US20110303423A1 - Viscous oil recovery using electric heating and solvent injection - Google Patents

Viscous oil recovery using electric heating and solvent injection Download PDF

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US20110303423A1
US20110303423A1 US13/086,896 US201113086896A US2011303423A1 US 20110303423 A1 US20110303423 A1 US 20110303423A1 US 201113086896 A US201113086896 A US 201113086896A US 2011303423 A1 US2011303423 A1 US 2011303423A1
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solvent
reservoir
injection
electrodes
wells
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Robert D. Kaminsky
Robert Chick Wattenbarger
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ExxonMobil Upstream Research Co
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ExxonMobil Upstream Research Co
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    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
    • E21B43/24—Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection
    • E21B43/2401—Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection by means of electricity
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/58—Compositions for enhanced recovery methods for obtaining hydrocarbons, i.e. for improving the mobility of the oil, e.g. displacing fluids

Definitions

  • 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.
  • 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)
  • CCS cyclic steam stimulation
  • SAGD steam assisted gravity drainage
  • 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.
  • a hydrocarbon solvent such as a C 6 -C 14 liquid, 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.
  • a heated fluid such as steam or solvent
  • 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.
  • 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.
  • 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.
  • 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
  • electrothermal heating of the reservoir itself by ohmic electrical conduction through the reservoir.
  • 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.
  • 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.
  • 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.
  • improved hydrocarbon methods which synergistically combine in situ electrical heating with solvent-aided recovery methods.
  • a method of recovering hydrocarbons from a subterranean reservoir by the synergistic use of electrothermal heating and solvent injection 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.
  • 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.
  • 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.
  • 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.
  • a method of recovering hydrocarbons from an underground reservoir 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.
  • 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.
  • FIG. 1 is a schematic of viscous oil recovery using electric heating and solvent injection, in accordance with a disclosed embodiment
  • FIG. 2 is a schematic of viscous oil recovery using electric resistive heating and solvent injection, in accordance with a disclosed embodiment.
  • 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.
  • in situ temperature means the temperature within the reservoir.
  • an in situ oil recovery technique is one that recovers oil from a reservoir within the earth.
  • formation refers to a subterranean body of rock that is distinct and continuous.
  • reservoir and “formation” may be used interchangeably.
  • a method of recovering hydrocarbons from an underground reservoir 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.
  • conducting electricity precedes solvent injection.
  • solvent injection precedes conducting electricity.
  • 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).
  • alternating current is preferred to minimize corrosion issues.
  • 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.
  • 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.
  • 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.
  • 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 ).
  • 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 C 3 -C 7 (or C 5- C 7 ) hydrocarbons or mixtures largely comprising C 3 -C 7 (or C 5 -C 7 ) 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.
  • 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.
  • the solvent Prior to injection, the solvent may be heated.
  • FIG. 1 depicts use of vertical wells, deviated or horizontal wells may likewise be used.
  • the solvent is heated downhole by an electric heating element in the wellbore.
  • the method involves injecting a liquid-phase hydrocarbon solvent through a wellbore which has an electric heating element.
  • 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.
  • the solvent is partially vaporized.
  • 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 .
  • the electric heating element may be part of an electrode used to conduct electricity through the reservoir.
  • 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.
  • cycling injection and production may be preferred rather than continuous injection and production through dedicated wells.
  • 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.
  • 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.
  • the wells used for cyclic injection and production may also be used as electrodes.
  • solvent injection phases the solvent could mitigate brine boiling.
  • production phases produced solvent-diluted bitumen and any (unmixed) reproduced solvent could mitigate brine boiling.
  • SDRPs solvent-dominated recovery processes
  • CSDRP solvent-dominated recovery processes
  • 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.
  • a viscosity-reducing solvent is injected through a well into a subterranean viscous-oil reservoir, causing the pressure to increase.
  • 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.
  • 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.
  • 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.
  • CSPTM processes The family of processes within the Lim et al. references may be referred to as CSPTM processes.
  • 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.
  • the primary mixing mechanism is thought to be dispersive mixing, not diffusion.
  • injected fluid in each cycle replaces the volume of previously recovered fluid and then adds sufficient additional fluid to contact previously uncontacted viscous oil.
  • 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.
  • 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.
  • Injectant Additional injectants may Only diluent, and only when composition, include CO 2 (up to about 30%), needed to achieve adequate additive C 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 fracture > P injection > P dilation > to whether most solvent is P vapor P.
  • 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.
  • infill injection and/or production wells targeting bypassed hydrocarbon from surveillance of pattern performance.
  • Well orientation Orientated in any direction.
  • 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.
  • MPP main solvent
  • day oil rate (CDOR) for example Alternatively, switch when total oil/total cycle length).
  • CDOR day oil rate
  • well is the oil rate is at about 0.8 ⁇ unable to sustain hydrocarbon CDOR.
  • 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.
  • well is out-of-synch with adjacent well cycles.
  • 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.
  • embodiments may be formed by combining two or more parameters and, for brevity and clarity, each of these combinations will not be individually listed.
  • 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.
  • the diluent is typically a viscous hydrocarbon liquid, especially a C 4 to C 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.
  • 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).
  • 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.
  • 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.).
  • 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.).
  • 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.

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US20140116683A1 (en) * 2011-04-22 2014-05-01 Schlumberger Technology Corporation Method for increasing the permeability of the bottom well-bore region of a seam (is11.0138-us-pct)
US20140251608A1 (en) * 2013-03-05 2014-09-11 Cenovus Energy Inc. Single vertical or inclined well thermal recovery process
US20150152718A1 (en) * 2013-12-03 2015-06-04 Tapantosh Chakrabarty Cyclic Solvent Hydrocarbon Recovery Process Using An Advance-Retreat Movement Of the Injectant
US9243472B1 (en) 2014-08-13 2016-01-26 Geodynamics, Inc. Wellbore plug isolation system and method
WO2016154002A1 (fr) * 2015-03-20 2016-09-29 Strategic Resource Optimization, Inc. Système électrolytique et procédé de traitement d'une source d'hydrocarbures
CN106014367A (zh) * 2016-06-08 2016-10-12 关俊华 一种油水井正电胶静电场辅助调驱、堵水的方法
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US10550679B2 (en) 2017-04-27 2020-02-04 Conocophillips Company Depressurizing oil reservoirs for SAGD
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