking SAGD steam chambers than other intervals of the infill well.
In some optional implementations, the process includes injecting the solvent
containing
startup fluid through a selected startup interval into a surrounding region of
the reservoir in
a greater amount, for a greater duration and/or at an earlier injection time,
based on the
temperature of the surrounding region, a distance from the well within the
selected startup
interval to the flanking SAGD steam chambers, and/or whether the flanking SAGD
steam
chambers have coalesced above the selected startup interval.
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In some optional implementations, the injecting of the greater amount, for the
greater
duration and/or at the earlier injection time is performed where the
surrounding region of the
selected startup interval is at initial reservoir temperature and/or is colder
than other
intervals of the well.
In some optional implementations, the injecting of the greater amount, for the
greater
duration and/or at the earlier injection time is performed where the distance
from the well
within the selected startup interval to the adjacent SAGD steam chamber is
greater than
other intervals of the well.
In some optional implementations, the injecting of the greater amount, for the
greater
duration and/or at the earlier injection time is performed wherein where the
flanking SAGD
steam chambers have not yet coalesced above the selected startup interval.
In some optional implementations, the isolating is performed by packers, by at
least one
diverter, using balls and/or sliding sleeves.
In some optional implementations, the startup intervals are sized to have
lengths in
accordance with well conformance.
In some optional implementations, the startup intervals are sized to have
lengths of at most
about 100 m.
In some optional implementations, the solvent containing startup fluid
contains a solvent
selected from aromatic compounds and alkanes.
In some optional implementations, the solvent in the solvent containing
startup fluid
comprises at least one of toluene, xylene, diesel, butane, pentane, hexane,
heptane and
naphtha.
In some optional implementations, the solvent in the solvent containing
startup fluid
comprises naphtha.
In some optional implementations, the solvent in the solvent containing
startup fluid consists
of naphtha.
In some optional implementations, the solvent containing startup fluid further
comprises
water.
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In some optional implementations, the solvent containing startup fluid is
formulated to avoid
asphaltene deposition.
In some optional implementations, the solvent-containing startup fluid is
injected at a
temperature between the initial reservoir temperature 8 and about 150 C.
In some optional implementations, the solvent-containing startup fluid is
injected at a
temperature above 100 C.
In some optional implementations, the solvent-containing startup fluid is
injected at a
pressure between about initial reservoir pressure and about 100 kPa below the
fracturing
pressure of the reservoir proximate the well.
In some optional implementations, the well is a multilateral well as described
herein.
In some optional implementations, there is an in situ bitumen recovery startup
process for a
well selected from an infill well and a step-out well located adjacent to at
least one SAGD
steam chamber, the process comprising:
injection of a solvent-containing startup fluid into the well, wherein:
the injection is commenced when a surrounding region contiguous
with the well is still unheated by heat from the at least one SAGD
steam chamber;
the injected solvent-containing startup fluid penetrates the
surrounding region and mobilizes bitumen therein, thereby forming a
solvent mobilized zone in the surrounding region; and
the injection is performed to establish fluid communication between
the at least one SAGD steam chamber and the solvent mobilized
zone; and
operating the well in production mode for bitumen recovery.
In some optional implementations, the injection of the solvent-containing
startup fluid is
performed along the entire length of the well.
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In some optional implementations, the injection of the solvent-containing
startup fluid
comprises injecting into at least one isolated section of the well in order to
form the solvent
mobilized zone around the at least one isolated section.
In some optional implementations, the at least one isolated section comprises
a plurality of
isolated sections, and the injection of the solvent-containing startup fluid
comprises injecting
into the plurality of isolated sections of the well in order to form
corresponding solvent
mobilized zones around respective isolated sections.
In some optional implementations, the at least one isolated section of the
well is selected in
order to provide enhanced conformance of production along the well.
In some optional implementations, the at least one isolated section of the
well is selected to
inject the solvent-containing startup fluid into a surrounding first region
that is colder and/or
further away from the at least one adjacent SAGD steam chamber than other
sections of
the well.
In some optional implementations, the well is a multilateral well as described
herein.
In some optional implementations, there is an in situ bitumen recovery startup
process for
an infill well located in a residual zone defined between two flanking SAGD
steam
chambers, the process comprising:
injection of a solvent-containing startup fluid into the well, wherein:
the injection is commenced prior to coalescence of the two flanking
SAGD steam chambers along the length of the infill well;
the injected solvent-containing startup fluid penetrates the reservoir
and mobilizes bitumen therein, thereby forming a solvent mobilized
zone; and
the injection is performed to accelerate advancement of the at least
one flanking SAGD steam chamber toward the infill well through the
solvent diluted zone and establish fluid communication between the
at least one SAGD steam chamber and the solvent mobilized zone;
and
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operating the infill well in production mode for bitumen recovery from the
residual zone.
In some optional implementations, the injection of the solvent-containing
startup fluid is
performed along the entire length of the infill well.
In some optional implementations, the injection of the solvent-containing
startup fluid
comprises injecting into at least one isolated section of the infill well in
order to form the
solvent mobilized zone around the at least one isolated section, wherein the
injection into
the at least one isolated section is commenced prior to coalescence of the two
flanking
SAGD steam chambers along a length corresponding to the at least one isolated
section.
In some optional implementations, the at least one isolated section comprises
a plurality of
isolated sections, and the injection of the solvent-containing startup fluid
comprises injecting
into the plurality of isolated sections of the infill well in order to form
corresponding solvent
mobilized zones around respective isolated sections, wherein the injection
into each of the
isolated sections is commenced prior to coalescence of the two flanking SAGD
steam
chambers along respective lengths corresponding to the isolated sections.
In some optional implementations, the at least one isolated section of the
infill well is
selected in order to provide enhanced conformance of production along the
infill well.
In some optional implementations, the at least one isolated section of the
infill well is further
selected to inject the solvent-containing startup fluid into a surrounding
first region that is
colder and/or further away from the at least one adjacent SAGD steam chamber
than other
sections of the infill well.
In some optional implementations, the infill well is a multilateral well as
described herein. :
In some optional implementations, there is an in situ bitumen recovery startup
process,
comprising:
injecting a solvent-containing startup fluid into a multilateral infill well
to form a
solvent diluted zone, the multilateral infill well being positioned in a
residual zone
defined in between two flanking SAGD steam chambers, the multilateral infill
well
comprising:
a main well extending longitudinally along the residual zone; and
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a plurality of branch side wells in fluid communication with the main well and
each extending from the main well in a lateral direction in the residual zone
toward and terminating in spaced relation with respect to one of the flanking
SAGD steam chambers;
establishing fluid communication between at least one of the flanking SAGD
steam
chambers and the multilateral infill well; and
operating the multilateral infill well in production mode.
In some optional implementations, the branch side wells are only provided in a
region of the
residual zone that is colder and/or further away from the flanking SAGD steam
chambers
than other regions of the residual zone.
In some optional implementations, the branch side wells are only provided at a
toe end of
the main well.
In some optional implementations, the branch side wells are only provided
below non-
coalesced area of the flanking SAGD steam chambers.
In some optional implementations, the branch side wells are provided in
greater number or
greater length in a region of the residual zone that is colder and/or further
away from the
flanking SAGD steam chambers than other regions of the residual zone.
In some optional implementations, the branch side wells are provided in
greater number or
greater length at a toe end of the main well.
In some optional implementations, the branch side wells are provided in
greater number or
greater length in a region below non-coalesced area of the flanking SAGD steam
chambers.
In some optional implementations, the injection of the solvent containing
startup fluid is
performed through the main well and the branch side wells simultaneously.
In some optional implementations, the injection of the solvent containing
startup fluid
comprises injecting into at least one isolated section of the multilateral
infill well in order to
form the solvent mobilized zone around the at least one isolated section.
In some optional implementations, the at least one isolated section comprises
a plurality of
isolated sections, and the injection of the solvent containing startup fluid
comprises injecting
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into the plurality of isolated sections of the multilateral infill well in
order to form
corresponding solvent mobilized zones around respective isolated sections.
In some optional implementations, the at least one isolated section of the
multilateral infill
well is selected in order to provide enhanced conformance of production along
the infill well.
In some optional implementations, the at least one isolated section of the
multilateral infill
well is selected to inject the solvent-containing startup fluid into a
surrounding first region
that is colder and/or further away from the at least one adjacent SAGD steam
chamber than
other sections of the infill well.
In some optional implementations, the at least one isolated section of the
multilateral infill
well comprises one of the branch side well sections.
In some optional implementations, there is an in situ bitumen recovery startup
process for
an in situ system in a bitumen containing reservoir, the in situ system
comprising a well pair
comprising a horizontal injection well and a horizontal production well
located below the
horizontal injection well and separated by an interwell region, the process
comprising:
injecting a solvent-containing startup fluid into the injection well below a
fracturing
pressure of the reservoir proximate the injection well;
providing a pressure sink in the production well to promote pressure drive of
the
solvent from the injection well toward the production well to mobilize bitumen
in the
interwell region; and
establishing fluid communication between the injection well and the production
well.
In some optional implementations, the pressure sink is created by a pump
associated with
the production well for producing fluids therefrom.
In some optional implementations, the solvent-containing startup fluid
contains a solvent
selected from aromatic compounds and alkanes.
In some optional implementations, the solvent in the solvent-containing
startup fluid
comprises at least one of toluene, xylene, diesel, butane, pentane, hexane,
heptane and
naphtha.
In some optional implementations, the solvent in the solvent-containing
startup fluid
comprises naphtha.
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In some optional implementations, the solvent in the solvent containing
startup fluid consists
of naphtha.
In some optional implementations, the solvent containing startup fluid further
comprises
water.
In some optional implementations, the process includes halting the injection
and the
production upon reaching an upper solvent concentration threshold in the
produced fluid.
In some optional implementations, the produced fluid comprises between about
20% and
about 50% volume of solvent based on the total volume of bitumen and solvent
mixture.
In some optional implementations, the upper solvent concentration threshold is
50% volume
based on the total volume of the bitumen and solvent mixture.
In some optional implementations, the solvent is selected to avoid asphaltene
deposition.
In some optional implementations, the solvent containing startup fluid is
formulated to avoid
asphaltene deposition.
In some optional implementations, the solvent containing startup fluid is
injected at a
temperature between the initial reservoir temperature and about 150 C.
In some optional implementations, the solvent containing startup fluid is
injected at a
temperature above 100 C.
In some optional implementations, the solvent containing startup fluid is
injected at a
pressure between about initial reservoir pressure and about 100 kPa below the
fracturing
pressure of the reservoir proximate the injection well.
In some optional implementations, the interwell region is about 3 m to about
10m high. In
some optional implementations, the interwell region is about 4 to 7 m high or
about 5 m
high.
In some optional implementations, the in situ system is a SAGD system.
In some optional implementations, the process includes:
(i) isolating a first horizontal startup interval of the well pair;
(ii) injecting the solvent containing startup fluid into the injection well at
the first horizontal startup interval;
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(iii) providing the pressure sink in the production well to promote
downward pressure drive of the solvent from the injection well toward
the production well at the first horizontal startup interval, to mobilize
bitumen in a first portion of the interwell region;
(iv) establishing fluid communication between the injection well and the
production well in the first portion of the interwell region;
(v) halting solvent injection and production in the first horizontal startup
interval; and
(vi) isolating additional horizontal startup intervals one-by-one and
repeating steps (ii) to (v) for each of the additional horizontal startup
intervals.
In some optional implementations, the isolating is performed using packers,
using at least
one diverter, or using balls and/or sliding sleeves.
In some optional implementations, the injecting of the solvent-containing
startup fluid is only
done via the injection well.
In some optional implementations, the providing the pressure sink is done only
in the
production well.
In some optional implementations, the in situ system comprises a plurality of
the well pairs
arranged in parallel relationship to one another and the process comprises
performing
solvent assisted startup on the plurality of well pairs.
In some optional implementations, three is an in situ bitumen recovery startup
process for
an in situ system in a bitumen containing reservoir, the in situ system
comprising a pair of
wells, a horizontal injection well and a horizontal production well located
above the
horizontal injection well, the wells being separated by an interwell region,
the process
comprising:
injecting a solvent-containing startup fluid into one of the wells below a
fracturing
pressure of the reservoir;
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providing a pressure sink in the other of the wells to promote pressure drive
of the
solvent from the one well toward the other well to mobilize bitumen in the
interwell
region; and
establishing fluid communication between the pair of wells.
In some optional implementations, the one well is the horizontal injection
well and the other
well is the horizontal production well.
In some optional implementations, the pressure sink is created by a pump
associate with
the production well for producing fluids therefrom.
In some optional implementations, the solvent containing startup fluid
contains a solvent
selected from aromatic compounds and alkanes.
In some optional implementations, the solvent in the solvent containing
startup fluid
comprises at least one of toluene, xylene, diesel, butane, pentane, hexane,
heptane and
naphtha.
In some optional implementations, the solvent in the solvent containing
startup fluid
comprises naphtha.
In some optional implementations, the solvent in the solvent containing
startup fluid consists
of naphtha.
In some optional implementations, the solvent containing startup fluid further
comprises
water.
In some optional implementations, the process includes halting the injection
and the
pressure sink upon reaching an upper solvent concentration threshold in the
produced fluid.
In some optional implementations, the produced fluid comprises between about
20% and
about 50% volume of solvent based on the total volume of bitumen and solvent
mixture.
In some optional implementations, the upper solvent concentration threshold is
50% volume
based on the total volume of the bitumen and solvent mixture.
In some optional implementations, the solvent is selected to avoid asphaltene
deposition.
In some optional implementations, the solvent containing startup fluid is
formulated to avoid
asphaltene deposition.
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In some optional implementations, the solvent containing startup fluid is
injected at a
temperature between the initial reservoir temperature 8 and about 150 C.
In some optional implementations, the solvent containing startup fluid is
injected at a
temperature above 100 C.
In some optional implementations, the solvent containing startup fluid is
injected at a
pressure between about initial reservoir pressure and about 100 kPa below the
fracturing
pressure of the reservoir proximate the injection well.
In some optional implementations, the interwell region is about 3 m to about
10m high.
In some optional implementations, the in situ system is a SAGD system.
In some optional implementations, the process includes:
(i) isolating a first horizontal startup interval of the well pair;
(ii) injecting the solvent containing startup fluid into the injection well
at
the first horizontal startup interval;
(iii) providing the pressure sink in the production well to promote
downward pressure drive of the solvent from the injection well toward
the production well at the first horizontal startup interval, to mobilize
bitumen in a first portion of the interwell region;
(iv) establishing fluid communication between the injection well and the
production well in the first portion of the interwell region;
(v) halting solvent injection and production in the first horizontal
startup
interval; and
(vi) isolating additional horizontal startup intervals one-by-
one and
repeating steps (ii) to (v) for each of the additional horizontal startup
intervals.
In some optional implementations, the isolating is performed using packers,
using at least
one diverter, or using balls and / or sliding sleeves.
In some optional implementations, the injecting of the solvent containing
startup fluid is only
done via the one well.
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In some optional implementations, the providing the pressure sink is done only
in the other
well.
In some optional implementations, the in situ system comprises a plurality of
the well pairs
arranged in parallel relationship to one another and the process comprises
performing
solvent assisted startup on the plurality of well pairs.
In some optional implementations, there is an in situ bitumen recovery startup
process for
an in situ system in a bitumen containing reservoir, the in situ system
comprising a pair of
wells, a horizontal injection well and a horizontal production well located
above the
horizontal injection well, the wells being separated by an interwell region,
the process
including:
(i) isolating a first horizontal startup interval of one of the wells;
(ii) injecting a solvent containing startup fluid into the first horizontal
startup interval;
(iii) mobilizing bitumen of the interwell region proximate the first
horizontal startup interval;
(iv) establishing fluid communication between the pair of wells in the
first
horizontal startup interval;
(v) halting solvent injection and production in the first horizontal
startup
interval; and
(vi) isolating additional horizontal startup intervals one-by-one and
repeating steps (ii) to (v) for each of the additional horizontal startup
intervals.
In some optional implementations, steps (ii) to (iv) include:
injecting the solvent containing startup fluid into the one of the wells below
a
fracturing pressure of the reservoir;
providing a pressure sink in the other of the wells to promote pressure drive
of the
solvent from the one well toward the other well to mobilize the bitumen in the
interwell region in the first horizontal startup interval; and
CA 02778135 2012-05-18
19
establishing fluid communication between the pair of wells.
In some optional implementations, the one well is the horizontal injection
well and the other
well is the horizontal production well.
In some optional implementations, the isolating is performed by packers.
In some optional implementations, the isolating is performed by at least one
diverter.
In some optional implementations, the isolating is performed using balls
and/or sliding
sleeves.
In some optional implementations, the horizontal startup intervals are sized
to have lengths
in accordance with well conformance.
In some optional implementations, the horizontal startup intervals are sized
to have lengths
of at most about 100 m.
In some optional implementations, the pressure sink is created by a pump
associate with
the production well for producing fluids therefrom.
In some optional implementations, the solvent containing startup fluid
contains a solvent
selected from aromatic compounds and alkanes.
In some optional implementations, the solvent in the solvent containing
startup fluid
comprises at least one of toluene, xylene, diesel, butane, pentane, hexane,
heptane and
naphtha.
In some optional implementations, the solvent in the solvent containing
startup fluid
comprises naphtha.
In some optional implementations, the solvent in the solvent containing
startup fluid consists
of naphtha.
In some optional implementations, the solvent containing startup fluid further
comprises
water.
In some optional implementations, the process includes halting the injection
and the
production upon reaching an upper solvent concentration threshold in the
produced fluid.
In some optional implementations, the produced fluid comprises between about
20% and
about 50% volume of solvent based on the total volume of bitumen and solvent
mixture.
CA 02778135 2012-05-18
In some optional implementations, the upper solvent concentration threshold is
50% volume
based on the total volume of the bitumen and solvent mixture.
In some optional implementations, the solvent is selected to avoid asphaltene
deposition.
In some optional implementations, the solvent containing startup fluid is
formulated to avoid
asphaltene deposition.
In some optional implementations, the solvent containing startup fluid is
injected at a
temperature between the initial reservoir temperature 8 and about 150 C.
In some optional implementations, the solvent containing startup fluid is
injected at a
temperature above 100 C.
10 In some optional implementations, the solvent containing startup fluid
is injected at a
pressure between about initial reservoir pressure and about 100 kPa below the
fracturing
pressure of the reservoir proximate the injection well.
In some optional implementations, the interwell region is about 3 m to about
10m high.
In some optional implementations, the in situ system is a SAGD system.
In some optional implementations, the injecting of the solvent containing
startup fluid is only
done via the injection well.
In some optional implementations, the providing the pressure sink is done only
in the
production well.
In some optional implementations, the in situ system comprises a plurality of
the well pairs
20 arranged in parallel relationship to one another and the process
comprises performing
solvent assisted startup on the plurality of well pairs.
In some optional implementations, there is an in situ bitumen recovery startup
process for a
well that is an infill well or a step-out well, comprising:
(i) isolating a first horizontal startup interval of the well;
(ii) injecting a solvent containing startup fluid into the first horizontal
startup
interval;
(iii) mobilizing bitumen of a first region proximate the first horizontal
startup
interval;
CA 02778135 2013-04-22
21
(iv) halting solvent injection into the first horizontal startup interval;
and
(v) establishing fluid communication between the well and at least one
adjacent
SAGD operation;
(vi) producing bitumen from the well.
In some optional implementations, there is provided an in situ bitumen
recovery startup
process, comprising:
injecting a startup fluid into a first horizontal well located in a bitumen-
containing
reservoir, where the fluid is injected below a fracturing pressure of the
reservoir
proximate the first horizontal well;
providing a pressure sink in a second horizontal well located adjacent to the
first well
to define an interwell region there-between, to promote pressure drive of the
startup
fluid from the first horizontal well toward the second horizontal well to
mobilize
bitumen in the interwell region; and
establishing fluid communication between the first horizontal well and the
second
horizontal well.
In some optional implementations, there is provided an in situ bitumen
recovery startup
process for a well in a bitumen containing reservoir, the well being
approximately parallel to
one or more adjacent SAGD steam chambers, the process comprising:
selecting a plurality of startup intervals along a length of the well;
for each of the plurality of startup intervals:
isolating the startup interval;
injecting a startup fluid into the startup interval; wherein the injected
startup
fluid penetrates the reservoir and mobilizes bitumen in a region proximate
the interval;
ceasing startup fluid injection into the startup interval; and
establishing fluid communication with at least one adjacent SAGD chamber;
and
producing bitumen from the well.
CA 02778135 2013-09-11
21a
In some optional implementations, there is provided an in situ bitumen
recovery startup
process for a well selected from an infill well and a step-out well located
adjacent to at least
one SAGD steam chamber, the process comprising:
injection of a startup fluid into the well, wherein:
the injection is commenced when a surrounding region contiguous with the
well is still substantially unheated by heat from the at least one SAGD steam
chamber;
the injected startup fluid penetrates the surrounding region and mobilizes
bitumen therein, thereby forming a mobilized zone in the surrounding region;
and
the injection is performed to establish fluid communication between the at
least one SAGD steam chamber and the mobilized zone; and
operating the well in production mode for bitumen recovery.
In some optional implementations, there is provided an in situ bitumen
recovery startup
process for an in situ system in a bitumen containing reservoir, the in situ
system
comprising a pair of wells comprising a horizontal injection well and a
horizontal production
well located below the horizontal injection well, the wells being separated by
an interwell
region, the process comprising:
isolating a first horizontal startup interval of one of the wells;
(ii) injecting a solvent-containing startup fluid into the first horizontal
startup
interval;
(iii) mobilizing bitumen of the interwell region proximate the first
horizontal
startup interval;
(iv) establishing fluid communication between the pair of wells in the
first
horizontal startup interval;
(v) halting solvent injection and production in the first horizontal
startup interval;
and
CA 02778135 2013-09-11
21 b
(vi)
isolating additional horizontal startup intervals one-by-one and repeating
steps (ii) to (v) for each of the additional horizontal startup intervals.
In some optional implementations, there is provided an in situ bitumen
recovery startup
process for an in situ system in a bitumen containing reservoir, the in situ
system
comprising a pair of wells comprising a horizontal injection well and a
horizontal production
well located below the horizontal injection well, the wells being separated by
an interwell
region, the process comprising:
selecting a plurality of startup intervals along a length of the injection
well;
for each of the plurality of startup intervals:
isolating the startup interval;
injecting a startup fluid into the startup interval; wherein the injected
startup
fluid penetrates the reservoir and mobilizes bitumen in a region proximate
the interval;
ceasing startup fluid injection into the startup interval; and
establishing fluid communication between the pair of wells.
Also provided are systems for implementing any one or more of the processes
described
herein.
BRIEF DESCRIPTION OF THE DRAWINGS
Fig 1 is transverse cut view of first and second wells, e.g. a SAGD well pair.
Fig 2 is a side cross-sectional view of a SAGD operation showing one SADG well
pair.
Fig 3 is a transverse cut view schematic of a SAGD operation with infill
wells.
Fig 4 is a transverse cut view schematic of a SAGD operation with infill
wells.
Fig 5 is a transverse cut view schematic of a SAGD operation with step-out
wells.
Fig 6 is a transverse cut view of two well pairs with solvent halo areas.
Fig 7 is a graph of viscosity versus solvent concentration at different
temperatures for
bitumen-naphtha mixtures.
Fig 8 is a side cross-sectional view of an infill or step-out well.
CA 02778135 2013-09-11
21c
Figs 9A to 9C are side cross-sectional view schematics of an infill or step-
out well and part
of a steam chamber.
Figs 10A to 10C are transverse cut view schematics of a SAGD operation with an
infill well.
Figs 11A to 11C are top cross-sectional view schematics of a multilateral
infill well and
flanking SAGD steam chambers.
DETAILED DESCRIPTION
Solvent assisted startup techniques for in situ bitumen recovery are described
below.
Solvent startup with well pairs and pressure sink
In some implementations, referring to Fig 1, an in situ recovery startup
process may utilize a
well pair, including a first well 10 and a second well 12 that are separated
by an interwell
CA 02778135 2012-05-18
22
region 14. The process includes injecting a solvent containing startup fluid
into one of the
wells, for example into the first well 10, below a fracturing pressure of the
reservoir
proximate the first well 10; providing a pressure sink in the other well, for
example the
second well 12, to promote pressure drive of the solvent from the first well
10 toward the
second well 12 to mobilize bitumen in the interwell region 14; and
establishing fluid
communication between the first well 10 and the second well 12.
In one optional scenario, the first well and second well may respectively be
an injection well
and a production well of a SAGD well pair, as illustrated in Fig 2.
In another optional scenario, the first well and second well may be at least a
first infill well 16
and a second infill well 18, as illustrated in Figs 3 and 4. An infill well is
a well that is
positioned in a residual zone that is formed between two chambers, such as
SAGD steam
chambers, flanking either side of the residual zone. It should be noted that
SAGD steam
chambers may be created from steam injection in a SAGD operation and/or SAGD
variant
operations that may inject other fluids such as solvents, gases, and so on.
The residual
zone may have other boundaries such as over-burden and under-burden. The
residual zone
may be formed by flanking SAGD steam chamber areas as well as an overlying
steam
chamber area along at least a part of its length, in regions where the SAGD
steam
chambers have coalesced.
In another optional scenario, the first well 10 and second well may be a first
infill well 20 and
a second infill well 22, as illustrated in Fig 5.
It should be understood that other scenarios and configurations of first and
second wells
may be used.
In one implementation, as illustrated in Fig 2, the startup process is a SAGD
startup process
including the steps of providing an injection well 10 having a vertical
portion 24 and a
horizontal portion 26 extending from its vertical portion and a production
well 12 having a
vertical portion 28 and a horizontal portion 30 extending from its vertical
portion. The
horizontal portion 30 of the production well 12 is downwardly spaced away from
the
horizontal portion 26 of the injection well 10 defining the interwell region
14 in between.
The injection well 10, the production well 12 and the bitumen interval 32 are
also shown in
Fig 1.
CA 02778135 2012-05-18
23
The injection and production wells form a well pair 34 and there may be
multiple well pairs
arranged in parallel to one another in the reservoir. The well pairs 34 are
connected to
above ground equipment on a pad 36.
In one implementation, the solvent assisted SAGD startup process includes
injecting a
solvent containing startup fluid 38 into the injection well 10 and providing a
pressure sink in
the production well 12. The injection of solvent or a mixture of at least one
solvent with water
in the injection well may be performed below the fracturing pressure of the
reservoir. The
injection of the solvent containing startup fluid 38 may be performed at a
pressure between
about initial reservoir pressure, e.g. between 500 and 1000 kPa and about 100
kPa, for
instance at a pressure at least 100 kPa below the fracturing pressure of the
reservoir
proximate the injection which will depend on the depth of the injection well.
The initial
reservoir pressure should be understood to be the pressure of the reservoir
before injection
of the startup fluid and prior to any substantial modification of the pressure
that may be
caused by injection, production or other operations. The solvent injection may
begin at an
initial pressure which may be increased until solvent-bitumen fluid flow
occurs in the
production well or up to at most the fracturing pressure of the reservoir.
This solvent
injection pressure constraint along with the pressure sink of the production
well, promote
downward pressure drive of the solvent from the injection well toward the
production well, to
mobilize the bitumen interval. The process also includes producing fluid from
the production
well using a pump or any other means to lower pressure in the producer.
In another optional implementation, the solvent assisted startup process is
utilized with well
pairs for which the interwell region has a lower amount of bitumen to improve
sweeping of
the solvent through the length or interval of the interwell region.
Referring to Fig 2, a subsurface pump 40 may be provided to provide the
pressure sink in
the production well 12. A drive 42, which may be surface or subsurface, may
also be
provided.
The process includes establishing fluid communication between the injection
well and the
production well.
Referring to Fig 2, the solvent containing startup fluid 38 may be provided
via a solvent
module 44 or a piping configuration for supplying solvent into the injection
well 10. The
CA 02778135 2012-05-18
24
efficiency of the pre-soak process can be improved by creating a pressure sink
in one of the
wells driving the solvent from one well to the other. This process promotes
confinement of
the solvent to the volume between wells estimating that the decrease of the
amount of
solvent needed to approximately 1/4 of the solvent needed in a pre-soak
process.
In addition, the process may also include monitoring of the solvent/bitumen
produced
allowing real-time assessment of the efficiency, corrective actions if
required and direct
evidence of the bitumen free path developed between wells.
Fig 6 illustrates a comparison between solvent soaking into both injection and
production
wells versus solvent injection into one of the wells with a pressure sink in
the other well. Fig
6 is also based on exemplary calculations and estimations as explained
hereafter. For both
cases, the injection and production wells were considered as spaced apart by
d, of 5 m. The
assumed porosity of the interval between the wells was 33% and assumed So was
78%.
The radius Rah of the co-injection case halo was taken as 2.5 m and the
lateral span Sps of
the pressure sink penetration region was taken as 2.5 m. The co-injection case
halo area
Acth was 27t(2.5)2 = 39m2 and the pressure sink case halo area Aps was
n(2.5)(1.25) =
10m2.The minimum volumes needed for an 800m long well are as follows.
For solvent soak:
Bitumen volume = 8,000 m3
20% naphtha content in the mobilized volume= 2,000 m3
50 % naphtha content in the mobilized volume = 8,000 m3
For solvent injection with pressure sink:
Bitumen volume = 2,000 m3
20% naphtha content in the mobilized volume = 500 m3
50 % naphtha content in the mobilized volume = 2,000 m3
In addition, the following is for an extreme case accounting for unoptimized
process and
solvent loses.
For solvent soak:
90 % naphtha content in the mobilized volume = 72,000 m3
CA 02778135 2012-05-18
For solvent injection with pressure sink:
90 % naphtha content in the mobilized volume = 18,000 m3
Solvent assisted startup in SAGD well pair implementations leveraging a
pressure sink may
provide advantages such as efficient use of existing injection and production
equipment for
the respective injection and production wells, alignment of gravity with the
pressure drive
direction from the injection to production well, relatively small interwell
region for SAGD well
pairs, and so on.
In another implementation, as illustrated in Figs 3 and 4, the first and
second wells may be
at least two infill wells, which may be provided in between adjacent SAGD well
pairs.
10 Referring to Fig 3, a first infill well 16 and a second infill well 18
may be provided in adjacent
relation to each other. Various configurations and relative positioning of the
infill wells may
be used. For example, two infill wells may be positioned beside one another to
be at a
generally similar depth and they may also be at a similar depth as the SAGD
well pairs.
Referring to Fig 4, there may be more than two infill wells and the infill
wells may be
arranged in a certain configuration, for example where an upper infill well 46
is located
above and in between two other lower infill wells 48, 50.
Referring back to Fig 3, one of the infill wells, for example infill well 16,
may be used as an
injection well to inject the solvent containing startup fluid into the
surrounding region, while
the other infill well 18 creates a pressure sink, in a similar manner to the
SAGD well pair
20 startup scenario described above. Either one of the two infill wells may
be used as the
injection well. It may be advantageous to select the injection well as the one
located in a
colder region of the reservoir compared to the pressure sink well.
Referring to Fig 4, one of the infill wells, for example infill well 46, may
be used for injection
of the solvent containing startup fluid, while one or more of the other wells
48, 50 are
operated in pressure sink mode to promote pressure drive of the solvent from
the injection
infill well 46 toward the other infill wells to mobilize bitumen in the
interwell region. Two of
the infill wells may also be used as solvent injection wells while the other
infill well is
operated in pressure sink mode. It may be advantageous to only have one infill
well
equipped to inject solvent, to provide efficient use of injection equipment
since all of the infill
wells will likely be put on production mode at some point in time. When three
of more wells
CA 02778135 2012-05-18
26
are used, the infill well that is in between the other two or has the shortest
total distance to
the other two wells may be used as the solvent injection well for efficient
use of solvent. In
the illustrated example, the upper infill well 46 may be the sole solvent
injector well.
Referring to Figs 3 and 4, the adjacent SAGD well pairs 34a, 34b may have been
operated
to form steam chambers 52a, 52b extending upward into the reservoir. The
infill wells may
be started up at various stages of development of the adjacent steam chambers.
For
example, the steam chambers may be separate from each other, as illustrated,
or may have
coalesced prior to solvent assisted startup the infill wells. More regarding
the steam
chambers, temperature distribution in the infill region of the reservoir, and
infill well startup
strategies will be discussed further below.
In another implementation, as illustrated in Fig 5, the first and second wells
may be at least
two step-out wells 20, 22, one of which may be provided adjacent to a SAGD
well pair 34. A
step-out well is a well that is positioned in the reservoir in an adjacent
zone to one SAGD
steam chamber such that the adjacent zone is flanked by the SAGD steam
chamber. A
step-out well is distinguished from an infill well in that there is a SAGD
steam chamber on
only one side of the step-out well when the step-out well is installed and
operated. At a later
stage, once the SAGD steam chamber has developed over a first step-out well,
another
step-out well may be added adjacent to the first step-out well. In this sense,
a step-out well
does not have to be adjacent to a SAGD well pair, but only a steam chamber
that is part of a
gravity drainage operation.
A first step-out well 20 and a second step-out well 22 may be provided in
adjacent relation to
each other. Various configurations and relative positioning of the step-out
wells may be
used. For example, two step-out wells may be positioned beside one another to
be at a
generally similar depth and they may also be at a similar depth as the SAGD
well pairs.
Referring still to Fig 5, one of the step-out wells, for example step-out well
22, may be used
as an injection well to inject the solvent containing startup fluid into the
surrounding region,
while the other step-out well 20 creates a pressure sink, in a similar manner
to the SAGD
well pair or infill well startup scenarios described above. Either one of the
two step-out wells
may be used as the injection well. However, it may be advantageous to select
the injection
well as the step-out well located in a colder region of the reservoir compared
to the pressure
sink well and/or the step-out well located further away from the SAGD steam
chamber 52.
CA 02778135 2012-05-18
27
For example, step-out well 20 may be put on production mode for creating the
pressure sink
and this well may also be more likely to produce mobilized bitumen due to its
proximity to
the steam chamber 52 and greater heat that may be available to reduce the
viscosity of the
bitumen proximate the closer step-out well 20. In addition, by injecting
solvent through the
further step-out well 22, where the surrounding region is colder, the solvent
impact on
viscosity reduction may be enhanced.
Solvent assisted startup in infill or step-out well implementations leveraging
a pressure sink
may provide advantages such as acceleration of startup and eventual bitumen
recovery with
efficient use of solvent.
Solvent assisted startup intervals
In some implementations, an in situ recovery startup process may include
isolating intervals
of a well and utilizing solvent injection into one or more of the isolated
intervals one at a
time. In one optional scenario, the well may be an injection well or a
production well of a
SAGD well pair. For example, the well may be a SAGD injection well as
illustrated in Fig 2.
In another optional scenario, the well may be an infill or step-out well 54,
as illustrated in Fig
8.
In one implementation, as illustrated in Fig 2, the startup process is a SAGD
startup process
including isolating intervals of the injection well 10 and fluidly connecting
these isolated
intervals with the production well 12 one at a time using solvent injection.
The injection well
10 may be divided into several isolated intervals illustrated as isolated
startup intervals 56a,
56b, 56c, 56d and 56e. The solvent injection techniques described above may be
performed
at the isolated intervals one at a time. In this regard, it should be noted
that the formation
rock and bitumen in the interwell region is not homogeneous or constant along
the length of
the in situ well pair, which can have horizontal portions about 1000 m long.
Certain intervals
of the interwell region have higher permeability and other regions have higher
bitumen
content with lower effective permeability to start up fluid. The interval-
based approach
improves the solvent assisted startup performance.
An interval-based approach to the solvent assisted startup process may provide
a number of
advantages. First, the interval-based approach enables adjustability to adapt
solvent
assisted startup conditions and procedures to each interval along the well
pair. This
CA 02778135 2012-05-18
28
adjustability may help adapt to geological and compositional variations of the
interwell
region, for example. Secondly, the interval-based approach helps to ensure
solvent
penetration and solvent assisted fluid communication along the length of the
interwell
region. Due to variations along the length of the interwell region running
from the heel to the
toe of the well pair, solvent injection along the entire length of the
injection well may tend to
have increased penetration at high permeability locations in the interwell
region. Such high
permeability locations may consist of low bitumen pockets or locations with
naturally
occurring higher permeability sand. If the solvent containing startup fluid is
injected along
the entire length of the injection well, it may quickly establish fluid
communication between
the injection and production well at a high permeability location, after which
the injected
solvent may tend to preferentially flow through the interwell region at this
location, which can
prematurely short-circuit the solvent assisted startup process. The interval-
based solvent
startup mitigates this problem by ensuring the solvent is injected into the
interwell region at
multiple intervals along the length of the well pair and thus reducing break
through issues.
Third, the interval-based approach enables reliability with progressive
solvent injection along
the entire length of the well pair.
It should be noted that the breakthrough issue of the solvent injection may
also be
addressed in a number of other ways optionally in combination with the
interval-based
approach. The solvent injection pressure and the production well pressure sink
may be
provided or modulated to promote uniform solvent penetration. Special
injection or
production well completions may be utilized to prevent solvent injection short-
circuiting or to
alleviate it in case break through is prematurely established such as by
blocking off the
portion of the injection well where the breakthrough has occurred and
continuing the solvent
injection in other portions of interwell region.
The isolating of the horizontal startup intervals may be done in a number of
ways. For
example, wellbore isolation methods used in hydraulic fracturing may be
adapted for use in
the present invention. One method uses frac-balls in combination with frac-
ports and sliding
sleeves, the frac-balls being delivered into the injection well to block or
close off portions of
the well. Each ball is smaller than the opening of all of the previous
sleeves, but larger than
the sleeve it is intended to open. Another method uses cup packers to isolate
the horizontal
startup intervals. A further method uses a diverter to block the flow through
the annulus
CA 02778135 2012-05-18
29
between the formation and the exterior surface of the liner which can improve
the efficiency
of the process improving the containment in the selected startup intervals
56a, 56b, 56c,
56d and 56e. It should be noted that any other means may be used to create the
horizontal
startup intervals.
The horizontal startup intervals may be, for example, about 100 m long. The
horizontal
startup intervals may each have identical lengths or may have different
lengths from each
other is desired. Depending on the method used to create the isolated
intervals, the order of
solvent injection and interval activation may be from toe to heel, heel to
toe, or another
order. When a string of packers is used, the order may be from toe to heel of
the injection
well, that is the injection would start at the toe end interval 56e and work
its way toward the
heel end interval 56a of the injection well.
In another optional aspect, the isolation method may be performed in order
that subsequent
isolation intervals to be activated are as far away as possible from the
previously activated
interval. This kind of isolation method may be used in order to reduce the
fluid
communication channels established in one interval from prematurely joining
with the
solvent injection of an adjacent interval and thus further reduce short
circuiting potential. In
such a method, the intervals may be alternately activated at the heel and toe
ends and work
its way toward the middle of the well. The solvent injection, the isolation of
intervals and
establishing pressure sink conditions may be controlled to promote a full
solvent sweep of
each interval. In addition, when activating an isolated interval that is
adjacent to a previously
solvent swept interval, the process may be controlled to avoid or reduce
premature
channeling of the injected solvent to the previously swept adjacent mobilized
zone. In
another optional aspect, each of the horizontal startup intervals is operated
to achieve
solvent sweep and is halted either upon reaching an upper threshold of solvent
concentration in the produced fluid or upon joining or coalescing its solvent
sweep zone with
an adjacent solvent sweep zone.
In another possible aspect, the horizontal startup intervals may be provided
alternating on
the upper and lower wells and the solvent injection and pressure sink may
accordingly be
provided to inject and produce from alternating wells. For instance, a first
interval is isolated
in the upper injection well and the pressure sink is provided in the lower
production well to
achieve fluid communication at the first interval. Next, after sufficient
fluid flushing and the
CA 02778135 2012-05-18
like, the upper well is converted to production mode, the lower well is
converted to injection
mode and a second interval is isolated in the lower well. The solvent
injection process is
performed for the second interval until fluid communication is established in
between the
wells. Subsequent intervals may be provided in alternating wells which may be
converted
back and forth between injection and production modes. Appropriate pump
configurations
for the two wells would be provided and operated to manage this process.
The startup process may then use injection of a solvent containing fluid into
one of the wells,
preferably the injection well 10, below the fracturing pressure of the
reservoir. The process
then preferably includes producing fluid from the producer well 12 with a pump
or any other
10 means to lower pressure in the producer. After a given amount of solvent
27 has been
injected, for example approximately 100 m3 (for about a 100 m interval), and
bitumen
content is low in the production stream 58 as a result of the completion of
the sweep
process, injection and production may be halted. The next step of the process
is to isolate
another horizontal startup interval, which may have the same or different
length as the first
horizontal startup interval, and repeat the injection and production procedure
until no
bitumen is detected in the production stream. The other horizontal startup
intervals are
sequentially isolated and the solvent assisted process is repeated in each of
the horizontal
startup intervals until the full length of the well has been treated. While a
length of about 100
m of the isolated horizontal startup intervals is preferred, they may be
smaller or extended to
20 more than 100 m if conformance is not impacted negatively. In one
aspect, the startup
interval isolation lengths are provided in accordance with conformance of the
well pair and
detected geological features.
Solvent assisted startup in SAGD well pair implementations with an interval
based approach
may provide advantages such as efficient use of existing injection and
production equipment
for the respective injection and production wells, alignment of gravity with
the pressure drive
direction from the injection to production well, relatively small interwell
region for SAGD well
pairs, and so on.
In another implementation, as illustrated in Fig 8, the startup process
includes isolating
intervals of an infill or step-out well 54 one at a time using solvent
injection. The infill or step-
30 out well 54 may be divided into several isolated intervals illustrated
as isolated startup
intervals 60a, 60b, 60c, 60d and 60e. Some of the solvent injection techniques
described
CA 02778135 2012-05-18
31
herein may be performed at the isolated intervals one at a time. In this
regard, it should be
noted that the formation rock and bitumen in the surrounding region may not be
homogeneous or constant along the length of the well 54, which can have
horizontal
portions about 1000 m long. Certain intervals of the surrounding region may
have higher
permeability and other regions have higher bitumen content with lower
effective permeability
to startup fluid. The interval-based approach improves the solvent assisted
startup
performance.
The interval-based startup strategy may also be implemented for the infill or
step-out well 54
so as to startup one or more intervals at certain locations or having initial
temperature
characteristics.
For example, in the case of an infill well located in between two SAGD well
pairs, the steam
chambers of the SAGD well pairs may be at different stages of development
along the
length of the well pairs. It may be that near the heel end of the well pairs,
the steam
chambers have coalesced in an upper part of the reservoir, while at the toe
end of the well
pairs the steam chambers are spaced apart from each other. This uneven
development of
steam chambers may occur to varying degrees at different points along the well
pairs,
depending on various factors.
Figs 9A to 9C are side cross-sectional view schematics of an infill or step-
out well 54
positioned in a reservoir. These Figures illustrate variations in the flanking
steam chamber
along the length of the well 54. In each case, part of a SAGD steam chamber 52
has
developed sufficiently from one or more adjacent SAGD operations to be present
overtop of
the infill or step-out well. In the case of an infill well, two SAGD steam
chambers may have
coalesced overtop of the infill well 54 (e.g. as shown in Fig 10C) in at least
one region along
the length of the infill well 54. In other cases, an upper part of one steam
chamber 52 may
have simply developed overtop of an infill or step-out well 54 in at least one
region along
the length of the well.
Referring to Figs 9A to 90, an infill well 54 may be located in a region of
the reservoir such
that there is a steam chamber 52 that has developed to be closer to certain
locations along
the length of the infill well 54.
CA 02778135 2012-05-18
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Fig 9A illustrates a scenario where part of the steam chamber 52 has developed
over top of
the infill well at interval 56a, for example by coalescing with the adjacent
steam chamber at
that region. However, the toe end of the infill well includes an interval 56b
toward which the
steam chamber has not yet progressed. In such a situation, the solvent
containing startup
fluid may be injected into isolated interval 56b in order to form a solvent
mobilized region
surrounding interval 56b.
Fig 9B illustrates a scenario where two areas of the steam chamber 52 have
developed over
top of the infill well at intervals 56a and 56c, and the solvent containing
startup fluid may be
injected into isolated interval 56b in order to form a solvent mobilized
region surrounding
interval 56b.
Fig 9C illustrates a scenario where part of the steam chamber 52 has developed
over top of
the infill well at interval 56b, and the solvent containing startup fluid may
be injected into
isolated interval 56a and/or 56c in order to form a solvent mobilized region
surrounding
intervals 56a and/or 56c.
By favoring solvent injection into one or more intervals of the infill well
that are colder and/or
are further away from the steam chambers, the overall operation of the infill
well once it is
put on production mode can have improved conformance. Conformance, in this
context, can
be generally viewed as the degree of uniformity in space of the composition,
fluid behaviour
and thermal characteristics of a given recovery zone of the reservoir.
Improved conformance
along the length of an infill well, for example, can be viewed as having
relatively consistent
recovery characteristics along the length of the infill well and can be
achieved by targeting
intervals of the infill well that are colder and/or are further away from the
steam chambers,
as described for various implementations herein.
Thus, solvent assisted startup may be focused on target intervals of the
infill well around
which there is lower heat-enabled mobility, while other intervals of the
infill well that are
proximate to hotter regions of the reservoir require less or no solvent to
facilitate startup. In
addition, by injecting a greater amount of solvent into intervals of the
infill well that are colder
and/or further away from the steam chambers, the infill well can benefit from
both the heat
mobilizing effects of the steam chambers and the solvent mobilizing effects in
the
appropriate intervals, thereby enabling efficient use of solvent and heat.
CA 02778135 2012-05-18
33
For instance, in the case where the heel end of an infill well has substantial
heat due to the
adjacent SAGD steam chambers while the toe end does not, the solvent assisted
startup
may include injecting the solvent containing startup fluid into the toe end of
the infill well
prior to injecting the solvent containing startup fluid into the heel end of
the infill well. Once
the toe end has been pre-treated with solvent, the startup method may continue
by injecting
solvent or another fluid adjacent SAGD operation and the infill may be put on
production
mode. In this case, by favoring solvent injection into the toe end of the
infill well, the overall
infill well startup can be more consistent along the length of the infill well
and the
conformance may be improved for production along the length of the infill
well.
Solvent assisted startup in infill or step-out well implementations with an
interval based
approach may provide advantages such as improved conformance and acceleration
of
startup and eventual bitumen recovery with efficient use of solvent
Solvent assisted startup for infill wells
One or more infill wells may be operated using solvent assisted startup to
enhance the
overall SAGD recovery of bitumen.
In some implementations, referring to Figs 10A to 10C, the infill well 54 is
located in
between two adjacent SAGD well pairs 34a, 34b having two corresponding steam
chambers
52a, 52b. The solvent containing startup fluid is injected into the infill
well 54 and forms a
solvent diluted region 62 surrounding the infill well 54. As illustrated in
Fig 10A, the solvent
fluid may be injected prior to coalescence of the adjacent steam chambers 52a,
52b. The
solvent diluted region 62 may mobilize the region surrounding the infill well
54 at a
temperature around initial reservoir temperature, e.g. 10 C. The initial
reservoir temperature
is the temperature of the reservoir prior to substantial heating of the
reservoir, e.g. by steam
injection or hot fluid circulation through wells, and is typically around 10 C
to 15 C. The
initial reservoir temperature should include where the reservoir may have been
marginally
heated by the drilling and completion operations or other operations that do
not substantially
heat the reservoir. As illustrated in Fig 10B, one or both of the steam
chambers 52a, 52b
may approach and eventually contact the solvent diluted region 62. As the
steam chambers
52a, 52b approach the solvent diluted region 62, the steam chamber advancement
may be
accelerated due to the combined effect of heat and solvent dilution on
viscosity reduction of
the bitumen. The steam chambers 52a, 52b may therefore advance more rapidly
toward
CA 02778135 2012-05-18
34
each other, eventually coalescing as shown in Fig 10C, and also advance
rapidly toward the
infill well 54. The infill well 54 may then be put on production mode.
In some situations, steam chambers of adjacent SAGD well pairs may have
coalesced along
some sections of the well length, but there may be remaining sections where no
coalescence has occurred. In such cases, solvent assisted startup of an infill
well may
promote coalescence to occur in some or all of the remaining non-coalesced
regions,
thereby enabling greater conformance for the infill operations. The solvent
assisted startup
may use an interval-based approach by injecting solvent into intervals above
which there is
little or no coalescence or solvent may be injected into the entire infill
well while ensuring
that at least some solvent is injected below non-coalesced regions.
If the infill well is started up at a later stage when the steam chambers are
relatively close or
have fully developed and coalesced, the benefit of the solvent assisted
startup may be
reduced.
In some implementations, the infill well may be operated with solvent assisted
startup such
that the initial temperature around infill well is at initial reservoir
temperature, e.g. 10 C.
Multilateral infill wells and step-out wells
Referring to Figs 11A to 11C, a multilateral infill well 64 may be positioned
in between two
flanking SAGD steam chambers and started up using one or more of the
techniques
described herein using solvent containing startup fluid. The multilateral
infill well 64 includes
a main well 66 that may extend longitudinally along the residual zone, at a
length
approximately the same as the adjacent SAGD well pairs 34a, 34b. The
multilateral infill well
64 also includes at least one branch side well section 68. The branch side
well sections 68
may be provided in certain locations to enhance the startup, conformance
and/or
performance of the multilateral infill well 64. For example, the branch side
well sections 68
may be located and operated using solvent assisted startup sin accordance with
the heat in
the reservoir and the relative locations of the flanking or overlying steam
chambers 52. The
branch side well section 68 may be provided only in a region of the residual
zone that is
cooler and/or further away from the flanking steam chambers.
CA 02778135 2012-05-18
Fig 11A shows a multilateral infill well 64 with branch side well sections 68
provided in a
wider region of the residual zone, in this case the region that is closer to
the toe end of the
SAGD operation.
Fig 11B shows a multilateral infill well 64 with branch side well sections 68
provided in wider
region of the residual zone and also in a region above which no steam chamber
coalescence has yet occurred.
Fig 11C shows a multilateral infill well 64 with branch side well sections 68
provided in two
wider regions of the residual zone, one near the toe (branch well sections
68a) and the other
near the heel (branch well sections 68b) of the SAGD operation.
10 The branch side well sections 68 may be provided in greater number
and/or greater length
in the wider and/or cooler regions of the residual zone. Solvent containing
startup fluid may
be injected into the entire multilateral infill well 64, including the branch
side well sections
68. Solvent containing startup fluid may be injected into certain intervals or
parts of the
multilateral infill well 64, for example into certain branch side well
sections that are located in
wider and/or cooler regions of the residual zone.
Regarding step-out wells, it should be noted that a similar strategy may be
adopted as is
outlined for infill wells above and illustrated in Figs 11A to 11C, but with
only one adjacent
SAGD steam chamber.
Solvent injection regime
20 The injection regime may be controlled in a number of ways. In one
optional implementation,
the injection regime may be continuous such that the solvent containing
startup fluid is
continuously injected through the injection well. In some scenarios,
continuous injection may
be done until the produced fluid from the production well reaches a solvent
fluid to bitumen
ratio sufficiently high to halt injection and production.
In another optional implementation, the injection regime may be alternating
such that a slug
of the solvent containing startup fluid is injected followed by a slug of
water. The solvent
containing slug may have a volume depending on the given startup interval or
based on
calculations, estimates or field data from the reservoir or field, to provide
an effective
amount of solvent for achieving startup. The water slug may enable improved
efficiency of
30 solvent use, since the hydraulic pressure on the solvent slug injection
is enabled by the
CA 02778135 2012-05-18
36
upstream water slug and thus solvent use is maximized for bitumen
solubilization in the
interwell region rather than merely providing sufficient hydraulics in the
system. The
alternating slug method may also be used by injecting a first pair of solvent
and water slugs
followed by subsequent pairs of solvent and water slugs, each subsequent pair
of slugs
decreasing in volume to continue the startup process while reducing the
possibility of
wasting solvent. In a further optional aspect, the solvent containing fluid
and/or water slugs
may be injected at a constant pressure or varying pressures. The solvent or
slugs may be
injected at progressively increasing or decreasing pressures depending on
various factors
such as the solvent content in the produced fluid. Pressure changes in the
injection can alter
and improve the solvent sweep efficiency, making it possible to sweep more
bitumen from
the interwell region.
In a further optional implementation, the injection and production well
pressurization regime
may be controlled to promote distribution of the solvent across the length of
the horizontal
startup interval or the injection well, as the case may be. More particularly,
the solvent may
be initially injected while the production well has no pressure sink, for a
sufficient time to
allow the solvent to begin penetrating generally across the entire length of
the horizontal
startup interval or the injection well. The production well is then activated
to create the
pressure sink to draw the solvent toward the production well and promote more
uniform
communication between the injection and production well over the length of the
well pair.
Solvent containing startup fluid
The solvent containing startup fluid 38 may contain one or more of a number of
solvents.
Solvent may include aromatic compounds such as toluene or xylene or aromatic
containing
fluids such as diesel and the like. Solvent may include alkanes such as
butane, pentane,
hexane, heptane and the like or a combination of such alkanes. Solvent may be
selected as
an oil sands processing or by-product stream and in accordance with site
availability and
location. In one preferred aspect, solvent includes naphtha which may be
available on site.
Naphtha may be used as diluent in the produced bitumen containing stream and
thus the
naphtha addition may be seen as a diluent pre-treatment. In one optional
aspect, the
amount of naphtha diluent used in the startup process produces a market ready
diluted
bitumen stream, e.g. as "dilbit", thus avoiding further treatment of the
produced bitumen
stream as would normally be required. The solvent containing fluid may contain
for example
CA 02778135 2012-05-18
37
about 50% naphtha and about 50% water. The proportion of the solvent and water
may be
varied and optimized to achieve various results such as efficient solvent
usage and
depending on other operating conditions such as pressure and temperature. In
another
optional aspect, the process includes a step of performing a bitumen-solvent
compatibility
test for each batch of solvent to be used. The solvent is preferably selected
to have no
undesired interaction with bitumen in downhole conditions, such as asphaltene
precipitation
or deposition which could lead to fouling and various problems. The solvent
may be
provided in a concentration in the solvent containing startup fluid sufficent
to minimize
asphaltene deposition, such as a solvent concentration below the asphaltene
precipitation
threshold in the case of alkane solvents.
Based on bitumen and naphtha studies, the process preferably uses naphtha
which does
not show adverse interactions with bitumen and which with a content between
20% and
50% of naphtha in the final bitumen naphtha mixture, which lowers the cold
bitumen
viscosity to a point where it is mobile. Thus, a naphtha content above 20%
allows fluid
mobility. In one aspect, referring to Fig 2, the produced fluid 58 will have
an initial
concentration around 20% naphtha and this concentration will increase over
time as the
startup process continues to mobilize bitumen in the interwell region and
establish fluid
communication. When the produced fluid 58 reaches an upper threshold, such as
50%
naphtha, production is halted. For instance, after a given amount of solvent
has been
injected and bitumen content is low in the produced fluid stream 58 as a
result of completion
of the sweep process, injection and production are halted.
Fig 7 shows viscosity versus solvent concentration at different temperatures
for bitumen-
naphtha mixtures. The naphtha allows a marked viscosity reduction of the
bitumen.
Solvent assisted startup techniques described herein provide faster and more
efficient
solvent assisted startup of SAGD well pairs or infill or step-out wells from
SAGD operations.
Some of the techniques allow pressure differential to drive the solvent and
minimize losses.
Injecting solvent or a mixture of one or more solvents with water in the
injection well and
producing fluid from the production well with a pressure sink drives fluid
from the injection
well to the production well making the process fast and efficient with less
solvent loses.
Solvent lowers the bitumen viscosity while simultaneous injection/production
keeps the
solvent contained in the interwell region and drives solvent diluted bitumen
to the production
CA 02778135 2012-05-18
38
well. Packers or diverter or any other means improves the conformance of the
process
along the horizontal intervals of the well. The elimination of the typical
SAGD wells preheat
lowers the steam to oil ratio (SOR) and allows earlier start-up with the
associated financial
benefit. The solvent assisted SADG startup process allows significant gas
savings due to
faster startup and reduced steam use.
In one example case, the injection well is given a completion including three
down-hole
pressure sensors with real-time surface reading, downhole temperature sensors
with real-
time surface reading, well head flow meter for water, well head flow meter for
bitumen-
naphtha mixture and a spinner log for horizontal wells. The production well is
given a
completion including PCP pump landed as close as possible to the reservoir,
three down-
hole pressure sensors with real-time surface reading, downhole temperature
sensors with
real-time surface reading.
Optional detection steps
In an optional implementation, the startup process includes a preliminary
detection stage for
assessing various features of the reservoir and wells such as cold water
mobility and cold
solvent mobility.
The cold water mobility test may include:
- Starting the producer PCP while keeping constant downhole pressure;
registering pressure in the injection well and adjacent well pairs; when a
pressure
drop is detected at an adjacent well pair or after a given time interval, e.g.
48 hrs,
pumping; and stopping production and wait for pressure recovery.
- Starting the producer PCP while keeping substantially constant downhole
pressure, injecting cold water in the injector at about 50% of the maximum
allowed injection pressure; waiting for pressure and flow stabilization; and
running spinner log in injection well.
The cold solvent mobility test may include:
- Keeping an injection/production ratio below about 0.7; adding solvent to
the
injection stream until 50 % v/vi is reached; waiting for pressure and flow
stabilization; running spinner log in injection well; taking samples of
produced
CA 02778135 2012-05-18
39
bitumen, for instance to determine viscosity and naphtha content; measuring
water cut; when production is stable (water cut), increasing the solvent
content
until 100 % solvent is injected; waiting for pressure and flow stabilization;
and
running spinner log in injection well.
The following is an example procedural overview for implementation of some
scenarios
described herein:
- Conformance control:
o When production is stable (water cut and naphtha content of the
bitumen produced as determined by density measurement in the
field) inject a slug of diverter to control the conformance of the
process.
o Repeat the cold solvent mobility step alternating with diverter slugs
several times, e.g. at least four times.
- Warm water mobility:
o Increase the bottom-hole temperature of the injected water to about
50 C, which will require steam at the well head. Repeat steps with
solvent and diverter.
o Increase the bottom-hole temperature to 100 C. Repeat steps with
solvent and diverter.
- Circulate steam in the injector and the producer with slight pressure
changes to
evaluate communication between wells and start them up in SAGD mode.
In other implementations, the startup process may include a monitoring step
for assessing
the status of the startup process. For example, for first and second wells,
such as a SAGD
well pair, the solvent assisted fluid communication between the wells may be
monitored by
circulating another fluid, such as steam, into the both wells and monitoring
whether the
steam pressure equalize, thereby indicating a fluid connection. In addition,
after one or more
solvent injection cycles, the interwell region may be heated and then cooled
and the
temperature reduction along the interwell region may be monitored to detect
one or more
locations where the solvent was able to significantly penetrate the formation.
CA 02778135 2012-05-18
Various optional aspects of the present invention may help to mitigate
technical challenges
of the SAGD startup process. For instance, the cold water infectivity tests
prior to performing
the process allows adjustments for low injectivity. Driving solvent from one
well to the other
by creating a pressure sink in the producer and actually producing fluids as
well as
maintaining injection/production ratio below 0.7 helps to minimize solvent
loss. Using
diverter or the like to improve conformance along the well can make a
particularly significant
difference especially in early behavior of the wells. Furthermore, performing
and analyzing
compatibility samples and testing to asphaltene deposition can help quickly
evaluate this
potential challenge and solvent selection can be modified, e.g. from an alkane
based solvent
10 to a naphtha-based solvent.
Referring to Fig 2, the surface equipment provided to inject the solvent may
include pumps
and holding tanks along with monitoring equipment to monitor pressure, flow of
solvent, slug
volumes, and the like as the case may be. The surface equipment may include
mixing
means (not illustrated) to mix pure solvent with water to create the solvent
containing startup
fluid 27. The mixing equipment may include static mixers, tee pipe junctions,
to generally
provide sufficient mixing energy to blend the solvent and water. The surface
equipment may
also include tanks 36 for the produced fluid 34 and pumps 38 for supplying the
produced
fluid to desired locations, recycling, solvent removal or downstream
processing as the case
may be. There may be multiple tanks for holding the production fluid 34
produced at
20 different periods of the startup process, e.g. a holding tank for
receiving bitumen-rich
produced fluid, a holding tank for receiving solvent-rich produced fluid and a
holding tank for
receiving produced fluid with a composition suitable to be considered
"dilbit".
In one example, a SAGD well pair was started up with solvent injection. A
naphtha based
solvent was injected through an injection well while the underlying production
well created a
pressure sink. The solvent was injected through two different intervals that
were not
adjacent to each other. Solvent was first injected through a 100 m interval at
the toe end of
the injection well. Solvent was then injected though a 100 m interval spaced
250 m away
from the first toe end interval. Evidence of fluid communication was observed.
When steam
was circulated through the wells, pressure equalization was observed,
indicating that the
30 steam was fluidly communication between the injection and production
wells. Secondly, in
the intervals where solvent injection was performed, longer cooling times were
observed in
CA 02778135 2012-05-18
41
response to reducing the heat injection, indicating that the heat penetration
in these regions
was greater due to solvent assisted mobilization.
In addition, two solvent injection amounts were tested. For one tested
interval, the amount of
solvent injected was at a 1:1 ratio with respect to the estimated bitumen in
the interwell
region for that interval. For another tested interval, the amount of solvent
injected was at a
1:2 ratio with respect to the estimated bitumen in the interwell region for
that interval. This
indicates that lower solvent injection quantities are possible to achieve
similar startup
effects.
In some implementations, the solvent containing startup fluid may be provided
upon
injection at a temperature between the initial reservoir temperature and about
150 C. The
solvent containing startup fluid may be injected at a temperature above 100 C.
The solvent
containing startup fluid may be injected at a temperature around ambient
temperatures,
which may depend on the season, e.g. between 15 C and 25 C.
In some implementations, various techniques described herein may be combined
with other
techniques described herein. For example, multilateral wells may be used with
the interval
approach (by providing isolated intervals in the multilateral well, e.g. such
intervals may be
the whole or part of one or more branch side well sections) and/or the
pressure sink
approach (by providing another well for injection or providing pressure sink
relative to the
multilateral infill well). Another example is that the multilateral well may
be a step-out well
with only one adjacent SAGD steam chamber. Many other examples of inter-
combining one
or more techniques described herein are also possible as should be apparent
from the
present description.
In some other implementations, various solvent assisted startup techniques as
described
may be used with other configurations such as vertical or slanted infill or
step-out wells,
SAGD variants such as solvent-SAGD operations, and/or infill or step-out wells
that are
provided in between or adjacent to steam chambers or mobilized zones other
than SAGD
steam chambers.
Indeed, various other variants, embodiment and aspects may also be used under
the
present invention.
