Note: Descriptions are shown in the official language in which they were submitted.
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TITLE OF THE INVENTION:
Improved Process and Apparatus for the
Recovery of Hydrocarbons from a Reservoir of
Hydrocarbons
NAME OF INVENTOR:
Roger M. Butler
FIELD OF THE INVENTION
This invention relates to processes and
apparatus for the recovery of hydrocarbons from
reservoir of hydrocarbons.
BACKGROUND AND SUMMARY OF THE INVENTION
The recovery of heavy oils using horizontal
wells has been carried out on an increasing scale in
Canada and other countries in recent years. Typical
practice in fields such as those in Winter, Senlac,
Long Lake, Cactus Lake and Hayter, all in Canada,
involves the construction of horizontal production
wells about 1000 m in length at the top of the
reservoir. Oil is produced by pumping and the
recovery is limited eventually by the watering out of
the production. Water displaces and replaces the oil
as it rises from aquifers lower in the reservoir. The
advantage of horizontal wells over conventional, near-
vertical ones is that the volume of the reservoir
affected by the rising water is much greater and oil
is drawn by each well from a larger area. In
favourable cases, cumulative production quantities of
100,000 barrels or more of oil are achieved at
economic production rates. These are sufficient to
more than pay for the cost of the horizontal well and
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its operation. The disadvantage of the process is
that a recovery of only about 5~ of the oil in place
is achieved. Much of the original oil is left behind
in the unswept and water-swept regions.
5 The inventor has previously proposed an
approach, known as the "Vapex" process, for the
recovery of heavy oils that involves the use of
vaporized solvents such as ethane, propane, or butane.
In this method use is made of gravity to cause the
10 oil diluted by the solvent to fall to the base of the
reservoir with its initial pore volume becoming filled
by solvent vapor. The process is effective if
appropriate reservoir conditions can be achieved. In
particular, for economic application of the process,
15 it is necessary to have a large mass transfer area
available since diffusive mixing is slow. The
pressure needs to be close to the vapor pressure of
the injected solvent since light hydrocarbon vapors
only have a high solubility in the oil when they are
20 close to their dew point. This limited the most
economic applications of the process to reservoirs
where the pressure can be controlled appropriately,
i.e. to about 500 psig for ethane, 110 psig for
propane and 20 psig for butane.
25 Propane has a particular advantage as a
solvent for use in such recovery techniques because it
allows the precipitation of considerable asphaltene
material in the reservoir thus producing an upgraded,
less viscous, and more valuable oil product. For
30 propane to be used by itself at normal reservoir
temperatures a pressure of the order of 110 psig is
required.
In a previous application for patent, which
issued as US 5,407,009 on April 18, 1995, the inventor
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proposed a process that uses saturated hydrocarbon
solvent vapor (typically ethane or propane) in
conjunction with horizontal wells to mobilize and
recover viscous oils and bitumens from reservoir of
5 hydrocarbons in which a bottom water zone (aquifer) is
used to deliver the solvent vapor to the base of the
reservoir. A hydrocarbon solvent in the vapor phase is
preferably injected at reservoir temperature into an
aquifer underlying the deposit. The hydrocarbon
10 solvent vapor is essentially insoluble in water, while
strongly soluble in oil, with the consequence that
there are no heat or material losses to the water
layer. Furthermore, the water in the bottom water
zone will be mobilized and underride the lighter
15 diluted oil and assist in moving it towards the
production well. Use of this process produces a much
larger interfacial area for mass transfer. However,
the pressure requirement probably limits the general
applicability of using propane alone in such a method
20 to relatively shallow bitumen reservoirs.
In this patent document, a further
improvement of the above described hydrocarbon
recovery process includes the injection of a non-
condensible displacement gas into a reservoir with a
25 hydrocarbon solvent. The displacement gas should be at
a pressure sufficient to limit the rate of ingress of
water into the recovery zone to a small manageable
value. The process is operated so that some of the
injected displacement gas is produced from the
30 horizontal production wells located at the base of the
reservoir. The injection may be into the bottom water
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layer if this exists or, if it is practical (as it
usually will be with conventional heavy oils but not
with bitumen), into horizontal injection wells located
at the top of the reservoir, parallel to and probably
5 displaced horizontally from the producers. Gas is
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injected into the reservoir from these wells and the
production is controlled so that there is a net but
manageable small flow of gas from injector to
producer. In conventional reservoirs such an
operation may produce a small recovery of heavy oil by
itself, but this will be limited because of the
tendency of the low viscosity gas to flow through the
oil as fingers and bypass it. The hydrocarbon solvent
should be a liquefied but vaporizable solvent such as
butane or propane. Confined evaporation of this
liquid solvent in the displacement gas maintains a
concentration of solvent vapor in the gas phase. The
rate of injection of liquefied solvent is preferably
controlled so that essentially all of the solvent is
vaporized before the gas stream reaches the production
well. This vaporized solvent diffuses within the gas
fingers and dissolves into the heavy oil reducing its
viscosity. The diluted oil becomes mobile and
accumulates at the bottom of the gas fingers so as to
tend to seal them off. However the steady flow of gas
results in displacement and diluted oil is produced.
The rate of injection of liquefied solvent is
controlled so as to maintain a practical concentration
in the produced oil (2-50~ by weight).
A limitation of this approach can be that
the fingers of gas produced by the initial injection
sweep only a small volume of the reservoir and, as a
result, there is only a limited interfacial area for
the solution of the vaporized solvent into the
bitumen. Mixing is limited and, as a result, the
production rate may be limited. Therefore, in a
further aspect of the invention, use is made of the
flow channels that have been developed in a reservoir
that has been previously produced by conventional
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water displacement of the type described above. In
the water-flooded reservoir there are numerous
passages in which water has been flowing through the
oil sand. In this further aspect of the invention,
5 the displacement gas is injected with liquefied but
vaporizable solvent into the horizontal wells)
already located at the top of the reservoir and to
displace the water downwards to new horizontal
production wells drilled at the base of the reservoir,
10 parallel to the injectors. The producers may be
located directly below each injector or in between.
Non-condensable gas is allowed to flow through these
interconnected passages and to displace water to the
production well. Again, as in the previous processes,
15 the pressures are arranged so that there may be a
small inflow of fluids from outside the recovery
region but only at a controllable rate. The liquefied
but vaporizable solvent such as propane or butane is
injected at a rate controlled to provide a practical
20 concentration of solvent in the produced fluids (2-50%
by weight).
An important advantage of the process is
that the tendency for the vaporized solvent to rise
will cause the swept region to increase in size
25 upwards.
The solvent is recovered from the produced
oil and recycled to the injectors. It is believed
that significant increase in recovery from horizontal
well projects in areas such as Lloydminster, Alberta,
30 Canada, can be achieved by use of this invention.
There is thus provided in accordance with
one aspect of the invention, a method for the recovery
of hydrocarbons from an underground reservoir of
hydrocarbons, the underground reservoir of
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hydrocarbons being penetrated by an injection well and
a production well spaced from the injection well, the
method comprising the steps of:
initially injecting a displacement gas into
5 the injection well until a communication path is
established between the injection well and the
production well;
subsequently injecting the displacement gas
along with a liquid vaporizable hydrocarbon solvent
10 into an injection well lying in the underground
reservoir to mobilize hydrocarbons in the underground
reservoir; and
producing mobilized hydrocarbons together
with displacement gas and hydrocarbon solvent from a
15 production well lying in the underground reservoir
spaced from the injection well.
Preferably, the mobilized hydrocarbons are
produced along a predominantly horizontal production
well in the underground reservoir.
20 In another aspect of the invention, where
the reservoir has previously been produced by an
existing horizontal production well lying at the top
of the underground reservoir, the displacement gas is
injected into the existing production wells, and in
25 addition, production wells are created by drilling a
new production well into the underground reservoir
below the existing production well.
Methane and nitrogen are preferred for the
displacement gas while butane and propane are
30 preferred for the liquid vaporizable hydrocarbon
solvent.
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In a further aspect of the invention, there
is provided apparatus for the recovery of hydrocarbons
from a reservoir of hydrocarbons, the apparatus
comprising:
5
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a source of liquid vaporizable hydrocarbon
solvent;
a source of displacement gas;
a first injection well drilled horizontally
5 into the reservoir, the injection well having a
portion open to fluid communication with the reservoir
and being connected to the source of liquid
vaporizable hydrocarbon solvent; and
a first production well drilled horizontally
10 into the reservoir, and spaced from the injection
well, the first production well including a pump for
pumping oil from the well.
A solvent stripper is preferably connected
between the first injection well and the first
15 production well.
In another aspect of the invention, a method
is provided for the production of hydrocarbons from a
reservoir of hydrocarbons having a first horizontal
well drilled into the reservoir of hydrocarbons, the
20 method comprising the steps of:
drilling a second horizontal well into the
reservoir of hydrocarbons spaced from the first
horizontal well;
initially establishing a communication path
25 with flow of displacement gas from the first
horizontal well to the second horizontal well;
injecting a liquid hydrocarbon solvent into
the reservoir of hydrocarbons through the first
horizontal well along with displacement gas such that
30 hydrocarbon solvent in the vapor state is present in
the displacement gas in the reservoir; and
producing hydrocarbons and displacement gas
from the second horizontal well.
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The hydrocarbon solvent is preferably
injected in the liquid phase and vapor from the
hydrocarbon solvent preferably saturates the
displacement gas. The hydrocarbon solvent is
preferably selected from the group consisting of
propane and butane.
Further aspects and advantages of the
invention are described in the detailed description
that follows and set out in the claims that follow.
BRIEF DESCRIPTION OF THE DRAWINGS
There will now be described a preferred
embodiment of the invention, with reference to the
drawings, by way of illustration, in which like
numerals denote like elements and in which:
Fig. 1 is a schematic section through a
reservoir of hydrocarbons showing the injection of a
hydrocarbon solvent vapor in an aquifer underlying the
deposit and the recovery of hydrocarbons from another
point in the aquifer;
Fig. 2 is a schematic section showing an
array of parallel horizontal wells in an aquifer below
a reservoir of hydrocarbons with alternating wells
used for vapor injection and hydrocarbon recovery;
Fig. 3A is a schematic showing an exemplary
horizontal production well for use in implementing the
method of the invention;
Fig. 3B is a schematic showing an exemplary
horizontal injection well for use in implementing the
method of the invention;
Fig. 4 is a schematic showing apparatus for
implementing the method of the invention including an
array of parallel wells drilled from an underground
tunnel;
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Fig. 5 is a schematic showing fingers of
propane vapor rising into bitumen in a reservoir of
hydrocarbons, with diluted deasphalted bitumen falling
countercurrently so as to drain to a horizontal
production well;
Fig. 6 is a fluid flow schematic showing a
closed loop extraction process for use with the
invention;
Fig. 7 is a schematic showing application of
an embodiment of the method of the invention to a
field that was previously produced by horizontal
production wells; and
Figs. 8, 9, 10, 11 and 12 show experimental
results obtained from using embodiments of the method
of the invention.
DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS
In this patent document, a displacement gas
is a gas that is non-condensible at reservoir
temperature and pressure conditions and that is
essentially non-soluble in the reservoir hydrocarbons.
Exemplary displacement gases include nitrogen, natural
gas and methane, with natural gas, which is normally
mostly methane with some other gases such as carbon
dioxide, being preferred. A liquid vaporizable
hydrocarbon solvent is a hydrocarbon that is liquid at
the reservoir pressure and at the reservoir
temperature, and has a vapor pressure such that a
significant portion of the solvent evaporates in the
reservoir. Preferred solvents are mixtures of C3 and
C4 hydrocarbons and their olefins and diolefins,
including butane, both iso-butane and n-butane. A
reservoir is a deposit of hydrocarbons and includes a
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permeable zone, should it at exist, at the base of the
reservoir.
A reservoir of hydrocarbons 10 containing
high viscosity hydrocarbons such as heavy crude oil or
5 bitumen is illustrated in Fig. 1 including a reservoir
cap 12 and main reservoir 14 lying in a permeable
formation or formations below the reservoir cap 12. A
permeable layer forming an aquifer 16 underlies the
main reservoir 14. The reservoir 10 is bounded from
10 below by a lower boundary 18. Overburden 22 above the
reservoir 10 is also illustrated along with
underburden 24 below the reservoir 10. The reservoir
10 is exemplary: not all reservoirs will have this
structure. As for example there may be no overburden,
but a further reservoir of hydrocarbons.
As illustrated in Figs. 1 and 3B
particularly, a horizontal injection well 26 is
drilled into the reservoir 10 using known techniques.
This well may be drilled into an aquifer at the base
of the reservoir 10, but may also be elsewhere in the
reservoir, for example at the top of the reservoir as
illustrated in Fig. 7. Horizontal well lengths should
be at least 10 m and preferably more than 100 m,
depending on the reservoir. That part of the well 26
lying in the reservoir 10 or in the permeable layer 16
is open to the reservoir 10 such as by perforation of
the well casing as shown at 28. The horizontal portion
of the well 26 may be as long as feasible. The
horizontal injection well may be placed anywhere
within the reservoir, but preferred locations are at
the top, or the bottom. Various factors will dictate
which is preferred. For example, the existence of an
underlying aquifer suggests placing the injection well
in the aquifer. Yet, if the reservoir has previously
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been produced from horizontal wells lying in the top
of the reservoir, these may be used for injection in
combination with a production well in the base of the
reservoir.
A horizontal production well 32, with tubing
34 and casing 36, is also drilled using conventional
techniques into the reservoir 10, and extends
laterally into the permeable layer 16 as illustrated
particularly in Figs. 1 and 3A. A significant length
of the production well 32 lying horizontally in the
permeable layer 16 is open, as for example by using a
slotted liner in portion 38 of the well, to the
reservoir 10. A pump 42 is located in the inclined
portion of the well 32. The pump 42 may be for example
a conventional sucker rod reciprocating pump (as
illustrated with sucker rod 44), rotary positive
displacement pump, electrically driven pump, or other
suitable pump. The pump 42 pumps production oil from
the casing 36 up the tubing 34 to the surface where it
is produced in conventional manner. As with the
injection well, the production well may be located
elsewhere in the reservoir, but production from the
bottom or near the bottom of the reservoir is
preferred .
As illustrated in Fig. 2, particularly in
the case where injection and production wells are in
a permeable layer at the base of the reservoir 10, the
injection wells 26 and production wells 32 may be
spaced approximately parallel to each other and
alternate with each other. Alternatively, the
injection wells 26 may be located above the production
wells 32 as illustrated in Fig. 7, or they may be
variably placed across the reservoir, the constraint
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being that there should be fluid communication between
injection wells and corresponding production wells.
Liquid vaporizable hydrocarbon solvent is
injected in the liquid phase along with a displacement
gas, such as nitrogen or methane, into the injection
well to mobilize at least a portion of the
hydrocarbons in the reservoir of hydrocarbons 10. The
injection pressure is selected so that the pressure of
the gas is below the reservoir pressure. This prevents
reservoir hydrocarbons from being pushed away from the
production region. The amount of liquid vaporizable
hydrocarbon solvent and gas must be controlled to
ensure production of the displacement gas and liquid
vaporizable hydrocarbon solvent with produced
hydrocarbons from the reservoir. The displacement gas
is first injected into the injection well until some
of the injected gas is produced at the production
well. Once fluid communication between the injection
and production wells has thus been established, and
while continuing to supply displacement gas into the
injection well at a rate sufficient to maintain
production of displacement gas at the production well,
the liquid vaporizable hydrocarbon solvent is injected
into the injection well.
The liquid vaporizable hydrocarbon solvent
need only be present in an amount necessary to ensure
that vaporized hydrocarbon solvent will be available
to dissolve in the reservoir hydrocarbons preferably
with the produced liquid containing solvent in an
amount about 2-50~ by weight. Liquid solvent need not
be present in a large amount within the region in
which extraction is to occur. Transfer of solvent
vapour within the gas phase to the oil gas contact by
diffusion is an important mechanism. The gas must be
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injected in an amount necessary to ensure production
of gas at the production well and maintain pressure in
the reservoir. An essentially constant pressure is
maintained on the injected material while gas flow is
ensured by the production of free gas with liquids
from the production well. Where there is an aquifer
present, a small amount of water should also be
produced. If water is not produced, solvent may be
lost to the aquifer. As the extraction continues much
of the pore volume initially occupied by oil is filled
with gas.
As the injected fluids contact the reservoir
the gas tends to remain saturated with vaporized
solvent. Solvent is transferred to the gas phase as
vapour and then, as the gas contacts the oil, the oil
becomes diluted with the solvent. Thus the solvent
gradually becomes dissolved in the oil by evaporation
from solvent rich liquid, diffusion in the gas phase
and dissolution in non-diluted or less diluted oil.
The injected solvent is mostly liquid and it becomes
mixed with the oil as it flows to the producing well.
The final produced liquid is oil containing dissolved
solvent.
The liquid should be present in the amount
such that the gas tends to become saturated with
solvent vapor. Too much liquid solvent should be
avoided since this may cause asphaltene precipitation
and plugging of the reservoir.
In case of injection of the hydrocarbon
solvent into the permeable layer 16, the hydrocarbon
solvent and gas spreads across the area below the
reservoir 10 on either side of the horizontal
injection well 26. The gas rises along with solvent
vapor, because of gravity, across this area and
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penetrates the overlying reservoir where the solvent
vapor dilutes and deasphalts the oil. Asphaltenes
which separate from the oil remain in the bulk of the
reservoir. The gas and vapor rises as a multitude of
fingers 46 into the reservoir as illustrated in Fig.
5, mobilizing the hydrocarbon in the reservoir 14 and
diluted bitumen or heavy crude oil falls
countercurrently to the hydrocarbon solvent as
indicated by the arrows 48. At the interface between
the gas and hydrocarbon solvent vapor and the oil, the
vapor condenses into the oil, mobilizing it, and
warming it up 0 - 5 °C.
The diluted hydrocarbon in the reservoir is
heavier than the gas and vapor and flows under gravity
towards the production well 32, as indicated by the
arrow 52 where the mobilized hydrocarbons are produced
from the reservoir of hydrocarbons. The interface
between oil and vapor rises steadily until the supply
of oil has been exhausted, near the top of the
reservoir.
As illustrated in Figs. 2 and 4, the
hydrocarbon solvent may be injected along an array of
predominantly horizontal injection wells 26 spaced
from each other in the aquifer and the mobilized
hydrocarbons may be produced along an array of
horizontal production wells 32 spaced from each other
in the aquifer. The wells 26 and 32 may be drilled
from the surface (Figs. 1 and 2) or from a tunnel 44
(Fig. 4).
In addition, production could be obtained
from vertical wells, with a vertical injection well
drilled into the aquifer, or any combination of
vertical and horizontal wells, so long as they are not
so far apart that communication cannot be established
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between them. However, vertical wells are considerably
less effective than horizontal wells since an
important aspect of the invention is the establishment
of a solvent - oil interface that extends over a wide
5 area.
If there is no pre-existing aquifer
underlying the main reservoir, under some conditions,
such as where fractures propagate horizontally, a
conductive horizontal layer may be initially created
10 at the base of the reservoir of hydrocarbons by
hydraulic fracturing of the rock at the base of the
hydrocarbon reservoir. Fracturing may also be
beneficial to assist in creating communication zones
between injection and production wells even in cases
15 where injection of the displacement gas and solvent is
not to be into an aquifer. This technique can be used
for the recovery of bitumen from shallow reservoirs in
the following manner.
Three parallel horizontal wells, such as
wells 26 and 32 shown in Figs. 1 - 4, are drilled near
the base of a shallow bitumen deposit such as those in
Athabasca, Alberta, Canada. The depth is chosen so
that an operating pressure of the order of 100 psi can
be employed without disrupture of the surface. A
depth greater than about 400 feet is satisfactory.
The depth is also chosen so that when a hydraulic
fracture is created within the reservoir, it becomes
horizontal rather than vertical. It is well known to
those skilled in the art that horizontal fractures
form at relatively shallow depths and that there is a
depth beyond which fractures tend to be vertical. The
exact depth at which this transition occurs depends
upon the in situ stresses in the reservoir body.
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Typically the depth is about 1000 feet. Thus, in this
example, a depth of about 600-800 feet is chosen.
The central well of the three is used as an
injector and the two flanking wells as producers. In
a larger project, many such parallel wells could be
employed with alternating injectors and producers.
The first stage in the process, for
establishing communication by fracturing, involves the
creation of a horizontal fracture extending between
the injector and the two producers. This is created
by injecting water or another fracturing liquid at a
high pressure into the injection well. A fracture
opens up and the producers, which are initially shut
in, are opened when the wellbore pressure rises above
the reservoir pressure. However, the wells are
throttled so as to maintain a high pressure in the
wellbore. During this phase, the injection of water
(or other fracturing fluid} is continued.
After the flow of water has been
established, a mixture of butane and a less soluble
gas such as natural gas or nitrogen is forced into the
injector, still maintaining a high pressure. The
pressure within the mixture will be above the vapor
pressure of butane at reservoir temperature. This
flow of gas is continued until a significant volume of
butane-diluted bitumen has been produced at each of
the production wells. During this time, these wells
are throttled so that the pressure in the fracture
remains high to help keep it open.
Once sufficient bitumen has been produced to
indicate that a channel has been leached above and, to
a lesser extent, below the fracture in the reservoir
sand, then the pressure in the production wells is
reduced gradually towards the normal operating
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pressure; this will usually be above the vapour
pressure of butane at the reservoir temperature. As
has been described previously, this reservoir
temperature will tend, during the process, to rise a
few degrees centigrade because of the heat of solution
of the butane. At this point, there is a continuous
flow of gas and butane in the plane below the
reservoir and the process can proceed as described
previously.
In summary, a horizontal, approximately
planar fracture, is created between injection and
production wells by hydraulic fracturing, a mixture of
a low solubility gas and butane is introduced into the
fracture, sufficient bitumen is leached by the butane
to create a flow passage within the matrix above the
fracture, and the process described previously is
continued.
By using conditions such as those described
above, the pressure within the vapor chamber can be
adjusted to less than that in the surrounding
reservoir and, as a result, there will be no tendency
for the valuable vaporized solvent to escape into the
reservoir. Rather, bitumen under pressure will tend
to flow towards the extraction chamber, albeit very
slowly.
The hydrocarbon solvent is taken from the
group of light hydrocarbons, such as ethane, propane,
butane or other low boiling point hydrocarbons,
hydrogen sulphide, and other materials having suitable
vapor pressure characteristics and solvency, as well
as their mixtures . Hydrocarbon solvent in this context
does not necessarily mean that the solvent is a
hydrocarbon, but that the solvent is capable of
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18
dissolving hydrocarbons. However, propane and butane
are preferred.
A recovery and recycling system for the
hydrocarbon solvent vapor is illustrated schematically
in Fig. 6. The system is composed of injection well
26, production well 32, solvent stripper 66 connected
between the wells 26 and 32, a gas recovery system 62,
a make-up solvent source 56 and a gas make-up source
57. Injection well 26 is drilled into the reservoir
and is fed by solvent/gas line 54 from a solvent
source 56 and gas source 57, or by recycled solvent
from stripper 66 depending on the amount of solvent
recycled and the injection requirements. Recycled
solvent is taken off the stripper 66 in gas form
through line 72, and condenser 73 to distillate drum
75 whence it may be pumped back to the stripper 66 on
line 76 through a pump (not shown) or into the well
via line 77 and pump 71. Gas dissolved in the solvent
may be taken off the distillate drum 75 along line 74.
The hydrocarbon solvent and gas is injected into the
aquifer by the well 26 with pressure controlled by the
pressure of gas source 56. The pressure required to
lift the produced liquids arises from the action of
pump 42. Mobilized production oil is forced by the
pump 42 of Fig. 3A through tubing 34 of the production
well 32 as indicated by the arrow 58. Gas produced
along with the oil flows through the annulus between
the tubing 34 and casing 36 as indicated by the arrow
60 to a gas recovery system 62 of conventional design.
Removal of reservoir and some chamber gas is believed
desirable since it is believed to assist in keeping
diluted bitumen flow channels open. Removal of gas
from the casing preferentially removes more volatile
_ ~147~79
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gases such as methane and carbon dioxide. The produced
gas can be recycled by compression.
Liquid production under pressure from pump
42 is pumped along line 64 to solvent stripper 66.
Heat from a source 67 is applied to the production
liquid through reboiler 68. Oil is produced along line
70 leading from reboiler 68, and solvent vapor is
returned along lines 72 from the stripper 66 for
injection into the reservoir through injection well 26
as required. The produced oil will be hot and heat may
be recovered from the produced oil.
In a preferred embodiment of the invention,
illustrated by reference to Fig. 7, the method is
applied to a field that has been previously produced
by existing horizontal production wells 80 lying at
the top of a reservoir 82. Such wells will have water
coning such as shown by cone boundaries 83. Production
wells 84 are preferably drilled into the base of the
reservoir and displacement gas 86 is injected into the
existing production wells 80 until communication is
established between the wells 80 and the wells 84.
Upon communication being established (or before then,
with some loss of efficiency) liquid vaporizable
hydrocarbon solvent is injected along with the
displacement gas into the injection wells 80, and
mobilized hydrocarbons are produced from the
production wells 84. Although production from
production wells 84 below the reservoir may be used,
communication can be established between laterally
spaced injection wells and production wells, even at
the same depth, if communication can be established.
In one example using a model of an oil
reservoir, the condition of a reservoir with a bottom
water layer was simulated. The solvent and nitrogen
CA 02147079 2005-08-23
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were injected near the water oil contact at one end of
the model and the oil was extracted by upward leaching
and produced from another well placed at the bottom of
the cell at the other end. The results of this
5 experiment are shown in Fig. 8 in which the curves
show, from top to bottom, the amount of nitrogen, live
production, debutanized oil, injected solvent and
solvent recovered.
In another set of experiments presented here
10 the possibility of using an embodiment of the
invention in a sideways leaching chamber was tested. A
high pressure, windowed, visual, scaled, physical
model was used in the experiments described below. A
front perspex plate of the cell allowed visualization
15 of the extraction process. A windowed steel plate
supported the perspex plate against the pressure
inside the cell. The dimension of the cell cavity was
706.4 x 205 x 31.8 mm. Experimental conditions are
summarized in Table I. Ottawa sand (20-30 meshy was
20 used as the packing in these examples.
In the experiments, the packed cell is
weighed on a load cell. The liquid solvent is
supplied at the operating pressure and preset rate
using an ISCO syringe pump. Nitrogen is supplied from
25 a cylinder through a mass flow meter. The regulator
on the cylinder controls the pressure to the preset
operating pressure. Produced oil drains to a
collection pot by gravity. As the liquid level in the
pot rises production is emptied to glass bottles. The
30 evolved gas is collected in a bubbler over water. The
gas bypassed from the top of the collection pot is
measured in another bubbler. Compositions of these
gas streams are analyzed using a gas chromatograph.
A Kitheley-Mertrabyte DAS-8PGATM and EXP-16TM data
CA 02147079 2005-08-23
21
acquisition system is used to record temperatures in
the cell and ambient temperature, operating pressures
and weight of the cell and display experimental data.
In the example #Lex4, but not in the other examples,
5 water was injected at a controlled rate using a PULSA
7120TM diaphragm pump.
The scaled cell is vibro packed with 20-30
mesh Ottawa sand and the permeability of the packing
measured. The sand pack is flooded with water for
10 sufficient time to remove gas bubbles. The water in
the cell is displaced by Lloydminster Tangleflags
heavy oil heated to about 50°C under a low applied
pressure (20 psig). The oil filled cell is cooled to
the ambient temperature prior to the beginning of the
15 experiment. Weights of the cell noted at different
stages of this operation and the displaced water gives
the porosity of the packing, water and oil saturation
in the cell and the original oil in place.
The cell remains supported by the load cell
20 during the experiment and the weight change during the
experiment gives the balance of the injection to and
production from the cell. Initially nitrogen is
injected at a controlled rate until gas breaks
through. Then the liquid solvent and nitrogen are
25 injected simultaneously. The produced oil is
collected in a collection pot by gravity. A level
indicator attached to the pot shows the fluid level
and as the level goes higher the produced fluid is
transferred to glass bottles from time to time.
30 During this transfer the pressure on the fluid is
reduced to atmospheric and considerable solvent boils
off from solution and is collected by downward
displacement of water in a graduated cylinder
(bubbler). The solvent vapor is also accompanied by
2m7o~o
22
small amount of nitrogen. A stream from this gas is
passed through the gas chromatograph and the gas
composition is analyzed.
To maintain the vertical extension of the
vapor chamber throughout the thickness of the
reservoir some gas is continuously bypassed at a
controlled rate through the valve on top of the
collection pot. This helps in the movement of the
carrier gas carrying solvent through the packing to
the unextracted crude interface. This vapor is
collected in another bubbler and its composition is
also analyzed. Results of these chromatographic
analyses are used to find the amount of solvent and
nitrogen flowing into each stream.
In the experiment #Lex4 the Pulsafeeder pump
was connected to the injection line and the line
pressurized to the experimental pressure with water at
the beginning of the experiment. After initial
breakthrough of nitrogen the injection of solvent and
nitrogen as above was accompanied by a controlled
stream of water. Due to the high capacity of the pump
the flow rate of water was greater than desired. As
a result water injection was stopped after some time
and controlled to a lower rate afterwards. The
produced oil was accompanied by water. The oil
samples were analyzed by Karl-Fisher technique for the
water content and the amount of extracted oil was
determined.
The results of the experiments were as
follows:
Experiment # Butex6
In actual field conditions, pressure may
need to be higher than about 0.779-0.814 MPa (100-105
psig). This can be achieved easily by increasing the
_ ~i~~o7~
23
carrier gas pressure. However, with increase in
pressure the diffusion coefficient in the gaseous
phase decreases proportionately to the reciprocal of
the pressure. Since in this process the butane vapor
has to reach the interface by diffusing through the
carrier gas the gas phase resistance to diffusion may
play a significant role in controlling the process at
higher pressure. This experiment was used to study
the effect of operating pressure on the process
performance. Due to the limited allowable operating
pressure of the physical model it was not possible to
raise the pressure. Hence in the experiment # Butex6
the pressure was lowered and controlled to 0.434 MPa
(50 psig). butane injection rate was maintained at
24.8 g/h and nitrogen was injected at a rate of 2.3
litre/h. Gas and butane were injected at the base of
the oil in the model at an oil/water interface. The
average production rate was 40.5 g/h compared to 41.7
g/h in a similar Butex experiment where the pressure
was 0.779 MPa. The operating pressure did not have
significant effect on the production rates over this
range.
Experiment # Lexl
As it is observed in the experiments using
butane as a solvent that extraction with liquid butane
in the presence of a high pressure gas does not
consolidate and plug the sand matrix the same
principle can be used in spreading chambers also.
This may be useful in reservoirs without bottom water
layer. This idea was demonstrated in experiment #
Lexl. The experiment started with an oil flooded cell
with an almost uniform water and oil saturation
( 79 . 10 everywhere in the pack. Initially Butane with
214'~Q7~
24
nitrogen was injected at the top of the cell
vertically above the production well. The pressure
was maintained at 0.779 MPa. At this pressure most of
the butane remains in the liquid phase and falls
through the vapor chamber to the interface and
extracts bitumen. As the chamber spread side ways the
butane injection point was moved along the top of the
reservoir to promote liquid butane draining along the
entire interface. Results of this experiment are
presented in Fig. 9. Oil was produced at a rate of
22.4 g/h for a butane injection rate of 9.5 g/h.
Nitrogen was injected at a rate of 1.5 litre/hr (about
1.8 g/h). Hence it is possible to use the present
method with the pressure above the vapor pressure of
the solvent. The vapor chamber is maintained by the
non condensible gas maintaining the high density
difference of a vapor-liquid system yielding a higher
gravity drainage rate and minimizing the net solvent
consumption.
Experiment # Lex2
In the experiment # Lexl movement of the
injection point is equivalent to employing a set of
closely spaced injection wells along the top of the
reservoir; for a thin reservoir this concept may be
prohibitively costly to put into practice. Although
offset may be possible, achieving initial
communication was a concern. The possibility of using
propane was also to be tested. In the experiment #
Lex2, nitrogen and propane were injected
simultaneously using an injection well placed at the
top corner of one end of the packing and oil was
produced at the bottom corner of the other end as
shown in Fig. 10.
- 214'~07~
The average temperature of the cell during
the experiment was 21.5°C. The vapor pressure of
propane at the same temperature is 0.879 MPa. Due to
the limitation of the cell the operating pressure was
5 maintained at 0.959 MPa. Thus the extraction was
being carried with liquid propane being injected and
vaporizing into a vapor chamber maintained by
nitrogen.
Fig.lO presents the experimental results.
10 The experiment started with injection of nitrogen gas
at the operating pressure. Nitrogen broke through
after a short time; the amount of oil produced during
the period was very small. This was followed by
injection of nitrogen and propane together, rates
15 being 1.25 g/h and 15 g/h respectively. For a very
short period after the injection of propane started
the oil was produced at a higher rate (50 g/h)
indicating that propane was invading through the
fingers created by nitrogen and contacting oil over a
20 larger interfacial area. However as those fingers
slowly filled with diluted oil the rate slowed down to
a typical gravity drainage rate. During the refilling
of the ISCO pump, propane injection was stopped
between the points X and Y shown in the figure.
25 However the production continued at the uniform rate
at 25 g/h, probably due to the presence of accumulated
propane in the chamber. Viscosities of the produced
oil measured at 20°C shows a considerable in situ
upgrading due to deasphalting with propane.
Experiment # Lex3
In this experiment i-butane was used as the
solvent. The initial breakthrough of nitrogen was
followed by injection of nitrogen and liquid i-butane.
._ 2147()79
26
Results of this experiment are presented in Figure 11.
Nitrogen was injected at a rate of 2.5 g/h and butane
injection rate was 24 g/h. After 7.5 hrs butane
injection rate was increased to 36 g/h anticipating an
increase in the production rate. The production rate
was increased slightly as seen in the curve for
cumulative production of debutanized oil. However
this resulted in lower nitrogen injection rate, higher
concentration of solvent in the produced oil and
bypassed gas. The solvent injection rate was reduced
back to 24 g/h at 12 hrs and continued for the rest of
the experiment. The average rate of production is
about 40 g/h.
Experiment # Lex4
In this experiment the effect of mobile
water on the performance of the process was
investigated. After breakthrough of nitrogen liquid
i-butane, nitrogen and water were injected together.
Results of this experiment are presented in Fig. 12.
Liquid butane was injected at a rate of 24 g/h and
average nitrogen injection rate was about 2 g/h.
Initially the water injection rate was about 225 g/h
which was stopped at 4 hrs as excessive water was
produced with the oil. The water injection pump was
adjusted and injection of water started at 7.5 hrs;
the injection rate was 70 g/h. The debutanized
produced oil was analyzed for water and the amount of
cumulative oil is presented in the curve marked
debutanized oil. The average rate of production in
this experiment is about 58.2 g/h which is
approximately 45~ enhancement in the production rate.
Probably a smooth and slower injection of water would
give even better results.
CA 02147079 2005-08-23
27
According to these results, the effect of
operating pressure was not significant in the range of
pressure used. In addition, the method of the
invention can be applied to laterally spaced wells
5 (sideways leaching?. Both propane and butane (iso and
normal) are effective as the liquid vaporizable
hydrocarbon solvent. The amount of noncondensible gas
used is small. Downward flow of mobile water enhances
the production rate significantly.
10 The hydrocarbon solvent may be injected in
the vapor state with the displacement gas, but this is
not preferred as it is difficult to maintain vapor
saturation in the displacement gas.
15 Table 1
Experiment
k
No . u~n2 c~ Crude S Solvent
Butex6 192.4 0.32LM 0.91 Butane +
NZ
Lexl 195.8 0.37LM 0.79 Butane +
N2
20 Lex2 194.0 0.33LM 0.93 Propane+
NZ
Lex3 195.0 0.35LM 0.89 i-C4 + NZ
Lex4 195 0 LM 0 . 87 i-C9,
. . H2o, Nz
0 36
Experiment Ave.
25 No. Pressure Temp.C Configuration
Butex6 0.434 21.6 Upward leaching
Lex1 0.779 21.8 Top injection*
Lex2 0.959 21.5 Top injection
Lex3 0.779 21.8 Top injection
30 Lex4 0.779 21.8 Top injection
* well moved
A person skilled in the art could make
35 immaterial modifications to the invention described and
claimed in this patent without departing from the essence
of the invention.
