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.
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For a solvent-based process, some of the injected solvent will remain
in the formation both as vapour and condensed liquids at the end 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, condensed solvent held
interstitial to sand grains 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
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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 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.
Preparing the chamber for solvent recovery may include a wind down
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period where the solvent injection rate may be transitioned to zero. Wind
down may also include a period of increasing the chamber temperature,
which will benefit the solvent recovery in the latter stages. The chamber
temperature may be increased by different methods, as understood by those
skilled in the art, including increasing the solvent injection temperature and
use of downhole heaters.
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 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 or controlled gas intake 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
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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;
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.
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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 1 is 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
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
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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. 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 11a toward a top of chamber 1
and 11b towards a bottom, or even underneath chamber 1 which are
discussed in more detail below. The provision and position of the access
openings 11a and llb 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
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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 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 out vessel 34. The remaining mixed hydrocarbon 43 may be
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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. The downhole pump is preferably fitted with a gas rejection
stage to allow for extended stable operation in the later phase of liquid
drawdown where well gas intake may be significant. This casing 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 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
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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. The
solvent make-up requirements of new and active wells to sustain facility oil
production may also determine the rate and overall timing requirements of
solvent recovery.
Stage I: Wind Down
During Stage I, the solvent injection rate 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 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
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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.
In another embodiment of the current invention, additional heat may
be added to the chamber before the solvent injection rate is decreased. This
may be achieved by increasing the solvent injection temperature, energizing
a downhole heater or other method known to those skilled in the art. The
additional heat may sustain hydrocarbon mobility in the chamber for a longer
period after solvent recovery begins.
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 decline 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 II 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. Solvent may also
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continue to condense where in contact with colder surfaces around the
chamber or wells, including the overburden or well liners. 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.
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 solvent and oil
production rates will drop-off and the water cut will begin to increase,
indicating there is little solvent and oil content in any free-draining
solvent
containing liquids reaching the production well, and the water phase is being
produced in greater proportion. The hydrocarbons draining to the producer
may also become progressively lower in solvent concentration as wind down
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progresses, which in conjunction with cooling conditions, can make the
resulting drainage fluid more viscous and less mobile. Adding heat downhole
to the production well may extend the practical operation of the downhole
pump by improving the mobility of drainage fluids in and around the wellbore
by lowering the viscosity through thermal effects. The present invention
comprehends other forms of viscosity reduction as well at the production well
as may be required. 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 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 this case, the producer casing gas
rates may be excessive since the producer will have drawn down local liquid
inventory and pressure, and the downhole pump may not operate in a
continuously steady manner due to the excessive gas intake with the liquids.
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
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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 and retain heat in the reservoir, the liquid
may
be collected from the 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 into 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. Other fluids available from the surface
facility such as diesel, warm water or condensate liquid separated from
product oil may also be used to maintain the liquid seal to the pump. Heating
the product oil or other fluids may assist in reducing the mixture viscosity
of
the pump intake fluids, and this heat may be added to the fluid at the surface
or with a downhole heater. These fluids may provide the added benefit of
flushing the producer to prevent build-up of high viscosity fluids.
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In another embodiment of the present invention, a combination of
liquids and gas may be collected from the producer, that is under gas intake
condition. The gas intake condition may allow the producer pump to operate
closer to its nominal flow rate rather than near turndown. This may be a
preferred method of operation for reservoirs where the ingress of formation
water is not excessive, even when the chamber pressure is not being
maintained by non-condensable gas injection.
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. The injection and withdrawal
points may be configured in a manner to encourage a sweep of the buoyant,
mobile hydrocarbon phase towards the withdrawal point.
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Stage 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 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, injector tubing, and/ or an observation well or a core well. As a
result, the chamber pressure 25 will decrease more rapidly, lowering the
bubble point temperature of the residual liquid solvent. Residual heat in the
reservoir rock may promote vapourization of 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. As the injector is used for pushing fluids during the
production phase, the injector casing design may include features to allow
suction of gas during the solvent recovery phase. These features may
include appropriate orifices and tubing for gas intake as well as heating
.. elements to discourage gas condensation along the length of the injector or
tubing.
Solvent gas drawn to the surface via the well casing or tubing through
suction alone is subject to various passivating effects. Specifically, heat
losses incurred along the casing and tubing cause some of the gas to
.. condense in transit to surface, and this condensate drains in a direction
that
is counter current to the gas flow. This counter current liquid flow may
sufficiently accumulate in the tube to create a major flow resistance to the
gas. Furthermore, where the gas is drawn from a liquid pool in the tube or
annulus, the lower pressure suction may induce flash cooling at the gas-
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liquid interfaces, which decreases the temperature and bubble point pressure
of the liquid pool and therefore greatly diminishes the extraction rate of the
gas. Additionally, in areas where the withdrawal point may be flooded or
surrounded with significant saturations of heavier hydrocarbons, a higher
viscosity fluid plug may form in the tubing or around the orifice, either
alone
or in combination with the above mentioned passivation mechanisms. To
address such passivating effects, downhole heating may be required. This
may prevent the gas from reaching condensing conditions in the tubular up to
surface or may warm any liquid pool to sustain higher bubble point pressures
and lower viscosity of the liquid to support gas draw down from the pool.
Furthermore, NCG injection may be used to lower the dew point temperature
of the gas to help prevent condensation or to promote gas draw down
through a liquid pool using similar principles as a flushing gas as discussed
further below.
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. Liquid draw down may also encourage gas recovery from the
same location. Reservoir simulations estimate an additional 5-20% of the
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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
reservoir or chamber.
The gas draw down phase is ended once the withdrawal locations
have 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
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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.
In yet another embodiment, the injection and production can occur through
wells that are associated with different well pairs to form broader sweeping
patterns.
Using observation wells and nearby core wells to inject or produce the
gas is also comprehended 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 solvent
purification system, which may use distillation, may not be capable to
separate produced gas which is rich in flushing gas, such as methane-rich
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rather than solvent-rich, which is the condition that the solvent purification
system operates under during normal extraction to efficiently separate the
targeted hydrocarbon solvent. In this case, a separate dedicated circuit
designed for efficient recovery of solvent from flush gas may be preferred.
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 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
,
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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 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
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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 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 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 or another fluid with or without
supplementary heating may also be provided to the downhole pump 32. The
downhole pump 32 may be optionally replaced with a unit for higher viscosity
fluid, which may be the pump used at start-up. While a downhole pump is
used to describe the artificial lift of fluids in this process, those skilled
in the
art are aware that various artificial lift devices may have application to
this
process, such as hydraulic or gas lift.
In an embodiment of the present invention, the operating pressure of
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the surface plant may be decreased over time to suit the reservoir conditions
and recovery metrics.
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.
