U.S. patent application number 13/086896 was filed with the patent office on 2011-12-15 for viscous oil recovery using electric heating and solvent injection.
Invention is credited to Robert D. Kaminsky, Robert Chick Wattenbarger.
Application Number | 20110303423 13/086896 |
Document ID | / |
Family ID | 45095298 |
Filed Date | 2011-12-15 |
United States Patent
Application |
20110303423 |
Kind Code |
A1 |
Kaminsky; Robert D. ; et
al. |
December 15, 2011 |
VISCOUS OIL RECOVERY USING ELECTRIC HEATING AND SOLVENT
INJECTION
Abstract
To recover in situ viscous oil from an underground reservoir,
electricity is conducted through the underground reservoir by at
least two electrodes in an amount that would, in the absence of
solvent injection, cause water in the reservoir to vaporize
adjacent to the electrodes, and injecting solvent into the
reservoir to mitigate water vaporization adjacent to the electrodes
by vaporizing solvent in this region. Oil and solvent are produced
through one or more production wells.
Inventors: |
Kaminsky; Robert D.;
(Houston, TX) ; Wattenbarger; Robert Chick;
(Houston, TX) |
Family ID: |
45095298 |
Appl. No.: |
13/086896 |
Filed: |
April 14, 2011 |
Current U.S.
Class: |
166/400 |
Current CPC
Class: |
E21B 43/2401 20130101;
C09K 8/58 20130101 |
Class at
Publication: |
166/400 |
International
Class: |
E21B 43/16 20060101
E21B043/16 |
Foreign Application Data
Date |
Code |
Application Number |
Jun 11, 2010 |
CA |
2,707,283 |
Claims
1. A method of recovering hydrocarbons from an underground
reservoir, the method comprising: (a) conducting electricity at
least partially through a conductive brine within the reservoir
between two or more electrodes disposed in the reservoir; (b)
injecting solvent into the reservoir at least partially in a liquid
phase and where the solvent has a bubble point temperature between
10.degree. C. and 100.degree. C. at a pressure of 1 atm.; (c)
heating a portion of the reservoir through said conduction of
electricity to vaporize at least a portion of the injected solvent;
and (d) producing hydrocarbons through one or more wells.
2. The method of claim 1 wherein sufficient solvent is 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.
3. The method of claim 1 wherein the hydrocarbons are a viscous oil
having an in situ viscosity greater than 10 cP at initial reservoir
conditions.
4. The method of claim 1 wherein the portion of the reservoir is
adjacent to at least one of the two or more electrodes.
5. The method of claim 1 further comprising injecting a conductive
brine into the reservoir to further control reservoir in situ
temperature or to maintain or achieve in situ conductivity.
6. The method of claim 1 wherein the solvent comprises propane,
butane, pentane, hexane, or heptane, or a combination thereof.
7. The method of claim 1 further comprising heating the solvent
above ground prior to injection.
8. The method of claim 1 further comprising heating the solvent
beneath ground prior to injection into the reservoir.
9. The method of claim 8 wherein the solvent heating is effected by
a subsurface electric heating element.
10. The method of claim 1 wherein the solvent is produced through
one or more wells and is at least partially produced as a
vapor.
11. The method of claim 1 wherein one or more wells used for
solvent injection are also used as, or houses, one or more of the
two or more electrodes.
12. The method of claim 1 wherein one or more of the one or more
wells used for production is also used as, or houses, one or more
of the two or more electrodes.
13. The method of claim 1 wherein the solvent is injected through
at least two injection wells which act as, or house, the two or
more electrodes, respectively.
14. The method of claim 1 wherein the solvent has a bubble point
temperature between 35.degree. C. and 99.degree. C. at a pressure
of 1 atm.
15. The method of claim 1 wherein the solvent has a solubility
limit at reservoir conditions of at least 5% by mass in the
hydrocarbons in the underground reservoir.
16. The method of claim 1 wherein the solvent has a solubility
limit at reservoir conditions of at least 20% by mass in the
hydrocarbons in the underground reservoir.
17. The method of claim 1 wherein the solvent has a solubility
limit at reservoir conditions of at least 50% by mass in the
hydrocarbons in the underground reservoir.
18. The method of claim 1 wherein at least 25 mass % of the solvent
enters the reservoir as a liquid.
19. The method of claim 1 wherein at least 50 mass % of the solvent
enters the reservoir as a liquid.
20. The method of claim 1 wherein the solvent comprises greater
than 50 mass % of components comprising propane, butane, or
pentane.
21. The method of claim 1 wherein the solvent comprises greater
than 50 mass % propane.
22. The method of claim 1 wherein the solvent comprises greater
than 70 mass % propane.
23. The method of claim 1 wherein cycles of solvent injection and
solvent and hydrocarbon production occur through the one or more
wells and where the one or more wells also act as or house one or
more of the two or more electrodes.
Description
CROSS REFERENCE TO RELATED APPLICATIONS
[0001] This application claims priority from Canadian Patent
Application number 2,707,283 filed Jun. 11, 2010, entitled Viscous
Oil Recovery Using Electric Heating and Solvent Injection, the
entirety of which is incorporated by reference herein.
FIELD OF THE INVENTION
[0002] 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
[0003] 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. Pat. No. 3,705,625 (Whitten)),
cyclic steam stimulation (CSS) (see, for example, U.S. Pat. No.
4,280,559 (Best)), and steam assisted gravity drainage (SAGD) (see
for example U.S. Pat. No. 4,344,485) are well-known methods that
employ steam injection to reduce in situ oil viscosity.
[0004] 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.
[0005] Certain prior disclosures exist describing methods using
both electrical heating and solvent addition to aid the recovery of
viscous oil from subterranean formations.
[0006] U.S. Pat. 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.
[0007] 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 the recovery of remaining
hydrocarbons after an area has been largely produced by heating and
gravity drainage.
[0008] U.S. Pat. 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
C.sub.6-C.sub.14 liquid, can be used to displace the oily bitumen
from the formation.
[0009] U.S. Pat. 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.
[0010] U.S. Pat. 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.
[0011] USSR Patent Document No. 1,723,314 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
magnitude. Then, the electromagnetic action is stopped, and is
recommenced again when the bottom-hole temperature falls below the
seam temperature.
[0012] 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.
[0013] U.S. Pat. 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.
[0014] U.S. Pat. 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.
[0015] Variations on electrothermal heating of viscous oil
formations are described in Canadian Patent Nos. 2,043,092,
2,120,851, U.S. Pat. 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.
[0016] 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.
[0017] 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.
[0018] 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.
[0019] 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
[0020] 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 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 electro-thermal 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.
[0021] 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.degree. C. and 100.degree. C. at a pressure
of 1 atmosphere, e.g., the bubble point at a pressure of 1
atmosphere for n-pentane is 36.degree. C., for n-hexane is
69.degree. C., and for n-heptane is 98.degree. 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.
[0022] 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.degree. C.
and 100.degree. C. at a pressure of 1 atmosphere; 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
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.degree. C. and 99.degree. C. at a
pressure of 1 atmosphere. 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 components comprising propane, butane, or pentane. 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
[0023] FIG. 1 is a schematic of viscous oil recovery using electric
heating and solvent injection, in accordance with a disclosed
embodiment; and
[0024] FIG. 2 is a schematic of viscous oil recovery using electric
resistive heating and solvent injection, in accordance with a
disclosed embodiment.
DETAILED DESCRIPTION
[0025] 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 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.degree. 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.degree. to about 10.degree. . The terms viscous oil, heavy
oil, and bitumen are used interchangeably herein since they may be
extracted using similar processes.
[0026] 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.
[0027] 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.
[0028] 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.degree. C. and 100.degree. 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.
[0029] 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.
[0030] 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.
[0031] 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.
[0032] 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.
[0033] The instant method may be used to recover hydrocarbons, and
preferably viscous oil as defined above.
[0034] In one embodiment, depicted in FIG. 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. FIG. 1 depicts an embodiment
where solvent injection occurs through wells that also act as
electrodes. As shown in FIG. 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).
[0035] 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.
[0036] 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
C.sub.3-C.sub.7 (or C.sub.5-C.sub.7) hydrocarbons or mixtures
largely comprising C.sub.3-C.sub.7 (or C.sub.5-C.sub.7)
hydrocarbons. The injected solvent has a bubble point temperature
at a pressure of 1 atmosphere between 10.degree. C. and 100.degree.
C. For example, the bubbling point at a pressure of 1 atmosphere
for n-pentane is 36.degree. C., for n-hexane is 69.degree. C., and
for n-heptane is 98.degree. C. Solvents may comprise components
other than linear alkanes; for example, cycloalkanes, aromatics,
ketones, or alcohols.
[0037] 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 FIG. 1 depicts use
of vertical wells, deviated or horizontal wells may likewise be
used.
[0038] Optionally, as shown in FIG. 2, the solvent is heated
downhole by an electric heating element in the wellbore. In the
embodiment of FIG. 2, the method involves injecting a liquid-phase
hydrocarbon solvent through a wellbore which has an electric
heating element. As shown in FIG. 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
FIG. 2. In some embodiments, the electric heating element may be
part of an electrode used to conduct electricity through the
reservoir.
[0039] 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.
[0040] 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.
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 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; U.S. Pat. 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 CSP.TM. 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 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.
TABLE-US-00001 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 %) C.sub.2-C.sub.5. Main solvent (>50 mass
%) is composition, Alternatively, wells may be propane (C.sub.3).
main subjected to compositions other than main solvents to improve
well pattern performance (i.e. CO.sub.2 flooding of a mature
operation or altering in situ stress of reservoir). Injectant
Additional injectants may Only diluent, and only when composition,
include CO.sub.2 (up to about 30%), needed to achieve adequate
additive C.sub.3+, 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 P.sub.fracture > P.sub.injection >
P.sub.dilation > to whether most solvent is P.sub.vaporP.
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 T.sub.hydrate + 5.degree. C. to
T.sub.hydrate + Boberg-Lantz mode 50.degree. C. Injection rate 0.1
to 10 m.sup.3/day per meter of 0.2 to 2 m.sup.3/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 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 500 m-1500 m (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 60-600 m; spacing of
60-320 m. 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, 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 500 m depth with near the native reservoir pure
propane, 0.5 MPa (low)-1.5 MPa pressure. For example, (high),
values that bound the perhaps 0.1 MPa-5 MPa, 800 kPa vapor pressure
of depending on depth and mode propane. 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 .times. 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. 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 500 m,
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)
[0050] 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.
[0051] 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.
[0052] The diluent is typically a viscous hydrocarbon liquid,
especially a C.sub.4 to C.sub.20 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.
[0053] In certain embodiments, the diluent may have an average
initial boiling point close to the boiling point of pentane
(36.degree. C.) or hexane (69.degree. 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 (174.degree. 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.degree. C.) or heptane (98.degree. C.), or even water
(100.degree. C.).
[0054] 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.degree. C.) and nonane (151.degree. C.),
particularly between the boiling points of heptane (98.degree. C.)
and octane (126.degree. C.).
[0055] 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.
[0056] 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.
[0057] 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.
* * * * *