US20110303423A1

US20110303423A1 - Viscous oil recovery using electric heating and solvent injection

Info

Publication number: US20110303423A1
Application number: US13/086,896
Authority: US
Inventors: Robert D. Kaminsky; Robert Chick Wattenbarger
Original assignee: ExxonMobil Upstream Research Co
Current assignee: ExxonMobil Upstream Research Co
Priority date: 2010-06-11
Filing date: 2011-04-14
Publication date: 2011-12-15
Also published as: CA2707283A1; CA2707283C

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.

Description

CROSS REFERENCE TO RELATED APPLICATIONS

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

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

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.
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.
Certain prior disclosures exist describing methods using both electrical heating and solvent addition to aid the recovery of viscous oil from subterranean formations.
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.
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.
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 C₆-C₁₄liquid, can be used to displace the oily bitumen from the formation.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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

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.
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 atmosphere, 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.
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 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° C. and 99° 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

FIG. 1 is a schematic of viscous oil recovery using electric heating and solvent injection, in accordance with a disclosed embodiment; and

FIG. 2 is a schematic of viscous oil recovery using electric resistive heating and solvent injection, in accordance with a disclosed embodiment.

DETAILED DESCRIPTION

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° 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.
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.
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.
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.
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.
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.
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.
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.
The instant method may be used to recover hydrocarbons, and preferably viscous oil as defined above.
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).
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.
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 C_5-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 atmosphere 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.
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.
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.
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.
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

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.
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.
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.
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.
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.
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™ processes.
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.
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.
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 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-C₅.	Main solvent (>50 mass %) is
composition,	Alternatively, wells may be	propane (C₃).
main	subjected to compositions
	other than main solvents to
	improve well pattern
	performance (i.e. CO₂flooding
	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	P_fracture> P_injection> P_dilation>
	to whether most solvent is	P_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_hydrate+ 5° C. to T_hydrate+
	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
		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 ×
	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)

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.
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.
The diluent is typically a viscous hydrocarbon liquid, especially a C₄to C₂₀hydrocarbon, 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.
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 (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.).
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.).
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.
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.
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.

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° C. and 100° 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° C. and 99° 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.