Note: Descriptions are shown in the official language in which they were submitted.
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SAUD SYSTEM AND METHOD
The present invention relates to recovering hydrocarbon from a reservoir using
steam
assisted gravity drainage (S,kGD).
BACKGROUND
Steam assisted gravity drainage (SAGD) is an enhanced oil technology that is
used for
producing hydrocarbon (typically in the form of heavy crude oil and bitumen)
from an oil
reservoir. It operates using several Nell pairs that are spaced throughout the
reservoir.
Each well pair is formed from a pair of vertically-spaced horizontal wells
that are drilled
through an oil reservoir. Groupings of several well pairs are often drilled
together from a
to drilling pad site, such that each of the well pairs is in the group is
horizontally spaced
from the other well pairs and all of the well pairs from each pad run more or
less parallel
to one another in the reservoir.
To produce bitumen or heavy crude from the reservoir, steam is injected under
high
pressure from the wells of the well pair. First, steam is injected from both
of the wells of
the well pair until fluid communication is established between the top well
and the
bottom well. Once this communication is achieved, steam is injected
predominantly
through the top well (or the injection well). This steam is injected into the
reservoir
where it typically forms a steam chamber extending upwards and outwards from
the -
injection well. The steam in the steam chamber heats hydrocarbon in the
reservoir,
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lowering its viscosity. This heated hydrocarbon with its lowered viscosity can
then drain
downwards (aided by gravity) where it can drain into the lower horizontal well
(the
producer well of the well par) to be produced from the lower horizontal well.
Because there are usually a series of horizontally-spaced well pairs passing
through a
reservoir where hydrocarbon is to be produced, each well pair will form its
own steam
chamber. Each well pair passing through the reservoir typically runs parallel
to one or
more adjacent well pairs. When steam is injected into the reservoir using the
top
injection wells of the each well pair, each well pair will form its own steam
chamber
extending upwards and outwards from the injection well.
This method of producing hydrocarbons (such as heavy crude or bitumen) from a
reservoir using a series of horizontally spaced well pairs assumes that the
reservoir has
relatively uniform conditions, with the flow properties of the reservoir and
the
characteristics of the hydrocarbon being consistent throughout the entire
length and width
of reservoir where the well pairs are placed. or that variations will not
affect the
performance of the wells. However, reservoirs are rarely consistent in the
real world and
these inconsistencies in the conditions of the reservoir and the inability of
the SAGD well
pairs to address these inconsistencies can result in an inefficient producing
of the
hydrocarbon from the reservoir or even result in hydrocarbon that could be
producible
being left in the reservoir,
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Conditions in a reservoir can vary greatly throughout the reservoir For
example,
permeability of a reservoir can vary quite significantly throughout the
reservoir. Over top
of one well pair or even across only a portion of the length of one well nore,
the
permeability of the reservoir may he relatively low causing poor steam
penetration and
therefore poor production of bitumen from this area of the reservoir. However,
because
the steam must be injected under one pressure in each injection well at the
ground surface
there may be little or no way in a conventional SAGD system to take into
account this
region of higher permeability by injecting more steam into this specific
region. This can
result in some of the hydrocarbon remaining unproduced from this lower
permeable
to region of the reservoir or requiring more steam than necessary to be
injected through the
entire reservoir to produce the hydrocarbon from this area of lower
permeability. This is
especially true where the lower permeability occurs over only a portion of a
length of a
well pair with the reservoir having higher permeability conditions along the
other
portions of the length of the well pair, since the steam cannot typically be
injected at.
different rates along a single injection well after the injection well is in
place.
In addition to the possible variability in the permeability of the reservoir
in different
areas, a number of other factors can affect the effectiveness of a
conventional SAGD
system. Changes in water saturation heterogeneity and characteristics can vary
over the
reservoir causing uneven production of bitumen from a SAGD system. Viscosity
of the
bitumen itself can vary over the reservoir, with some of the bitumen in the
reservoir
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having a higher viscosity in certain areas than in others. All of these
variations in the
conditions of the reservoir can be hard if not impossible to address using
horizontally
spaced well pairs, alone.
DESCRIPTION OF THE DRAWINGS
A preferred embodiment of the present invention is described below with
reference to the
accompanying drawings, in which:
FIG. 1 is a schematic of a SAGD well pair;
FIG. 2 is a schematic illustration of a steam plume formed using an injection
well;
FIG. 3 is a schematic illustration of steam plumes formed using a pair of
adjacent
well pairs;
FIG. 4 is a schematic illustration of a SAGD well pair with supplemental
injection
wells;
FIG. 5 illustrates the startup of steam injection of the SAGD system shown in
FIG. 4;
is FIG. 6
illustrates the growth of the steam chamber of the SAGD system shown in
FIG. 4;
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FIG. 7 illustrates a mature steam chamber formed using only the injection well
of
the SAGD system shown in FIG. 4;
FIG. 8 illustrates a steam chamber when steam is injected into it using
supplemental injection wells of the SAGD system shown in FIG. 4;
FIGS. 9-10 illustrates the steam chamber in FIG. 8 as steam continues to be
injected into the steam chamber using the supplemental injection wells;
FIG. 11 illustrates a well field having a number of well pairs and a number of
supplement injection wells where each supplemental injection well intersects
with
only a single well pair;
FIG. 12 illustrates a long well pair with supplemental injection wells; and
FIGS. 13-18 illustrates the steam chamber in FIG. 12 as steam continues to be
injected into the steam chamber using the supplemental injection wells; and
FIG. 19 illustrates a schematic side view of a well pair with a low placed
supplemental injection well.
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DETAILED DESCRIPTION OF THE ILLUSTRATED EMBODIMENTS
Referring to FIG. I, a conventional SAGO well pair 10 is shown in a reservoir
50. The
reservoir 50 can be provided below a ground surface 55 and contain hydrocarbon
such as
heavy crude or bitumen that cannot be produced using the same methods used for
conventional oil. The SAGD well pair 10 is provided passing substantially
horizontally
through the reservoir 10, typically below the majority of the hydrocarbon in
the reservoir
50.
The SAGD well pair 10 is made up of an injection well 20 and a producing well
30. The
injection well 20 is provided vertically spaced above the producing well 30.
Steam is
injected into the reservoir 50 from the injection well 20 and hydrocarbon that
has drained
downwards after being heated by the steam collects in and is produced from the
producer
well 30.
The injection well 20 and the producing well 30 each start from the ground
surface 60
where they initially run substantially vertically until a heel 22, 32. From
the heel 22, 32
IS both the injection well 20 and the producing well 30 run substantially
horizontal through
the reservoir 50 until a toe 24, 34 of each well 20, 30.
FIG. 2 illustrates a steam chamber 60 formed using the injection well 20 of
the well pair
10. Initially, steam is injected through both the injection well 20 and the
producer well
30 until steam places the wells 20, 30 in fluid communication, at which time,
steam is
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predominantly injected through the injection well 20. The steam chamber 60
originates
at the injection well 20 and as the steam rises from the injection well 20 it
will spread
outwards forming an inverted cone shape when viewed along the direction of the
horizontal wells 20, 30. Hydrocarbon in the reservoir that is located in the
steam
chamber 60 is heated by steam and, with the viscosity of this hydrocarbon
sufficiently
lowered, begins to drain towards the producer well 30.
The steam chamber 60 forms a theoretical drainage zone 65 from which
hydrocarbon can
be produced by the well pair 10. This drainage zone 60 can be visualized as a
rectangle
in FIG. 2 or a long box shaped pattern along the length of a well pair 10. The
drainage
i0 zone 65 will be the section of the reservoir 10 that the well pair 10
affects.
Typically, a series of horizontally spaced well pairs 10 are used to produce
hydrocarbon
from the reservoir. The well pairs 10 are spaced apart horizontally with each
well pair 10
running substantially parallel to adjacent well pairs 10. FIG. 3 illustrates a
two (2)
adjacent well pairs 10A, 10B. Each well pair 10A, 10B is shown in the
direction the well
pair 10A, 10B is running.
Steam chambers 60A, 60B are formed using the injection wells 20A. 20B of each
well
pair IOA, 10B. Each steam chamber 60A, 60B rises upwards and outwards from the
injection well 20A, 20B that is creating the steam chamber 60A, 60B. If the
well pairs
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10A, 10B are positioned properly from one another, the steams chambers 60A,
608 will
mingle as they rise upwards.
The drainage zones 65A, 658 of each well pair 10A, 10B will lie adjacent to
one
another. but each steam chamber 60A, 60B should be contained within a single
drainage
zone 65A, 658. With the first steam chamber 65A created by the first well pair
10A
enclosed with the first drainage zone 65A and the second steam chamber 658
created by
the second well pair 1.0B enclosed within the second drainage zone 65B.
FIG. 4 illustrates the well pair 10 provided in the reservoir 50 where
supplemental
injection wells 70A, 70B have been provided. With the well pair 10 in place
and the
injection well 20 positioned vertically above and parallel to the producer
well 30,
supplemental injection wells 70A, 70B can be provided. These supplemental
injection
wells 70A, 70B can be substantially horizontal and run at an angle to the well
pair 10. In
one aspect, the supplemental injection wells 70A, 70B can pass substantially
perpendicularly to the well pair 10. The supplemental injection wells 70A,
7013 can pass
between the injection well 20 and the producer well 30 so that, where the
supplemental
injection wells 70A, 70B intersects with the well pair 1.0, the supplement
injection wells
70A, 70B are below the injection well 20 but above the producer well 30.
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Although FIG. 4 illustrates two (2) supplemental injection wells 70A, 70B, any
practical/desirable number of supplemental injection wells can he provided
related to the
well pair 10.
In one aspect, the supplemental injections wells 70A, 70B can be positioned so
that they
pass much closer to the producer well 30 than the injection well 20 of the
well pair 10.
There is no requirement for the supplemental injection wells 70A, 70B to be of
the same
length. In some cases, it may be desirable for the supplemental injection
wells 70A, 70B
to be of different lengths. This allows for applications with odd-shaped
portions of the
development area as dictated by the geology of the reservoir and can eliminate
the need
to avoid portions of the potential developmental area where the pay thickness
for
example is either generally less than the optimum or odd-shaped portions of
the oil
formation.
Referring to Fig. 19, in one aspect a supplemental injection well 270 can be
positioned so
that it runs in approximately the same horizontal plane as a. producer well
230 of a well
pair 210. Where the supplemental injection well 270 intersects the producer
well 230, the
supplemental injection well 270 can be routed to run over top of the producer
well 230
before once again being routed to run in a plane substantially parallel to the
producer well
230. Therefore, a portion of the length of the supplemental injection well 270
will be
positioned in substantially the same plane as the producer well 230 except for
where the
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supplemental injection well 270 passes over the producer well 230. In this
manner, the
supplemental injection 270 well can be placed much closer to the producer well
230 than
the injection well 220 of the well pair 210.
With the supplement injection wells 70A, 70B in place, a steam chamber can be
generated in the reservoir 50 to heat the hydrocarbon and cause it to drain
towards the
producer well 30. The steam chamber can be formed in one of two ways: by first
creating a conventional steam chamber and then adding steam using the
supplemental
injection wells 70A, 70B; or by injecting steam into the reservoir 50 through
the injection
well 20 and the supplemental injection wells 70A, 708, simultaneously.
in in a first method, the injection well 20 of the well pair 10 can be
first used to create a
conventional steam chamber and then the supplemental injection wells 70A, 708
can he
used to inject additional steam into the steam chamber altering the shape and
heat of the
steam chamber. Referring to FIG. 5, steam can be injected into the reservoir
using the
injection well 20 of the well pair 10 after steam has been injected through
both to
injection well 20 and the producer well 30 to place the injection well 30 and
producer
well 20 in fluid communication. At this point, no steam is injected into the
reservoir 50
using the supplemental injection wells 70A, 708. In this manner, a steam
chamber 100
begins to form having the configuration of a steam chamber that is created
using a well
pair 10 alone.
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As steam continues to be injected into the reservoir 50 using only the
injection well 20 of
the well pair 10, the steam chamber 10 will continue to grow in size in the
reservoir 50 as
shown in Fig. 6. Eventually, the steam chamber 100 will reach it mature size
as shown in
FIG. 7. At this point, the steam chamber 100 should resemble the steam chamber
formed
by a SAGD well pair alone since only the injection well 20 has been used to
inject steam
into the reservoir 50 and no steam has been injected into the reservoir by the
supplemental injection wells 70A, 70B.
With the steam chamber 100 reaching maturity for a conventional SAGD well pair
10 as
shown in FIG. 7, additional steam can then be injected into the existing steam
chamber
100 using the supplemental injection wells 70A, 70B. FIG. 8 illustrates the
changes in
the steam chamber 100 as a result of steam starting to be injected into the
reservoir 50
using the supplemental injection wells 70A, 70B. Eventually, as steam
continues to be
injected into the reservoir 100 by the supplemental injection wells 70A, 70B
the shape of
the steam chamber 100 can be altered as shown in FIGS. 9 and 10.
IS In a different method, the steam chamber can be formed by injecting
steam into the
reservoir 50 using the injection well 20 of the well pair 10 and the
supplemental injection
wells 70A, 70B, simultaneously. In this manner, the operator of the steam
injection can
have much greater control over the injection of steam into the reservoir
including during
the growth of the steam chamber or during recovery of the hydrocarbon.
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In some applications it may be possible to initiate communication between the
primary
well pair 10 while no fluid injection occurs into the supplemental injection
wells 70A,
70B. This communication can be monitored with measurement tools from within
the
supplemental injection wells 70A, 70B because the supplemental injection wells
70A,
70B are open to the main steam chamber. One can then decrease fluid injection
into the
injector well 20 while commencing injection through the supplemental injection
wells
70A, 708 to activate additional steam chambers along these locations. This
sequence can
be repeated as many times as desired and used to control steam chamber growth
in
multiple dimensions and locations along the well pair 10. By evaluating
different
combinations of operating sequences, an operator can determine the most rapid
and
effective steam chamber growth pattern that provides the best strategy as
determined
from performance parameters.
FIGS, 4-10 illustrate the steam chamber 100 when there are two supplemental
injection
Wells 70A, 70B positioned as shown in the figures. However, by varying the
position and
Is number of supplemental injection wells, the steam chamber can be altered
providing the
ability to tailor the eventual steam chamber as desired based on the
characteristics of the
reservoir. In this manner, supplemental injection wells can be provided along
the well
pair where it is desired to inject more steam into the reservoir. This can be
done to
account for conditions that occur in specific regions of the reservoir to help
address these
conditions.
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Referring again to FIG. 2, the use of the supplemental injection wells 70A,
70B can be
used to increase the size of the steam chamber 100 in the theoretical drainage
zone 65
surrounding each well pair 10. Rather than simply have a roughly cone shaped
steam
chamber 60 (as shown in FIG. 2), the injection wells 70A, 708 can be used to
increase
the volume of the steam in the drainage zone 65, better filling the boundaries
of the
drainage zone 65 and allowing more hydrocarbon to be recovered from the
drainage zone
65 associated with a well pair 10. It can also increase the temperature of the
steam in the
steam chamber around the boundary of the steam chamber.
Additionally, the use of the supplemental injection wells 70A, 70B can improve
a
to reservoirs steam/oil ratio. Hydrocarbon reservoirs are evaluated based
on a steam/oil
ratio to determine how viable a reservoir is for SAGD hydrocarbon recovery.
The
amount of steam required to recover hydrocarbon in a reservoir is used to
determine this
steam/oil ratio. The lower the ratio the potentially more profitable the
reservoir is for a
SAGD site. Needing more steam to recover the hydrocarbon in a reservoir, such
as in
cases where the permeability of the reservoir is relatively low or the
hydrocarbon is
relatively viscous, causes this ratio to increase. The supplemental injection
wells 70A,
708 can inject steam into the reservoir at specific locations. This can reduce
the amount
of steam needed overall for the reservoir. With a conventional SAGD well pair
alone,
steam can only be injected through the injection well requiring additional
steam to have
to injected along the entire length of the well pair, even if it is only
required at very
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specific locations along the well pair. By using one more supplemental
injection wells
70A, 70B, steam can be directed where it is required in the reservoir,
allowing a
relatively normal amount of steam to be injected through the injection well of
the well
pair. The supplemental injection wells 70A, 70B can also lower this steam/oil
ratio by
increasing the amount of hydrocarbon recovered with a well pair in certain
circumstances. By using the supplemental injection wells 70A, 70B to increase
steam in
specific locations along the well pair, more hydrocarbon could be recovered
from these
areas than normally would be. This can allow the same amount of steam (or
slightly
more) than what would normally be used to recover more hydrocarbon, thereby
increasing the amount of oil recovered and reducing the steam/oil ratio for a
reservoir.
The supplemental injection wells 70A, 70B can also be used when the reservoir
is
relatively short and the well pair 10 is relatively close to the ground
surface or a low
saturation zone (thief zone) lies relatively close above the well pair 10.
Injecting the
steam through the injector well 20 into the reservoir at too high a pressure
can result in
is the steam reaching the ground surface or low saturation zone. When it
reaches this point,
the steam will tend to travel upwards in the reservoir to the ground surface
or the low
saturation zone rather than spreading out. This can cause the steam to be
narrower than it
ideally should. However by using the supplemental injection wells 70A, 70B,
steam can
be injected through both the injection well 20 and the supplemental injection
wells 70A,
70B at lower pressure but at a similar volume than it would be through just
the injection
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well 20 alone. This lower pressure of the steam in the reservoir can delay the
time it
takes for the steam to reach the ground surface of the low saturation zone,
causing the
steam to spread out and the steam chamber to be wider than it would if higher
pressure
steam was injected through the injector well 20 alone.
In addition to the supplemental injection wells 70A, 70B improving the steam
chamber
that is formed by the well pair 10, injecting steam into the reservoir using
the
supplemental injection wells 70A, 70B can cause micro-steam chambers or steam
chamberlets to form. These steam chamberlets can form from the intersection of
the
primary steam chamber along the main well-pair 10 and steam chamber formed
alone the
to supplemental injection wells 70A, 70B. These steam chamberlets can be
very dynamic.
Once formed, these steam chamberlets can be manipulated by the injection of
different -
ratios of steam and other injectants through the supplemental injection wells
70A, 70B
and can be made to grow independently to contact new bitumen, adapt to the
geological
characteristics of the reservoir in the affected location, and effect
mobilization and
recovery in areas previously untouched by the primary steam chamber.
Although FIGS. 4-10 show a single well pair 10 used with the supplemental
injection
wells 70A, 70B, the reservoir would usually have a number of horizontally
spaced and
substantially parallel well pairs (not shown). Each supplemental injection
well 70A, 70B
would then run substantially perpendicular and between the injection well and
the
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producer well of each of the well pairs. In this manner, each supplemental
injection well
70A, 708 would add steam to the steam chamber formed by each well pair.
Although steam is described as being the principal injectant for the injector
wells 20 and
the supplemental injections wells 70A, 70B, other fluids could be injected in
addition to
the steam. These could include an appropriate combination of: steam: non-
condensible
gases such as methane, nitrogen, etc.; petroleum solvents such as propane,
butane, etc.;
and flue products of combustion including CO2. The use of these fluids in
addition to the
steam allows the operator to achieve volumetric conformance, transport the
steam away
from the interior parts of the chamber to affect unrecovered oil as well as
solvents to
to increase steani chamber size by mobilization by solvent extraction and
effect greater oil
recovery. These approaches help to further reduce the steam-oil ratio.
The volume/combination of injectants into each supplemental injection well
70A, 70B
can be adjusted in relation to its location and reservoir attributes.
The flexibility provided by the supplemental injection wells 70A. '70B
(compared to the
conventional SAGD well pair 10) allows for sequencing of injection of
combinations of
steam, solvents, condensable and non-condensible gases as may be desired or
determined
from simulation to the extent that they are useful for growing the steam
chamber both
along the primary well pair 10 and also along the trajectories of the
supplemental
injecting wells 70A, 70B. Different sequencing of injection into the main
injector well
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20 as well as the supplemental injection wells 70A, 70B will produce different
steam
chamber growth patterns. Such manipulation may be necessary for example to
slow
down the vertical growth of the steam chamber along the well-pair 10 and
increase lateral
growth along the supplemental injection wells 70A, 70B and increase the
recovery factor.
FIG. 11 illustrates a field of well pairs 110 where a number of supplemental
injection
wells 170 are provided. Well pairs 110, each having an injection well 120 and
a producer
well 130, are positioned running horizontally. The well pairs 110 are spaced
apart and
run substantially parallel to one another.
A number of supplemental injection wells 170 can be provided. However, rather
than
w each supplemental injection well 170 mining substantially perpendicular
to all of the
well pairs 110, each supplemental injection well 170 can be substantially
perpendicular
and pass below the injection well 120 and above the producer well 130 of only
a single
well pair 110. In this manner, the supplemental injection wells 170 can be
used to
increase the steam at a target point at a single point alone only a single
well pair 110
rather than all of the well pairs 110.
The supplemental injection wells can be drilled at the same time the well
pairs are drilled.
However, in many cases it will be beneficial to determine how effectively the
horizontally-spaced substantially parallel well pairs are able to produce from
a reservoir.
After it is has been determined how effective the well pairs alone may be in
the reservoir,
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supplemental injection wells can be provided in locations in the reservoir
that require
increased steam for increased hydrocarbon recovery from these areas of the
reservoir.
In one aspect, the supplemental injection wells can constructed by first
drilling a vertical
well through the reservoir. Then after the vertical well is drilled, running a
horizontal
lateral off of the vertical well. In this manner, the vertical well can be
logged to
determine the vertical characteristics of the reservoir where the vertical
well portion of
the supplemental injection well is drilled.
In one aspect, the locations of the supplemental injection wells can be
determined using
data obtained from the drilling of the well pairs. First, the well pairs 1.0
can be drilled
through the reservoir 50 so that the well pairs 10 are substantially parallel
and of
substantially equal length as is typically done in conventional SAGD practice.
Geological logs can be obtained from drilling the well pairs 10 and these
geological logs
reviewed to determine any abnormalities in the reservoir 50, shale intervals
and any other
features in the reservoir that may restrain the flow of steam and/or
hydrocarbon and result
in a lower recovery of hydrocarbon from reservoir 50.
Using the results of the analysis of the geological logs, target points along
the well pairs
10 can be identified. These target points can be chosen to try and address any
geological
features observed along the well pairs 10 as well as for geometric balance
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Since the placement of the supplemental injectors is designed to achieve
specific process
objectives including lowering the steam-oil ratio compared to a standard SAGD
well-
pair, as well as providing operation control and flexibility in steam
placement and
management to achieve these performance objectives as well as address specific
reservoir
and geological features not possible with conventional well-pair. These
factors therefore
have an overarching influence in the number and location of the target points
determined
for placement of supplemental injection wells. For geometrical balance the
separation of
the supplemental injecting wells at both entrance and end of the horizontal
well pairs
should be such as to ensure maximum effectiveness in achieving coverage of the
entire
to well pattern at both ends of the well pair.
In cases where the placement of the supplemental injection wells is well-pair
centric
therefore it may be desirable in certain circumstances to place fewer
supplemental
injection wells along one or more well-pairs than the others in a pad of
several well-pairs,
depending on the extent the supplemental injections wells is required to
address
production performance objectives.
Furthermore, the supplemental injection wells provide access to reservoir not
easily
accessible with the conventional well-pair, the greater the number the more
reserves are
contacted, and the greater the ability to distribute the injected steam,
further reducing the
steam-oil ratio of the well-pair, increasing the recovery factor, accelerating
the recovery
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process. The appropriate number of supplemental injection wells can be
established
through numerical simulation.
At each selected target point along the well pairs 10 a supplement injection
well 70 can
be drilled.
In addition to or alternatively to the geological well profiles of the well
pairs, the target
points along the well pairs could be determined by from the analysis of
numerical
simulation results to try and optimize the locations of the supplemental
injection wells.
It is common practice to use commercially available numerical reservoir
simulation
software to establish the prospectivity of a SAGE. operation in any particular
reservoir,
lo especially when the first application of the process is contemplated.
The reservoir and
fluid properties characteristic of the target formation obtained from cores
and well logs
are used to populate a reservoir model for use in numerical simulation of a
life-time of
SAGE) operation to predict the performance of a SAGD well-pair. The result of
such
simulation often include process performance parameters such as oil rates,
recovery
factor, steam-oil ratio, cumulative production over the time of operation.
Numerical
simulation will be even more critical with the addition of supplemental
injection wells,
firstly to determine the number of supplemental injection wells needed along a
well-pair
in order to achieve the desired performance objectives. A more refined series
of
simulation will be required after the well-pair is drilled and an improved set
of reservoir
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properties have been gathered and such model run is then used modify or
improve the
positioning of the target points where supplemental injection wells will be
provided.
With the drilling of the supplemental injection wells, additional sets of
geologic and
reservoir data will be available providing more detail and more specific to
each
supplemental injection well location. All the accumulated data is then fed
into the
numerical model to improve the performance prediction and develop improved
developmental and operating strategies. Where such model runs are often not
repeated
with subsequent extension to new pads in application of conventional SGAD, the
uniqueness of each well-pair and the opportunity for improved performance
dictates the
benefit of on-going integration of numerical modelling with the field
production
operation of the well-pair.
Referring again to FIG. 4, the supplemental injection wells 70A, 70B can be
used right
after a field of well pairs 10 is drilled or the supplemental injection wells
70A, 70B can
be drilled long after the well pairs 10 have already been used. to recover
some of the
hydrocarbon from a reservoir. Rather than designing a new field and installing
the
supplemental injection wells before the reservoir in the field is first
produced, the
supplemental injection wells 70A, 70B can be used to increase the productivity
of an
existing field of well pairs 10 or could be used with a reservoir where
production has
been ended to go back in and produce hydrocarbon that was not recovered from
the
reservoir using the well pairs alone. After a reservoir has already been
produced using
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well pairs 10 alone, supplemental injection wells 70A, 70B can be then drilled
and the
well pairs 10 and the supplemental injection wells 70A, 70B used to try and
obtain
additional hydrocarbon from the reservoir with the supplemental injection
wells 70A,
70B being placed to try increase the steam in certain portions of the
reservoir were
hydrocarbon was under produced previously. This allows the supplemental
injection
wells 70A, 70B to be backwards compatible with existing well pair 10 fields.
By first drilling vertical wells and the forming the supplemental injection
wells 70A, 70B
as horizontal laterals from these vertical wells, these vertical wells can be
logged to
provide useful information for the current state of the reservoir and the
concentration of
to remaining hydrocarbon. =
In one aspect, if the supplemental injection wells 70A, 70B are being used to
retrofit and
existing field of well pairs 10. The supplemental injection wells 70A, 70B can
be placed
as close as possible to the producer well 30 of the well pair 10. In this
manner, steam
injected into the reservoir 50 from the supplemental injection well 70A, 70B
can cross
the steam chamber at its narrowest point. Because the reservoir has already
been
produced using the well pair 10. The space within the previous steam chamber
will have
much of the hydrocarbon recovered from it and will therefore be highly
permeable. This
area will cause steam to be more easily injected into the reservoir in this
zone of higher
permeability losing potential steam that could be used to expand beyond the
zone where
the previous steam chamber was formed. By running the supplement injection
wells
CA 02777120 2012-05-17
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70A, 70B through the old steam chamber at a narrower spot, less steam should
be
released into the old steam chamber.
In addition to injection of additional steam into the reservoir, the
supplemental injection
wells 70A, 70B can be equipped with pressure and temperature monitoring
devices. This
can allow the supplemental injection wells 70A, 70B to serve a useful role in
the
development of an extensive monitoring program through different stages of the
recovery
operation. Measurements recorded could include progressive heating at
different
locations along the well pair 10 as well as steam chamber development along
the
supplemental injection wells 70A, 70B. Pressure monitoring devices could be
installed to
to determine operating pressures of the supplemental injection wells 70A,
70B. Pressure
monitoring can be especially useful where there is a requirement to control
peak steam
chamber pressures in a reservoir because too high a pressure can comprise the
stability of
the cap rock.
FIG. 12 illustrates a relatively long well pair 210 with supplement injection
wells 270
35 being provided along the length of the well pair 210. In relatively long
well pairs 210,
such as 500-1500 meters or longer, the steam being injected by the injection
well 220 can
vary significantly over the length of the well pair 210. Steam injected into
the reservoir
250 near the heel 212, of the well pair 210 can be of a better quality than
the steam
injected near the toe 214 of the well pair 210 because the steam being
injected near the
20 toe 214 must travel the entire length of the injection well 220 of the
well pair 210.
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By drilling a number of supplemental injection wells 270 the quality of steam
along the
entire length of the well pair 210 can be improved in addition to allowing the
amount of
steam being injected in certain places along the well pair 210 to be improved.
The supplemental injection wells 270 can alter the steam chambers formed by
the more
conventional well pair 210. Referring to FIG. 13, steam can be injected into
the reservoir
using the injection well 230 of the well pair 210. At this point, no steam is
injected into
the reservoir 250 using the supplemental injection wells 270. In this manner,
a steam
chamber 200 begins to form having the configuration of a steam chamber that is
created
using a well pair 210 alone.
As steam continues to be injected into the reservoir 250 using only the
injection well 230
of the well pair 210, the steam chamber 210 will continue to grow in size in
the reservoir
250 as shown in Fig. 14. Eventually, the steam chamber 200 will reach it
mature size as
shown in FIG. 15. With the steam chamber 200 reaching maturity for a
conventional
SAGD well pair 210 as shown in FIG. 15, additional steam can be injected into
the steam
chamber 200 using the supplemental injection wells 270 as shown in FIG. 16.
FIG.
17illustrates the changes in the steam chamber 200 as a result of steam
starting to be
injected into the reservoir 250 using the supplemental injection wells 270.
Eventually, as
steam continues to be injected into the reservoir 200 by the supplemental
injection wells
270 the shape of the steam chamber 200 can be altered as shown in FIGS. 18.
CA 02777120 2012-05-17
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The foregoing is considered as illustrative only of the principles of the
invention.
Further, since numerous changes and modifications will readily occur to those
skilled in
the art, it is not desired to limit the invention to the exact construction
and operation
shown and described, and accordingly, all such suitable changes or
modifications in
structure or operation which may be resorted to are intended to fall within
the scope of
the claimed invention.
