Note: Descriptions are shown in the official language in which they were submitted.
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VISCOUS OIL RECOVERY USING ELECTRIC HEATING AND SOLVENT INJECTION
FIELD OF THE INVENTION
[0001] The present invention relates generally to in situ recovery of
hydrocarbons.
More particularly, the present invention relates to the use of electric
heating to recover in situ
hydrocarbons including viscous oil such as bitumen.
BACKGROUND OF THE INVENTION
[0002] Recovering viscous oil from a subterranean reservoir in an economic
manner
typically requires reducing the in situ viscosity of the oil. Most commonly,
this is
accomplished by steam injection. Steamflooding (see for example U.S. Patent
No.
3,705,625 (Whitten)), cyclic steam stimulation (CSS) (see, for example, U.S.
Patent No.
4,280,559 (Best)), and steam assisted gravity drainage (SAGD) (see for example
U.S. Patent
No. 4,344,485) are well-known methods that employ steam injection to reduce in
situ oil
viscosity.
[0003] Steam injection, however, is not always an appealing method. Steam
generation requires large upfront capital expenditures for water handling and
clean-up
facilities. Additionally, steam is costly to distribute over a large field due
to thermal losses in
pipes. Alternatives to steam injection include electrical heating and solvent
addition. Each is
useful by itself as a way to aid the recovery of viscous oil from subterranean
reservoirs.
[0004] Certain prior disclosures exist describing methods using both
electrical
heating and solvent addition to aid the recovery of viscous oil from
subterranean formations.
[0005] U.S. Patent No. 4,450,909 discloses a method for opening a fluid.
communication channel between injection and production wells in a previously
unheated
heavy oil reservoir wherein the oil is not amenable to being produced by a
drive fluid, which
consists essentially of injecting a cold solvent for the heavy oil into the
unheated reservoir;
and while such solvent is moving through the unheated reservoir,
simultaneously passing
electric current between a positive electrode positioned in the injection well
and a negative
electrode positioned in the production well to reduce the injection pressure
required.
[0006] U.S. Patent Publication No. 2009/0090509 discusses using a solvating
fluid to
aid the recovery of the heavy oil from tar sands which is heated using
electrical resistive heat
sources. The process involves using solvent as a secondary process to improve
the
recovery from a neighboring area that received residual heat from a first area
or to improve
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the recovery of remaining hydrocarbons after an area has been largely produced
by heating
and gravity drainage.
[0007] U.S. Patent No. 4,412,585 discloses a method comprising a pair of
injection
and production wells for recovering heavy hydrocarbons where electrodes are
formed by
inserting a heating device in each borehole and heating the surrounding
formation to a
temperature at which the hydrocarbon-containing material undergoes thermal
cracking,
resulting in a coke-like residue surrounding the heater. This conductive and
permeable
material serves as an electrode, for each well, by which the formation is
heated. The heavy
hydrocarbon material, such as bitumen found in tar sands, becomes mobile and
can be
recovered. Additionally, a hydrocarbon solvent, such as a C6-C14 liquid, can
be used to
displace the oily bitumen from the formation.
[0008] U.S. Patent No. 4,085,803 discloses a method for recovering
hydrocarbons
from a subterranean formation where a heated fluid, such as steam or solvent,
is injected
into the formation by means of a perforated conduit which is positioned
substantially
horizontally through the formation to heat hydrocarbons within the formation.
After a suitable
heating period, injection of heat is terminated to permit fluids including
formation
hydrocarbons to drain from the formation into the conduit. The drained fluids
within the
conduit are then heated to a temperature such that at least a portion of the
drained fluids are
vaporized. These vaporized fluids pass from the perforated conduit and into
the formation to
further heat formation hydrocarbons. Subsequently, formation fluids of reduced
viscosity are
recovered from the formation through the perforated conduit.
[0009] U.S. Patent No. 5,167,280 discloses a solvent stimulation process where
a
viscosity-reducing agent is circulated through a horizontal well via a
production string. This
agent exits the production string and enters an annulus formed by said string
and a liner.
This agent diffuses into the reservoir at a pressure below the reservoir
pressure. As this
agent diffuses through the reservoir under the influence of a concentration
gradient, it
reduces the oil's viscosity and makes it mobile. Simultaneously, oil of
reduced viscosity
migrates into the well under a pressure drawdown influence.
[0010] USSR Patent Document No. 1723314 discloses a method for the recovery of
viscous or bituminous crude oil where solvent, or a mixture of solvents, is
pumped into a
producing seam through the injection hole. At the same time, the bottom-hole
zone is heated
by a high frequency electromagnetic field until the viscosity of the
hydrocarbons increases
sufficiently and corresponds with the viscosity of the solvent, i.e., it is of
the same order of
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magnitude. Then, the electromagnetic action is stopped, and is recommenced
again when
the bottom-hole temperature falls below the seam temperature.
[0011] T. N. Nasr and O. R. Ayodele (SPE Paper 101717, "New Hybrid Steam-
Solvent Process for the Recovery of Heavy Oil and Bitumen", 2008) describe a
modification
of the well-known steam-assisted gravity drainage (SAGD) method where, by
introducing
heat through electrical heating or the injection of a small amount of steam,
the heat may
serve to establish communication between an injector and producer well and
speed diffusion
of an injected solvent into the oil interface at the edge of the vapor
chamber. As diluted oil
moves towards the producer well, vaporized solvent is driven out of the oil by
heat and the
solvent returns to the vapor chamber where it mobilizes more oil.
[0012] U.S. Patent No. 5,400,430 discloses a method of stimulating an
injection well
comprising placing an electric heater within the well, at or near the bottom,
adjacent to the
area to be treated. Solvent is flowed past the energized heater to heat the
solvent and then
heated solvent flows into the treatment area to contact and remove solid wax
deposits
located in the treatment area and then injecting waterflood water into the
injection well. This
patent focuses on removing near-wellbore waxy blockages and does not involve
conducting
electricity through the formation.
[0013] U.S. Patent No. 5,167,280 discloses a solvent stimulation process where
a
solvent is circulated through a horizontal well via a production string. The
solvent diffuses
through the reservoir under the influence of a concentration gradient and
reduces the oil's
viscosity and makes it mobile. In some embodiments, the reservoir is thermally
stimulated
by an electrical induction or electromagnetic heating process so as to heat
the stimulated
zone containing the horizontal wellbore. This patent does not envision
pressure-driven flow
of solvent through the reservoir nor use of resistive heating of the
reservoir.
[0014] Variations on electrothermal heating of viscous oil formations are
described in
Canadian Patent Nos. 2,043,092, 2,120,851, U.S. Patent Nos. 849,524,
3,782,465,
3,946,809, 3,948,319, 3,958,636, 4,010,799, 4,228,853, 4,489,782, 4,679,626,
and U.S.
Application Publication Nos. 2008/0236831, and 2008/0277113.
[0015] There are three general classes of electric heating: electrical
resistive heating
of a subsurface heating element (e.g., a wellbore element or an electrically
conductive
propped fracture), radio frequency heating of the reservoir by high-frequency
alternating
electromagnetic waves propagating through the formation, and electrothermal
heating of the
reservoir itself by ohmic electrical conduction through the reservoir.
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[0016] In certain cases, electrothermal heating may be the preferred heating
approach. Energy may be distributed to a reservoir much faster by
electrothermal heating
than by electrical resistive heating of a heating element. Thermal conduction
of heat away
from a heating element is typically fairly slow, whereas electrical conduction
through the
reservoir is essentially instantaneous. Radio frequency heating may also
rapidly send heat
into a reservoir. However, radio frequency heating is significantly more
complex than ohmic
heating due to the need for high-frequency alternating current to be generated
and sent
down into the subsurface.
[0017] Electrical conduction through a reservoir necessary for electrothermal
heating
occurs due to electricity flowing through a conductive brine in the reservoir.
However,
conduction ceases if the brine sufficiently heats that it boils away. This is
particularly an
issue near electrodes where, due to geometric factors, the electrical current
is concentrated
and thus maximum heating may occur. This behavior generally means that the
heating of
the bulk reservoir has to be kept fairly modest so as to prevent overheating
near the
electrodes. Being limited to modest temperatures may result in insufficient
viscosity
reduction of the oil and thus cause unacceptably slow oil production rates.
[0018] One method of moderating temperatures near an electrode is to inject
water
or brine through or near the electrode. The injected water convects heat away
and prevents
the region adjacent to an electrode from drying out and thus losing electrical
conductivity.
However, brine injection near an electrode may be problematic since the
heating may cause
salts to precipitate and foul the injection well and the near-wellbore region.
Thus, there
exists a need for improved methods for moderating temperatures near an
electrode to
maintain a desired electrical conductivity for improved hydrocarbon recovery.
Moreover,
there exists a need for improved hydrocarbon methods which synergistically
combine in situ
electrical heating with solvent-aided recovery methods.
SUMMARY OF THE INVENTION
[0019] According to an aspect of the present invention, there is provided a
method of
recovering hydrocarbons from a subterranean reservoir by the synergistic use
of
electrothermal heating and solvent injection. The method requires that a
conductive brine
exist between electrodes disposed within the reservoir. The conductive brine
may be
naturally occurring or may comprise injected brine. The conductivity of the
brine should be
such that fluid-filled reservoir rock has a low electrical resistivity, for
example less than 100
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ohm-meters, 10 ohm-meters, or even 1 ohm-meter. The solvent is used to limit
vaporization
of water in the brine adjacent to one or more of the electrodes so as to
maintain good
electrical conductivity between electrodes. Sufficient electricity is supplied
that would, in the
absence of solvent injection, cause water to vaporize within the reservoir
adjacent to the one
or more electrodes. The electrothermal heating reduces the viscosity of the
oil. Sufficient
solvent is injected to keep the reservoir adjacent to the one or more
electrodes below the
boiling point temperature of water at reservoir pressure conditions. Finally,
oil and solvent are
produced through one or more production wells.
[0020] According to another aspect of the present invention, there is provided
a
method of recovering hydrocarbons from an underground reservoir including
conducting
electricity at least partially through a conductive brine within the reservoir
between two or
more electrodes disposed in the reservoir. Solvent is injected into the
reservoir at least
partially in a liquid phase. In one embodiment, the solvent is a fluid which
is at least
modestly soluble in the oil at reservoir conditions, e.g., having a solubility
limit of at least 5%,
or at least 20%, or at least 50% by mass in the oil within the reservoir. The
solvent may have
a bubble point temperature between 10 C and 100 C at a pressure of 1 atm,
e.g., the bubble
point at a pressure of 1 atmosphere for n-pentane is 36 C, for n-hexane is 69
C, and for n-
heptane is 98 C. Alternatively, or in addition, solvents may include
components other than
linear alkanes, e.g., cycloalkanes, aromatics, ketones, or alcohols. A portion
of the reservoir
is heated through the conduction of electricity to vaporize at least a portion
of the injected
solvent. The hydrocarbons are produced through one or more wells.
[0021] According to another aspect of the present invention, there is provided
a
method of recovering hydrocarbons from an underground reservoir, the method
comprising:
conducting electricity at least partially through a conductive brine within
the reservoir
between two or more electrodes disposed in the reservoir; injecting solvent
into the reservoir
at least partially in a liquid phase and where the solvent has a bubble point
temperature
between 10 C and 100 C at a pressure of 1 atm.; heating a portion of the
reservoir through
the conduction of electricity to vaporize at least a portion of the injected
solvent; and
producing hydrocarbons through one or more wells. Within this aspect, the
following
features may be present. Sufficient solvent may injected into the reservoir
and proximate to
one or more of the two or more electrodes to maintain the portion of the
reservoir at a
temperature below the boiling point temperature of water at reservoir pressure
conditions.
The hydrocarbons may be a viscous oil having an in situ viscosity greater than
10 cP at initial
CA 02707283 2010-06-11
reservoir conditions. The portion of the reservoir may be adjacent to at least
one of the two
or more electrodes. The method may further comprise injecting a conductive
brine into the
reservoir to further control reservoir in situ temperature or to maintain or
achieve in situ
conductivity. The solvent may comprise propane, butane, pentane, hexane, or
heptane, or a
combination thereof. The method may further comprise heating the solvent above
ground
prior to injection. The method may further comprise heating the solvent
beneath ground prior
to injection. The solvent heating may be effected by a subsurface electric
heating element.
The solvent may be at least partially produced as a vapor. One or more wells
used for
solvent injection may also be used as, or may house, one or more of the two or
more
electrodes. One or more of the one or more wells used for production may also
be used as,
or house, one or more of the two or more electrodes. The solvent may be
injected through at
least two injection wells which act as, or house, the two or more electrodes,
respectively.
The solvent may have a bubble point temperature between 35 C and 99 C at a
pressure of 1
atm. The solvent may have a solubility limit at reservoir conditions of at
least 5% by mass in
the hydrocarbons. The solvent may have a solubility limit at reservoir
conditions of at least
20% by mass in the hydrocarbons. The solvent may have a solubility limit at
reservoir
conditions of at least 50% by mass in the hydrocarbons. At least 25 mass % of
the solvent
may enter the reservoir as a liquid. At least 50 mass % of the solvent may
enter the
reservoir as a liquid. The solvent may comprise greater than 50 mass % of a C3-
C5 paraffinic
hydrocarbon solvent. The solvent may comprise greater than 50 mass % propane.
The
solvent may comprise greater than 70 mass % propane. Cycles of solvent
injection and
solvent and hydrocarbon production may occur through the one or more wells and
the one or
more wells may also act as or house one or more of the two or more electrodes.
BRIEF DESCRIPTION OF THE DRAWINGS
[0022] Fig. 1 is a schematic of viscous oil recovery using electric heating
and solvent
injection, in accordance with a disclosed embodiment; and
[0023] Fig. 2 is a schematic of viscous oil recovery using electric resistive
heating
and solvent injection, in accordance with a disclosed embodiment.
DETAILED DESCRIPTION
[0024] The term "viscous oil" as used herein means a hydrocarbon, or mixture
of
hydrocarbons, that occurs naturally and that has a viscosity of at least 10 cP
(centipoise) at
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initial reservoir conditions. Viscous oil includes oils generally defined as
"heavy oil" or
"bitumen". Bitumen is classified as an extra heavy oil, with an API gravity of
about 10 or
less, referring to its gravity as measured in degrees on the American
Petroleum Institute
(API) Scale. Heavy oil has an API gravity in the range of about 22.3 to about
10 . The terms
viscous oil, heavy oil, and bitumen are used interchangeably herein since they
may be
extracted using similar processes.
[0025] In situ is a Latin phrase for "in the place" and, in the context of
hydrocarbon
recovery, refers generally to a subsurface hydrocarbon-bearing reservoir. For
example, in
situ temperature means the temperature within the reservoir. In another usage,
an in situ oil
recovery technique is one that recovers oil from a reservoir within the earth.
[0026] The term "formation" as used herein refers to a subterranean body of
rock that
is distinct and continuous. The terms "reservoir" and "formation" may be used
interchangeably.
[0027] In one embodiment, there is provided a method of recovering
hydrocarbons
from an underground reservoir, the method comprising: conducting electricity
at least
partially through a conductive brine within the reservoir and between two or
more electrodes
disposed in the reservoir, in a quantity that would, in the absence of solvent
injection, cause
water in the brine to vaporize in a portion of the reservoir adjacent to one
or more of the
electrodes, and injecting solvent into the reservoir, to limit water
vaporization in the portion of
the reservoir adjacent to the one or more electrodes, by controlling a
temperature of this
portion of the reservoir to maintain electrical conductivity through the
brine; and producing oil
and solvent through one or more production wells. The solvent is a fluid
having a bubble
point temperature of between 10 C and 100 C at 1 atmosphere and which is at
least
modestly soluble in the oil at reservoir conditions; for example, having a
solubility limit of at
least 5%, 20%, or 50% by mass in the hydrocarbons.
[0028] In one embodiment, conducting electricity precedes solvent injection.
In
another embodiment, solvent injection precedes conducting electricity.
Similarly, either
conducting electricity or injecting solvent may proceed alone after both are
effected together
or they may be effected together after one or the other is started alone.
Therefore, where
methods described herein refer to conducting electricity and injecting
solvent, this is not
intended to limit the method to the case where solvent injection precedes
conducting
electricity.
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[0029] The solvent type and solvent injection rate are chosen to control an in
situ
temperature and prevent excessive boiling of in situ brine, which would
otherwise lead to
excessive degradation or loss of electrical conductivity of the reservoir and
hinder the ability
to heat the viscous oil in situ. While it is preferable that sufficient
solvent is injected into the
reservoir to maintain the portion of the reservoir adjacent to one or more of
the electrodes at
a temperature below the boiling point of water at reservoir pressure
conditions, some boiling
is acceptable. Therefore, reference herein is made to limiting water
vaporization. There may
be, for instance, localized areas or certain time periods where water is
vaporized without
reducing the electrical conductivity to an unacceptable amount.
[0030] The "conducting electricity" may be alternating current (AC) or direct
current
(DC). However, alternating current is preferred to minimize corrosion issues.
Moreover, low
frequency alternating current in the range of 50-60 Hertz is preferred so as
not to complicate
generation and distribution of the current. Such alternating current
frequencies are
compatible with much of the standard electrical equipment used in the world.
[0031] The electricity may be generated on site using a portion of the
produced
hydrocarbons or may be obtained from an offsite source. The offsite source may
be a
conventional power plant, for example, fired by coal or natural gas or may be
a renewable
energy source such as hydroelectric, wind, solar, or geothermal.
[0032] The instant method may be used to recover hydrocarbons, and preferably
viscous oil as defined above.
[0033] In one embodiment, depicted in Figure 1, the method mitigates
electrothermal
overheating and aids viscosity reduction by injecting a hydrocarbon solvent
into the reservoir
where electrothermal heating is, or will be, occurring. In some embodiments,
the solvent
injection can occur through the same wells which act as, or house, electrodes.
This may be
accomplished by electrically insulating or isolating an upper portion of the
well to ensure
safety and avoid electrical losses to overburden regions. Electricity may be
conducted
downhole, for instance, through a casing, internal tubing, or cables. Figure 1
depicts an
embodiment where solvent injection occurs through wells that also act as
electrodes. As
shown in Figure 1, A supply of solvent (102) is injected through
injection/electrode wells
(104) passing through the overburden (106) where the electrodes are insulated
(108), and
into a viscous oil zone (110), where the electrodes are exposed (112).
Electrical current flow
occurs between the electrodes. Solvent and mobilized oil (116) flow to the
producer well
(118). The source of electricity is also shown (120).
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[0034] Preferably, the solvent is chosen to at least partially vaporize at a
temperature
below that of the water within the reservoir. In this way, in situ
temperatures are limited to
the solvent vaporization temperatures as long as the solvent does not
completely boil off.
[0035] The solvent may also act to reduce viscosity of the native oil. Even if
the
solvent vaporizes, it will travel and then condense farther away and then mix
with native oil to
reduce its viscosity. Non-limiting examples of the solvent comprise C3-C7 (or
C5-C7)
hydrocarbons or mixtures largely comprising C3-C7 (or C5-C7) hydrocarbons. The
injected
solvent has a bubble point temperature at a pressure of 1 atm between 10 C and
100 C.
For example, the bubbling point at a pressure of 1 atmosphere for n-pentane is
36 C, for n-
hexane is 69 C, and for n-heptane is 98 C. Solvents may comprise components
other than
linear alkanes; for example, cycloalkanes, aromatics, ketones, or alcohols.
[0036] The solvent injection rate and composition may be such that the solvent
at
least partially vaporizes in situ so as to maintain at least a portion of said
reservoir below the
boiling point/temperature of water at reservoir pressure conditions in a
region where both
solvent vaporization and electric heating occur. In some embodiments, water or
brine is
additionally injected into the reservoir to further control in situ
temperatures and maintain or
achieve a desired in situ electrical conductivity. Prior to injection, the
solvent may be heated.
Although Figure 1 depicts use of vertical wells, deviated or horizontal wells
may likewise be
used.
[0037] Optionally, as shown in Figure 2, the solvent is heated downhole by an
electric
heating element in the wellbore. In the embodiment of Figure 2, the method
involves injecting
a liquid-phase hydrocarbon solvent through a wellbore which has an electric
heating
element. As shown in Figure 2, solvent is injected (202) through a well (204)
passing
through the overburden (206) and into the viscous oil zone (208). The
resistive heating
element (210) heats the solvent in the wellbore prior to the solvent entering
the formation.
The heated solvent flow (212) and the source of electricity (214) are also
shown. In some
embodiments, the solvent is partially vaporized. Use of a hydrocarbon solvent
may serve to
avoid the potential buildup of inorganic scale (e.g. salt precipitation) in or
near the injection
well since hydrocarbon solvents generally cannot hold ionic components.
Depiction of the
electrical current flow through the reservoir is not illustrated in Figure 2.
In some
embodiments, the electric heating element may be part of an electrode used to
conduct
electricity through the reservoir.
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CA 02707283 2010-06-11
[0038] In some embodiments, a backpressure maintained in the reservoir through
a
choke or other means, permits the solvent to be produced primarily in the
liquid phase. In
other embodiments, it may be preferable to reduce the pressure sufficiently to
produce some
or most of the solvent as a vapor phase. This may be particularly advantageous
towards the
end of the field life so to recover as much of the solvent as possible.
[0039] In certain cases, cycling injection and production may be preferred
rather than
continuous injection and production through dedicated wells. In such an
embodiment, one or
more of the injection wells may also act as production wells. Some or all of
these wells may
also be used as electrodes. For example, such an embodiment may combine
electrothermal heating with a cyclic solvent-dominated recovery process
(CSDRP). CSDRPs
are non-thermal recovery methods that use a solvent to mobilize viscous oil by
cyclic
injection into a subterranean viscous oil reservoir followed by production
from the reservoir
through the same well. In particular, the wells used for cyclic injection and
production may
also be used as electrodes. During solvent injection phases, the solvent could
mitigate brine
boiling. During production phases, produced solvent-diluted bitumen and any
(unmixed)
reproduced solvent could mitigate brine boiling.
[0040] CSDRP
[0041] A further discussion of a CSDRP is now provided. Where any aspect of
CSDRP, as discussed below, is inconsistent with embodiments of the instant
invention, as
described above, the above description shall prevail. Of particular note is
that when
electrothermal heating is combined with solvent injection, as described above,
heating may
account for greater viscosity reduction than solvation.
[0042] At the present time, solvent-dominated recovery processes (SDRPs) are
rarely used to produce highly viscous oil. Highly viscous oils are produced
primarily using
thermal methods in which heat, typically in the form of steam, is added to the
reservoir.
Cyclic solvent-dominated recovery processes (CSDRPs) are a subset of SDRPs. A
CSDRP
is typically, but not necessarily, a non-thermal recovery method that uses a
solvent to
mobilize viscous oil by cycles of injection and production. Solvent-dominated
means that the
injectant comprises greater than 50% by mass of solvent or that greater than
50% of the
produced oil's viscosity reduction is obtained by chemical solvation rather
than by thermal
means. One possible laboratory method for roughly comparing the relative
contribution of
heat and dilution to the viscosity reduction obtained in a proposed oil
recovery process is to
CA 02707283 2010-06-11
compare the viscosity obtained by diluting an oil sample with a solvent to the
viscosity
reduction obtained by heating the sample.
[0043] In a CSDRP, a viscosity-reducing solvent is injected through a well
into a
subterranean viscous-oil reservoir, causing the pressure to increase. Next,
the pressure is
lowered and reduced-viscosity oil is produced to the surface through the same
well through
which the solvent was injected. Multiple cycles of injection and production
are used. In
some instances, a well may not undergo cycles of injection and production, but
only cycles of
injection or only cycles of production.
[0044] CSDRPs may be particularly attractive for thinner or lower-oil-
saturation
reservoirs. In such reservoirs, thermal methods utilizing heat to reduce
viscous oil viscosity
may be inefficient due to excessive heat loss to the overburden and/or
underburden and/or
reservoir with low oil content.
[0045] References describing specific CSDRPs include: Canadian Patent No.
2,349,234 (Lim et al.); G. B. Lim et al., "Three-dimensional Scaled Physical
Modeling of
Solvent Vapour Extraction of Cold Lake Bitumen", The Journal of Canadian
Petroleum
Technology, 35(4), pp. 32-40, April 1996; G. B. Lim et al., "Cyclic
Stimulation of Cold Lake
Oil Sand with Supercritical Ethane", SPE Paper 30298, 1995; US Patent No.
3,954,141
(Allen et al.); and M. Feali et al., "Feasibility Study of the Cyclic VAPEX
Process for Low
Permeable Carbonate Systems", International Petroleum Technology Conference
Paper
12833, 2008.
[0046] The family of processes within the Lim et al. references describes
embodiments of a particular SDRP that is also a cyclic solvent-dominated
recovery process
(CSDRP). These processes relate to the recovery of heavy oil and bitumen from
subterranean reservoirs using cyclic injection of a solvent in the liquid
state which vaporizes
upon production. The family of processes within the Lim et al. references may
be referred to
as CSPTM processes.
[0047] During a CSDRP, a reservoir accommodates the injected solvent and non-
solvent fluid by compressing the pore fluids and, more importantly in some
embodiments, by
dilating the reservoir pore space when sufficient injection pressure is
applied. Pore dilation is
a particularly effective mechanism for permitting solvent to enter into
reservoirs filled with
viscous oils when the reservoir comprises largely unconsolidated sand grains.
Injected
solvent fingers into the oil sands and mixes with the viscous oil to yield a
reduced viscosity
mixture with significantly higher mobility than the native viscous oil.
Without intending to be
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CA 02707283 2010-06-11
bound by theory, the primary mixing mechanism is thought to be dispersive
mixing, not
diffusion. Preferably, injected fluid in each cycle replaces the volume of
previously
recovered fluid and then adds sufficient additional fluid to contact
previously uncontacted
viscous oil.
[0048] On production, the pressure is reduced and the solvent(s), non-solvent
injectant, and viscous oil flow back to the same well and are produced to the
surface. As the
pressure in the reservoir falls, the produced fluid rate declines with time.
Production of the
solvent/viscous oil mixture and other injectants may be governed by any of the
following
mechanisms: gas drive via solvent vaporization and native gas exsolution,
compaction drive
as the reservoir dilation relaxes, fluid expansion, and gravity-driven flow.
The relative
importance of the mechanisms depends on static properties such as solvent
properties,
native GOR (Gas to Oil Ratio), fluid and rock compressibility characteristics,
and reservoir
depth, but also depends on operational practices such as solvent injection
volume, producing
pressure, and viscous oil recovery to-date, among other factors.
[0049] Table 1 outlines the operating ranges for CSDRPs of some embodiments.
The present invention is not intended to be limited by such operating ranges.
[0050] Table 1. Operating Ranges for a CSDRP.
Parameter Broader Embodiment Narrower Embodiment
Injectant volume Fill-up estimated pattern pore Inject, beyond a pressure
volume plus 2-15% of threshold, 2-15% (or 3-8%) of
estimated pattern pore volume; estimated pore volume.
or inject, beyond a pressure
threshold, for a period of time
(for example weeks to
months); or inject, beyond a
pressure threshold, 2-15% of
estimated pore volume.
Injectant Main solvent (>50 mass%) C2- Main solvent (>50 mass%) is
composition, C5. Alternatively, wells may be propane (C3).
main subjected to compositions
other than main solvents to
improve well pattern
performance (i.e. CO2 flooding
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of a mature operation or
altering in situ stress of
reservoir).
Injectant Additional injectants may Only diluent, and only when
composition, include CO2 (up to about 30%), needed to achieve adequate
additive C3+, viscosifiers (for example injection pressure.
diesel, viscous oil, bitumen,
diluent), ketones, alcohols,
sulphur dioxide, hydrate
inhibitors, and steam.
Injectant phase & Solvent injected such that at Solvent injected as a liquid,
and
Injection the end of injection, greater most solvent injected just under
pressure than 25% by mass of the fracture pressure and above
solvent exists as a liquid in the dilation pressure,
reservoir, with no constraint as Pfracture > Pinjection > Pdilation
to whether most solvent is > PvaporP.
injected above or below
dilation pressure or fracture
pressure.
Injectant Enough heat to prevent Enough heat to prevent hydrates
temperature hydrates and locally enhance with a safety margin,
wellbore inflow consistent with Thydrate + 5 C to Thydrate
Boberg-Lantz mode +50 C.
Injection rate 0.1 to 10 m3/day per meter of 0.2 to 2 m3/day per meter of
completed well length (rate completed well length (rate
expressed as volumes of liquid expressed as volumes of liquid
solvent at reservoir conditions). solvent at reservoir conditions).
Rates may also be designed to
allow for limited or controlled
fracture extent, at fracture
pressure or desired solvent
conformance depending on
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reservoir properties.
Threshold Any pressure above initial A pressure between 90% and
pressure reservoir pressure. 100% of fracture pressure.
(pressure at
which solvent
continues to be
injected for either
a period of time
or in a volume
amount)
Well length As long of a horizontal well as 500m -1500m (commercial well).
can practically be drilled; or the
entire pay thickness for vertical
wells.
Well Horizontal wells parallel to Horizontal wells parallel to each
configuration each other, separated by some other, separated by some regular
regular spacing of 60 - 600m; spacing of 60 - 320m.
Also vertical wells, high angle
slant wells & multi-lateral wells.
Also infill injection and/or
production wells (of any type
above) targeting bypassed
hydrocarbon from surveillance
of pattern performance.
Well orientation Orientated in any direction. Horizontal wells orientated
perpendicular to (or with less than
30 degrees of variation) the
direction of maximum horizontal in
situ stress.
Minimum Generally, the range of the A low pressure below the vapor
producing MPP should be, on the low pressure of the main solvent,
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pressure (MPP) end, a pressure significantly ensuring vaporization, or, in the
below the vapor pressure, limited vaporization scheme, a
ensuring vaporization; and, on high pressure above the vapor
the high-end, a high pressure pressure. At 500m depth with pure
near the native reservoir propane, 0.5 MPa (low) - 1.5 MPa
pressure. For example, (high), values that bound the 800
perhaps 0.1 MPa - 5 MPa, kPa vapor pressure of propane.
depending on depth and mode
of operation (all-liquid or limited
vaporization).
Oil rate Switch to injection when rate Switch when the instantaneous oil
equals 2 to 50% of the max rate declines below the calendar
rate obtained during the cycle; day oil rate (CDOR) (for example
Alternatively, switch when total oil/total cycle length). Likely
absolute rate equals a pre-set most economically optimal when
value. Alternatively, well is the oil rate is at about 0.8 x
unable to sustain hydrocarbon CDOR. Alternatively, switch to
flow (continuous or injection when rate equals 20-40%
intermittent) by primary of the max rate obtained during
production against the cycle.
backpressure of gathering
system or well is "pumped off'
unable to sustain flow from
artificial lift. Alternatively, well
is out-of-synch with adjacent
well cycles.
Gas rate Switch to injection when gas Switch to injection when gas rate
rate exceeds the capacity of exceeds the capacity of the
the pumping or gas venting pumping or gas venting system.
system. Well is unable to During production, an optimal
sustain hydrocarbon flow strategy is one that limits gas
(continuous or intermittent) by production and maximizes liquid
primary production against from a horizontal well.
CA 02707283 2010-06-11
backpressure of gathering
system with/or without
compression facilities.
Oil to Solvent Begin another cycle if the Begin another cycle if the OISR of
Ratio OISR of the just completed the just completed cycle is above
cycle is above 0.15 or 0.3.
economic threshold.
Abandonment Atmospheric or a value at For propane and a depth of 500m,
pressure which all of the solvent is about 340 kPa, the likely lowest
(pressure at vaporized. obtainable bottomhole pressure at
which well is the operating depth and well
produced after below the value at which all of the
CSDRP cycles propane is vaporized.
are completed)
[0051] In Table 1, embodiments may be formed by combining two or more
parameters and, for brevity and clarity, each of these combinations will not
be individually
listed.
[0052] In the context of this specification, diluent means a liquid compound
that can
be used to dilute the solvent and can be used to manipulate the viscosity of
any resulting
solvent-bitumen mixture. By such manipulation of the viscosity of the solvent-
bitumen (and
diluent) mixture, the invasion, mobility, and distribution of solvent in the
reservoir can be
controlled so as to increase viscous oil production.
[0053] The diluent is typically a viscous hydrocarbon liquid, especially a C4
to C20
hydrocarbon, or mixture thereof, is commonly locally produced and is typically
used to thin
bitumen to pipeline specifications. Pentane, hexane, and heptane are commonly
components of such diluents. Bitumen itself can be used to modify the
viscosity of the
injected fluid, often in conjunction with ethane solvent.
[0054] In certain embodiments, the diluent may have an average initial boiling
point
close to the boiling point of pentane (36 C) or hexane (69 C) though the
average boiling
point (defined further below) may change with reuse as the mix changes (some
of the
solvent originating among the recovered viscous oil fractions). Preferably,
more than 50%
by weight of the diluent has an average boiling point lower than the boiling
point of decane
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CA 02707283 2010-06-11
(174 C). More preferably, more than 75% by weight, especially more than 80% by
weight,
and particularly more than 90% by weight of the diluent, has an average
boiling point
between the boiling point of pentane and the boiling point of decane. In
further preferred
embodiments, the diluent has an average boiling point close to the boiling
point of hexane
(69 C) or heptane (98 C), or even water (100 C).
[0055] In additional embodiments, more than 50% by weight of the diluent
(particularly more than 75% or 80% by weight and especially more than 90% by
weight)
has a boiling point between the boiling points of pentane and decane. In other
embodiments, more than 50% by weight of the diluent has a boiling point
between the
boiling points of hexane (69 C) and nonane (151 C), particularly between the
boiling
points of heptane (98 C) and octane (126 C).
[0056] By average boiling point of the diluent, we mean the boiling point of
the diluent
remaining after half (by weight) of a starting amount of diluent has been
boiled off as
defined by ASTM D 2887 (1997), for example. The average boiling point can be
determined by gas chromatographic methods or more tediously by distillation.
Boiling
points are defined as the boiling points at atmospheric pressure.
[0057] In the preceding description, for purposes of explanation, numerous
details
are set forth in order to provide a thorough understanding of the embodiments
of the
invention. However, it will be apparent to one skilled in the art that these
specific details
are not required in order to practice the invention.
[0058] The above-described embodiments of the invention are intended to be
examples only. Alterations, modifications and variations can be effected to
the particular
embodiments by those of skill in the art without departing from the scope of
the invention,
which is defined solely by the claims appended hereto.
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