Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
CA 02235085 1998-04-17
CANADA
PIASETZKI 8~ NENNIGER
PN File No.: NE10191JTN
PATENT APPLICATION
Title: METHOD AND APPARATUS FOR STIMULATING
HEAVY OIL PRODUCTION
Inventor: John Nenniger
CA 02235085 1998-04-17
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TITLE: METHOD AND APPARATUS FOR STIMULATING HEAVY
OIL PRODUCTION
FIELD OF THE INVENTION
This invention relates generally to the extraction of hydrocarbons
s such as heavy oil and bitumen from naturally occurring formations such as
tar sands or the like. Most particularly this invention relates to a means to
accelerate the recovery process thereby increasing the rate of return on
capital and decreasing 'the financial risk of such heavy oil production
projects.
to BACKGROUND OF THE INVENTION
Heavy oil and bitumens, such as may be found in deposits known as
tar sands, may have viscosities greater than 1000 centipoise or specific
gravities greater than .934 at 60°F (i.e. less than 20° API).
Hydrocarbons
with such a high specific gravity and viscosity are difficult to efficiently
is recover because they do not readily flow.
It has been long known that heat can be used to decrease the
viscosity of heavy oils and hence improve the flow . Currently steam is the
most common thermal stimulation used for heavy oil extraction. However,
steam stimulation is subject to a number of problems, including heat losses
2o during injection, clay swelling problems, thief zones, emulsions, capillary
surface tension effects and lack of confinement for shallower zones. In
addition to these problems, the heating equipment is expensive to purchase
and install and even more expensive to run, because of the large energy
consumption required. For these reasons alternate techniques are being
25 SOUght.
Another thermal extraction technique, known as fireflood, is generally
uneconomic due to very severe operating problems including corrosion,
scale precipitation and explosion hazards after breakthrough.
One of the factors affecting the recovery of in situ oil, is the well
3o configuration. There are many different well configurations used. Different
well configurations are used in different recovery techniques. The two main
approaches in the past have been "huff and puff' (i.e., cyclic steaming) and
steam floods. Recently, steam assisted gravity drainage (SAGD) has also
been proposed and used.
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SAGD requires the formation of a steam chamber. The steam
chamber is essentially what is left behind in the oil bearing formation after
the oil has been recovered from the chamber; as more oil is recovered, the
chamber grows. Essentially in SAGD, water is heated above grade to form
s steam, and then the steam is injected into the formation into the chamber.
The heated oil flows down the walls of the chamber and drains into the
producing well. The advantage of SAGD that the countercurrent flow of
steam upwards into the chamber in the reservoir and oil down and out of the
reservoir is relatively efficient, thus the fluid flow rates may be high
enough
to to provide favorable economics.
There are many ~>ossible SAGD geometries including single well
(injection and production from the same well) and dual or multiple well. The
wells may be either horizontal or vertical. Generally horizontal wells are
favored because they offer a longer exposure to the oil rich pay zone and
is thereby facilitate economic production rates for highly viscous oils.
Single well SAGD requires the least capital cost, but heat losses due
to countercurrent flow of steam into the well and oil out of the well having
passing contact in the wellbore can be quite severe. For example, at an
injection pressure of 1000 psig and 285°C, the enthalpy of the steam is
1192
2o btu/lb and the enthalpy of the water is 542 btullb. Due to countercurrent
heat exchange the temperature of the produced fluids (water and oil) will
lower the temperature of the injected steam to some low temperature
equilibrium point. Usually, the steam quality is 80% (i.e., 80% vapour and
20% liquid). Thus, the maximum heat delivered to the formation is only the
2s latent heat of vaporization (i.e. about 50% of the total heat input). With
additional heat losses through the well casing during injection, the net heat
delivery to the formation is quite low and therefore this technique
inefficient.
The idea of replacing steam with cold solvent was first proposed by
Nenniger' (1979). This technique has shown much promise for production
30 of heavy oil with minimal environmental impact, primarily because oil
production would not require the use of significant amounts of water and
energy to form the needed steam. Energy requirements for cold solvent
extraction are expected to be less than 4% of those required for steam
extraction. Insitu recovery with cold solvent has minimal environmental
' Nenniger, E.H., Hydrocarbon Recovery, Canadian Patent 1,059,432
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impact compared to surface mining techniques.
The physics of cold solvent stimulation are not fully understood. The
measured solvent diffusion rates are typically 100-1000 times higher than
predicted by theory2~3. A key economic requirement is efficient recovery of
s the solvent, so light gases such as ethane and propane which can be
recovered by pressure blowdown are generally preferred. A recent study
has reported the ratio of ethane solvent loss to bitumen produced, was low
as seven percent (wtlwt).
However, the calculated production rates for solvent extraction are
to believed to be too low to justify commercial application and a field test
of
cold solvent extraction has never been performed. Bench tests4 with warm
solvent (propane) have shown that production rates can be increased about
20 fold simply by increasing the temperature from 20°C to 90°C.
However,
the heat capacity of heated solvents (i.e. vaporized propane and ethane) is
is very low, so it is impractical to heat hydrocarbon gas above grade and pump
the same downhole and achieve any heat delivery at the reservoir.
The Vapex process4 proposes to combine heat with solvent to benefit
from possible synergies. However, the heat is provided by steam or hot
water which is heated above grade and consequently suffers from the all
2o problems mentioned above (countercurrent heat exchange, formation
damage problems with clays, emulsions, capillary pressure, water treatment,
water supply, etc).
Lab tests and modeling have shown that the viscosity reduction of the
oil occurs due to dissolution of the solvent into the oil and the upgrading of
2s the oil by de-asphalting. The de-asphalting appears to occur locally when
the oil is initially mobilized by dilution with solvent. Thus, in lab scale
tests
there has not been evidence of formation damage due to asphaltene
accumulation in the near wellbore area.
A key requirement for both steam assisted gravity drainage and
z Dunn, S.G.; E.H. Nenniger, V.S.V. Rajan, A Studx of Bitumen Recovery by
Gravity
Drainage Usine Low Temperature Soluble Gas Injection, The Canadian Journal of
Chemical
Engineering, Vol 67, December 1989.
3 Lim, et al, Three dimensional Scaled Physical Modelling of Solvent Vapour
Extraction
of Cold Lake Bitumen, JCPT, April 1996, Page 37
4 See Table 1 and Figure 7 of Butler et al, A New Process for Recovering Heavy
Oils
using Hot Water and Hydrocarbon Vapours, JCPT Jan 1991, pg 100
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solvent assisted gravity drainage is the formation of a steam or solvent
chamber in the reservoir. The chamber allows efficient countercurrent flow
of solvent (or steam) upwards and flow of the heavy crude downwards along
the walls of the chamber. The predicted oil drainage rate is proportional to
s the square root of the height of the chamber (reference 4). Thus the oil
production rates are predicted to be small initially and then grow with time
until the roof of the chamber encounters a boundary such as an
impermeable shale. Lab tests have confirmed the beneficial effect of the
formation of the solvent chamber. Lab tests have also shown that the
io maximum oil production rates will not occur until a large solvent chamber
is
formed. Unfortunately, this means that peak oil production rates do not
occur until 3-4 years after' the well is placed on production.
Thus, for cold solvent extraction the peak oil production rates are not
expected to be achieved until perhaps three years after the capital costs of
is the well and the production facilities are incurred. The delayed production
response decreases the rate of return and increases the risk to the operator.
For example thief zones, etc, may not be identified until substantial costs
have been incurred and yet before the recovery has become economic.
Thus, there is potential for a significant economic benefit, if the
2o solvent chamber could be quickly established. For example, the capital cost
of drilling and completing a horizontal well might be typically 500,000
dollars.
The minimum internal rate of return for a oil project is typically about 15%.
Thus, the opportunity cost of a one year delay in the peak production rate
is 75K$. If peak production is accelerated, so it occurs in the first year
rather
2s than the third, then the value added by early development of the solvent
chamber would be 150K~ to 250K$ per well.
Thus, while the cold solvent extraction process has great advantages
due to energy efficiency and minimal environmental damage, it has never
actually been field tested. The primary reason for this is the belief that the
3o cold solvent production rates will be too low to be economic, particularly
with
the expected 3-4 year delay in achieving peak production rates.
BRIEF SUMMARY OF THE INVENTION
What is desired therefore, is a means to accelerate the initial oil
production rate by encouraging the rapid formation of a solvent gravity
3s drainage. According to one aspect of the present invention there is
provided
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a method to accelerate the process of forming a gravity assist drainage
chamber by effectively and rapidly injecting significant volumes of
sufficiently
heated gaseous and liquid solvents into the reservoir using downhole heater
technology.
The preferred apparatus to perform the method of the present
invention is a coiled tubing conveyed downhole heater. This heater can be
used to place the desired heat without the usual wellbore heat losses
associated with surface injection of hot fluids. In the preferred method the
heater is lowered into the well, placed on a pump seating nipple or packer
io and the cold fluid is pumped into tubing-coiled tubing annulus. The cold
fluid
is heated as it passes through the heater and then the hot fluid is squeezed
into the formation. Because the heater is deployed on coiled tubing, it can
also be displaced to the end of a horizontal well. The most preferred heater
has an extremely high output (for example more than about 100 kW), yet it
is fits inside 2 718" production tubing. Because the heat is added downhole
close to the target formation, it is feasible to heat fluids with relatively
low
heat capacities (i.e. hydrocarbon gases and liquids) and provide efficient
delivery of heat into the formation with minimal heat losses.
Thus according to an aspect of the present invention a heated solvent
2o stimulation is performed to initiate formation of a gravity drainage
chamber.
Once the chamber has been established, there would be a large interfacial
area for efficient mixing of the solvent into the oil. Subsequent cold solvent
injection would achieve commercial production rates without requiring
additional heat. Therefore according to the present invention there is
2s provided: A method for stimulating heavy oil production from an oil bearing
formation comprising:
a) placing a downhole heater in the formation adjacent to the oil
producing zone, to heat a heat transfer fluid;
b) energizing said downhole heater and passing said heat
3o transfer fluid past said heater to thereby heat said heat transfer fluid;
c) injecting said heated heat transfer fluid into the oil bearing
formation to bring said heated fluid into contact with said oil to thereby
decrease the effective viscosity of said oil; and
d) recovering said reduced viscosity oil to form an oil extraction
3s chamber in said oil bearing formation.
According to another aspect of the invention there is provided a
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method according to the foregoing further including the step of regulating the
pressure in said heater to permit low heat capacity solvents to be heated.
According to a further aspect of the invention there is provided a
downhole heater having a pressure regulator at an exit end of said heater
s for maintaining pressure in said heater sufficiently high to permit
efficient
heating of low heat capacity fluids.
BRIEF DESCRIPTION OF THE DRAWINGS
Reference will now be made, by way of example only, to preferred
embodiments of the invention as illustrated in the accompanying drawings
io and in which:
Figure 1 illustrates a schematic of the invention, the injection of hot
fluid into the heavy oil reservoir to accelerate the creation of a solvent
chamber.
Figure 2 illustrates a typical well site deployment for the hot solvent
is stimulation
Figure 3 illustrates a typical solvent chamber created as a
consequence of the injection of hot solvent.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
Figure 1 shows a schematic of the apparatus used in the method
2o according to the present invention. A heater 2 is mounted on the end of a
length of coiled tubing 4~. The heater 2 is deployed from a coiled tubing
truck 6 to a target zone 8 by an injector 10. During deployment a pressure
seal 12 is formed between a wellhead assembly 14 and the coiled tubing 4
by a stripper 16. Once the heater 2 has reached the target zone 8, a BOP
2s (Blow Out Preventer) 18 is energized and an additional pressure seal
around the coiled tubing is formed with the BOP tubing rams in a
conventional manner. A power cable 5, carried within the coiled tubing 4 is
used to energize the heater 2. As the power cable 5 is contained within the
coiled tubing it is protected from damage due to abrasion and pressure
30 cycles.
The heater 2 may be in the form of an electrically powered resistance
heater of the flow through type. While other heater designs would also
work, the electrical resistance heater provides adequate results. To provide
best results it is preferable to have a power output of more than 100 kw .
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The heater is most preferably compact i.e. small diameter and of a short
length (preferably less than 2 metres) to be easily positioned in the well
near
the formation to be treated. A packed bed resistance element as disclosed
in my prior patent 2,052,202 will provide adequate results.
s A heat transfer fluid 20 is pumped through a valve 22 and into a flow
"T" fitting 24. The fluid 20, which is described in more detail below, then
travels downhole in the annulus between well tubing 26 and the coiled
tubing 4. A seal 27 between the heater 2 and the well tubing 26 forces the
fluid 20 through the inside of the heater 2 and thereby provides fluid flow
io past the heating elements of the heater 2. The seal 27 is usually achieved
via a pump seat or a packer. The fluid 20 passes through the heater 2, and
is thereby heated. The fluid 20 then passes through a pressure reducer 28
and is displaced out into the reservoir target zone 8 through perforations 30
in the casing 32.
is Simultaneous withdrawal of the heavy oil up the tubing-casing
annulus 34 may or may not take place during hot fluid injection. For
instance, it may be advantageous to allow the hot fluid to soak in the well
for
a short period prior to oil production to allow the heat to penetrate further.
The pressure reducer 28 maintains a high fluid pressure inside the
2o heater. This is very useful for multi-phase (i.e. combined gas & liquid
phases at downhole temperature and pressure) fluids, because high
pressure helps to minimize the difference in the volumetric heat capacities
between the gas and liquid phases and thus helps avoid the formation of hot
spots in the heater.
2s The pressure reducer 28 is most preferably in the form of a flow
restriction such as a valve (such as a back pressure regulator) or narrow
orifice. For the purpose of this invention it will be understood that pressure
reducer 28 is any structure that has the effect of increasing the pressure
upstream of the pressure reducer 28 namely in the heater 2. The pressure
3o reducer 28 may be fixed in effect or may be variable in effect. In other
words, the pressure reducer 28 may be for example a fixed orifice which
does not change with flaw through and thus has a variable effect on the
upstream pressure (the higher the flow the greater the pressure). Or the
pressure reducer may be in the form of a valve which changes orifice size
3s to allow various flows through the pressure reducer as required. The
preferred form of the invention is a back pressure regulator which can be
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preset to maintain a given pressure over a range of flows, to ensure efficient
heat transfer to the fluid from the heater.
It will be appreciated that the higher the temperature, the greater a
pressure will be required to keep the heat transfer fluid in a liquid state in
the
s heater 2. The higher pressure can be achieved by altering the flow rate
(i.e.
increasing the flow rate to increase pressure as the temperature increases)
or by altering the orifice size, (i.e. decreasing the orifice at the same flow
rate as temperature increases).
In the most preferred form of the invention the pressure reducer 28
to is a variable sized flow restricter which can be adjusted during operation
of
the heater 2 to maintain pressure in the heater 2 at a desired level. A less
preferred but adequate pressure reducer 28 is one which is sized and
shaped to cause a predetermined pressure at a predetermined flow rate of
a particular fluid , having regard to ambient reservoir conditions. It will be
is appreciated that the predetermined pressure will be the pressure required
to maintain substantially even heat transfer to the heat transfer fluid 20 in
the heater to prevent local hot spots from developing in the heater leading
to heater burnout.
In addition the pressure reducer 28 is most preferable in the form of
2o an active element which is remotely adjustable as needed to maintain the
desired pressure. In such a case the pressure reducer 28 is actively
incorporated into a control system to permit the size of the orifice to be
remotely adjusted as needed for pressure maintenance. A less preferred
form, but one that still provides adequate results, is to use a passive
2s pressure reducer 28, and to monitor the pressure, temperature or flow
through the heater 2. In the event that non-optimal conditions exist in the
heater 2 then the temperature or flow rates (pumping rates) can be modified
to bring the conditions in the heater back into optimal conditions. In this
regard, optimal conditions refer to pumping as much fluid 20 through the
3o heater 2 as quickly as possible at a pressure sufficient to keep the heat
transfer to the fluid in the heater 2 substantially even to permit optimal
heat
transfer without the formation of hot spots leading to heater burnout.
In the preferred method, a sufficient volume of hot fluid 20 is injected
into the target zone 8 for a sufficient time to allow a large volume of insitu
oil
3s to be liquefied and drained. The injection pressure may be above fracture
pressure. The injected fluid 20 will be displaced away from the wellbore as
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more fluid is injected but, depending upon the heat capacity of the fluid 20,
as compared to the heat capacity of the formation, the heat will likely be
lost
fairly quickly to the near wellbore region.
The preferred heat transfer fluid 20 is a solvent for the heavy oil. The
s solvent can be either a gas or liquid or a mixture thereof at ambient
conditions. Better results are expected if the solvent is slightly below its
bubble point pressure at reservoir conditions, so that it is present as a gas
in the solvent chamber but has appreciable solubility in the crude oil. The
solvent can be either a mixture of compounds (i.e., methane, ethane,
to butane, propane, pentane, hexane plus other hydrocarbons, and carbon
dioxide) or a relatively pure compound. Because any solvent co-produced
with the oil can be extracted and recycled back into the reservoir, the
solvent
will typically be a blend of compounds. As discussed above the fluid 20 will
also be keep sufficiently dense as either a liquid or gas in the heater 2 that
is an efficient and even heat exchange takes place with the heater elements.
Pure gas pockets would lead to local hot spots and burnouts which why
there is a need for pressure maintenance in the heater as previously
discussed. The most preferred solvents are the so called light
hydrocarbons, from C1 to C4.
2o While the preferred form of the invention is to use a solvent as the
heat transfer fluid, it will be appreciated that present invention also
comprehends the use of other fluids such as water or steam or a mixture
thereof which are not solvents. For these fluids the change in viscosity of
the
in situ heavy oil is derived solely from the heat delivered to the formation
by
2s the fluid. It will be appreciated that the one of the preferred forms of
the
present invention is a method of relatively quickly (in the order of hours or
days) modifying the viscosity of the in situ oil. As such, for some formation
conditions it may be more efficient to deliver a greater amount of heat, via
a higher heat capacity fluid such as water, than to provide additional
3o viscosity reducing effects such as a solvent would provide. However, it
will
be appreciated that the use of solvents is generally preferred due to the
relative permeable effects and other negative effects that can occur when
introducing water into an oil producing formation. Quite simply, in some
reservoirs, introducing water into the oil bearing zone may cause lower
3s production once the short term effect of the heat added dissipates.
Figure 2 shows the typical deployment of equipment used to
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implement the invention on a well site. There is a solvent truck 36 (in this
case a propane truck), and a rig tank 38 with kill fluid 40. The fluid 20 is
pumped from the solvent truck 36 to the wellhead 14 via conventional tubing
42. Fluid pressure may be raised by a charge pump unit 44, if needed. A
s check valve 46 and a relief valve 48 are preferred as safety features to
avoid
excessive fluid pressure.
In some circumstances, it may be desirable to have a flare stack on
site also. Alternatively there may be a (or several) propane tanks) which
are periodically refilled by propane trucks 36.
to Also shown is a generator truck 50 which supplies power to the
heater 2 via power and ground transmission lines 54 which connect the
generator truck 50 to the coiled tubing truck 6. Process control trailer 52,
is
connected via data acquisition, power and control lines 56 to the coiled
tubing truck 6 and the generator truck 50.
is Figure 3 shows more detail of cross section AA of the heater 2 of
Figure 1. A chamber 60 is created in a heavy oil reservoir 62 by the
withdrawal of mobilized oil 64. The chamber 60 may initially form around a
fracture if the fluid injection pressure is above fracture pressure. The
fracture will be oriented either vertically or horizontally depending on the
2o depth of the reservoir. Over time, as the oil drains (shown at 64) it will
eventually form an inverted teardrop shaped chamber 60 around a point
injector (i.e. vertical injection well) and an elongated cylinder with an
inverted
teardrop cross-section around a horizontal well. Mobilized oil 64 drains
down the sides of the chamber 60 and into the casing via perforation tunnels
2s 30, or slots or screens in the casing 32. Fluid 20 (preferably solvent)
rises
in the center of the chamber 60 and dissolves into the fresh oil at the
surface
of the chamber. This process is very efficient because the upward flow of
solvent fluid 20 is physically separated from the downward flow of the
mobilized oil 64. Alternatively the pressure can be cycled to separate
3o solvent injection from oil production. As the oil withdrawal proceeds the
chamber 60 will grow in size until it encounters for example a shale barrier
66.
As can now be appreciated according to the invention described
herein the heated solvent does not suffer heat losses during flow downhole,
3s because it is pumped downhole at ambient temperature. Furthermore, the
present invention is not restricted to using water, as in the prior art to
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provide sufficient heat capacity to ensure that heat is delivered downhole.
According to the present invention the present method can be used to
initiate formation of a gravity drainage chamber of sufficient size that
significant production rates can be achieved very quickly. Once the
s chamber has been established, there would be a large interfacial area for
mixing of the solvent into the oil. Thus, subsequent recovery will occur with
cold solvent, at a low cost and with environmental benefits, or possibly with
periodic heat stimulations to, for example, spur extra production.
According to the present invention either a gas or hydrocarbon liquid
io is heated in the downhole heater and then this hot liquidlgas mixture is
injected into the formation to rapidly mobilize the oil within the near well
bore
area, namely within about 5-10 meters of the well. The present invention
has a number of advantages over the prior steam techniques, including the
following:
is 1 ) no requirement for water although water may be used;
2) no risk of formation damage due to clay swelling if water is not
used;
3) no risk of formation damage due to emulsions;
4) no countercurrent heat exchange losses in the tubing because
20 of heating below grade;
5) efficient and inexpensive heat delivery to deeper reservoirs
because heat losses during transportation are eliminated;
6) large thermal gradients within the formation will promote
solvent reflux (i.e., vaporization of the solvent from the near wellbore area
2s and condensation of the solvent into the "cold" heavy crude oil).
7) elevated near-wellbore temperatures to increase production
rates.
8) reduced capital and operating costs (no water treatment, or
steam generation required).
30 9) reduced environmental impact (in situ recovery vs surface
mining).
10) quick payout of the stimulation costs because the operator can
expense costs directly against increased revenue from the well.
According to the present invention the method described herein will
3s be accomplished in one of two manners. The first way is to provide short
stimulation treatment, namely, a short (1-14) day duration stimulation
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followed by a 1-2 month blowdown or draw down. The second way is to use
the method as an ongoing continuous injection process with simultaneous
oil production over a time sufficient to establish a viable chamber in the
formation. Of course depending upon the well and the flows from the well,
s in some cases the increase in production may justify a continuous on site
stimulation and draw down over a longer term.
By way of example, according to the present invention a hot solvent
stimulation could deliver up to 10,000 kg of ethane to the reservoir at
200°C,
or 25,000 kg of ethane at 100°C, within a 24 hour period. With an
average
io solvent efficiency ratio of 0.3 and 30% porosity, 25,000 kg of ethane at
100°C could produce a chamber of 500m3 volume simply by blowing down
the initial hot solvent injection. Initial production rates after a
stimulation are
much higher than the cold production rates would be without the stimulation
because of a number of effects including the lower viscosity of the oil due
is to higher temperatures, presence of the dissolved solvent and the upgrading
of the oil by de-asphalting. Quick production of the stimulated oil will
result
in quick formation of a chamber. Thus, production rates can be greatly
accelerated as compared to production rates achievable without such a
stimulation as set out in more detail below. If the stimulation cost is 50K$,
2o then the net saving to the heavy oil operator is expected to be 100 to
200K$
per well.
The principal advantage of the hot solvent injection as described
herein is to rapidly and efficiently form a solvent chamber. The thermal
stimulation provided by the present invention is a short term effect, and the
2s formation temperature will tend to cool fairly soon after the treatment is
finished. However, during the short interval while the elevated temperature
is in effect, much more production can be expected. The method taught
in this patent allows a large solvent chamber to form in a matter of several
weeks (vs 3-4 years). A sufficiently large solvent chamber would provide
3o economical oil production rates with or without requiring additional heat
input. Thus, this process would allow efficient and economic extraction of
subsequent oil with cold solvent.
It can now be further appreciated that another advantage of the hot
solvent stimulation described herein is that the heat loss from the solvent as
3s it flows out into the reservoir will tend to provide a localized thermal
benefit.
This might be useful to accelerate oil extraction and chamber formation at
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a particular location in a horizontal well. This is useful because it is
difficult
to control fluid placement in a horizontal well.
The concepts taught in this patent may also have application in
enhancing recovery of less viscous oils depending on the circumstances.
s It will be appreciated by those skilled in the art that the foregoing is
a discussion of preferred embodiments of the invention and that various
modifications or alterations are possible without departing from the broad
spirit of the invention as defined by the appended claims. Some of these
are discussed above and others will be apparent to those skilled in the art.
io For example, although various heat transfer fluids may be used, the overall
concept is to more quickly form a viable oil extraction chamber to improve
commercial recovery rates of insitu oil.
