Note: Descriptions are shown in the official language in which they were submitted.
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Title: METHOD FOR SOLVENT RECOVERY FROM GRAVITY
DRAINAGE CHAMBER FORMED BY SOLVENT-BASED
EXTRACTION AND APPARATUS TO DO THE SAME
FIELD OF THE INVENTION
This invention relates generally to the field of hydrocarbon
extraction and more particularly to in situ hydrocarbon extraction using
solvents. Most particularly, this invention relates to solvent based gravity
drainage processes and to the recovery of solvent remaining in situ at the
end of the primary recovery process.
BACKGROUND OF THE INVENTION
Gravity drainage is a known technique for the in situ extraction of
hydrocarbons. At present, it is mainly performed by injection of steam into
the hydrocarbon bearing formation; however, gravity drainage by injection
of solvent vapour has also been demonstrated using the nsolv
technology. In a gravity drainage extraction process, the steam or solvent
vapour is injected into a formation from a generally horizontal injection
well and recovered from a lower parallel running generally horizontal
production well. An extraction chamber gradually develops in the
formation as the oil or bitumen is removed from the reservoir above and
between the wells. As the vapour flows towards the perimeter of the
chamber, it encounters lower temperatures, resulting in condensation of
the vapour and transfer of heat to the sand and bitumen, causing the
bitumen to warm up. In a solvent based process, the warmth reduces the
viscosity of the bitumen, thereby allowing the solvent to penetrate more
rapidly into the bitumen. The mobilized bitumen and liquid solvent drain
towards the bottom of the chamber and are then recovered from the
formation through the production well located near the bottom of the
chamber. As the mobilized bitumen drains downward, fresh bitumen
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becomes exposed at an extraction interface that is subsequently exposed
to the vapour, such as the condensing solvent and becomes in turn
mobilized. This bitumen depleted extraction chamber is called a gravity
drainage chamber.
The chamber volume grows vertically and laterally around the wells
as bitumen is extracted, eventually approaching the overburden of the
formation. The chamber growth may also approach other chambers from
other operating wells nearby. At the point where pay hydrocarbon
productivity is deemed too low for a given production well, or a set of
production wells where their associated solvent chambers have
coalesced, the production phase of the chamber may be ended. Then it
may be necessary to prepare the chamber for abandonment and eventual
reclaim of land at the well pad. Chamber abandonment generally involves
stopping the flow of steam or solvent vapour into the chamber and
balancing the final chamber pressure with the formation to prevent the
chamber from acting as a low pressure sink that attracts steam or solvent
vapour from nearby operational well pads or high pressure source that
leaks pressure into adjacent areas.
Typically, the injected vapour delivers heat into the chamber to
mobilize bitumen or pay hydrocarbons. Therefore, as the vapour injection
rate is reduced and eventually stopped, the bitumen drainage rate
decreases until it is economically impractical to continue producing oil;
that is, when the volume of oil produced is of less value than the cost to
operate the wells and corresponding surface plant.
Once all flow is stopped to and from the chamber, the downhole
equipment (e.g. tubes, pumps, heaters) may be pulled out of the wells
and the wells are plugged, usually with cement up to grade. The well
casing is cut just below the surface and capped. At this point, the
chamber may be abandoned.
For a solvent-based process, some of the injected solvent will
remain in the formation both as vapour and condensed liquids at the end
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of the production phase, occupying the volume of the produced bitumen
and water. This remaining solvent is valuable, therefore as much as
economically feasible should be recovered before chamber abandonment
so that the recovered solvent can be reallocated, for example, to other
operating wells and in situ chambers.
U.S. Patent No. 7,464,756 presents a solvent-assisted extraction
process involving a unique sequence of steam/solvent injections to
recover hydrocarbons from a heavy hydrocarbon reservoir. The patent
teaches continuing production at reducing reservoir pressures even after
hydrocarbon (solvent) injection is complete to recover additional volumes
of solvent. It also teaches to inject a displacement gas, which may be a
non-condensable gas, to maintain the pressure of the vapour chamber.
This patent assumes that the solvent remaining in the reservoir is
primarily condensed liquid solvent that is able to drain by gravity and be
extracted as produced fluids. However, a significant amount of solvent
retained in the reservoir may not be able to easily drain by gravity. This
includes uncondensed solvent gas in the chamber, solvent that may be
located below the producer so that it cannot be drawn to surface through
the producer, and solvent that is dissolved in the immobile asphaltene
phase which is therefore trapped. The pay hydrocarbons may also include
significant amounts of solvent which are at too low a concentration to
mobilize the hydrocarbons at that temperature. Other methods are
required to recover this solvent in an economic manner.
SUMMARY OF THE INVENTION
What is required is a procedure to recover both liquid and gas
solvent remaining in a mature gravity drainage chamber that has been
formed by solvent-based extraction of the hydrocarbons, before chamber
abandonment. The apparatus for carrying out the procedure should be
compatible with the apparatus required for the preceding oil production
phase so as to require little to no additional equipment and minimal plant
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modifications or disruptions.
The present invention may address some of these requirements.
According to the present invention, solvent remaining in a mature gravity
drainage chamber formed by solvent-based extraction may be recovered
by:
= Reducing the injection rate of solvent vapour into the injector until
solvent injection is completely stopped while continuing to draw
down on the producer well to produce mobilized pay hydrocarbons;
= Producing solvent-containing liquids through the producer well to
the surface plant without adding any further solvent vapour into the
chamber, until the water cut of the produced fluids reaches an
undesirable liquid threshold which may be when the produced
fluids contain too much water to economically separate them;
= Extracting vapours from the reservoir by producing solvent-
containing gas to the surface plant until the solvent content in the
produced gas reaches the gas threshold which may be until it is
uneconomic to separate the solvent from the other produced
vapours, for example due to low solvent production rates, or if it is
impractical to further reduce chamber pressure.
The present invention may use the same well pump, compressor
and surface facilities already used for the production phase of the
chamber with only some minor variations. The present invention may
also use the injector well or nearby vertical wells, such as observation
wells or a new core well to produce the solvent-containing gas or to inject
non-condensable gas.
Chamber pressure management may be an aspect of the present
invention. The pressure of the chamber will decrease as the solvent
containing liquids and gases are drawn from the chamber in the absence
of further injection. In reservoirs with sufficient water saturation,
formation
water may enter and eventually flood the chamber as the chamber
pressure drops below the native reservoir, hindering the liquid solvent
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recovery. The present invention may comprehend injecting a non-
condensable gas to maintain the chamber pressure and may include
drawing solvent-containing liquid from the chamber under a gas-trap
condition. The present invention may also comprehend simultaneously
injecting a non-condensable gas to maintain the chamber pressure while
producing solvent-containing vapour to maintain a balanced pressure with
the reservoir. For chambers that must be left in pressure balance to the
reservoir, the present invention may comprehend injecting a non-
condensable gas or water into the chamber after the solvent recovery is
completed to achieve such pressure balance.
Some chambers may have a significant portion of liquid solvent
located below the producer well, such as reservoirs with relatively low
water saturation. An embodiment of the present invention includes
injecting water into the volume of the chamber below the producer. This
may encourage the lower density liquid solvent to float on top of the water
and up to the producer so that such liquid solvent may be recovered and
brought to surface.
In another embodiment of the present invention, the wells are
initially shut-in to allow more time for any formation liquids, including
liquid
solvent to drain before producing the solvent-containing formation liquids.
Therefore, according to a further embodiment of the present
invention there is provided a method of recovering solvent from an in situ
gravity drainage chamber, said method comprising the steps of:
transitioning from injecting solvent into said gravity drainage
chamber to ceasing to inject solvent;
continuing to produce draining liquids from said gravity drainage
chamber during said transition step;
monitoring a content of said produced liquids and continuing to
produce draining liquids from said formation until a level of at least one
fraction in said produced liquids becomes uneconomic to separate at
surface;
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transitioning to producing vapour from said formation;
monitoring a percentage of a least one valuable fraction of said
produced vapour; and
continuing to produce said vapour until a level of said at least one
valuable fraction becomes uneconomic to separate at surface.
According to a further embodiment of the invention, there is
provided a surface facility for recovering solvent from an in situ chamber
formed by a gravity drainage process, said surface facility comprising:
a liquids separator to separate water from a mixed fluid production
stream extracted from said chamber;
a vapour separator to separate gases which are non-condensable
at reservoir conditions from said mixed fluid production stream extracted
from said chamber;
a first return circuit to permit said separated water to be reinjected
back into said chamber and a second return circuit to permit said
separated non-condensable gases to be reinjected into said chamber.
BRIEF DESCRIPTION OF THE DRAWINGS
Reference will now be made by way of example only to preferred
embodiments of the invention by reference to the following drawing in
which:
Figure us an illustration of a mature gravity drainage chamber;
Figure 2 is a contour graph showing the distribution of solvent in a
mature chamber in preparation for abandonment;
Figure 3 is a schematic of a surface plant for separating the
formation fluids taken from the well during oil production;
Figure 4 is a schematic showing the different stages of a solvent
recovery procedure according to the preferred embodiment of the present
invention;
Figure 5 is the contour graph showing the distribution of solvent
remaining in a chamber after performing part of the solvent recovery
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procedure according to the preferred embodiment of the present
invention;
Figure 6 is the contour graph showing the distribution of solvent
remaining in a chamber after performing another part of the solvent
recovery procedure according to the preferred embodiment of the present
invention;
Figure 7 is the contour graph showing the distribution of solvent
remaining in a chamber after performing the solvent recovery procedure
according to one embodiment of the present invention; and
Figure 8 is a schematic of a surface plant for separating the
formation fluids taken from the well during solvent recovery.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
Figure 1 illustrates the key features of one form of a fully developed
extraction chamber, ready to begin a solvent recovery process. The
chamber 1 may be located in the payzone of a bitumen-bearing reservoir,
such as the Alberta oil sands and may encompass a horizontal well pair,
generally consisting of an upper injector well 2 and lower producer well 3.
The chamber has grown laterally into the payzone and vertically towards
the overburden during extraction of the bitumen by a solvent condensing
EOR such as the nsolv process. During the production phase, which
may also be referred to as the solvent injection phase, warm solvent
vapour enters the chamber through the injector. The vapour condenses
when it comes into contact with the colder walls of the chamber, which
represents a bitumen-solvent interface 6. The heat transfer from the
solvent to the interface reduces the bitumen viscosity to increase its
mobility. The condensed solvent may penetrate into the bitumen at the
interface, further lowering the bitumen viscosity such that the mixture may
drain by gravity down the chamber walls towards the producer well 3,
where it may be produced to the surface to recover the bitumen as sales
oil. This mixture of bitumen and solvent may be called a drainage layer 5.
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The area in the chamber from which bitumen may have already drained is
referred to as a swept zone 4. Also shown is an observation well 9 with
an access opening 11 a toward a top of chamber 10 and 11 a towards a
bottom, or even underneath chamber 10 which are discussed in more
detail below. The provision and position of the access openings 11 a and
11 b will depend upon reservoir conditions and what stage the solvent
recovery process is then at, as explained in more detail below.
Figure 2 is a contour graph illustrating an example of a possible
distribution of solvent remaining in a chamber 10 that is ready to begin a
solvent recovery process. While this example is provided for illustration
purposes, it will be understood that the precise distribution of remaining
solvent will vary, according to local reservoir characteristics, including
permeability, the presence of unconformities, the choice of solvent used,
and the like.
In Figure 2, the shading represents the moles of solvent contained
within each grid cell, corresponding to the legend shown at 12. The
injector is shown at 14, while the producer is shown at 16. The highest
concentration of solvent is expected in the drainage layer 18 generally
below the injector 14 and around the producer 16, indicated by the
darkest shading, with a large volume of medium concentration solvent in
the swept zone 20.
The solvent remaining may be described as either dynamic or
static. Dynamic solvent is free-draining liquid solvent which will drain to
the bottom of the chamber under the force of gravity alone. In the
reservoir, this may be solvent that has condensed above the producer
and is trickling down through the formation towards the production well, as
well as solvent in the drainage layer located above the producer well, so
long as the drainage layer mixture is still sufficiently mobile.
Static solvent is that solvent which does not drain under the force
of gravity. This includes solvent in the gas phase, solvent held up in the
swept zone of the chamber that is held in place by surface tension or
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capillary forces, and solvent dissolved into the in situ hydrocarbons which
hydrocarbons have insufficient mobility to drain under gravity alone.
In Figure 2, the distribution of dynamic and static solvent is shown
as roughly 50/50 by way of example for a particular reservoir, located in
the Alberta oil sands. The distribution will vary from reservoir to reservoir
as it is dependent on permeability, porosity, solvent to oil ratios applied,
temperature, viscosity, solvent used etc. The present invention may be
applicable to a wide distribution of dynamic and static solvent remaining in
a chamber.
Figure 3 shows process steps which may be suitable for separating
produced fluids and recovering solvent during the production phase of a
solvent-based extraction, for reuse in the production process. The surface
plant 30 receives mixed produced fluids 39 from the downhole pump 32 of
the producer well 31. The produced water 42 may be separated in a free
water knock vessel 34. The remaining mixed hydrocarbon 43 may be
submitted to multi-stage flash to separate produced oil 44 from the lighter
hydrocarbons 45, 46 consisting of solvent and non-condensable gas. The
lighter hydrocarbons may be distilled in the distillation system 36 into
purified solvent 47 and fuel gas 50. Casing or annulus gas 40 that may be
drawn to surface by the downhole pump 32, may be primarily non-
condensable gas, solvent vapour and condensed solvent that has flashed
due to the heat of the downhole pump. This gas may be compressed
along with the low pressure light hydrocarbons 45 in a compressor 38,
and injected into the distillation system 36. The purified solvent 47 may be
heated 37 for circulation back into the injector well 33. Make-up solvent 49
may be added at the inlet of the distillation system for introduction into the
solvent circulation loop. This process configuration is suitable for the early
stages of the present invention, although other configurations that
separate the water, oil and solvent from the mixed fluids are also
comprehended.
Figure 4 shows the different stages of a solvent recovery
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procedure according to a preferred embodiment the present invention by
way of example only. The x-axis 20 represents the four stages of the
procedure, while the y-axis 21 plots changes in various parameters during
the procedure. The four stages may be defined as I) wind down, II) liquid
draw down, Ill) gas draw down and IV) chamber pressure adjustment.
At the bottom, line 22 is the solvent injection rate trend line which
tapers off to zero at the end of phase I. Next, line 23 is the cumulative oil
production trend line from the start of wind down, typically reported in
barrels per day. Line 24 is the bottom hole chamber temperature trend
line, while Line 25 is the bottom hole chamber pressure trend line. Line 26
is the water cut in the produced fluids trend line. Line 27 is the total
solvent recovery trend line, calculated as the fraction of solvent recovered
divided by the total solvent in the chamber. The total solvent in the
chamber can be estimated by a mass balance of the solvent used in the
EOR process, with the difference between in the cumulative solvent
injected into the formation and the cumulative solvent produced from the
formation being the amount remaining below surface in the chamber.
The timescale of the x-axis 20 will vary by reservoir, but for the
example shown in Figure 4, which represents an example of a chamber,
reservoir and distribution of solvent remaining, the total duration of the
four stages may be approximately ten to eighteen months or longer but
preferably around twelve months depending upon the nature of the
reservoir.
Stage 1: Wind Down
During Stage I, the solvent injection 22 may be transitioned from its
value at the end of the production phase to zero. Preferably, this may be
done by first turning down the make-up solvent that is added to the
solvent that circulates between the chamber and the surface plant,
followed by turning down the solvent re-circulation until the solvent being
injected through the injection well reaches zero at the end of Stage I.
According to the present invention, the rate of decrease in solvent
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injection and re-circulation is driven by a number of factors, including
chamber size, temperature, pressure, and well productivity and thus the
rate of changes in turn down may vary from chamber to chamber. Solvent
that may be no longer required for circulation into this chamber may be
redirected to other chambers in the well pad or other active well pads.
In one embodiment of the current invention, the solvent injection
purity specification may be relaxed in conjunction with the ramp-down of
solvent injection rate. This may be accomplished by various means,
including the recompression and reinjection of producer casing gas vent
which may be enriched in non-condensable gases.
Oil production continues in Stage I, as shown by line 23, although
at decreasing rates compared to the production phase (not shown) due to
the decreasing solvent injection rates and chamber temperature 24. The
chamber pressure may drop slightly due to the drop in injected solvent.
The water cut in the produced fluids 26 may increase. As solvent is still
being injected at the beginning of Stage I, net solvent recovery 27 may
not be expected until towards the end of Stage I, when more solvent may
be produced than is injected into the well.
Stage II: Liquid Draw Down
Stage ll begins when solvent injection has stopped. This next
stage may be called liquid draw down because the main intent is to draw
as much solvent containing liquid as possible from the production well.
Liquid draw down recovers primarily mobile liquid or dynamic solvent,
which can drain to the bottom of the chamber under the force of gravity
either alone or in combination with other mobile formation liquids. This
liquid will be initially oil and solvent rich drainage fluids that have
collected
during primary production and wind down phases and which has not yet
been collected from the production well, for example by the downhole
pump. Typically, the solvent/oil phase may be lighter than water and
tends to float on top of the produced water. In turn, the water may tend to
settle below the producer well.
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In one embodiment of the present invention, the injector and
producer wells may be shut-in for a period of between 4 to 12 weeks after
wind down before starting liquid draw down. This allows time for the free-
draining fluids to collect at the bottom of the chamber, without being
inhibited by the counter-flow of non-condensable gas that may be
simultaneously injected during liquid draw down. The disadvantages of
shutting in the well are the lack of any hydrocarbon production during this
period and the chamber heat loss during the shut-in period, which will
have a negative impact on hydrocarbon production in the later phases. As
the effectiveness of the initial shut-in varies from reservoir to reservoir
due
to reservoir properties, operating conditions, and relative location to other
wells, reservoir simulations may be used in the planning of chamber
abandonment to determine if an initial shut-in is advantageous for the
particular well pair.
Going back to the liquid draw down stage in Figure 4, as much
liquid solvent as possible may be taken to surface via the producer
downhole pump. However, the liquid level in the chamber cannot be
monitored directly, therefore the water cut 26 and solvent/oil production
rates 23, 27 act as useful indicators for identifying the end of the liquid
draw down phase. As the solvent-rich fluids above the producer are
depleted, the production rates will drop-off and the water cut will begin to
increase, indicating there is little solvent content in any free-draining
solvent containing liquids reaching the production well, and the water
phase is being produced in greater proportion. The liquid draw down
phase may be ended when approximately 40-60% of water content exists
in the produced fluids. Depending on the surface facility the water content
will reach a level at which it becomes uneconomic to separate and
dispose, and so it becomes uneconomic to further produce. This may be
considered the liquid threshold and may be based, for example, on the
trailing average water cut over several days. For example, as the water
cut increases above 60%, it may become increasingly uneconomic to
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recover solvent in this manner as the energy required to separate the
water, along with the potential cost for water treatment and disposal may
exceed the value of any recovered hydrocarbons including solvent. In
reservoirs with low water saturation, the liquid (solvent and oil) production
rate may drop below an economical recovery operation even before the
water cut rises to 40%.
In the preferred embodiment, the chamber pressure 25 may be
maintained during Stage II by injecting a non-condensable gas.
Maintaining the chamber pressure may be used to prevent the ingress of
formation water into the chamber as more liquids are removed thus
reducing the water cut in the produced fluids as compared to what it
would be without such pressure maintenance. The non-condensable gas
means, for this purpose, any gas that will not condense under the
chamber conditions, and some examples include but are not limited to,
methane, CO2, nitrogen, and the like. A source of non-condensable gas
according to an aspect of the present invention may be readily available
from the overheads of the solvent purification system in the surface plant.
The non-condensable gas is optionally heated before injection into the
chamber to slow the chamber temperature drop, pressure drop and the
loss of bitumen mobility.
The non-condensable gas may be injected through the injector well
and/ or nearby generally vertical observation wells or core well. Well
perforations may be included in the liner before installation of the
observation or core wells or strategically added after well placement by
perforating the casing to provide direct access to specific elevations and
areas within the extracted chamber. For solvent recovery, the custom
placement of access may be preferable to permit the operator to select a
location of injection of non-condensable gases or water or other flushing
media where the chamber is at most risk of formation water ingress.
To avoid by-passing of the non-condensable gas directly from the
injection points to the producer, the liquid may be collected from the
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producer under the condition of little or no gas intake. For example, the
production rate may be set to keep the producer downhole pump flooded
with liquid so that little to no casing gas, including the non-condensable
gas is drawn through the pump. If the liquid production is lower than the
turndown of the downhole pump, some product oil may be recycled
downhole to maintain the liquid seal.
In this phase, the solvent recovered 27 may be in the range of 15-
50% of the total solvent initially remaining in the formation, although the
exact extent of recovery will be dependent on several factors mentioned
before as well as the condition of solvent remaining.
There may be a significant portion of liquid solvent located below
the producer well, in reservoirs with relatively low water saturation for
example. For these reservoirs, the present invention comprehends
injecting water, which may be produced water from the surface plant, into
the chamber through an available injection point, for example the injector,
producer or an observation well. This allows the lower density liquid
solvent to float on top of the injected water as the water fills the chamber
from below and drives the liquid solvent up to reach the inlet of the
producer so that it can be brought to surface. This may be done either
before liquid draw down starts, or towards the end of liquid draw down in
order to recover solvent that may be below the producer downhole pump
suction. The water is optionally heated before injection into the chamber
to slow the chamber temperature drop and the loss of bitumen mobility.
The water may be injected into injector well or preferably the producer
well or even lower down through an access point provided by a vertical
observation or core well.
Stage III: Gas Draw Down
Once the water cut in the produced fluids has reached the liquid
threshold value of between 40-60% (or the solvent and oil production
rates are no longer economic), the next stage of solvent recovery begins.
Stage III may be referred to as the gas draw down stage because the
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main event is to recover solvent in the vapour or gas phase. This may
include solvent that is considered static solvent, as well as slow-draining
dynamic solvent that remains in the swept zone at the end of liquid draw
down.
In the preferred embodiment of the present invention depicted in
Figure 4, solvent-containing gas is drawn from the chamber via the
injector well casing, and/ or an observation well or a core well. As a result,
the chamber pressure 25 will decrease rapidly, lowering the bubble point
temperature of the residual liquid solvent. Residual heat in the reservoir
rock may flash that solvent into the gas phase so that it may be recovered
through the injector well and/or observation well or core well as well.
During gas draw down, some free-draining liquid solvent that
remained in the swept zone at the end of liquid draw down may continue
to drain and settle at the producer. Because the chamber pressure is
being reduced significantly in this stage, formation water may also flow
into the chamber from the surrounding reservoir. In one embodiment of
the present invention, the liquid draw down may be continued even during
gas draw down. The settling of free-draining liquid solvent and ingress of
formation water tends to cool and sequester residual solvent in the
flooded area, making it difficult to flash solvent during gas draw down.
Continuing to draw down the liquids from the chamber allows for the
solvent in the area that would otherwise be flooded to evaporate and be
produced to the surface. This liquid may be drawn from the producer or
with an appropriate lift system, from a higher elevation, for example
through the injector, observation wells or core wells. Reservoir
simulations estimate an additional 5-20% of the total solvent remaining
may be recovered with simultaneous gas and liquid draw down. The
anticipated value of the additional solvent recovered may be evaluated
against the cost of the additional water production during planning of the
chamber abandonment activities for a particular chamber to determine if
simultaneous gas and liquid draw down should be used in a particular
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reservoir or chamber.
The gas draw down phase is ended once the injector has been
flooded with formation water or if there is not enough production of solvent
from the injector casing/ observation wells/ core wells to justify the
continued operation. This may be considered the gas threshold. The latter
may occur before the injector is flooded if simultaneous liquid draw down
is employed or if large quantities of solution gas are being drawn into the
chamber, such as may be expected for reservoirs with low water
saturation and high gas to bitumen ratio.
In this phase, the solvent recovered 27 is expected to be in the
range of 20-40% of the total solvent remaining at the end of solvent
injection, although the exact recovery will depend on several factors
mentioned before as well as the type of solvent remaining.
For chambers that are located close to an aquifer, if gas draw
down is done with decreasing chamber pressure, the chamber may fill
very quickly with formation water before a significant amount of solvent
can be recovered. Similarly, for chambers that are close to
intraformational gas zones, decreasing chamber pressure may induce
formation gas intake to the chamber and further dilute recovered vapours.
Therefore, in another embodiment of the present invention, gas draw
down is conducted with the chamber pressure in balance to the reservoir
by injecting gas and producing gas simultaneously. A gas other than
solvent; preferably one which is non-condensable at reservoir conditions
may be injected into the chamber, for example, through the injector well,
while solvent-containing gas may be produced at another point in the
chamber, such as the producer well. The non-condensable gas may act
as a flush to force solvent gas towards a recovery location. When using a
flushing gas, the injection and production may occur simultaneously. In
another embodiment the injection and production can occur through the
same well, but may take place sequentially. Using observation wells and
nearby core wells to inject or produce the gas is also comprehended
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again either simultaneously or sequentially. As will now be understood
the present invention comprehends minimizing mixing of the injected gas
(which is to be left in the extraction chamber) and produce solvent gas
(which is to be removed from the chamber) by means of separating the
injection/production locations, by means of species selection, or by other
means.
Injecting a flushing gas into the chamber may reduce the partial
pressure of solvent in the gas phase to a point below the vapour pressure
of the solvent at the then temperature of the chamber, causing some of
the residual liquid solvent to evaporate, after which such newly
vapourized solvent gas may also be collected in the gas phase. Such a
process is analogous to a low-temperature dehydration process, in which
dry air is used to slowly remove water from another medium at a
temperature well below the boiling point. A possible limitation of injecting
a flushing gas to try to strip solvent from the chamber is that the gas may
not expand to the chamber perimeter, therefore such a dehydration step
may be more effective near the wellbore or across the source/sink
pathways then at the chamber perimeter. In addition, solvent losses in the
surface facilities may rise as the distillation system may not be capable to
separate produced gas which is rich in flushing gas, such as methane-rich
rather than solvent-rich, which is the condition that the distillation system
operates under during normal extraction to efficiently separate the
targeted hydrocarbon solvent.
Therefore, in one embodiment of the current invention, a water
soluble gas such as CO2 may be used as the flushing gas and the surface
facility equipped with a selective separation step involving an aqueous
phase absorption of CO2. In the end such CO2 may be sequestered in the
chamber if the conditions are appropriate.
Stage IV: Chamber Pressure Adjustment
If there are other operating wells nearby, the present invention
comprehends steps to re-pressurize the chamber to approximately the
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native reservoir pressure or any other pressure that may be appropriate to
facilitate extraction of an adjacent resource. Such re-pressurization or
pressure adjustment may be done either by injecting additional flushing
gas or high water cut produced fluids/ produced water into the chamber
through one or more injection points, for example, the injector, the
producer and/or observation wells to fill the chamber and thus discourage
this chamber from attracting solvent from nearby extractions.
Figure 5 is a contour graph showing the distribution of solvent
remaining in the chamber 10 after performing the liquid draw down
according to the preferred embodiment of the present invention. In
comparison to Figure 2, the moles of solvent in the drainage layer 18 at
the level of the producer 16 are reduced and there is a nearly solvent-free
zone 11 generally above the injector 14 where NCG may have been
injected for pressure maintenance. However, there may not be much
change in the moles of solvent present in the rest of the swept zone 20.
This is solvent in the gas phase that cannot be produced to surface
through the downhole pump and some liquid solvent that has not yet
settled to the drainage layer. In the presented example, the estimated
recovery between Figure 2 and Figure 5 may be about 40% of the total
solvent retained in the reservoir in some cases.
Figure 6 is the contour graph showing a distribution of solvent
remaining in the chamber 10 after performing the gas draw down
according to the preferred embodiment of the present invention. In
comparison to Figure 5, the amount of solvent in the swept zone 20 has
significantly decreased. The estimated recovery between Figure 5 and
Figure 6 may be an additional 25% to 30%, for a total recovery of about
70% of the solvent hold-up.
Over time, a thickness of solvent-rich layer near the producer 16
may grow due to some further settling of liquid solvent from the swept
zone 20 into the drainage layer 18 during gas draw down. Additional
recovery of this liquid solvent may be achieved by simultaneous gas and
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liquid draw down. Sequential gas and liquid production is also
comprehended depending upon reservoir conditions.
Figure 7 is a contour graph depicting the distribution of solvent
remaining in the chamber 10 after further gas and liquid draw down after
the initial liquid draw down in this example. In comparison to Figure 5, a
thin layer of solvent may remain around the perimeter of the chamber.
Additional solvent recovery beyond this point may not be economical due
to a high water cut in the liquid phase and since there may no longer be
enough residual heat in the chamber to flash the solvent into the gas
phase. In this example, simultaneous liquid draw down during gas draw
down increases the estimated recovery to a total of 80% to 85% of the
solvent remaining depending upon reservoir conditions.
Now it can be understood that the present invention may recover at
least 50%, preferably 60-70%, most preferably 80-90% of the total solvent
remaining in the reservoir after primary extraction has been completed.
The exact extent of recovery will vary depending on the reservoir and
chamber conditions, including conformance of the wells, the extent of
liquid and gas solvent present at the end of production, and rate of heat
loss to the overburden and surrounding reservoir rock from the chamber
and near well bore areas.
The present invention most preferably is able to use the
substantially same surface plant and downhole equipment used during
the production phase as previously shown in Figure 3, with some
adjustments or plant modifications to accommodate the changing nature
of the liquid draw down and gas draw down. Figure 8 is a schematic of the
surface plant configuration which may be used for the liquid draw down
stage (shown with solid lines), and for the gas draw down stage (shown
with dashed lines). In preparation for liquid draw down, the solvent
recovered in the distillation system 36 may be reallocated for other wells
or stored as solvent for resale. A compressor may be reconfigured or
modified to inject overheads 59 from the distillation system 36 and a
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make-up methane or other (non-condensable gas) stream 51 along with
the casing gas 40 into the chamber to maintain the surface plant and
chamber pressure during liquid draw down. An observation well 54 which
has been provided with direct communication with the chamber as
described above in Figure 1 may also be connected to the compressor 38
outlet. Recirculation of product oil 52 may also be provided to the
downhole pump.
Once liquid draw down is complete, another adjustment to the
surface facility may be required to reorient the compressor 38 so that it
may draw gases from the injector 33 and/ or observation well 53 and feed
the same to the distillation system 36. However, as this is just a piping
and valve arrangement most preferably the surface plant will be initially
configured to permit such adjustments to be quickly and easily performed
with a minimum amount of additional or new piping installations. Fuel gas
50 from the overheads of the distillation system 36 may be used as fuel in
other areas of the facility.
While reference has been made to preferred embodiments of the
invention those skilled in the art will understand that various modifications
and alterations are comprehended which do not depart from the scope of
the claims attached. Some of these has been discussed above and other
will be apparent to those skilled in the art.
