Note: Descriptions are shown in the official language in which they were submitted.
CA 02281276 1999-08-31
A THERMAL SOLVENT PROCESS FOR THE RECOVERY OF
HEAVY OIL AND BITUMEN AND IN SITU SOLVENT RECYCLE
Field of the Invention
This invention relates to a process for the in-situ recovery of high viscosity
hydrocarbon resources from subterranean hydrocarbon bearing reservoirs with
the application of heat and solvent, a process of in situ solvent recycling,
and a
process for the indirect heating of the hydrocarbon bearing reservoir.
1 o Background of the Invention
Highly viscous hydrocarbons, known as heavy oil and bitumen, exist inside the
fine pores of the subterranean porous formation (known as a reservoir). To
extract the hydrocarbons from these reservoirs, the hydrocarbons have to be
mobilized inside the porous formation and allowed to flow to well holes
drilled
inside the formation. The mobilized hydrocarbon is then brought to the surface
and processed for its end use. Attempts to provide for the efficient in-situ
extraction of hydrocarbons from these porous formations have not, in general,
been particularly successful.
Although an enormous amount of resources are potentially available in the
form of heavy oil and bitumen, their high viscosities prevents their flow in
the
formations. Depending on the reservoir temperatures and the type of resources
the mobility of the fluid varies. In large areas of the underground Alberta
oil
sands the formation temperature is in the range of 10°C and the
hydrocarbons
in the formation are a few million times more viscous than water at ambient
conditions. Under these reservoir conditions the hydrocarbons have a thick,
semi-solid appearance and are substantially immobile even outside the
formation. In the heavy oil reservoirs the mobility is usually higher than
that at
the Athabasca oil sand reservoirs; however, conventional recovery techniques
CA 02281276 1999-08-31
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have been unsuccessful in recovering these resources. The high viscosities of
these resources demands special recovery techniques.
The mobility of these hydrocarbons is known to increase with increases in
temperature. Based on this principle various thermal recovery techniques have
been applied to the recovery of these hydrocarbons. In the cyclic steam
stimulation process, slugs of steam are injected into the reservoir to heat
the
formation and mobilize the oil. Each injection step is followed by a soak
period
to distribute the heat in the reservoir and the hot oil and steam condensate
are
l0 produced back to the surface. These steps are repeated several times until
the
recovery rate becomes uneconomic. This process has met with limited success
in relatively mobile bitumen and heavy oil reservoirs.
In situ combustion has also been attempted as a method for producing heavy
I S oil. In this process an underground fire is initiated and is propagated by
injecting air at higher pressure into the formation. The hot oil and the
combustion gases are produced to the surface. This process, although having
been investigated for a few decades, has not been very successful thus far.
Both
of the above described recovery techniques do not appear to have any potential
2o for the recovery of the highly viscous bitumen.
Steam assisted gravity drainage (SAGD), as described in Canadian Patent
1,130,201, R.M.Butler, 1982, a steam based process using a pair of horizontal
wells drilled into the reservoir and placed one vertically above the other,
has
25 been used successfully for the recovery of these high viscosity
hydrocarbons. In
this process steam is injected in the upper well of the well pair. The
injected
steam condenses inside the reservoir and heats the formation and hydrocarbons.
The hot mobilized oil and the condensed water drain to the lower horizontal
CA 02281276 2006-04-26
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well by gravity. This hot fluid is produced to the surface by natural or artif
cial
Lift. Heat transfer over a huge surface area along the edge of the steam
chamber
formed during the process and the gravity head are the key factors in
achieving
a high extraction rate in this process. Various other weU configurations have
also been attempted.
Although the SAGD process has met with commendable success, it suffers
from the inherent disadvantages of a steam process, some of which are listed
below:
a) The energy consumption for the steam generation for this process is
equivalent to about 25% of the energy of the hydrocarbons ultimately
produced.
b) Steam generation is accompanies by the emission of a huge volume of
green house gases.
Z 5 c) The cost for the steam generation facilities, water treatment and
disposal/recycle facilities ete. constitutes a major part of the total capital
investment.
Illustrative embodiments of the present invention mitigate some of these
problems
leading to a more efficient and environmentally friendly recovery process.
The viscosity of heavy oil and bitumen may also be reduced by injection of
solvent into the re,~ervoir. Figure 1 presents a comparison of the effect of
solvent dilution and heating on bitumen viscosity. This forms the theoretical
basis for any solvent recovery process. Many of the prior proposals for the
recovery of these resources using solvents relied on the use of vertical
wells.
Solvent gases comprising carbon dioxide, lower alkanes e.g: methane, ethane,
propane etc. and atkenes such as ethylene, propylene and the isomeric butenes
CA 02281276 2006-04-26
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were proposed for this purpose. Due to the limited contact area between the
solvent and oil in this arrangement using vertical wells, the anticipated
extraction rates were relatively low.
Other proposals using single horizontal well huff and pu~processes or twin
horizontal well continuous processes for solvent vapor extraction of heavy oil
and bitumen have been proposed. In these solvent-based extraction processes,
efficient solvent recovery at the surface is crucial for the economic success
of
the process. When using only vaporized solvent the development of initial
communication between the injector and the producer wells may be very
challenging in highly viscous hydrocarbon reservoirs.
Summary of the Invention
An illustrative embodiment of the invention provides a method for the in-
situ recovery of viscous petroleum hydrocarbons from an underground
formation comprising: providing a production well within the formation;
providing solvents in the formation above the production well which are
capable of dissolving in and diluting the hydrocarbons to reduce the viscosity
and promote drainage of said hydrocarbons toward the production well, with a
2o vapour chamber being created above the production well in the hydrocarbon-
depleted formations resulting from said drainage; maintaining a hot zone
adjacent to or at the production well to vaporize the solvents contained in
the
dowawardly draining hydrocarbons prior to their entry into the production well
such that the vaporized solvents move upwardly through the vapour chamber in
a continuing manner to again contact said hydrocarbons in the formations at
the
boundaries of the vapour chamber to promote the continued dilution and
drainage of the hydrocarbons toward said production well whereby a
substantial portion of the solvents are recycled in a closed-loop fashion.
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A typical embodiment of the invention provides a technique for the in-situ
recovery of viscous petroleum hydrocarbons from an underground formation
using a combination of heat and vaporized solvents comprising greenhouse or
waste gases, and hydrocarbons; the process may be termed a "thermal solvent
process". Solvent is typically injected through a horizontal well (injector
well)
either as vapor or vaporized in situ by applying heat as described below. Hot
solvent vapor contacts the cold viscous hydrocarbons and condenses, dissolves
and diffuses into the hydrocarbon in the reservoir. As a result, the viscous
hydrocarbon is diluted to a lower viscosity fluid, which drains to the
production
l0 well that is placed vertically below the injector well at a suitable
distance inside
the reservoir. Under certain circumstances the injection and the production
wells may be staggered and need not be vertically above each other. A set of
vertical wells may also be used, instead of a horizontal well, to inject the
solvent into the reservoir. Although the primary effect of viscosity reduction
is
achieved due to the solvent dilution, the increased temperature inside the
reservoir also aids the process by causing additional reduction in viscosity.
Depending on the solvent composition used there may be some in situ
deasphalting and upgrading of the viscous hydrocarbon. This may also cause
some reduction in viscosity.
The production well is typically completed with a closed loop circulation
heating arrangement. Steam or any other hot fluid is preferably circulated
through concentric tubings of a closed loop circulation heating system to
transmit heat to the reservoir fluid without contacting the reservoir with
steam
(termed as indirect heating). The indirect heating of the reservoir sand and
fluids reduces the required amount of treatment of water at the surface for
the
purpose of recycling or disposal. This also eliminates the operating pressure
and temperature constraints, which are dictated by the fracture pressure of
the
CA 02281276 2006-04-26
~Y
formation. The purpose of this supply of energy into the reservoir is to boil
off
the solvent dissolved in the diluted oil (termed as "reboil"). T'his
vaporized,
previously injected solvent, along with the required makeup amount of solvent
moves to the unextracted formation, contacts the viscous hydrocarbon and
continues the extraction process. This process is repeated in a continuous
fashion and the solvent component is recycled again and again inside the
reservoir. This process may be termed as "in situ solvent recycle". This
reduces
the solvent recycle at the surface, thereby reducing the size of the surface
treatment facility and the solvent recovery wait in addition to providing for
the
to sequestration ofthe waste gases and green house gases inside the extracted
reservoir. The capital and operating costs are also reduced significantly as
competed with prior art proposals.
A further illustrative embodiment of the invention provides a method for
recovery
of viscous petroleum hydrocarbons from an underground formation wherein a
production well is located in the formation, including the step of effecting
indirect heating of the formation to reduce the viscosity of said hydrocarbons
and promote movement of same toward and into the production well.
2o Preferably said indirect heating is effected by circulating hot fluid in a
tubular
structure situated in said formation adjacent to or at the production well.
Advantageously said tubular structure comprises at least one pair of
concentric
tubes arranged to provide for circulation of the heated fluids therein, and
the
outermost one of the concentric tubes is finned to promote heat transfer into
the
formation.
CA 02281276 2006-04-26
_'
As an enhancement to the "reboil" portion of the process, a third horizontal
well
could be drilled between the injector and producer wells or any other
location.
The purpose of this well would be to provide additional heat to the reservoir
thereby allowing the re-vaporization of the solvent from the oil to begin
before
the fluids reach the producer. The well would preferably contain two
concentric
tubings to act as a closed loop circulation string, similar to the one in the
producer. However, this well would not have a slotted liner so that the
formation fluids would not enter into the well.
One overall purpose of the process is to sufficiently saturate the bitumen
with
solvent, such that its viscosity is reduced enough to allow the oil to flow by
gravity drainage to the production well. The heating provided by the producer
serves to further reduce the viscosity of the oil through heating, and to re-
vaporize the dissolved solvent in the oil. This causes a "reboil" effect in
the
reservoir, as the re-vaporized solvent rises and combines with the injected
solvent vapor to continue the extraction of the viscous hydrocarbon. Indirect
heating through a third horizontal well is expected to enhance the reboil
effect.
The heated oil is produced to surface substantially free of dissolved solvent,
and potentially water, which will remain in the reservoir. As such, this
provides
a continuous process for the recovery of heavy oil from oil sands.
Apart from providing an e~cient recovery technique for these hydrocarbons
the process mitigates green house gas emission, and provides an innovative
technique for the disposal of these harmful gases while deriving benefits out
of
these. While most of the prior art thermal processes generate a considerable
volume of green house gases, an illustrative embodiment of this invention can
utilize
green house gases created through other processes and available solvent
streams to fluidify the high viscosity hydrocarbons in the subterranean
CA 02281276 2006-04-26
_g_
hydrocarbon reservoir and thus help to recover these hydrocarbons, leaving the
greenhouse gases inside the reservoir.
In accordance with one illustrative embodiment of the invention, there is
provided a
method including exposing an underground formation containing desired
hydrocarbons
to a solvent, to produce a fluid including a solvent portion and a desired
hydrocarbon
portion. The method further includes extracting at least some of the solvent
portion
from the fluid before the fluid exits from the underground formation.
Exposing may include injecting the solvent into the underground formation.
Alternatively, or in addition, exposing may include exposing the underground
formation to the extracted solvent portion, thereby recycling the extracted
solvent
portion. In either case, exposing may include exposing the underground
formation to a
vaporized solvent.
Injecting may include injecting a solvent including a waste gas.
Alternatively, or in
addition, injecting may include injecting a solvent including a hydrocarbon.
Injecting
may include injecting an organic solvent. Alternatively, or in addition,
injecting may
include injecting an inorganic solvent.
Injecting may include heating the solvent. This may include vaporizing the
solvent.
Heating the solvent may include maintaining a hot zone in a vicinity of an
injection
well via which the solvent is injected into the underground formation.
Extracting may include heating the fluid before the fluid exits from the
underground
formation. Heating the fluid may include vaporizing the solvent portion.
Heating the
fluid may include maintaining a hot zone in a vicinity of a production well
via which
the fluid exits from the underground formation.
Exposing may include injecting the solvent into the underground formation via
a first
one of at least three wells, the fluid may exit from the underground formation
via a
second one of the at least three wells, and extracting may include heating the
fluid by
CA 02281276 2006-04-26
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maintaining a hot zone in a vicinity of at least one of the at least three
wells. For
example, this may include maintaining a hot zone in a vicinity of at least two
of the at
least three wells, or may include maintaining a hot zone in a vicinity of each
of the at
least three wells.
Maintaining a hot zone in the vicinity of a well may include circulating
heated fluids
through a conduit extending through at least part of the formation. The
conduit may
include a pair of concentric tubes.
In accordance with another illustrative embodiment of the invention, there is
provided
an apparatus including means for exposing an underground formation containing
desired hydrocarbons to a solvent, to produce a fluid including a solvent
portion and a
desired hydrocarbon portion. The apparatus further includes means for
extracting at
least some of the solvent portion from the fluid before the fluid exits from
the
underground formation.
The apparatus may further include means for carrying out the various functions
described herein.
Other aspects and features of the present invention will become apparent to
those
ordinarily skilled in the art upon review of the following description of
specific
embodiments of the invention in conjunction with the accompanying figures.
Brief Description of the Drawings
Figure 1 is a graph showing the effect of solvent concentration and
temperature on
bitumen viscosity;
Figure 2 is a schematic diagram of a thermal solvent process in accordance
with an
embodiment of the invention showing a vertical cross section of the reservoir
perpendicular to the axes of a horizontal well pair;
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Figure 3, comprising Figures 3A and 3B, is a schematic diagram of a closed
loop
circulation heating unit in a production well for indirect heating of the
reservoir;
Figure 4, comprising Figures 4A and 4B, is a schematic diagram showing closed
loop
heating in the injection well;
Figure 5 is a schematic diagram of a third well with a closed loop system for
supplying
additional heat to enhance the "reboil" process; and
Figure 6 is a schematic similar to Fig. 2 and showing possible well locations
which
may be used in the thermal solvent process of illustrative embodiments of the
present
invention.
Detailed Description of Illustrative Embodiments
One illustrative method of in-situ recovery of heavy oil and bitumen, using a
combination of heat and vaporized solvents will be described with reference
firstly to
Figure 2. Heavy oil and bitumen are present in underground reservoir 1 shown
in
Figure 2, in a highly viscous and immobile form. The solvent is injected into
the
reservoir through a horizontal well 2 or a set of vertical wells drilled into
the reservoir.
The solvent typically consists of a combination of "greenhouse" or waste gas
and
hydrocarbon
CA 02281276 1999-08-31
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vapors. The waste gas portion of the solvent may consist of a combination of
one or more of carbon dioxide, sulfur dioxide, and hydrogen sulfide, including
small amounts of nitrogen and oxygen. The hydrocarbon traction of the solvent
may contain one or more of methane, ethane, propane, butane, pentane, hexane,
heptane, octane, xylene, toluene, distillate, natural gas condensate, naphtha
and
all of their isomers. The solvent may be injected either as a vapor, liquid or
a
vapor-liquid mixture and may be vaporized inside the reservoir by the
application of heat. The solvent selection strategy will be described later on
in
this specification.
t0
The hot solvent vapor moves through the vapor chamber 3 and condenses at the
oil-solvent vapor interface 4, dissolves in the heavy oil and reduces its
viscosity; the heat transfer effected at the interface also aids in viscosity
reduction due to the increase in temperature. The hot and diluted mobile oil
15 drains 5 by gravity to the base of the reservoir and forms a pool of
mobilized
oil 6. This mobilized oil is withdrawn continuously through the horizontal
well
7 and is produced to the surface, either by natural lift or using any
artificial lift.
Heat is injected into the reservoir at the base through the closed loop
circulation
heating system 8 in the production well 7 as explained below in detail. The
20 primary purpose of the heat injection is to boil the solvent out of the
diluted oil
accumulated at the base; the hot oil with minimal solvent is produced to the
surface through the production well. The vaporized solvent 9 goes back into
the
solvent chamber 3 inside the reservoir and again dissolves and leaches the
reservoir oil in the colder section of the reservoir. Thus the waste gases and
25 solvents used to aid the drainage of the oil by dilution, is recycled 10 in
situ,
and the waste gases are sequestered in the reservoir. Since, the same solvent
is
recycled and reused again and again inside the reservoir once continuous or
steady-state operation is achieved, only a small amount of makeup solvent is
CA 02281276 1999-08-31
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injected to fill up the void space created inside the reservoir due to oil
production. The amount of makeup solvent is also related to the amount of
solvent produced to the surface with the oil and the amounts of solvent
retained
inside the chamber 3 in the vapour phase and in the diluted residual oil. This
significantly reduces the surface operations, offering an efficient method for
the
recovery of highly viscous hydrocarbons with greatly reduced emissions.
The preferred solvent is selected on the basis of the reservoir temperature
and
operating pressure. The proposed solvent should stay in the vapor phase under
the conditions inside the vapor chamber 3. However, it should condense at the
solvent vapor-bitumen interface. Around the injection and the production
wells, due to higher temperature, the solvent will remain in the vapor phase.
However, the reservoir beyond the solvent oil interface will be close to the
initial reservoir temperature and the solvent should have enough solubility at
the interface. Ideally the solvent composition should be such that at these
temperatures and pressures it is in the vapor-liquid region and splits into
the
liquid and vapor phases in the required proportion.
The first step in solvent selection involves setting an operating pressure.
This
should be close to the reservoir pressure and obviously should be lower than
the
fracture pressure of the reservoir. A lower operating pressure ensures
confinement of the chamber 3 and maintains the vapor phase. On the other
hand a higher operating pressure translates into a higher amount of
sequestration, eliminates the need for artificial lift and increases the
solubility
of the waste gases and lighter components in the bitumen.
In the second step the range of temperatures achievable inside the reservoir
due
to the indirect heating is estimated. The third step involves pre screening of
the
CA 02281276 1999-08-31
possible solvent compositions through PVT calculations with the help of an
equation of state. Any PVT software package may be used for this purpose.
Solvent compositions in the vapor-liquid region at the operating pressure and
the lower end of the temperature range are short-listed.
In the fourth step either PVT measurements should be carried out or the same
PVT software package may be used (when the interaction parameters are
known / approximated) to estimate the solubility and the corresponding
viscosity reduction of these selections at the solvent oil interface
conditions.
t 0 The composition that yields the highest viscosity reduction would be
selected.
An overall optimization of the operating pressure, temperature range and the
solvent composition should be carried out for the best performance of the
process.
Example
Consider an example of a heavy oil reservoir with operating pressure and
temperature of 300 psig and 12 degree Celsius, respectively. With the
limitation of heat input by indirect heating, one may expect the near well
bore
region to be at 100 degree Celsius. Under this condition a 80-20 mixture of
ethane and propane would be suitable as a solvent. The mixture being in the
2o two phase region at the condition of the colder section of the reservoir
would
have good solubility in the oil. However, at the condition of the near well
bore
region, the solubility will be small and most of the solvent will vaporize and
help continue the process.
Figure 3 presents a schematic of the horizontal or nearly horizontal
production
well 7 with its closed loop heating system. This well is drilled from the
ground
surface 12 through the overburden 13 into the reservoir 1 and completed with a
casing 14 from surface to the horizontal segment of the well. In the
horizontal
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segment the well is completed with either of slotted liners, wire mesh wrapped
screens, prepacked liners, perforated casing, open hole or any combination of
these. The closed loop circulation heating system 8 consists of a pair of
concentric tubes placed inside the well and extends from the surface to the
end
(toe) of the well completion string 15 or open hole inside the formation
containing the viscous hydrocarbon. The external tube 16 of the pair of
concentric tubing, may or may not consist of sections of finned tubes of any
suitable design along the entire or part of the horizontal length, and is
closed
with a plug 17 at the toe. The inner tube 18 is of a smaller diameter than the
external tube, creating an annular space between the two tubings, 16 and 18.
Hot fluids including steam are injected through the inner tubing and condensed
liquid, with or without any vapor, returns to the surface through the closed
annulus. Alternatively the hot fluid is injected through the annulus of the
concentric tubing and the condensed liquid and associated vapor, if any, is
produced through the inner tubing. The heat is transmitted from the hot fluid
inside the external tubing to the fluid outside the external tubing through
the
wall of the external tubing without the fluids physically contacting each
other
and hence the process is termed as indirect heating.
The heat transfer process is limited by the amount of heat transfer area (the
wall
of the external tubing). Preliminary calculations show that only 50 m3/d
(condensed water equivalent) of steam could be used in a closed loop
circulation heating system of 1000 m horizontal length, and 1600 m total
length
with a external and internal tubing diameter 5'/2" and 3'/2" respectively.
Depending on the extraction rate in the thermal solvent process and the
solvent
concentration in the diluted oil in the mobilized liquid pool 6, the amount of
heat transfer may not be sufficient to vaporize or "reboil" all or most of the
solvent dissolved in the oil. The purpose of the fins on the external tubing
is to
CA 02281276 1999-08-31
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increase the heat transfer area and facilitate the heat transfer process.
Addition
of the external fins may result in utilization of more than 150 m3/d
(condensed
water equivalent) of steam inside the same closed loop system thus
substantially increasing the heat input into the reservoir 1. A second tubing
string 19 may be landed in the annular space between the closed loop heating
system and the completion casing. This tubing is used to withdraw the fluid to
the surface either by natural lift or artificial lift.
The solvent injection well 2 may also be equipped with a closed loop
circulation heating system 11 to vaporize any liquid solvent injected through
this well.
A schematic of the solvent injection well is presented in Figure 4. This has a
very similar configuration to the production well except the solvent is
injected
into the annular space between the casing 20 and the outside of the external
tubing 21 of the closed loop circulation heating system 8. The closed loop
circulation heating system in the injection well is used only when additional
heat is needed and may not be necessary and may be eliminated. In some
reservoirs a set of vertical wells may also be used as the injector in place
of the
horizontal injection well.
To provide sufficient heat for the "reboil" effect and enhance the solvent
recycle, it is proposed that a third well be drilled into the formation near
the
base in the pool of diluted hot liquid 6 as explained in Figure 2. A schematic
of
this well is presented in Figure 5. This well is drilled from the ground
surface
12 through the overburden 13 into the reservoir 1 and completed with a casing
22 from surface to the horizontal segment and left open hole 23 in the
horizontal segment. The closed loop circulation system 8 is placed inside the
CA 02281276 1999-08-31
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well. If normal tubing instead of the finned tube is used as the external
tubing
of the closed loop system, this may act as the casing thus eliminating the
casing
22.
As discussed above the process may employ two and possibly three horizontal
or nearly horizontal wellbores, one above the other, with a vertical
separation
of 5 to lOm, or staggered with a horizontal separation, drilled into the
formation
containing the highly viscous hydrocarbon. The possible location of the wells
relative to the production well is presented in Figure 6 which presents a
vertical
cross section of the reservoir perpendicular to the axes of the horizontal
wells.
The production well 7 including the closed loop circulation heating system as
described in Figure 3 is placed at the bottom of reservoir. The solvent
injection
well 2, with or without the closed loop circulation heating system, is placed
above the production well. The position of the well 2 vertically above the
production well may be used. Alternatively this injection well may be
staggered
horizontally depending on the viscosity of the reservoir crude and other
reservoir parameters and operational reasons either of positions 25 or 26 may
be used. Depending on the in situ viscosity of reservoir hydrocarbon, the
horizontal distance between the injection well 2 and the production well 7 may
vary from 0, in which case the injection well is vertically above the
producer, to
150m. The third well 24 for additional heat supply may be placed either
vertically above the production well 7 or staggered to positions 27 or 28. The
vertical separation between the third well 24 and production well 7 may be 0,
in
which case the wells are at the same horizontal plane, to Sm. The horizontal
distance between the production well 7 and the third well 24 may vary from 0,
in which case the injection well is vertically above the producer, to 150m.
Under certain situation this third well may not be needed and is eliminated
altogether. One or more of the set up presented in Figure 6 may be placed in
the
CA 02281276 2006-04-26
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reservoir with a selected pattern to extract the viscous hydrocarbon.
Unlike other proposed processes of using solvents) for the extraction of
viscous hydrocarbon this process employs both heat and solvent vapors. The
presence of the closed loop circulation heating system in the present
embodiment
will be very helpful during the start up process, which is a major issue in
the
other proposals. During the start up in this process the hot fluid may be
injected in the closed loop circulation heating system of any or all of the
well 2,
7 and 24. Solvents including those mentioned in this invention or other
t0 reasonable organic or inorganic solvents compatible with the hydrocarbons
being extracted may be injected into the wells 2, 7 and 24. The effect of this
heating or the combined effect of heat and solvent would create the required
communication between the injector and the producer. In another situation the
closed loop circulation heating systems may be lowered into the wells after
communication between the injector and the producer is established by
circulating steam or hot fluid in these wells. In any case, once the required
communication between the injector and the producer is achieved, the thermal
solvent extraction process is initiated.
Some of the major advantages of the present embodiment include (a) the usage
and sequestration of the green house and waste gases inside the reservoir, (b)
in
situ recycling of the solvent reducing surface operation, and (c) providing an
efficient and economic process for the recovery of heavy oil and bitumen.
Illustrative embodiments of the invention have been described and illustrated
by
way of example. Those skilled in the art wiU realize that various
modifications
and changes may be made while still remaining within the spirit and scope of
the invention. Hence the invention is not to be limited to the embodiments as
CA 02281276 1999-08-31
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described but, rather, the invention encompasses the full range of
equivalencies
as defined by the appended claims.
15
25
